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Home My WebLink AboutAPA2499-.;, '~-'"'11 ~ I 71. ~ m·~~~®®. m ~ ~ ~ ID ~~ .1 ·~ SUS/TNA JOINT VENTURE [}{]&[ru~£c§[ru£@@@ SUsitna Joint Venture Document Number Please Return To DOCUMENT CONTROL . • ., ., . • t. ~ • 1. ·{'{ r • Design Office: 400.1 t2th A11enue, NE Bellevue, I Main OffictJ•: 8740 Hanzel/ Road Anchon Mr. Robert Ao Mohn ·Project Manager · Alaska Power Authority 334 West 5tb Avenue Arlchorage~ Alaska 99501 Subject: Susitna Hydroelectric. Project C~.t£ f, cd T~IL June 7 & 8 1983 Review Committee Neeting Dear Robert: Enclosed ar£~ three copies of responses to FERC non-conferring • items scheduled for the June 7 -8, 1983 Review Committee :J 451-4500 •J 349-8581 meeting. Attachtn.ent I of this package lists revisions to sections of Exhibits B + D transmitted for your revie'YT. Also contained herein are draft responses to FERC Schedule A, Exhibit F items. RLM/HU/ml Enc: As noted cc: D. Jane Drennan, PHS, w I enc. c~ Debelius, Acres, w/enc. D. Neagher, H-·E 7 w/enc.. H. Chen, H-E, Tll/enc. S. Simmons, H-E, w/enc. J. Robinson, H-E, w/o encM ( \ I l r B 5.1 B 5.2 B 5.2.1 B 5.2.2 5 5.2.3 .B 5. 3 B 5.3.1 B 5.3.2 B 5.3.2.1 B 5.3.2.2 B 5.3.2.3 B 5.3.2.4 B 5 .. 1.2.5 B 5.3.3 B 5.3.3.1 B 5.3.3.2 B 5.4. B 5.4.1 B 5.4.2 B 5.4.3 B 5.4.4 B 5.5 B 5.5.1 B 5.5.2 B 5.5.3 B 5.6 APP. B.2 D 1.5 D 1.9 D 2.0 D 3.1 b 3.2 D 3.3 D 3 .. 4 D 3.5 D 3.6 D 3.7 D 4.5 D 4.6 D 4. 7 D 4.8 . ~.·~-~; r ' June 6, 1983 Attachment 1 ~ List of Draft Responses for Exhibits B and D Introduction System Description The Inter connected Rail belt Market Railbelt Electric Utilities Historical Data for the Market Area Forecasting Methodology The Effect of World Oi 1 Prices on the Need For Power The Forecasting Models Mode 1 Overview· PETREV MAP Model RED Model OGP Model Model Validation MAP Model RED Model (not available) Forecast of Electric Power Demand Oil Price Forecasts Other Key Variables and Assumptions Base Case Forecast Model Output Alternative Forecast§ -Model Output Evaluation of Electric Power Market Forecast Comparison with Previous Forecasts Impact of Oil Prices in Forecasts Sensitivity to Other Key Variables and Assumptions Project Utilization Appendixii Fuels Pricing Studies Allowance For Funds Used During Canst. Previously Constructed Project Facillities Estimated Annual Project Costs The Railbelt Power System Regional Elec. Power Demand & Supply Market & Price For Watana Output in 1994 Market & Price: Watana Output 1995-2001 Market & Price~ Watana & D.C. Output: 2003 Potential Impact of State Appropriations Conclusion Thermal Options-Development Selection Without Susitna Plan Economic Evaluation Sensitivity to World Oil Price Forecast ............. '~·; :.. 'i ... 4 :,;~ .. :~;:~_'i:? :~or:'-~.-' ,:· SUSITNA HYDROELECTRIC PROJECT • VOLUME 1 . /'\ PROJECT COSTS AND FINANCING TABLE OF CO~TENTS 1 ~STIMATES OF CO~T _ ......................................... . 1.1-Construct1on Costs .................................. . / {a} Code of Accounts ............................... . (b) Approach to Cost Estimating .................... . ( c ) Co s t 0 at a . . . . . . . . . .. . . . . . . .. . . . . . . . . . . . • . . . . . . . . . . ( d ) Se as on a l I n f l u en c e s on Prod u c t i v i t y . . • • . . . . . . • . • (e) Construction Methods ................ ····o······· ( f) Qu ant i t y Takeoffs •••.•.....•.•.••...••...•..•... (g) Indirect Construction Costs .................... . 1 2 .,. .. t-r . .. -l'-J 1 t 1 g a _ 1 o n \.., o s t s • . . . • • . . . ... . . . . . . . . . . . . . . . . . . . . .. . ~ . . -· . 1.3-Engineering and Admin1stration Costs ................ . (a) Engineering and Project ~aragement Costs ....... ~ (b) Construct1on Management Costs .................. . (c) Procurement Costs •.............................. (d) Owner's Costs ................................... . 1.4-Operation, Maintenance and Replacement Cost§ .•....... 1.5 Allowance for Funds Used During Constru~tion ........ . 1.6 ·Escalation .......................................... . 1.7-Cash Flow and Manpower Loading Requirements .........• 1.8.., Continqency ········••s••········J;I··-················· 1.9 ~Previously-Constructed Project Facilities .•........•. 1.10-EBASCO Check Est1mate ...............................• ESTIMATED ANNUAL P~OJECT COSTS ............................ . . ~ARKET VALUE Of PROJECT POWER .............•......•......... 3.1 ... The Rai lbelt Power System ............................ . 3.2-Regional Electric Power Demand and Supply ........... . 3.3-Market and Price for Watana Output in 1994 .......... . 3.4-Market and Price for Wdtana Output 1995-2001 ........ . 3.5-Market and Price for Watana and Uev;l Canyon Output in 2003 ·······~································ 3.6-Potential Impact of Stdte Appropriations ···o·•······· 3.7-Conclusions ..... , ................................... , .. 4 ·EVALUATION OF ALTERNATIVE ENERGY PLANS .................... . 4.1 .. General ········--·················~--······oil:•·•······· 4.2-Existing System Character1st1cs .......... ·········~·· (a) System Description ............................. . (b) Retirement Schedule~····:························ ( c ) Sc h ed u 1 e a f Ad d 1 t 1 on s . . . . . . , . . . . . . . . . . • . . . . . . . . . Page 0-1-1 0-1-1 0-1-1 0-1-2 0-1-3 D-1-4 D-1-5 0-1-5 }-1-5 0-1-6 D-l-8 0-1-8 0-1-9 0-1-9 0-l-10 0-1-10 D-1-11 0-1-12 0-1-12 0-1-12 0-1-12 0-l-13 D-2-1 0-3-1 D-3-1 0-3-1 0-3-2 D-3-3 0-3-3 0-3-4 0-3-4 0-4-1 0-4-1 Q ... 4-2 D-4-2 0-4-2 0-4-3 ! I I ,, 1 TABLE OF CONTENTS (Continued) 4.3 -Fairbanks -Anchorage Intertie .. . 4.4-Hydroelectric Alternatives ..... . . . (a) Selection Process . . . (b) Selected Sites .. . tc) Lake Chakachamna ............ . 4.5 -Thermal Options -Development Selection .. . (a) Assessment of Thermal Alternatives ... . (b) Coal-Fired Steam . . .......... . (c) Combined Cycle . . . . . . . .. (d) Gas-Turbine . . . . . . . . . . . . . (e) Diesel Power Generation ........ . (f) Plan Formulation and Evaluation . . . . . 4.6 -Without Susitna Plan . . . .. . (a) System as of January 1993 ... . (b) System Add it ions . . . . . .. (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 (-imr±n t1 ----. . . . . . . . . . . . . . . 4.9 -Other Sensitivity and Probability Assessment (a) Introduction . . . . . . . . . ..... . (b) Sensitivity Analysis .......... . (c) Multivariate Sensitivity Analysis ... . (d) Comparison of Long-Term Costs ..•. (e) Net Benefit Comparison ..... . (f) Sensitivity of Results to Probabilities 4.10-Bettelle Railbelt Alternatives Study . . . (a) Alternatives Evaluation ...... ~ (b) Energy Plans .......... . 5 -CONSEQUENCES OF LICENSE DENIAL . . . . . . . . . 5.1-Cost of License Denial ..... 5.2 -Future Use ot Damsites if License is Denied 6 -FINANCING 6.1 -Forecast Financial Parameters ..... . 6.2 -Inflationary Financing Deficit . . . . ..• 6~l -Legislative Status of Alaska Power Authority and Susitna Project . . . . . . . . .. 6.4 -Financing Plan ............... . REFERENCES J, IST OF TABLES LIST OF' FIGURES Page D-4-3 D-4-4 D-4-4 D-4-5 D-4-6 D--4-9 D-4-9 D-4-10 D-4-11 D-4-12 D-4-13 D-4-14 D-4-15 D-4-16 D-4-16 D-4-16 D-4-17 D-4-18 D-4-18 D-4-35 D-4-3.5 D··-4-36 D-4-37 D-4-37 D-4-38 D-4-39 D-4-48 D-5-l D-5-1 D-5-1 D-6-1 D-6-1 D-6-1 D-6-2 . 1 . . . 111 LIST OF TABLES D.2 0 .. 3 D.4 D.5 D.6 D.7 0.8 D.9 D .10 D. ll D. 12 D. 13 D.l4 D. 15 D .16 D .17 D. 18 D .19 D. 20 0.21 D.22 D. 23 D.24 D.25 0.26 D.27 D.28 D. 29 D.30 0.31 Summary of Cost Estimate Estimate Summary -Watana Estimate Summary -Devil Canyon Mitigation Measures -Summary of Costs Incorporated In Construction Cost Estimates Summary of Operation and Maintenance Costs Variables for AFDC Computations Watana and Devil Canyon Cumulative and Annual Cash Flow Anchorage Fairbanks Intertie Project Cost Estimate Summarv of EBASCO Check Estimate "' Pro Forma Financial Statements No Fund-No State Contribution Scenario Susitna Cost of Power Forecast FinanciaL Parameters Total Generating Capacity Within the Railbelt System Generating Units Within the Railbelt -i980 Scheudle of Planned Utiltty Additons (1980-1988) Operating and Economic Parameters for Selected Hydroelectric Plants Results of Economic Analyses of Alternative Generation Sceneries Summary of Thermal Generating Resource Plant Parameters/ 1982$ Bid Line Item Costs for Beluga Area Station Bid Line Item Costs fo 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 Summary of Load Forecasts Used for Sensitivity Analysis Load Forecast Sensitivity Analysis Discount Rate Sensitivity Analysis Capital Cost Sensitivity Analysis Sensitivity Analysis -Updated Base Plan (January 1982) Coal Prices Sensitivity Analysis -Real Cost Escalation Sensitivity Analysis -Non-Susitna Plan "'ith Chakachamna i (Revised) LIST Of TABLES (Continued) D.32 D.33 D.34 D.35 D.36 D.37 D.38 Sensitivity Analysis -Susitna Project Delay Summary of Sensitivity Analysis Indexes of Net Economic Benefits Battelle Alternatives Study for the Railbelt Candidate Electric Energy Generating Technologies Battelle Alternatives Study, Summary of Cost and Performance Characteristics of Selected Alternatives Battelle Alternatives Study, Summary o.f Electr.ic Energy Plans Financing Requirmeents-$ Milian for $1.8 Billion Stat:e Appropriation $1.8 Billion (1982 Dollars) State Appropriation Scenario 7% Inflation and 10% Interest ii (Revised) LIST OF FIGURES 0.1 0.2 0.3 0.4 0 .. 5 O.b 0 .J.\- 0 • .a-~ D "'9.': b D.~ 7 D.¥ ~ D.~ C) D,U.lO D.~ l ( 0 .lS 12- D.h8-t3 O.l3 l4 D.)ftt~ o.~tb Watana Development Cumulative and Annual Cash Flow January 1982 Dollars Devil Canyon Oeveiopment Cumulative and Annual Cash Flow January 1982 Dollars Susitna Hydroelectric Project Cumulative and Annual Cash Flow Entire Project, January 1982 Dollars Ra;lbelt Regio" GeRe~atiAg aRn TraAs~ission FaGllitie5 Service Areas of Ratlbelt Utilities EAergy Supply; Generating faGilities; Net Generation by Ty~es of Fuel; Relative Mix of Electrical GeAeratiAg TecAAology Rai~oelt Utilities 1980 Energy Demand and Deliveries From Susitna Energy Pricing Comparisons -1994 System Costs Avoided by Developing Susitna Energy Pricing Comparisons -2003 Formulation of Plans Incorporating Non-Susitna Hydro Generation Selected Alternative Hydroelectric Sites Formulation of Plans Incorporating Al 1-Thermal Generation Alternative Generation Scenario Battelle Medium Load Forecast Probability Tree-System with Alternatives to Susitna Probability Tree·-System with Susitna Susitna Multivariate Sensitivity Analysis -Long-Term Costs vs Cumulative Prooability Susitna Multivariate Sensitivity Analysis -Cumulative Probability vs Net Benefits Energy Cost Comparison -100% Debt Financing 0 and 7~ Inflation l ... _ l iii . ~ l .. -... _.. ~ "l\ll. ",.' ~. • " -~-' .~ ~ ·. . ... . .. 'T ~ -.. C ~· .. j '-'< Allowances have also been made for environmental mitigation as well as a contingency for unforeseen costs. Estimates for Susitna have been based on original estimates and actual experience at Churchill Falls. It should be realized that alternative operating plans are possible which would eliminate the need for permanent town site facilities and rely on more remote superv1.sor y systems and/or operations/maintenance crews transported to the plant on a retating shift basis. Cost im- piications of these alternatives have not yet been examined. 1.5 -Allowance for Funds Used During Construction (AFDC) At current high levels of interest rates in the financial marketplace, AFDC will amount to a significant element of financing cost for the lengthy per:od required for construction of the Watana and Devil Canyon porjects. Hawver, . . tn economtc evaluations of the Susitna project the low real rates of interest assumed would have a much reduced impact ~n assumed project development costs. Furthermore, direct state involvement in financing of the S~sitna project will also have a significant impact on the amount, if any, of AFDC. Pr ov is ions for AFDC at appropriate rates of interest are made in the economic and financial analyses included in this Exhibit. 0 -I -I I ( ;{'(:;:l_;t .s~ d) f (1 + ~~--~B _, f_ . t + ... -X)/Bl(l+f)--11 Lt l co '-· - (l+fu B ln (l+f) + 2 B ln -· where 1 + f =Total cost upon commercial service (%) co l+f=l+y 1 + X x = effective interest rate y -escalation rate B -construction period l J The value of the variables used in the computations are summarized ~n Table D.6 The Watana and Devil Canyon constructions periods were taken from Exhibit Cas 8.5 years and 7.5 years, respectively. ' 0 -I -II/) (f?~rJtS<--1) ..... 1 The resultant total project cost was then calculated for each interest/escalation scenario used in econimic and financial studies as shown in Table D.l. 1.6 -Escalation Provision must be made for future cost escalation which will take place over the construction periods involved. The financial evaluation takes full account of such escalation, as discussed 1n the prev1ous 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 studit•s. The bases for the cash flow are the construction cost estimates ~n January !982 dollars and the construction schedules presented in Exhibit C. The cash flow estimates were computed opn an annual ba;:; is and do not include adjustments for advances payments for mobilization or for holdbacks on construction contracts. the results are presented in Table D.7 and Figures D.l through 0~3. The manpower loading requirements were developed from cash flow projections. These curves were used as the basis for camp loading and associated socioeconomic impact studies. 1.8 -Contingency An overall contingency allowance of approximately 15 percent oif construction costs has been included in the cost estimates~ Contingencies have be~n 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. 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 -Previousll Constructed Project Facilities An electrical intertie between the major load centers of Fairbanks and Anchor age wilt be completed in the mid-l980s. f h~ ftn~ ~~ // Co,.f/1~ c:: f' 0-1-12 A. (~~;.A.!K',/ "*''"'*" -- existing transmissioo/systems at Willow in the south and Healy in the north. The intertie)..l$ iei~43 bui 1 t to the same standards as those proposed for the Susitna project transmission lines and will become part of the ltcensed project~ The line will be energized initially at 138 kV in 1984 and will cperate 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 o.)r. 1.10 -EBASCO Check Estimate An independent check estimate was undertaken by EBASCO Services Incor- porated (EBASCO 1982). The estimate was based on engineering drawings, technical information and quantities prepared by kres American in the feasibility study. Major quantity items were checked. The EBASCO ~ check estimated capital cost was approximately 7 percent above the J' ~ Acres estimate. · A summary of EBASCO's check estimate has been included in this exhibit. 2 -ESTIMATED ANNUAL PROJECT COSTS As a two-stage (Watana and Oevi 1 Canyon) development with varying 1 evel s of ener"gy output and the assumption of ongoing i nf l at ion (at 7 per':~nt per annum), the real cost of Susitna power will continually vary. As a consequence, no simple single value real cost of power can be used. \'V Table Os't gives tne projected year-by-year energy levels on the f.~·~~ line and, on the second, the year-by-year unit cost of n 1982 do 11 ars. A breakout of this coc;t into operation~ rep 1 acements and debt service is included on Sheet 4 of Table D. . The r~nainder of the taole is a cash flow surrwnar·y of revenue (R.LS 5), operating costs ( 170), interest, and casn sources and uses. These costs are in nominal .~ 0 ~~ do 11 ars assuming 7 percent i nf l at 1 on and 10 percent cost of capita 1 • / C:.J.-r;)n Costs are based on power sa 1 es at cost assuming 100 percent deb trll~ 0/1 __ in d at 10 percent interest. This results in a real co ower\ f?c,1P ----o f 12 i 1 1 s i n 19 9 4 • ( f i r :; t f u 11 y e a r o f W at an a ) f a 1 1 i n g t 7 3 i 1 1 s i n '"'--, 20C (the first full year of watana and Oevi 1 Canyon). Hi real cost of power, c:,djusted for infldtion of 7 percent per annum. would then fall progressively for the remaining life. No taxes have been assessed to the project's annual costs. Althougn these taxes would be ex pres sed as a percent age of project p 1 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 Autnority is a not-for-profit entity. As such, the A~ ority would not be sub- ject to a revenue tax. 11 The cost of power given in Table D. is designed to reflect as fully as possible the economic cost of power for purposes of broad comparison with alternative power options. It is, therefore, based on the capaci- ty cost which would arise if the project were 100 percent debt financed at market rates of interest. It does not ref .ect the price at which power will be charged into tne system. "' . ' l n-'-! ( {J_,.,MJJ) - 3 -MARKET VALUE OF PROJECT PO\~ER This section presents an assessment of the range of rates at which energy and capacity of the Susitna development could be price<£l)i... --•••z:ss together with a proposed basis for contracting for the supply of Susitna energy. 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 Rai lbelt reg1on covers the Anchor age-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 delivered to the Region via the linkage of the Anchorage and Fairbanks systems by an intertie to be completed iu the mid-1980s. The proposed intertie will allow a capacity transfer of up to 70 MW in either direction. The proposed plan of interconnection envisages 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 SupeLI The base case forecast of electric power demand is presented in E~hibit B. The results of studies presented in Exhibit B and Section 4 of the Exhibit call for Watana to come int0 operatiot1 in 1993 and to deliver a full year's energy genera- tion in 1994. Devil Canyon will come into operation in 2002 and del ~ver a full yea_r' s .energy. in 2~03. Energy d~man~ in thf{., Rai lbelt reg1on and the del1ver1es from Sus1tna are shown 1n F1gure D.~. 3.3 -Market and Price for Watana Output in 1994 @ " It has been projected that Watana energy will be supplied at a single wholesale rate on a free-market basis. This requires, in effect, that Susitna energy be priced so that it is attractive even to utilities J;Jb<(c.L.[ with the lot-lest cost alternative source of energy. On this basi~"-1-nS t.f...tc est irnated that for the in~ t i ctl.ly mark~tab le 3315 GWh ~~ gener- ated by Watana in 1994 to be attractive, a price of ~1ni11s per kWh in 1994 dollars is required. This estimate assumes a prevailing 7 per- cent rate of inflation per annur1. Justification for this pr;ce, as ~---, compared to the price of alternatives, is illustrated in Figure 0 .• The costs for alternatives in Figure D. are based on ca cu a 1ons using the financial parameters in Table 0. . Plant capital and oper- ating costs are shown in Table D.~The most cost effective alterna- tive plan is specified in Section 4.6.~ 12 Figure O~shows on the far right of the figure the area in which costs of the best thermal and Susitna options are conmon. These costs are incurred by plants required in both system configurations to meet the 1-b b~ full generating requirements of 1994. Watana, coming on-line at 'th~ ~. (u.J time, would effectively avoid all costs represented by tt}.e.-s+ra<fed C'-Vc.. areas. These costs divided by the marketable Wa~~of 3315 GWh gives a wholesale energy rate of approximately 45 mills/kWh (in 1994 dollars) which is the maximum to be charged if onsumers were to be neither better nor worse off in 1994 under the with-Susitna plan or the best a l tern at i v e p lan . Th e w i t h-and w i thou t -S u s i t n a p 1 an s and the generation planning program described in this exhibit. were used to cal- culate the power value. Note that the assumption is made that the only capital costs which would De avoided in the early 1990s would be those due to the alternative addition of new coal-fired generating plants (i.e., the 2 x 200 MW cqal-fired Beluga station). The financing considerations under whicn~~oeappfopr i ate for Wat a~ a ener~y to b~ so 1. d at approx im~t; 1 ~.14 5 ..,..,rn.ll1 s. per kWh price are cons1dered 1n Sect1on 6 of th1s Exhtblt; rrowe1er, 1t should be noted that some of the energy ~i-::h ~uld be displaced by Watana• s product ion would have been generated at a lower cost than 145 mills, and utilities might w~sh to delay accepting it at this price until the escalating cost of natural ges or other fuels made it more attractive. The pro- jected real escalation used in the study of the market price are~'t..IOLJO. m~ teuet ~ ecastn ee Taales 0~23 H-e!fl~li ±D ~. A nunber of approach- es to the resolution of this problem can be postulated, including pre- contract arrangements. ,. ,, .... .. ... B The Power Authority will seek to contract with Railbelt utilities for the purchase of Susitna capacity and energy on a basis appropriate to support financing of the project. Pricing policies for Susitna output, as defined by the Alaska legisla~ ture, will be constrained both by cost and by the price of energy from the best alternative option. These options are discussed in Section 4 of this Exhibft. Marketing Susitna•s output ~ithin the~~ twin constraints would ensure that all state financial support for Susitna flowed through to con- sumers and under no circumstances would prices to consumers be higher than they would have been under the best alternative option. In addi- tion, consumers would also obtain the long-term economic benefits of Susitna•s stable cost of energy. 3.4 -Market and Price for Watana Output 1995-2001 , After its first full year of operation in the systen in 1994, 3315 GWh of the total 3387 GWh of Watana output is initially marketable. The excess energy occurs in the su0111er. The market for the project strengthens over the years to 2001 since energy demand will increase by 20 percent over this period as projected in Exhibit B forecasts. As a result there would be a 70 percent increase in cost savings com- pared with the best thermal generating alternative; the increasing cost per unit of output from a system without Susitna is illustrated in Figure 0.~ The addition of the Susitna project will add a large generating re- source 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 tot a 1 energy demand.. The d i sp 1 aced units wi 11 be used as reserve capacity and to meet growing 1 o ad unt i 1 the Oev i 1 Canyon project comes on 1 ine. This effect is illustrated on Figure 0 0 • A diagramnatic analysis of the total cost savings which the combined Watana and Devil Canyon output will confer on the system compared with .,..._._t~h~e"'L a 1 tern at i ve therma 1 option in the year 2003 is shown in Figure D. • These total savings are · ed by the energy contributed by Susitna to indicate a price 250 mills per kWh (2003 dollars, 7 percent general escalation per as the maximum price which can be charged for Susitna output. Only about 90 percent of the total Susitna energy output will be ab- sorbed by the system in 2002; the balance of the output w;ll be pro- gressively absorbed over the following decade. This wi 11 provide additional total savings to the system with Susitna since no other resources will be needed. After the Devil Canyon project comes on line, the Susitna project will provide 90 percent of the energy demand. 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. This effect is shown on the shaded portion of Figure D. 3.6 -Potential Impact of State Appropriations In the preceding paragraphs, the maximu~ price at which Susitna energy could be sold has been identified. Sale of the energy at these prices w i 11 depend upon the magnitude of any proposed state appropriation designed to reduce the cost of Susitna energy in the earlier years. At significantly lower prices, it is likely that the total system demand will be higher than assumed. This, combined with a state appropriation to reduce the energy cost of Watana energy, would make it correspond- ingly easier to market the output from the Susitna development; how- ever, as the preceding analysis shows, a viable and strengthening market exists for tne energy from the development that would make it possible to price the output up to the cost of the best thermal alter· native. The effect of pricing policy on power demand has been taken into account by the elasticity loop of the Battelle load forecasting methodology described in Section 5 of Exhibit B. The forecasts used for market price studies resulted from pricing assumptions consistent with those presented. 3.7 -Conclusions 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 lev'el of state appropriation and with pricing policy as defined in Alaska State Laws, a viable basis exists for the Susitna power to be absorbed by the Railbelt utilities. D-3-4 ·~ -••w-- I [II I • . . I 4 -EVALUATION OF ALTERNATIVE ENERGY PLANS 4.1 -General This section describes the process of assembling the information neces- sary to carry out the systemwide generation planning studies for as- sessment of the economic feasibility of the Susitna project. Included is a discussion of the existing system characteristics, the planned Anchorage-Fairbanks intertie, and details of various generating options including hydroelectric and thermal. Performance and cost information required for the generation planning studies is presented for the hydroelectric and thermal generation options considered. The approach taken in economically evaluating the Susitna project in- volved the development of long-term generation plans for the Railbelt electrical supply system with and without the proposed project. In order to compare the with-and-without p!ans, 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 s t u d i e s proceeded i n par a 1 l e 1 wh i c h addressed t h e a 1 tern at i v e s i n g en - erating power in the Alaska Railbelt. These studies are the Susitna H droelect-ic Project Feasibility Study OOfle by Acres ~rilrican IncoJ:po .. ra•iH~ fm-the Alaska Power Authority and the Railbelt Electric Power 1ternatives Studyjaonc ~Y ~attelle Pacjfjc Northwest Laborateries for the Office of the Governor, State of Alaska. ~ o b j ec t i v e of the Sus i t n a Fe as i b i 1 i t y S t u d y was to de t e r m i n e the feasibility of the proposed project. The economic evaluations per- formed during the study found the project to be feasible as documented in this exhibit. The independent study conducted by Battelle focused on the feasibility of all possible generating and conservation alterna- tives. Although the studies were independent, several key factors were con- sistent. Both studies used the approach of comparing costs by using generation planning simulation models. Thus, selected alternatives were put into a plan context and their econoHllC performance compared by comparing costs of the plans. Additionally, parameters such as costs for fuel and capital costs and escalation were consistent between the two studies. The following presentation focuses primarily on the Susitna Feasibility Study process and findings. A separate section provides the findings of the Battelle study, which generally agree with the feasibility study findings. ·~\ 4.2 -Existing System Characteristics (a) System Description (b) The two major load centers of the Rai lbelt region are the Anchorage-Cook Inlet area and the Fairbanks-Tanana Valley area ~ '' !t§Ufb EJ.:;::r which at present operate independently. The existing transmission system between Anchorage and Willow consists of a network of 115 kV and 138 kV lines with interconnect ion to Palmer. Fairbanks is primarily served by a 138 kV 1 ine from the 28 MW coal-fired plant at Healy. Coi11Tlunities between Willow and Healy are served by local distribution. systQwr Taole D.l.XA summarizes the total within the Railbelt system in 1980, based on informat · n provided by Railbelt utilities and other sources. Table D.~~presents the resulting detailed listing of units currently operating in the Railbelt, information on their performance characteristics, and their on-line and projected retirement dates for generation planning purposes. The total Railbelt installed capacity of~ ~-t MW consists of two hydroelectric pla~ts totaling 46 MW plus ~fMW of thermal generation units fired by oil, gas, or coal, as summarized in Table D.~~ Retirement Schedule ~ In order to establish a retirement policy for the existing gener- ating units, several sources were consulted, including the Power Authority•s draft feasibility study guidelines, FEHC guidelines (FERC 1979), the BattelL: Railbelt Alternatives Study (Battelle 1982), and historical records. Uti 1 it ies, particularly those in the Fairbanks area, were also consulted. Based on these sources, the following retirement periods of operation were adopted for use in this analysis: -Large Coal-Fired Steam Turbines (> 100 MW): -Small Coal-Fired Steam Turbines (< 100 MW): -Oil-Fired Gas Turbines: -Natural Gas-Fired Gas Turbines: -Diesels: -Combined Cycle Units: -Conventional Hydro: 30 years 35 years 20 years 30 years 30 years 30 years 50 years a•, i ~I Table O.~ists the retirement dates for each of the erating units based on the above retirement policy. (c) Schedule of Addi t ~ ... , current gen- .fi~t...new projects were expected to be added to the Railbelt system prior to 1990p as shown in Table D. The Chugach Electric Asso- c i at ; on i s i n the p roc e s s o f add i n g gas-f i red comb i ned -c yc 1 e capacity in Anchorage at a plant called Beluga No. 8. When com- plete, the total plant capacity will be 178hMW, but the plant will encompass existing Units 6 and 7.. Chugac added a 26.4 MW gas turbine rehabilitation at Bernice Lake No. 4 in August 1982. In recent years, the Corps of Engineers has conducted post- authorization planning studies for the Bradley Lake hydroelectric project located on the Kenai Peninsula. This project was deauth- orized as a Federal development in December 1982. The Alaska Pow- er Authority now plans to prepare a license application for sub- mittal to the Federal Energy Regulatory Corrrnission in mid-1983 and to proceed with detailed design concurrent with license process- ing. The project wou1d include between 60 and 135 MW of installed capacity and would produce an dverage annual energy of 350 GlrJh. For analysis purposes, the project is assumed to come on line in 1988. 4.3 -Fairbanks -Anchorage Intertie Engineering studies have been undertaken for construction of an inter- tie oetween the Anchorage and Fairbanks systems. As presently envis- aged, this connection will involve a 345 kV transmission line between Willow and Healy scheduled for completion in 1984. The line will ini- tially be operated at 138 kV with capability of expansion as the loads grow in the load centers. Based on these evaluations, it was concluded that an interconnected system should be assumed for the generation planning studies and that the basic intertie facilities would be common to all generation scenar- ios considered. Costs at additional transmission fac1lities were added to the scenarios as necessary for edch unit added. ln the 11 With Susitna" scenarios, the costs of ddding c1rcuits to the intertie corr-idor were ddded to the D-4-3 (({ e(J( ~~Jj "·f. -·. .. . ... i!f 4 \. i ,· (ii) Fuel Costs Coal prtces and real coal pr~ce escalation were analyzed from production cost and market value perspectives. The de t a i 1 s of the co a l pr i c i n g stud i e s ar e con t a i ned ~ n Exhibit B, Appendix B-2, a brief summary follows. The price of Nenana field coal delivered to Nenana was set at $1.72/MMBtu (1983). This pr~ce ts based on the production costing approach, existing contracts for Nenana coal and assumes domestic consumption. The price of mine mouth Beluga coal was set at $1.86/MMBtu (1983). This price assumes that an export market is available ~n the Pacific Rim countries. The net back approach was used to obtain the price. Real escalation of these values was based on supply- demand factors. A 2.6% real r'kte of increase is applied to the mine-mouth price of Nenana Field coal as this mine is used to supply a domestic market. For the D-1-/-/I (f(~v~J"er:d) 14 __ ... _, Beluga Field there is sufficient evidence to support the use of an export market driven value. Therefore, an export-specific escalator of 1.6% is applied. With exports as the basis for Beluga field development, all prices of that coal will reflect world market con- ditions, as power plant sales will comprise a modest share of mine output. For the analysis it was assumed that When e~ch coal plant was added to the system the coal price in existence would /4( be fixed and the price would not experience real escalation for the economic life of toe pl.ant. (iii) Other Performance Characteristics Annual operation and maintenance costs and representative forced outage rates are shown 1n Table D. 18. (c) Combined Cycle A combined cycle plant is one in which electricity is generated partly in a gas turbine and partly in a steam turbine cycle. Combined cycle plants achieve higher efficiencies than conventional gas turbines. There are two combined cycle plants in Alaska at present. One is operational and the other is under construction. The plant under construction is the Beluga No. 8 unit owned by Chugach Electric Association (CEA). It is a 42-MW steam turbine, which will be added to the system 1n late 1982, and utilize 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 1s based on economic s1z1ng for plants 1n the lower 48 states and projected load increases in the Railbelt. A heat rate of 8000 Btu/kWh was adopted based on the alternative study completed by Battelle. The capital cost was estimated sing the Battelle study basis (Battelle 1982, Vol. XIII) and is listed in Table D.l8~ A bid line item cost is shown on Table 21. - (ii) FueL Costs The combined cycle facilities would burn gas with a domestic market value of $2e38/MMBtu (1983) with an additional demand charge of $0.35/MMBtu (1983) beginning; in 1986. The gas prtce is based on the plant being located at the wellhead and a recent contract for the purchase of uncommitted reserves in the Anchorage area. Real escalation of the gas price corresponds with escalation of the base case world oil price scenario, as follows: Real Escalation Period Rate 1984 1985 1986-1988 1989-2010 2011-2020 2021-2030 2031-20t*O % -4.63 ~4. 74 0 3.0 2.5 1.5 1.0 f)-4-/2(/?evtsed) l-- A detailed discussion of gas pr1c1ng and world oil prices is contained in Exhibit B, Appendix B-2. (iii) Other Performance Characteristics Annual operation and maintenance costs, along with a representative forced outage rate, are given in Table D. 18. (d) Gas-Turbine Gas turbines burn natural gas or oil in units similar to jet engines which are coupled to electric generators. These also require an appropriate water cooling arrangement. Gas turbines are by far the main source of thermal power generating resources in the Railbelt area at present. There are 470 MW of installed gas turbines operating on natural gas in the Anchorage area and approximately 168 MW of oil-fired gas turbines supplying the Fairbanks area (see Table D.l4)o Their low initial cost, simplicity of construction and operation, and relatively short implementation lead time have made them attractiv~ as a Railbelt generating alternative. The extremely low-cost contract gas in the Anchroage area also has made this type of generating facility cost-effective for the Anchorage load center. I. J:w .. p Ilia - A unit size of 75 MW was considered to be representative of a modern gas turbine plant addition in the Railbelt . reg ton. Gas turbine plants can be built over a two-year construction period and have an average heat rate of approximately 10,000 Btu/kWh. The capital costs were again taken from the Battelle alternatives study. (ii) Fuel Costs Gas turbine units can be operated on oil as well as natural gas. The market cost for oil is $5.58/MMBtu (1983). The real annual growth rates in oil costs were discussed above. ( ... ) .,tll Other Performance Character is tics Annual operation and maintenance costs and forced outage rates are shown in Table 0.18. (e) Diesel Power Generation Most dieseL plants in the Railbelt today are on standby D-Lf -IZ/3(R¢</tS,.d) "l'" t status or are operated only for peak load serv1ce. Nearly all the continuous duty un.its were retired in the past sev~ral years because of high fuel prices. About 65 MW of diesel plant capacity 1s currently available. (i) Capital Costs The high cost of diesel fuel and Low capital cost make new diesel plants most effective for emergency use or 1n 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. Paten- tially, capital cost savings of 10-20 percent could be realized by going to the larger units. However, these larger units operate at very Low speeds and may not have the reliability required if used as a major alternative for Rai lbelt electrical power. The capital cost was derived from the same source as given in Table 0.18 (Battelle 1982, Vol. IV). ( ii) Fuel Costs Diesel fuel costs and growth rates are the same as oil costs for gas turbines. ~·~"--''-''"-"~••.-_.__,..-.... ,.-~-·~>L '+ !) && (iii) Other Performance Characteristics Annual operation and maintenance costs and the forced outage rate are given in Table D.l8. (f) Plan Formulation and Evaluation ~·~: ------------------------------- The four candidate unit types and s1zes were used to formulate plans for meeting future Railbelt power generation requirements. The objective of this exercise was defined as the formulation of appropriate plans for meeting the pro- jected Railbelt demand on the basis of economic preferences. Economic evaluation of any Susitna basin development plan requires that the impact of the plan on the cost of energy to the Railbelt ... 4 #J ,;;, q area consumer be assessed on a systemwide basis. Since the con- sumer 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 system costs was the mathematical model developed by the Electricity Utility Systems Engineering Depart- ment of the General Electric Company. The model is commonl kno or Optimized Generation Planning fvt>del. Version he following information is paraphr·ased from GE literature o the program. The OGPS 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 patterlrS in terms ofjconomics, reli- abi 1 ity and operation. ~1e"J t:rt-tl it i~s as£!· OSP to study loaa managemP_ot, unit size, ca.pjtal and fuQl 'Gsts, energ;¥ stor-1~, -fwret:~ oat aye rates, a" a fet·~c ~t--uneer~+rrty. The OGP~program requires an extensive system of specific data to perform its planning function. In developing an optim~l plan, the program considers the existing and corrrnitted units (planned and under construction) available to the system and the characteris- tics of these units including age, heat rate, size and outage rates as the base generation plan. The program then considers the given load forecast and operation criteria to determine the need for additional system capacity based on given reliability cri- teria. This determines "how much" capacity to add and "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 selected and added to the system. Finally, an investment cost analysis of the capital costs is completed to answer the question of 11 what kind 11 of generation to add to the system. The mode 1 is then further used to compare alternative p 1 ans for meeting variable electrical demands, based on system reliability and production costs for the study period. r T~;s, it s~ou ~!!-·r-et;~~~~ z~ . ttlaJ:-.t.lle;,.,..;;,..,..;-_.;..··pr-o'O~-.-ue-t-1-o--n-co-s-t-s-roo-~e0 repre~e!l,Lon..ly--11-portlonof"' ttl t tmate .consumer costs and in effe~t) \ , are -5 n 1 y a port i on , a l be i t maj or , of tot a 1 costs t \ '" ....,...---........ --------~·-.. -~ ... """"'" . ~ "'>!l<f .. ----~·~1>.~--"" ~ .,. ... ...,,, ,..._ ..,__...... ~'lilt ... ' ' The use of the output from the generation planning model is in Section 4.6(a). 4.6 -With,cut Susitna Plan In order to analyze the economics of developing the Susitna project, it was necessary to analyze the costs of meeting the projected Al asl<a Rai lbel t loiJd forecast with and without the project. Thus, a p 1 an using the identified components was developed. Using the generation planning model, a base case ''without Susitna" plan was structured based on middle range projections. The base case input to the model inc1ucted: -. __ ~--.. ft ,~ ~. d g:<) -n.... Ba.se. Co.s<L R[ = ,n T· / !!at tetft:' s .n i dd 1,; ,...,~ 1 oad forecast (Exhibit ~~; -Fuel cost as specified; Coal-fired steam and gas-fired combined-cycle and combustion turbine units as future additions to the syste~; -Costs and characteristics of future additions as specified; The existing system as specified and scheduled comnitments listed 1n Tables D.lt dnd 0.1~ ~;e-{uel escalation as specified; interest and 0 percent genera 1 in- -Generat)on s.ys.tem reliability set to a loss of 1oaa probability of one day in ten years~ This ts a probabilistic measure of the inabil- ity of the generating system to meet projected load. One day in ten years is a value generally accepted in the industry for planning gen- eration systems. The model was initially to be operated for a period from 1982-2000. It was found that, under the medium load forecast, 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 ar'td 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 1993-20[0. In early yedrs {1993-1996), the economically preferred units are those which generate base load power. Aft;!:L&\10 MW of this type of power in ( -: -) l ·. ' I I-,, 1 ' '•' !'' i / ... the form of coal units are added, the preference switches to gas turoine units which are used to meet seasonal (winter) peak months and daily peaking needs. During the later stage, the generating system needs capacity to meet target reliability rather than to generate power continually. The following was established as the non-Susitna Railbelt base plan (see Figure D.~ (a) System as of January 1993 Coal-fired steam: Natural gas GT: Oil GT: Diesel: Natural gas CC: Hydropower: 59 MW 452 MW 140 MW 67 MW 317 MW 155 MW Total (including committed conditions): (b) System Additions 1190 MW {c) Year 1993 1994 1996 1997 1998 2001 2003 2004 2005 2006 2007 2009 Tot a 1 Gas Fired Gas Turbine _jMWl__ 1 X 70 1 X 70 1 X 70 1 X 70 1 X 70 2 X 70 1 X 70 1 X 70 630 System as of 2010 Coal-fired steam: Natural gas GT: Oil GT: Di ese 1: Natural gas CC: Hydropower: Coal Fired Unit (MW) __ 1 x 200 (Beluga Coal) l x 200 (Beluga Coal) 1 x 200 (Nenana/Healy Coal) 1 x 200 (Beluga Coal) 800 813 MW 746 MW 0 MW 6 MW 317 MW 155 MW Total (accounting for retirements and additions) 2037 MW Y.LUtS(. wtfh r~so\ts 1> otjff, rv11s. • • • ~:~···· • 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 conmercial development. That develop- ment is not a certainty now and is somewhat beyond the control of the state, since the rights are in the hands of private interests. Even if the seam is mined for export, there will be environmental problems to overcome. The greatest problem will be the availability of cooling water for the units. The problem could be solved in the "worst" case by using the sea water from Cook Inlet as cooling water; however, this solution would add significantly to project costs. Two a 1 t ern at i v e s wh i c h Bat t e 1 1 e i n c 1 u de d i n the i r base p 1 an wh i c h have not been included in this plan are the Chakachamna and Allison Creek hydroelectric plants. The Chakachamna plant is currently the subject of a feasibility study by the Power Authority. The current p'lan would develop a 330 MW plant at a cost of Sl.45 billion at January 1982 price levels. The plant would produce nearly 1500 GWh on an average annual basis . . Dtl~to/ 9 urr ~ ;qu~~t ions r:~~.ing ~as ~b.i, · / ctr ~ pl n t · A'fas) no tl beer};.,;tnc l u<t'e1 )rr" the n·-sit n )5 , chec nowev¢r, 0!Y'tne sen~t~~ sis pre 'II..IC~ ... _...- . ts sect 1on. .._/' ' The Allison Creek Hydroelectric Project was included in the non-Susitna base plan by Battelle. It has not been included in this base plan due to its high costs ($125/MWh in 1981 dollars). The thermal plan described above has been selected as representative of the generation scenario that would be pursued in the absence of Sus- itna. The selection has been confirmed by the Battelle results which show an almost identical plan to be the lowest cost of any non-Susi tna plan. 4. 7 -Economic Evaluation This section provides a discussion of the key economic parameters used in the study and develops the net economic bene.fits stenming from the Susitna Hydroelectric Project. Section 4.7 (a) deals .,.,ith those eco- nomic principles relevant to the analysis of net economic benefits and develops inflation and discount rates{!)an-d the ~ht:;ltaA e~~8••ht<Rit;to- ~!~;~. ( '~:"~ pr h:11') of oil, Ra~ijul §1i& MID c;e it.l.-~~n tic a 1 &I the., .cs __ --&tJsee on the ~9J.Hj@l*•term f31"&speet:~-fo-r cot!i ,,Hwket~ •6-- ~re:s:. Tit is-fillgRSW trnm;:::t:fre=--e~~~on that, ;n-the-<l!u.eE,ce .. ~ .Sus.itn~e next bes.Lthermal .. gene~on p1an YK>Ul<t . ..cely o'n exploita:.. • tion of Alaskan coal. The-tuture...,.....ca·tJrprice is therefor"e-considered in detai 1 to provide .rigorou~~.estfmates 9-t "P''rices i.n th.!!-IDO.S.L.likely al-· tern at i ve markets and l'rence the market ~itt··oT'coa·1-at the:::mine-=mouth- within the state.------·~ Section 4.7 (b) presents the net economic benefits of the proposed hydroelectric power investments compared with this thermal alternative. n 1t 1., In ..... , J \ - .X X rates have averaged about 2 to 3 percent in the U.S. in real ( infl at io,n-adjusted) terms (Data Resources 1980; U. S. Depar·tment of CofTillerce). Forecasts of real in- terest rates show average values of about 3 percent and 2 percent in the periods of 1985 to 1990 and 1990 to 2000, respectively. The U.S. Nuclear Regulatory Corrmission has atlso analyzed the choice of discount rates for investment appraisal in the electric utility industry and has recornnended a 3 percent real rate (Roberts 1980). Therefore, a real rate of 3 percent has been adopted as the base case discount and interest rate for the period 1982 to 2040 . . Nominal Discount and Interest Rates The nominal discount and interest rates are derived from the real values and the anticipated rate of gen- eral price inflation. Given a 3 percent real discount rate and a 7 percent rate of price inflation, the nomi- nal discount rate is determined as 10.2 percent or about 10 percent~. I Cost £seal cost orpor luati to 1r av her ca Prices * (1 + the nominal rate) = (1 + the real rate) x (1 + the inflation rate) = 1.03 x 1.07, or 1.102 ¢4UAW i ~efined products are imported. The supply of petrolelJll oducts is not believed to be a problem through th ecast period, however. The current price of utili y oi 1 is a good indicator of its current opportun ty , especially in view of the recent price decon rol on In the do 11 ar I~MBt u. period (January 1982), the Alask n 1982 o f No . 2 f u e 1 o i 1 i s e s t i mated $ 6 . 50 I Long-term t ends in oi 1 events that re economic, nature, and a e therefore tic framework. prices w~ll be po l i t i c a 1 and t e estimated withi 1 uenced by nolog.ical in a probabilis- As shown in Tabl D.23, the base cas (most likely es- calation rate) is stimated to be 2 p cent to 2000 ano 1 percent from 2000 to 2040. To e consistent with Battelle forecasts, 2 percent rat was used throughout the OGP planning peri d 1982 to 20 and 0 percent there- after~ ln other seen rios the owth rates were esti- mated at 0 percent from 1982-20 (low growth); and at 4 percent to 2000, and 2 p eyond 2000 (high growth). These projections are als co istent with those recently advanced by such organizat s as Data Resources (1981), World Bank (1981), U. S. De rtment of Energy (1980), and the National Energy Board f anada (1981). A September 1982 review f maj forecasts for oi 1 price trends reaffirms the attelle rejection. Projections from seven sources i icated ten forecasts which varied from a low trend pr jection of -.5 to a high of 5.3 percent. Seven of he ten trend f ecasts were within a band of + 1. 7 to + • 4 percent. The ends are summarized in Table 0.25. - G a s P t· i c e s The av a i 1 ab i i t y and co s t o f Cook I n 1 e t t u r a l gas for electric p er generation is the most c plex of all a l tern at i v f u e 1 s for t h e R a i l be 1 t . Th i s 1 due to the uncertain y in estimates of recoverable reser es, the low costs of fuels under existing contracts and th potential for ex ort of the fuels to the \t/Orld marke . Many existi g contracts in the Railbelt reflect pr·~es and esc a t i on c 1 au s e s e s t a b l i shed when t he market " r the gas as restricted to Cook Inlet. However, new su plies use(j to meet demand in excess of the contracted s pply a ~e p r i c e d by the i r o p p or t u n ; t y v a 1 u e . The o p p or t u i t y yalue is based on the net-back from 1 iquid natural as /Sdles to Japan. __ _..... ____________________________ ._ ... _.._...,.._.,....____ __,.. __ _ -- ~· -----··· -·---·---·--. .. ··----. -1-- Railbelt. gas prices have. been forecast .using both e.xplot 1 opportun1ty values (nett1ng back CIF pr1ces from Japan Cook Inlet) and domestic market prices as likely to e faced in tne future by Alaskan electric utilities. 1 he qeneration planning analysis used rnarket prices/ as estimated by Battelle (1982, Vol. VI!). S;nce the~~ are indications that Cook Inlet reserves may jremain insufficient to serve new export markets, th study conducted a review of both price and quant ty from potential. sources. \ . . . Availability of Natural Gas \ The Battelt~ study developed a number of pas!: ible sup- ply and use\ scenarios, all of which ave uncertainty attached to ~e i r underlying as sumpt i The resu 1 ts of the study indicated that the exis ing reserves cur- rently committe-d for in-state use ecome exhausted in the early 1990s.\ As contracts exP. re and new reserves are secured, ext~me price chang are likely to take place. \ A major factor in th.e future cenarios of natural gas use i s the P a c i f i c A 1 as k a L ( PAL N G ) Pro j ec t . Th i s project would include con~ruct ion of an LNG plant which would supply gas· to/the lower 48. Currently, 1 a r g e amo u n t s o f Cook I fl'. ' t r e s e r v e s a r e co mm i t t e d to this project. If it pr ceeds, all new gas contracts will compete with PALN ft.1r reserves, driving up pri- ces. If 1t does not through, prices may remain low- er. \ Details on supply volumes and possible utilization scenarios are giv in Battelle 1982, Vol. VII. Domestic The Cook Inle area consumer has in recent decades ben- efitted grea ly from a buyer's market position for nat- ural gas. In the 19~0s and 1960s, oi 1 companies in· search of rude oil, C.\ readily transportable commodity, found mor. natura 1 gas than oi 1. Due to transport at ion difficu ies, the 9as was more of a problem than an asset. In order to sell the gas, the cornpan i es offered i t at very 1 ow p r i c e s . R e s u 1 t i n g co n t r a c t: s wh i c h a r e stil in existence today enable the Cook Inl·et consumer to ay some of the lowest prices for natural gas in the wo ld. For example, in Apri 1 1982, Chugach .Electric A sociation (the largest producer of electricity in the ailbelt) paid a weighted average of $0.41 per Mcf. This amount is 12 percent of what the rest of the· util- ities which report costs to DOE paid. Anchorage Muni- cipal Gas and Electric currently pays over $l.OO}Mcf for gas. Although high, the price .,still refle\\ts • r.a~orable conditions of long term contracts.· ·------·-------------- \ D-4-23 (f<'t:vi5.~J J -- I\ is n;t·· ex~~~t-;dth;t these costs wi 11 be .indi.~at iv 1 o f f u t u r e p r i c e s for Cook I n 1 e t . As the con t r ac s ex p r e , new g as w i 11 be so 1 d at pr i c e s ref 1 ec t i n g e o p po tun i t y v a 1 u e of the g as . S t u d i e s of a 1 tern a i v e prici futures by Battelle (1982, Vol. VII) ind' ate· that t ere will be significant domestic price dis- rupt i on i n the ear l y 1 9 90s as c omp e t i t i on f r the uncommit d reserves develops. Actual pric s vary depending on the scenario with the key fa tor the developmen of the PALNG plant. For e ample, a weighted av rage of the cost of gas to r ugach and Enstar (Alas a Gas and Service Co.) re lts in an estimate of .03/Mc f in 1993 in the ab ence of the p 1 ant. If the 1 ant goes ahead, the est i, ate increases to $3.92/Mcf. etails behind these e imates are in Battelle's Vol. II. Recent contracts r gas support th e estimates. In December 1982, Ens ar signed contr cts with Marathon Oi 1 Company and She 1 Oil Compan for gas from the Beluga and Kenai fiel~.· The bas price of the gas is $2.32 in 1982. In ad~tion to e base price, Enstar will need to build a pipeline t take delivery and pay a demand charge triggere_,d by igh volume deliveries. l · I t has been pro j ec ted by E t a r off i c i a 1 s t h at the ; demand charge wi 11 be in fo e by 1990. Furthermore, l Enstar expects that the co t of the pipeline, demand charge and taxes will rai~\their-acquisition cost to! about $3.00/Mcf in 1990. In ~ddition to the base plus fringe costs, the cos of the fuel will be tied directly to the cost of o. 2 f'~·el oi J in the Rai lbelt. Thus the gas contract ice will track the price of oil annually. The contr ts will be in force until 1997 and 2 000 . Ens t a r i c u r r en t 1 y t m aj or sup p 1 i e r of gas to Anchorage Mu cipal Power an~Light. Table 0.25 depict the low, medium "nd high oornestic market prices us in the generation p\anning analysis. I n the me d i um s t l i k e 1 y) c as e , p r i ~. es esc a 1 at e at I real rates of 2. 5 percent from 1993 \.o 2000 and 2 ! percent beyon 2000. In the low case, '~here is zero escalation; n the high case, gas price\ grow at 4 percent 198 to 2000 and 2 pet"cent beyond\2000.. The starting oint for these prices is Sf.03/MMBtu beginning n 1993. \ . Export 0 portunit Values "' Tab 1 e . 25 also shows the curreru.,. and projected OJ>por- tunit~ values of Cook Inlet gas in a sc.enario wher~ the Jap.anese export market for LNG cant inues to be \the alternative to domestic demand. From a basE? per·od plant-gate price of $4.65/MMBtu (CIF Japan), lo , medil1ll and high price escalation rates have be,en esti -~:.u:..:..t~-:...:for the intervals 1982 to 2000 and 2000 to 2040. t ·= ::; 'I , I [j D; ... · ,, ! I I r ( v) ---.~-· . ·----.. -·-·----------------,;1-- The cost of liquefaction and shipping (assumed to be constant in real terms) was subtracted from the es calated CiF prices to derive the Cook Inlet plant-gat prices and their growth rates. These Alaskan apport ity values are projected to escalate at 2.7 percent and 1.2 percent in the medium (most likely) case. ote t~at the export opportunity values consistently xceed th~· domestic prices. In the year 2000, for ample, the opportun,·.ty value is nearly double the omestic pric estimated by Battelle. It is expected that the Japane\e market will hold firm at current 1 vels. As previou\ly discussed, the PALNG plant is an ther possi- bility fO( gas export. Its future is unce tain as pre- viously d~~cussed. \ Coal Prices ~ The shadow price~ opportunity value Beluga and Healy coal is the delivereo price in alterna ve markets less the cost of transportati'o.n to those mark s. The roost likely alternative demand fo' thermal coal s the East Asian mar- ket, principally Japan. South Korejl·, and Taiwan. The de- velopment of 60-year for asts of 1coal prices in these mar- kets is co'lditional on he prQCurement policies of the import1ng nations. These r.~cto s, in turn, are influenced to a large extent by the prf e movements of crude oi 1. -Historical Trends Ex~ination of historic trends reveals that FOB and CIF prices hav escalate at annual real rates of 1.5 percent to 6.3 pe cent as sho n below: . Co a l pr i c e s { b i nit value, FOB U.S. 1.5 percent (1950 9) (U. S. Depart- ports) grew at eal annual rates to 1979) and 2 8 percent (1972 to 1 ment of Ener 1980) . the ·GVEA (1965 to • In Alaska, the price of thermal coal utility a vanced at real rates of 2.2 1978) anl2.3 percent (1970 to 1978). In Ja ~. the aver age C IF prices of steam c ex peri- ence real escalation rates of 6.3 percent pe year in an se Ministry of International Trade and I dustry 1 82). This represents an increase in the a erage price from approximately $35.22 per metric ton (mt) 1 /(2200 pounds) in 1977 to about $76.63/rnt in 1981. I / ,As shown below, ex. port prices of coal are highly correla ted with oil prices, and an analysis of production costs / has not predicted accurately the leve1 of coal prices. ·-···----·----------------- ... 1 _'AI.IWWi : Even if the production cost forecast itself is accurate, it wil-J establisn a minimum coal price, rathe-r than the market learing price set by both supply and dernand con- ditions. . In real percent (1950 to errns export prices of U.S. coal showed a 94 1d 92 percent correlation with 011 pr1ces 1 79 and 1972 to 1979).* \ \ . Supply functr-on (production cost) analysis has estim- ated Canadian\coal at a price of $23.70 (1980 tLS. $/ton) for S.E'~ British Columbia (B.C.) coking coal, FOd Roberts Bani(,~ B.C., Can:1da (Battelle 1980), (Bat- telle 1982, Vol. VII.) In fact, Kaiser Resource5 (now B . C . Co a 1 L t d . ) h as s i ')ned a 9 r e em en t s w i t h J a p a. n a t an FDd Price ot about $47.50 (1Y80 U.S. $/ton) (B.C. t3usiness 1981). Th'is is 100 percent more thant'he price estimate hased on production cost~ . . The Sdlne comparison for Canadian B.C. thermal coal in- dicates that the expected price of $55.00/mt (1981 Can- adian S) or about S37~00 (1980 U.S. S) per ton would be 6U percent above estimates founded on production costs (Battelle 1980; n.C. Business 1981; dattelle 1982, Vol. V II) • . I n l on g e r-t e rm coal expo r t con t r a c t s , there h as been provision for reviewing the base price (regardless of escalation clauses.) if significant developments occur in pricing or markets. That is, prices may respond to market conditions even before the exp i rat; on of the contract.** . I Energy-impor~1ing nations 1n Asia, especially Japan, have a sta~·ed policy of diversified procure,nent for their coal/suopl ies. They wi 11 not buy only frow the lowest-cost supplier (as would be the case in a per- fectly c'ompetitive model of coal trade) Dut instead wi 11 pay a risk premium to ensure security of supply (Batt~11e 1980; Battelle 1982, Vol. VII). -Survey of Forecasts , Oa~a Resources Incorporated (1980) is projecting an aver- age annual real growth ra1te of 2.6 percent for U.S. coal prices in the period 1981 to 2000. The World Bank (1981) 1has forecast that the r~al price of steam coal -* Analy~is is based Jn data from the World Bank.. ** This a use f orrns. part of the recent 1 y cone 1 uded agre,.!ment between Denis n Mines and Tack Corporation and Japanese steel makers. - \ ) ' ' 11; would advance at approximately the same rate as oil prices (3 percent/a) in the period 1980 to 1990. Cana- dian Resourcecon Limited (1980) has recently forecast rowth rates ot 2 percent to 4 percent {1980 to 2010) for s bituminous and bituminous steam LOal. of Alaskan Coal Based '~tn these considerations, the shadow price of coal (CIF pr\~·ce in Japan) was forecast us·ing conditional probabil ties given low, medium, ana high oil price scenarios. Table 0.26 depicts the ~~timated coal price growth rat and their associated 1-probabilities, given the three s ts of oi 1 prices. Combining these proba- bilities wit those attached }6 the oil price cases yields the fol owing coal pri~e scenarios, CIF Japan. I \ / Scenario Medium (most likely) Low High R(obabi l i txt 4 9\'Q e r c e,n ·{· \ /' \ . ·( Real Price Growth 2 percent (1982-2000) 1 percent (2000-2040) 0 percent (1982-2040) 24 p-er~ent / \ ~~ perce~t 4 percent (1982-2000) ~ "' 2 percent (2000-2040) The 1982 /e period pricl!_ was initially estimated using the ata from the Bat\elle Beluga Market Study (Battelle 980). Based on thi\ study, a sample of 1980 spot pri es published in Coal W~ek International (aver- aging 1.66/MMBtu) was escalat~ to January 1982 to provi e a starting value of $1.95l~MBtu in Janu3ry 1982 dol rs.* \ \ ~ more recent and roore complete coal\import price sta- istics became available, this meth(>Q of estimating was found to give a significant underes~mate of actua.l CIF prices. By late 1981, Japan's avera~ import pric~ of steam coal reached $2.96/MMBtu.** \An importdnt \ ___ __,.c.__a 1 at ion factor was l. 03 x 1.14, where 3 percent ~the fore- r e a 1 growth i n p r i c e s ( m i d-19 8 0 to J an u a r y 198 2 ) at an ann u a 1 e of 2 percent, and 14 percent is the 18-month increase if the CPI used to convert from mid-1980 dollars to January 1982 dollars~ l **As reported by Coal Week ~nter~ndtional in October 1981, the average C I F v a 1 u e of s team co a 1 w c?i s $7 5 . 50 I m t . At do a v er age heat v a l u e of 11,500 Btu/lb, this is equivalent to $2.96/MMBtu. I t \ sensitivity case was therefore developed reflect.fng \these updated actual CIF pri·res. The updated base iod value of $2.96 was ·. t.~uc~d by 10 percerJt to 66 to recognize the price qscount dicta ed by q {~ty differentials between Alaskan coal an other sou~.es of Japanese codl ~mports (Battel!e 198 . . Oppor\nity .12.1 ues in A 1 ask a -Battelle-based CIF Prices, ;I No Exp rt Potential for Healy Coal / Transpor tion costs of $0.52/MMBtu ;Zre subtracted from the ·nitially estimated CIF pl"ice of $1.95 to determine e opportur.ity value of Beluga coal at Anchorage. In January 1982 dollars, this base period net-b k price is therefore $1.43. In subse- quent years, t e opportunity value is derived as the difference bet en the escalay'ed CIF price and the transport cost stimated tg' be constant in real terms). The real rowth r·ate in these FOB prices is determin~d residua ly from the forecast opportunity v a 1 u e s • I n t h e d i um : ( mo s t 1 i k e 1 y ) c a s e , the Beluga opportunity v lues' escalate at annual rates of 2.6 percent and 1 ..... p'ercent during the intervals 1982 to 2000 and 2000 t 2040, respectively. . ,· I For He a 1 y coal , i t I was e s t i mated that the base period price of $1 ;75/MMB · (at Healy) would also escalate at 2.6 ptfcent (t 2000) and 1.2 percent (2000 to 2040). ding thee calated cost of trans- portation from H aly to Nenan resuits in a January 1982 price of $ .75/MMBtu (Nati nal Energy Board of Canada 1981; W ld Bank 1980). subsequent years, the cost of ansportation (of w ·ch 30 pen::ent is represented y fuel cost which escalates at 2 percent) is added to t.he Healy pri , resulting in Nenana pri es that grow at real rates of 2.3 percent (1982 to 2000) and 1.1 percent (2 0 to 2040). Tab 1 e D 0 summarizes the rea 1 esc a -t ion rates app1 ica le to Nenana and Beluga coal the low, medium and high price scenarios . . • Sens tivity Case -Updated ClF Prices, Exp rt Potential for Healy Coal T e updated CIF price of steam coal {S2.66/ , fter adjusting for quality differentials) was :duced by shipping costs from Healy and Beluga Japan to yield Alaskan opportunity values. "f .... IA414CA¥p;Q - ll ~. January 1982. prices were $2.08 and $1.74 at Anchor- age and ·-'Nenana. respective 1 y. The d i fe"6ncf:S -between escala CIF prices and · ping costs ~t--i.n_FOB prices at have r growth rates of 2 . 5 perc en t ·anG-1.. 2 perc e r Be 1 u g a co a 1 and 2 . 7 percent and 1. 2 per or He co a 1 (at Nenana). Table 0.26 show cal~rates the opportu- nity value laskan coal ;n-tn.e..Jow, ium, and high pr·i e scenarios, using updated base .... per1 -~1--· _,..._._ ·-W ue~. (v) Generation-.._P·l;nniifq ·Analysis -Base Case Study Values ·,. <.........,,. " ----Based on the ~s; ~erat ions pres~~ in ( i) throu ( i v) above, <l consis_~ set of fuel prices · asse led for the b~se case proti ilistic generation plann1 alysis, as shown in Table 0.2 The study values in ude pro · ities for the low, med1 and high fuel rice scenarios. -.. __ The probabilities are comn for the ee fuels (oil, gas -.and coal) within each scenar in order to keep the number of generation p 1 ann+ng--t.uns _t_ .mdn ageab 1 e size. In the case of the natural gas price.s<' do 'slfCitrerl€iL.Qrices were selected for the base cas analysis . th the export oppor-.,. tunity values used in ensitivity run The base period v a 1 u e of $ 3 was i v ed by de f 1 at i n g "' e 19 9 6 Bat t e 11 e pri!=eS to 198? l pr·ices were also select ··from the base case using Sattel 's-!980 sam- P 1 e of R · c e s as the s t art i n g po i n t , w i t h the d at ed C I F price of coal reserved for sensitivity runs. ·1 prices h' been escalated by 2 percent (1982 to 2040). (b) Anal~sis of Net Economic Benef)ts (i) Modeling Approach Using the economic parameters discussed ;,, the previous section and data relating to the electrical energy genera- t i on a 1 t ern at i v e s a v a i 1 a b 1 e for the R a i 1 b e 1 t , an an a 1 ys i s was made comparing the costs of electrical energy produc- tion with and without the Sus i tna project. ..+he pr +'"ary : ~~~''i,{~~ ~ :gg;;. PffaaCt!YJh!'ilN(~":~:;:,anr:tfl~h:~ .,.!!r iod eX ~hePhty-....... s 1022. fJtl 2QlQ a ...... The method of comparing the "with" and "without" Susitna alternative generation scenarios is based on the long-term present worth ( P W ) or tot a 1 s y s t em cost s ., Th e p 1 ann i n g model determines the total production costs of alternative plans on a year-by-year basis. These total costs for the ·r ,, J I. !44Pi ¥«4 - i % period of modeling include all costs of fuel and operation anc maintenance (O&M) for all generating units included as part of the system~ and the annualized investment costs of )<· any generating and syc;tem transmission plants added during _ the period 1993 to ~. Zc'Zo F a c t n r s wh i c h con t r i b u te to the u 1 t i mat e con s urn e r co s t of power but which are not included as input to this model are investment costs for all generJtion plants in service prior to 1993 investment, cost of the transmission and distribu- t i o n f a c i l i t i e s al r e a d y i n s e r v i c e , and a dm i n i s t r a t i v e costs of utilities. These costs are comnon to all scen- arios and therefore have been omitted from the study. In order to aggregate and compare costs on a significantly long-term basis, .~nnual costs have been aggregated for the period 1993 to 2051. Costs have been computed as the sum of two components and converted to a 1982 PW. The first component is the 1982 PW of cost output (rom the first~ zg years of model s imul at ion from 1993 to ~-Th{l seccnd componeJ],t is the estimated PW of 1 onq-costs from~ to 2051. 'UJZ,.I For an assumed set of economic parameters on a particular generation alternative, the first element of the PW value rep res en t s the amo u n t o f c ash ( no t i n c 1 u d i n g tho s e co s t s noted above) needed in 1982 to meet electrical production Q~o needs i n the R a i 1 be 1 t for the per i o d 1 9 9 3 to ~8~ . ---The _:,:V ~~:~d element of the aggregated PW value is the long-term . ~ to 2051) PW estimate of production costs. In consid-::\r·· ering the value to the system of the addition of a hydro-,.,otf · electric power plant which has a useful life of approxi- v mately 50 years, the shorter study period \tvQuld be inade- / quate. A hydroelectric plant added in 1993 or 2002 would '·~-accrue PW benefit for onl~ or years, respectivel us1ng an investment horizon t a extends to . owever, to roode1 the system for an additiona13c:Dyears, it 'MJuld be necessary to develop future load forecasts and generation alternatives which are beyond the realm of any prudent pro- jections. For this reason, it has been assumed tha the production costs for the final study year (~) would sim- Ply recur for an addition a 1 ~~ years. and t~~ PW of these was added to the3f-year PW ( 1993 to to establish the long-term cost differences between alternative met ods of power generation. (ii) Base Case Analysis -Pattern of Investments 11 With 11 and "Without .. Susitna The base case comparison of the 11 With" and "without" Susitna plans is based on an assessment of the PW produc- ..... - II , ~fu 6au C.tU.U.- tion costs for the period 1993 to 2051, wshtg mhi=• ""~ values for the energy demand and load forecast, fuel prices, fuel price escalation rates, capital costs, and capital cost escalation rates. Tit~ capital cost ':l'cala- t ion rate was set at approx jmat e]y 2 percent per year ha£Qd Q~=t -s-tt:t&ies af loA~ ter~ ttends · tn =the Batte II~ ..Stuli5 ( Bottethrl:982;-VoJ t~)". The with-S.usitna plan calls for 680 MW of generating cap .. acity at Watana to be available to the system in 1993. A 1 though the project may come on line in stages during that year, for modeling purposes full-load generating capability is assumed to be available for the entire year. The additional two units, totaling 340 MW of capa- city, will come on line in 1994. These units esdd flexi- bility of operation and project reliability. They will also be a source of additional capacity if high load growth is realized. Providing for these units in plann- ing for Watana allows for the project to become a peaking project well into the future. The second stage of Susitna, the Devi 1 Canyon project, is scheduled to c~rne on line in 2002. The optimum timing for the add it 1 on of Dev 11 Canyon was tested for ear 1 i er and later dates. Addition 1n the year 2002 was found to resu1t in the lowest long-term cost. Devi 1 Canyon wi 11 have 600 MW of installed capacity. ~he without-Susitna plan is discussed in Section 4.5. It inc 1 udes three 200 MW co a 1-fi red p 1 ant '3 added at Be 1 ug a in 1993, 1994, and 2007. A 200 MW unit is added at Nenana in 1996 and nine 70 MW gas-fired combustion tur- bines (GT's) would be added during the 1997 to 2010 peri- od. -Base Case Net Economic Benefits he economic comparison of tt).f:se plans is s.hown in Taole D. . During the 1993 to 2~ study period? the 1982 PW cot for the Susitna p,lan is:n:=rr, billion. The an~ual prod u c t i on cos t i n 2 CQ'u i s !tf. j §2. b i 11 i on . Th e P W of this level cost, which remains virtually c.onsta11t for a period extending to the end of the life of the Devil Can- yon plant (2051), is?;J.;zrs billion. The resulting tot -€8i..,.Of the with-Sus1tna plan is a:~ billion in 1982 dollarse, .. eseiltl§' adl-ned te }iS. Ttl e non -S u s i t n a p 1 an ( Sec t i on 4 . 5 ) w h i c h was mode 1 e d has a 1982 PW cost Q.f l<J.~tJ billion for the 1993 to 2~0 period wi tt1 a 2U!O annua 1 cost of SgLct'ft b i 1 t ion. The total long-term cost has a PW of ~· bi 11 ion. There- l l ....... ,--.. fore, the net economic,<~it o.f adopting the Susitna plan is_:1l.J!S billionJj In other words, the present- value cost difference between the Susitna plan and the expansion plan based on thermal plant addition is 11--::ft1 -billion in 1982 dollars. T 1s .\s ·. ·, . ~ ene 1t,.o.f $2,700/per cap(ta for tf1e\ 1982 pop~ 1 at i , n .a f \the S~ at ~ o f ~ r as k h . Ex p r s sed i n \ 1 ~ 9 3 olflars (at" the\ on-1 1ne ~ate 6f Wa~ana), the net benaf_JtS ~d have a 1e\te1ized va\~eo~ $2.4B billton:'** It is noted that the maqnitude of net economic benefits (i:l lirbillion) is not particularly sensitive to alterna- t 1ve assumptions concerning the overall rate of price i nfl at ion as measured by the Consumer Price Index. The analysis has heen carried out in real (inflation-adjus- ted) terms. Therefore, the present valued cost savings wi 11 remain close to ~ bi 11 ion regardless of CPI movements, as long as the real (inflation-adjusted) dis- count and interest rates are maintained at 3 percent. The Susitna project's inter"nal rate of r·eturn (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 4.1 percent in real terms, and 11.4 percent in nominal (inflation- inclusive) terms. Therefore, the investment in Susitna would significantly exceed the 5 percent nominal rate of return "test" proposed by the State of Alaska in cases where state av~ropriations may be involved.~ It is emphasized that these net economic benefits and the rate of return stemming from the Susitna project are in- herent 1 y cons e r v at i v e est i mat e s due to sever a 1 ass urn p - tions made in the OGP6? analysis. These items are discussed .individually in the following paragraphs. U lh1s -~ iffel'ttnt fr.~the e~."'ted ,Y'a~l net ~fit 0 • 5 a-;1 ion .. ¢'a\: ulaJ~~/rn-the multiva;{· ~,ana Y,si~00f ~ctioA 4 8 e ult}'van.~!! )f"based o, r<y'lg~gtpro.l(a 1l1y1es of\yjtt'Jabl s rat- ertJhan 1 e~~int es~t-e'S. V ~-~ · sr':\l8 1 ~; 1 L~ t.i~ ....... ~.l~, wh~2 .10?1'11\ the _gene-ra 1 prf& in f)'~ _ ioVn/lsX fOVhe ~lad ~2 to ~-\_/ \..._,· ~ '-.../ v •esee Alaska legislation AS 44.83.670 l ---- V' ... I Zero Growth in lcn~-term Costs From 2010 to 2051, the OGP6 analysis assLl111ed constant annual production costs in both the Susitna and non- Susitna plans. This has the effect of excluding real escalation in fuel prices and the capital costs of thermal plant replacements, thereby understating the long-term PW costs of thermal generation plans . . Loss of Load Probabilities The loss of load probability in the non-Susitna plan is calculated at~ in the year 2Ql0. This means thai the system in-2010 is on the ven:;e of adding an addi- tional plant, and would do so in 2011.. These costs are, however, not included in the ana'1ysis, which is cut off at 2010. On the other hand, the SIJsitna plan has a loss of load probability of 0.025, and may not require additional capac1ty for several years beyond 2010 . . .!:_ong -term Energy From Sus i tna. Some of the Sus i tna energy output (about 350 GWh) is still not used by 2010. This energy output would be available to meet future increases in projected demand in th~ summer months. No benefit is attributed to this energy in the analysis . • Equal Estimation of Environmental Costs The generation planning ana~ysis has implicitly assumed that all environmental costs for both the Susitna and the non-Susitna plans have been casted. To the extent that the thermal generation expansion plan may carry greater environmental costs than the Susitna plan~ the economic cost savings from the Susitna project may be understated. Due to the qreater level of study of the Susitna project, costs for mitigation plans were in- cluded. This may not be the case with the coal alter- native. For example, coo11ng water may not be avai1- ab1e at the Beluga sit~s in necessary ~uantities. The consequences of this (,'nd similiar problems h~ve not been studied or casted in detail equal to the Susitna study. These differences or added costs cannot be quantified at this stage of study on the Beluga coal alternative. ,'' ,,,__.. -,._ . , ' ~ 1 ' ' ;s:i; :a: 1 • -~ ·. ~ . • " ' t '"I • • i ' ! i ; I 4.8-Sensitivity to World Oil Price Forecasts Assumptions regarding future world oil prtces impact the forecasts of electric power demand for the Railbelt area. This relationship ts discussed in detail in Exhibit B, Seciton 5.4. Table D.23 contains a summary of the load forecasts considered. A sensi- tivity analysis was performed to identify the effect of power demand forecasts lower and higher than the base case demand forecast. Table D.24 depicts the results of the sensitivity analysis. (NOTE FOR DRAFT Add discussion of results here when results are available.) ll!Mt i$f ... 4.9 -Other Sensitivity and ProbabiLity Assessments (a) Introduction (NOTE FOR DRAFT) The other sensitivity and probability analyses described below were completed prior to the sensitivity analyses of world oil prices discusse1 above. A transitional paragraph will be added here to relate the oil price sensitivity analyses to the other sensitivity and probablity analyses. (b) Sensitivity Analysi~ Rather than rely on a single point compar1son to assess the net benefit of the Susitna project, a sensitivity analysis was carried out to identify the impact of modified assump- tions on the results. The analysis was directed at the following variables. -Load forecast (Table D.29) -Real interest and discount rate -Construction period Period of analysis -Capital costs 0 Susitna 0 Thermal alternatives I ," ···~ ~ . "~'~-"' ·~ . ._,___,~., ;') - -O&M costs -Base period fuel priceY -Real escalation in cap~al coste;, O&M cnc;,ts, and fuel prices -System reliability -ChackachaJnna -Susitna Project deldy. t-5 ~~ Tables 0.~ to D.~ depict the result the sensitivity analysis. In particular, Table o._,:i, sumlllarizes the net economic benefits of the Susitna project associated 't~ith each sensitivity test. The net benefits have been compared using indexes relative to the base case value ($1.176 billion) which is set to 100. The greatest variability in results occurs in sensitivity tests pertaining to fue~ escalation rates, discount rates, and bJse period coal prices. For example, a scenario with hlgh fuel price escalation results in net benefits that have a v.alue of 253 relative to the base case. In other words, the high case provides 253 percent of the base case net benefits. ln general, the Susitna plan maintains its positive net benefits over a reasonably wide range of values dSSi~ned to the key variablesv A multivariate analysis in the form of probability trees has been undertaken to test the joint effects of varying several assumptions in combination rather than individ- ually. This probabilistic analysis reported in Section 4.8 provides a range L'f expected net economic benefits and probability distributions that identify the chances of exceeding pdrticular values of net benefits at given levels of confidence. (G!,) Multivariate Sensitivity Analysis The feasibility study of the Susitna Hydroelectric Project in- cluded Qn economi~ andlysis based on a comparison of generation system r:r-oduc t i ort costs with and without tne proposed project using a computerized model of the Rdilbelt generation syst':!m. In order to carry ou~ this andlysis, numerous projections dnd fore- cdsts of future conditions were made. These for~cAsts of uncer~ t a i n con d i t i on s i n c 1 u d P f u t ur e e l ec t r i c a 1 d etn and , cos t s , and esc a- e.r :w i:c:ie; .. .• i ' ' -• ~"' \ . .. : . ,J.."' p• • .. ·~ • • • I""' . . . ,. " . ' lation. In order to address these uncertain conditions, a sensitivity analysis on key factors was carried out. This analysis focused on the variance of each of a number of forecast conditions and determined the impact of variance on the economic f e as i b i 1 i t y of the pro j e c t . Each f actor w a 5 v a r i ed s i n g u 1 a r 1 y with all other variables held constant to determine clearly its importance. Tt1e purpose of this rnultivariable analysis was to select the most critical and sensitive variaoles in the economic analysis and to test the economic feasibility of the Susitna project in each pos- sible combination of the selected variables. While a number of variables were identified and tested in the single variable sensitivity analysis for the Susitna economic feasibility study, the variables which were.chosen for the multi- variate sensitivity analysis represent the key issues such as load forecasts, capital cost of alternatives, fuel escalation and SusitnJ capital cost. The metnodology for the multivariate analysis was implemented by constructing probability trees of future conditions for the Alaska Railbelt electrical system, with and without tne Susitna project. Each branching of tne tree represents three values for a given variable. These were ass1gned a high, medium, and low value as well as a corresponding probability of occurrence. The three values represent the expected range and midpoint for a given variable. In some cases, the midpoint represents the most 1 ikely value which would be expected to occ~r. End limbs of the probability tree represent scenarios of mixed variable conditions and a probability of occurrence of the scenario. The OGPS production cost model was then used to determine the PW (in 1982 dollars) of the long-term cost of the electric generation related to each variable~ The PW of the long-term costs for each "with" and ~~~lithout" Susitna scenario in terms of cumulative probability of occurrence were determined and plotted. Net bene- fits n·f the project have also been calculated a.nd analyzed in a probabilistic manner. \~ \71 Figures 0.~ and D.li present the non-Susitna and Susitna proba- bility trees with resultant long-term costs. Comparison of L~~a-term Costs Figure D.~ pre~ents the two histograms of long-term costs for the "witn" and "witnout 11 Susitna cases plotted on the same axes. From these plots it is ~een that the non-Susitna plan co~ts could be expected to be significantly less than the Susit~a plan costs for D-4-36 (/(~IS~ J ~ I about 6 percent of the time, approximately equal to the Susitna costs 16 percent of the time, and significantly greater 78 percent of the time. A comparison of the expected value of long-term costs of the "with" and 11 without" Susitna cases yields an expected value net benefit of $1.45 billion. This value represents the difference between the non-Susitna LTC of $8.48 billion and the Susitna LTC of $7.03 bi 11 ion. These expected net values were calculated by summing the products of each LTC and associ4ted probabi 1 ity as shown on Figures 8.16 and B.l7, respectively. Net Benefit Comparison A second method of comparing the "v..ith" and 14 Without" Susitna probability trees is by making a direct comparison of similar scenarios and calculating the net benefit which applies. As in the case of the individual tree cases, the net benefits were ranked from 1ow to high and plotted against cumulative prob- ability. This graph has been represented as a single line due to tne number of points on the curve. It would, however, be most accurately portrayed as a histogram in the manner of Figure 0.13. The net benefits vary from a negative $2.92 billion with an asso- ciated probability of .0015 to a high of $4.80 billion with an associated probability of .018. The single ccynparison with the highest prelbability of occun~ence of .108 rias a net benefit of $2.09 bi 11 ion. \t5 Figure 0.~ plots the net benefit with the crossover between the "with" and nwithout" Susitna costs occurring at about 23 percent. This is consistent with the previous comparison and with the ex- pected value net benefit calculated by this method of S1.45 bil- lion. Sensitivity of Results to Probabilities In assigning the probabilities of occurrence for each set of vari- ables.~ a number of subjective assumptions were made. An exception was the Susitna capital cost probabi 1 ity distribution which was supported by a probabilistic risk assessment of construction cost. The p~·obabilities for load forecast of 0.2. 0.6 and 0.2 for the lc';;, medium and high cases, respectively 9 reflect the analysis by Battelle and the prob ab i 1 i ty of exceedence of approximate 1 y 10 percent for the high level of demand. Capital costs for alternative generation modes estimated in the Battelle study reflect a 0.20, 0.60 and 0.20 distribution, again within a range of a 90 percent chance of exceedence of the low and 10 percent exceedence of tne high level. 'I l,; 0=.4=~7 I/! ~Ut (~J .) 1 ~ Ci _41Mto:;: ... _ • ' ~ .. '1, The single variable to which the results are most sensitive is the rate of real fue1 escalation adopted. (This conclusion 1s supported by the single variable analysis as well.) The distribution of probabilities was 0.25, 0.50 and 0.25 for low, medium and high fuel co~t escalation scenarios. A case can be made for the argu-ment that some of the combined events, for example high fuel cost escalation, load and capital cost, are not (as our results assume) independent of each other. High fuel prices, it may be argued, wou1d result in lower load dnd increased capital cost. It is probable, however, that the greater revenues consequent on higher fuel prices would result in greater economic activity in Alaska, thus increasing demand for energy. This and other considerations led to the conclusion that the results would be relatively insensitive to probable ranges of interdependence. 4-.10 ~-Battelle Railbelt Alternatives Study The Office of the Governor, State of Alaska, Division of Policy De- velopment and Planning, and the Governor's Policy Review Cotmtittee con- tracted with Battelle Pacific Northwest Laboratories to investigate potential strategies for future electric power development in the Rail- belt region of Alaska. This section presents a summary of final re- sults 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 ana1ysis -electrical demand forecasts -generation and conservation alternatives evaluation -development of electric energy themes or "futures" avail able to the Rail belt -systems integration/evaluation of electric energy plans. Note that while each of the tasks contributed data and information to the final· results of the project, they also developed important results that are of interest independently of the final results of this pro- ject. Output from the first three tasks contributed directly as input to analysis of the Susitna project presented in this Exhibit. The results of the last two tasks are presented in this subsection. The first task evaluated the price and availability of fuels that e i the r d i r e c t 1 y co u 1 d be used as f u e 1 s for e 1 ec t r ; cal genera t ; on or indirectly could compete ~ith electricity in end-use applications such as space or water heating. 6.1 -Forecast Financial Parameters The financial, economic. and engineering timates used in the finan- cial analysis are summarized in Table The interest rates and forecast rates of inflation (in the Consumer Price Index-CPI) are of special importance. They have been based on the forecast inflation rates dnd the forecast of interest rates on industrial bonds (Data Resources Inc. 1980) 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 exeflllt financing waul d be at a rate of 80 percent rather than the historical 75 percent or so of the taxable interest rate. This identifies the forecast interest rates in the financing periods from 1985 in successive five-year periods as being on the order of 8.6 percent, 7.8 percent, and 7 percent. The accompanying rate of inflation would be about 7 percent. In view of the uncertainty atta\:hing 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 Defic1t 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 1 debt financed, long life, capital intensive projects (see Figure D. 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 fina.nc- 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 CollTTlerce and Economic Development but with separate and independent legal existence. The Authority was created with all general powers necessary to finance, construLt and operate power production and transmission facilities throughout the State. The Authority is not regulated by the Alaska Public Utilities Conmiss1on, but is subject t: the Executive Budget Act of the State and must identify projects for ~evelopment in accordance .. . n-Fl-1 ' 0 • with the project selection process outlined within Alaska Statutes. The Authority must receive legislative authorization pr1or to proceeding with the issuance of bonds for the financing of construction of any project which involves the appropriation of State funds or a project which exceeds 1.5 megawatts of installed capacity. The Alaska State Legislature has specifically addressed the Susitna project in legislation (Statute 44.83.300 Susitna River Hydroelectric Project). The legislation states that the purpose of the project is to generate, transmit and distribute electric power in a manner which w i 11 : Minimize market area electrical power costs; ( 1) (2) Minimize adverse environmental and social impacts while enhancing environmental values to the extent possible; and ( 3) Safeguard both life and property. Section 44.83.36 Project Financing states that Hydroelectric Project shall be financed by general general obligation bonds" revenue bonds, or other approved by the legislature." 6.4 -Financing Plan "the Susitna River fund appropriations, plans of finance as 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 11 of the State. On this basis it is expected that project costs for Watana through the end of 1989 will be financed by $1.8 bill ion (1982 dollars) of state appropriations. Thereafter completion of Watana is expected to be accomplished by issuance of approximately $2.4 bill ion (1982 dollars) of revenue bonds. The year-by-year expend~i~t!u~r~e~s~in~~--~~ stant and then current dollars are detailed in Table 0 ese an- nual borrowing amounts do not exceed the Authority's estimated annual debt capacity for the period. The revenue bonds are expected to be secured by project power sa 1 es contracts, other available revenues, and by a Capital Reserve Fund (funded by a State appropriation equal to a maximum dnnual debt ser- vice) and backed by the "moral obligation" of the State of Alaska. ___ he completion of the Susitna project by the building of Devil Canyon is ect d to be financed on the same basis requiring (as detailed in Table the issuance of approximately $2.1 billion of revenue bonds (in 1982 ollars) over the years 1994 to 2002. StJ'llmary financial statements based on the assumption of 7 percent inflation and bond financing at a 10 percent interest rate and other estimates~;~n. accor ance with the above economic analysis are given in Tab 1 es D /~)and D. . . .... , ~ D-6-2 - I r: The actual interest rates at which the project will be financed in the 1990s and the related rate of inflation cannot be determined with any certainty at the present time. A material factor wi 11 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 Sect ion 103 of the IRS code would be met. On this assumption the 7 percent inflation and 10 percent interest rates used in the analysis are consistent with authoritative estimates of Data Resources {U.S. Review July 1982) forecasting a CPI rate of inflation 1982-1991 of approximately 7 percent and interest rates of AA Utility Bonds (non exempt) of.ll.43 percent in 1991, dropping to 10.02 percent in 1995. TABLE D.l: SUMMARY OF COST ESTIMATE (REVISED) Januar v 1982 Dollars $ X 106 Category Watana Devil Cc:myon Total Production Plant $ 2,293 $ 1 '065 $ 3,358 Transmission Plant 456 105 561 Genera 1 Plant 5 5 10 Indirect 442 206 648 Total CJnstruction 3,196 1,381 4,577 Overhead Construction 400 173 573 TOTAL PROJECT CONSTRUCTION COST $ 3,596 $ 1,554 $ 5,150 ECONOMIC ANA,t_,YSIS Escalation AFDC TOTAL PROJECT COST FINANCIAL ANALYSIS Escalation AFDC TOTAL PROJECT COST 1 ' ;q;.. • ... TABLE D.6: VARIABLES .FOR AFDC COMPUTATIONS (NEW) Analysis_ Economic Financial Effective Interest Rate (x) % 3 10 1·-... .,.,_ ... - Escalation Rate (.Ly...;..)_ 0 7 l r t c; 1 ·------\ UTILITY IN ANCHORAGE-COOK INLET AtiEA Anc::hor~e Municipal Light wad Power Chu;ach Electrtc Auociation M~t•nuska Electric Association Homer El•ctrcc AnocaattOI'i Seward Elec:tric System Alaska Po~i' Administrni~"" I Nation~ Defense ' lndustri.l -Kf1nai IN ~AIRBANI<S-TANANA VA\U,EY . Fairb.tnks Municipal Utility System 1 Golden Valley Electric Association 1 University of Aladu National Dtftnse1 IN GLENALLENNALDEZ AREA Copper Valley Electric Association TOTAl 1Pooliog Arrangemt:nts in force - I I Generatint C•p.city 1981 MW It o-F Rating ~ 395.1 0.9 2.6 5.5 30.0 58.3 23.0 68.5 221.6 ~8.6 46.5 19.«J 1114.3 SCCT SCCT ~MI Ote~'-.., Diesel Hydro ST SCCT ST/OieMI ,. SCCT/OieMI ST ST I SCCT I Tox Status Re: IRS Sechon 103 Eaompt Non-Ex amp~ Non-Exempt Non-Exempt ~, ~on-Exempt NOO.~xempt Non-E•emQt ' Non-Ext!mpt Ellti'tmpt Non-Exempt Non-Exempt Non-Exempt Non-Exempt ' -1 I ,.~ ' Purcha~s Whofeule Eeectrical Enervv • • • • • ,, "" ' - - -- - " Prowide1 Wholeaale Supply - • --- • -·,, -' 'il,,, ~- - I "' Utihty Annu.a Energy [71-~mond 198(} GWh 585.8 941.3 268.0 284.8 26 ... 11&.7 316.7 ........ ~ 2571.1 t \ I . f'LANT No. 2 3 6 1 10 22 23 32 34 35 36 37 38 47 55 58 59 75 ao 81 82 13 84 NAME OF PLANT Anchor-ve No. 1 Anehor-ee Eklutna Chen a Knik Arm Elmtndorf·Wtst. Fairbanks Cooper lake Elmendorl· E011 Ft. Ricnerdson Ft. '!'•inright Eifson ft. Greeley Btmice Lake I ntern~tionar St.ti • Huly Beluga PLANT LIST UTILITY Anchoriilgt Municipal Light 1nd Po-.r AnchGr~~ Municip-' LiGht and Power Alaska Power Administration F airbanka Municipal Utilititl Sytttm Chugach Electric Auoci1tion, rnc. Unittd States Air Force Goldsn Valley EleC'tric Anoci1tion, Inc.. Chugach Electric Atsocietion, hw:. •• Air F01cs .;tug;ch Eiectric Associa\ion, Inc. Golden ValltV Electric Auociation, 1M. c/ugad\ Electric Association, Inc. Clur AFB Collier-Kenai Eyak North Pole V.Jdez Glennallen / 'UnSttd Statts Air F orct Collier· Ken .M I ~:::::-:.~,:~• E~:~~:i:~sooci•tion, Inc. Golden V;aUcy Electric Association, Inc. Golden Valft'f Electric Auociation, Inc. TYP£ Of OWNERSHIP Munecipal Municipal Ftderaf Munici~l Cooperative Fodtr .. Cooperat=we Cooperative F5dtr_. Federal Federel F~erll Ftder.a Coop.ratiwe Cooperative Cooperatin Cooperative Ftdaral Municipal Municipal Cooperadn Cooperative Cooparatiwe TABLE 0.13 -LtST OF GENERATING PLANTS SUPPLYING AAtLBELT REGION P • I 4 - .; 4 i t -· ... I . [ (. [ - [ [ [ [ c r -·' / ;) TABL€ D.t_l:' TOTAL GENERATING CAPACITY WITMIH THE RAttBELT SYSTEM[((~()tS.et:::'.) ~bbr•v I ~t ions Rail~ It UtI t I tx -f I nst'a lied Capacity • - (1) (2) NI$LPO CEA G.VEA fS«JS 8\IEJ!< MEA HEA SES APAd U of A TOTAL ' AnchOf"age t4un I c I pat Ugh t & Po.•r Depart-nt Chugach E l.ctrlc Associ at I on Golden Vell•y Electric As~oclatlon fa~rbenks Municipal Uti J lty Systt.Wr lt:alir E I ~t~ I c As50:e i at I on Seward E I ectr I c Sr!i tam Al~s~a Pe-er Administration Unlversltv of Alaska lnstalled capacity es of 1980 at O"f • Excludes ~tl~al Defense Installed c~paclty of 46.5 MW 395.1 2lt.6 0.9 2.6 JO.O . ~"' ~ ~ r-·r· 0 s O!l}-~ ... • • .; , • • ,~~ • ., • .... • • , • , ' , s: 7 ~ .! :t. • ,_,;::; • o q l' ,...,_ ·~ t ~ ~ ,Po "' . "' .~ "' \' •• ,.L , \ c . ;. ~.,. ,. ::· 4 , ~I • ~ ,. {.... • ... -, • -q ' • ;> 4> • ""'-~ ... • " --~. "' • ~ t ' . _.-__,_ . . . . ,_.-' . 0. -' 0 2 . -4 9 . ~ • ' " . ~-' 0 • j:l1 ' <1!i • -• • • • ..,, 4t . > ~ ~.,. ' • .... '(;>.~ • 4 -~ .~.. > ... t " ,. • • . _ ...... -~ -· .. <\ .. ~ . ........__ ___ .,.._ 1 . , ,. 6 • .J. \ ... "'h. ·• tt l • 'f. . • .. ... ___. • . ,.--""' ... ~ . ,.--.. -""" l ' ....... ,· ::. .:--" • ' ,. ' "!' . ... "' • ~... .. U ~ • • • r ,._ , • ____-, :: -• ' ~ 'w ' • D ' \.:;::-• 11' • o • ..., • "' • ' ~ t1 • • -• .:. .., • .. • • • • -• • ... • • . • • • -. ..-.: ' 't'• . • \ - ~ .~LE 0, *'-GENERATING UNITS HITHIN THE i3MlBELT -1980 ( ,c( ~vtse-d) I· r· r , ' ( I lraltbelt St•t!on Orilf Ofllt lnsfaT!at!on Hl'af ~te lnif<t! lea ---.. Utility _!,jarne _ No. Type Year (Btu/kWh) C•padty 6MW) _ F•Jel Type Retl!"e~Hnt Y.ar . ~ . .,.;~ I Anchorage Munlclpa! ll gh't ' Power O.p6r'tmeflt (N4LPD) Chugach Electric A~soclatlon (CEAi Go J den V a I I ''Y Electric Association CGVEA) Folrbonks Munlcfpel UtH lty System (fMUS) N-1LPO AMLPO AMLPO A:-4l?O G.M. Sui II van Beluga ~!uga B~luya Beluga Beluga Be lug~ Berll!c::e Lak• lntGrnattonat Station Copper lake H.wely Narth Pole Zehander Chene Ffil.JS -u.. [) ~ ' /:. /1' ~ M.<.,-. 1-... c. k. {! 4 1 lf, ~ GT 2 GT l GT 4 G'f ~.6,1 ex; 1 GT 2 GT ' GT 5 GT 6 GT 7 GT 1 Gf :2 GT &Jt GT 1 GT 2 GT 3 GT " HY d 1 ST 2 IC 1 GT 2 GT 1 GT 2 GT ' GT 4 GT 5 IC ~ I{; 7 iC 8 IC 9 IC 10 IC 1 5T 2 ST J ST 4 GT 5 ST 6 GT 1 tC 2 H; ) IC I I 7 I -'I /1) "'" .. ' 4... ~-·_,_ ---~ ". ,, "'~''-~:<~ r-)" 1962 14,000 1964 14,000 1968 14,000 1972 'i2,000 1~19 8,500 1968 ,,000 !968 15,000 l97l \0,000 1975 15.,000 ~9?6 ,5.,000 1977 15,000 196) 2J,·HO 19n 2),440 1978 23,440 1964 40,000 l965 --· 1970 -· 1961 --· 1967 11,808 1967 14,000 1976 IJ,OOO 1977 tl,~O 1971 14' 500 1972 14., 500 1975 1~, 900 1975 14,900 1965 14,000 1965 14,000 196~ 14,000 1965 14,000 1965 14,000 1965 14,000 1954 14,000 1952 14,000 1952 t•,ooo I96J 16,500 ~970 14.500 1976 12.490 1967 \l''i~OOO 1968 11,000 1966 11,000 16,. l 16.) 18.() 12.,0 1}9,0 16. l 16. I 53.0 56 .. 0 tt8.0 68.0 t.6 18.~ 26.4 14 •. 0 14.0 !8.0 16.0 25.0 2a8 65.0 65.0 18.4 17.4 .5.5 ).,5 3.5 l. 5 '·' -'·' ];o,, ).5 5.0 :l.5 1. 5 1.0 .... 21.0 2:S.J / 2.8 2.8 2. 6 ~ NG t.G t4G ~ NG t-13 NG ~ NG ..-.; NG 1-G NG Ni NG. ~ Co a~ Oil OH 011 011 '011 Oil 011 011 Of I 011 t)f ~ CH t 011 Coel Coel Coal 011 Coal O·ll 011 011 OH 199'1 i994 1998 2002 200 1998 1998 200l 2005 2012 2012 1993 2002 2006 19,94 199~ 2000 20 II 2002 1997 1996 1~7 1991 1992 1995 1995 1995 1995 1995 1995 1995 1995 1969 1987 1967 199J 2005 1997 1991 1998 1998 -, I ' .-. ........j l X' TABLE o.Ji CContlnued) Raitbelt Station Ulllt Unit Installation· Heat Rate fnstali~d h Utility Name No. l'ypa Year (Btu/k~h) Capacity 4MW) fuel Typ•, Retir~~men? Yur Homer E I ectr i c Hc:Mfter' Association Kenai (HEA) M,. Graham S. I dov Ia Uf'lverslty of University Alaska (U of A) lkllverslty University Unlver-..lty University Elltctric CVEA (CYEA) CVEA f \ootC::., I""U~Ii L ..... , CVEA ' fi4&tanuska Elee. Talk•etna AssociaTion (MEA) Seward El.ctrlc SES Syst-CSES} Ataske Power Eklutna .!\dtnl n l str•tlon (APAd) TOTAL . Notes: GT • Gas turbine CC • Combined cycle KY • Conventional hydro IC m Internal combustion ST • Steam turbine NG • Natural gas NA • Not available 1 fC 1979 1 tc 1971 1 IC ,952 2 IC 1964 3 IC 1970 1 ST 1980 2 ST 1980 ' ST 1980 1 IC 1960 2 IC 1980 , .. , lC IMl 4-5 IC 1966 6-7 IC 1976 1-1'~1967 4 IC ~j- ~--IC 1975 6 IC 1975 r GT 1976 1 IC 14167 1 IC 1965 2 IC 1965 3 IC 1965 -HY 195, 15,000 0.9 011 2009 1!S,GOO 0 .. 2 Olt 2001 15,000 0.]. OH 1982 15,000 0.6 011 1994 15,000 0.6 011 2000 J 2~:f$00 '·' Coal 2015 12.:000 1. 5 Coal 2015 12,;000 10.0 Cord 2015 10, ~00 2.8 011 2011 10,,500 2.8 01 I 201 1 10,500 '· 10,500 2.4 Qll 1996 10,500 _},2 011 2006 10~500----1.8 OH 1997 ------~500 1. 9 011 2002 10,'5Uu 1.0 011 2005 10,500 2.6 Qll 200, 14 000 3.5 Ott 1996 . ' :..::.f..-·-. - 15,000 0.9 011 1997 15,000 '·' 011 1995 15,000 1. 5 011 1995 15,000 2.5 Olt 1995 --lO.O ---2005 ~ ~ r• 9'4-·4- •This ~·lue judged to be unrealistic for large ranye planning and therefore Is adjusted to 15,000 for gen•r•tlon planning studies. for purposes of generation planning studies, O&M costs ond outage rates were assumed equal to those r•t•s given for new plants In Tabl• D. 17. ' JS ( 19811-1 ~1. (R ~ f!;:..rd) S04EDULE OF P\.A~O UTILITY AOOITIONS ,Uti I It~ lkt If 'lf! Avg. Energy NW Year 8'41EA ztcwon 8utch HT 1%. I tel CEA Bern Ice lake 14 GT 26.4 1982 AMLPO AMlPO 18 GT 90.0 191~3 -u CEA S.luge 16,7,8 a: 4~ 1982 COE Bred ley L8ke Hydro 90.0 1918 APA Grant L..ke Hydlro 7.0 1988 TOTAL 267e 4 • Nn I.Mit Pb. 8 •Ill •neOIIIP&~S ~Its 6 end 7, ~ rated et 68 Ml(. Totel new stetiOf'l CAp.clty will be 17Sl ,._ l _.,..,._.. __ I .. (GWtt) '' - - 347 )] • i -I r i ~ • r_ r_ r r_ c r I r - f' r r- r--- r r I . ,~ TABLE 0.~: S~Y Of TH~L GENERATING RES<:UlCE PlANT PARAMETEf!S/1982S Paranwter Heet Rate CBtu/kWh) E..-llest Availability O&M Co$tS fIxed 011-( (1/yr/kW) Variable 0414 <lfli4WH> Outages Planned Outages C%> Forced Outages <J> Construct I on Pttr lod (yrs) 200 * 10,000 !919 16. 8.} 0.6 8 5 .. 7 6 Startup Tl .. Cyrs) 6 Unit Capital Cost Cl/kW)1 Rait~lt - Be,uga 2,061 ~Mna 2,107 Unit Capital Cost (S/~W)2 C:O..bJned Cycl• 200 * 8,000 1980 7.25 1.69 7 e 2 1,075 Ges Turbine 70 MW 2.7 c.s 3.2 e 627 Olnal 10 HW 11,500 1980 0.55 5.38 l 5 1 1 856 Rallbelt 1 2.242 Beluga 1, 107 6.36 869 Nenana ~ 2~-, ~/ ~ ~ J __ ,ve~--------·~~------~-------- Notas: \ .... ""' ... '------- (1) As estiMted by Battella/Ebasco without AFOC. (2) lncludtnr.· IOC at 0 p.cMt •s~latlon and.) percent Interest, ~ ass~lng ~n s-shaped expenditure eyrve. ,. Source: Bat1'et le 1982, Yot. II, I Y, XJ I a, XIII #; ...... ----.--~~· -- -·~ - I .... .' ~I~~ • I : / 'f("lr-.. , .... .. / ,.-~ ... I t:H... fiGURE 0 ... LOCATK>P\1 MAP LEGEND PROPOSEC t'AM SITES ---131 !!;V INTl'ltTI[ ......... £XISTIIfG u .. rs ' 138 KV / / / GVEA lO 0 20 60 !--' =~·~~---j SCAl E IN WILU OF RAILBELT UTILITIES ,..,.. Et.etr• CCJQI*,..t.a 7ft AdrnMiall•tloft-EklutM 1. Do. Not lnduch $eft~-E'*'VY from MllitBy fftllblfteticne ~ The Uniw.-.1ty of ...... A. ENERGY SUPPLY (S.sed on Net Generation 1980) I .• / a. 10 I / Not I ~~ct. G~'ori by Milit-.-y nation .00 Th• Un;.,~ of Aa..a C. N T GENERATION BY YPES OF FUEL (B Otl Net Gene.·nion 19801 ·--,. ·---------------... A~ Etectrt. c.~· I ..... an. J 8. GENERATING FACILITIES (Based on Nameplat• Generati"9 C&pacity 1980J ~ined Cyct.a COinbullion TYrtMna (13'1 MW-1~~ Ra~g~~twr'ft;.,e Cycle Ccmbuscion TurtMne ~r-(111 MW- Simple Cycle C4m1Mmion Turtaine (520MW-5R) 1~) D. RELATIVE ~11 IX OF ELECTRICAL GENERATING TECHNOLOGY .RA!LBE LT JJT I L.t T.! ES ~ !-9·80 FIGURE 0.6 j , I . i I i \ . . . ~ . . 1.000 1.000 1,000 £1*ty o.;-.-. From Sr.ltitM / l.OOO z.ooo -------WNn~oAioM------~-----Wit.aN And 0..,~~----- 1.000 1H2 2010 ENERGY DEMAND AND DELIVERIES FROM SUSITNA ·l·- "' ' ._ low Case TABLE ll. 2J: REAL ( INFLATION-t\OJUSTED> ANti\l G1tOWTH IN OIL ~ICES Growth Retn !P..-oon~ 0 •. Nedlu-Case· (-ast likely) 0 High Case 0 Base Period ( Janu.ary 1982) I / ~j\ .,.,.. l: Ui::SW. 4 Pr-obab Ill !Y Q.l 0.5 0.2 ' ' / ,/ / / TABLE 0.24: ~"iY Of MAJ~ F~ECASTS Of OIL ffi ICE TRENDS Data Resources Inc. lnt•r~tlon.f Energy ~y•ncy -low .. High US Energy Jnfon.atJon ~g--~,, Is trat I on Energy 1141 nes and Resources Canada Ont•rlo Hydro Energy Node I I ng f orua., Wor I d 0 I I Report• -averag• of 10 mod• Is -range ot 10 MOdets Or. F. Feshar~J, Resource Syst8m$ Institute, East-~est Centr'e, Honolulu ' // / DATE Of FffiECAST .. Su~r 1982 •2.8 •'' Spring 1982 -o.5 ~2 .. 0 above +J .,. 7 1982 +!.8 february 198? +3.4 +le9 Spring 1982 •t. 7 / • The tO ~defs .re: Getefy-Kyle-FJscher CNe. York lv.>. lEES-OMS W. s. Dept. JO'f Ener51·0., I PE (~. 1. T.)., Sa I ant-tCF W. F edero J Trade / COI'IWftlsslon end ICF., Inc.>, ETA-MACRO CSta.,ford Unlv.), WJIL (U.Stt Dept. of Energ~nd Environmental Analysis. Inc.), Kennedy-No fng (Unlv. of Te•as .,rd the R41nd Corp.). OtLTANK (Chr. ~lchelsen lnstlt e). Op.c~lcs CBP ~ ltd.), OfLMAA (Energy and Power Subc~ ttee, u.s. Hou~ of Representatives). / ~~- ''\., " TA8lE ~ 2': C04ESll C ~ET ~ICES Afl() EXPOlT ~Tl.IHTY VAlUES Of Nl\l~L GAS Probllb~ of Occurr~~!~ ' Base Period Val-.,u. '\ R.al Escatatlon Cl{ PrIce, Japan "'- 1982 -2000 2000 -2040 ANI Escaletron 4 A I aska Pr lc:• 1993 -2000 2000 -2040 ' n:.-stlc fl4arket Prfce1 tOw ll4ed I~ Rl g,n N. A. N. A. N. A. IJ.. 0.3/M'iBt u ~ - -~ 2. ~-,/ 5.0~ ~ 2. 7"" 2. 0$ / ''., ./~ ', 1 Generation plannlngz:•t sis us&d domestic .a escaletlon be,ond 201~ 2 Bes~ on CIF pr-fce Japan CS6. 75> tess estltMt 2S 1. 2'S Pf* t ces •I th Z«"o of flquef&etlon and shlppJng CS2. 10>./' 3 Prfce estf .. ted;ffor t993, after ndJust~t of prices d to expiration of long to;-a co~acts. 4 Alaska op~tunlty waluo osealate~ MOre rapidly than CIF pr es as llquefec:tyOfi and shipping costs are estl.atld to reMain cons nt In real twas. / / / , .. ··l· $1. I I TABLE 0.26: S~Y C7 COAL ~Tl.IUTY VALUES ~ Base Period Annual RNI Growth Rate Probebl I lty (Jun. 1982) of '\ Value 1980 -2000 2000 -2040 Occurrenc• UI'M3tu) {J) U> J I' Bas• Case Sattel I• S.se Porlod CJF Price Nedlu• Scenario - C IF Japan 1.95 2.0 49 -FOO Beluga '·" 3 2.6 49 ' -Nenana ~.75 2.3 49 Low Scenario - C l F Jap.tJn 0 0 24 -F08 Beluga 0 0 24 -N.nana o. 1 O.J 24 HIgh Scei1ar J o ~ -CIF Japan J. 95 \, 2.0 27 -Foe Belug., t ... J 2.2 27 -Nenana 1& 75 t.9 27 Sensitivity Case Updated Base Period C IF Pr lc~l Medium Scenario .., CIF Japan 2.66 2.0 49 -FOO Beluga 2.08 2.5 49 -F<l3 Nenana l. 74/ 2.7 49 / Low Scenario II -CIF Japan 0 0 24 ' 2.66 -fOB Beluga 2.oe 0 0 24 -FOO Nenana 1. 74 -o.2 -o.s 24 High Scenario -CIF Japan 2.66 4.0 2.0 -FOO Beluga 2.oa 4 .. 8 2.2 .. FOO Nan~uta 1. 74 5 • .} 2 .. J ssumfng a 10 percont discount tor Alaskan ooaJ due to quality dlfteren- . .r t I a ts, dnd e•port potent I a I for Hea 1 y coa 1. / K\i / L) I-· rr ~I .... .,_.,_) TABLE l4 27: Sl.JIIo\'4AAY C7 FUEL ~ tCES USED IM 'THE OOP5 PRC.eABIL tTY TREE A~L YS IS Probabll ity of occurrett~e ... .... Base per Jod J.,.4.utry 1982 pr lees !19825/Mtitu) ~ Fuel 0 II . Natural Gas Coat • Belug• -Heman• Real ~alation rates per year (per'eent) Fuel OJ r -1982 .. 2000 -2000 -2010 -201 J -2040 Netur•l Gas -1982 -2000 -2000 -2010 -2011 -2040 Beluga Coal .. 1982 -2000 -2000 -2010 ... 2011 -20-40 Nenano Colli -1982 - .. 2000 -20 0 -201 J -0 I I I / Low 25S 0 0 0 0 0 0 0.1 Q.1 0 Fuet Price Scenario Medic. 1.6 1.2 0 2.3 1. 1 0 4.5 1. 9 0 / TABLE ~: ECONOMIC ANALYSIS SUSITNA PROJECT -BASE PLAN @ 1962 Plan Non-Susltna 491 630 MW GT Susltni! 680 MW Watana 600 MW Devil 180 MW GT Net Econ~ic Benefit of Susltna ? I an ~ 1990 892 2000 1,084 2010 1,537 t,G TABLE D.~ SUMMARY OF LOAD fORECASTS USED FOO SENSITIVITY ANALYSiS Mediu11 La. G"Nh ,...... GWtl MW 4,456 802 l,999 J ,098 5,469 921 4,641 1,439 7,791 I p24~ 6,303 2,163 199.3- 2051 5,0~ 7,062 Hlg.h GWh 5, 70J 7,457 1 t ,.4.35 .. [' Year 1990 2000 2010 2020 • TABLE 0.23: FORECASTS OF ELECTRIC POWER DEMAND (NEW) SCA Base M~---- SCA +2 Per cent 0 Per cent -1 Per cent -2 Per cent NSD Escalation Escalation Escalation .,:[scalatiog_ MW <1)\7h ~ ~ ·-· MW~~wh-~-M~(;;-fu·-MW lOwh . .._.. -.. --............... ___... -- lu rrY TABLE 0.24,: ELECTRIC POWER DEHAND SESITW.~ ANALYSIS (NEW) Plan Non-Susitna SCA Base Susitna SCA Base Non-Susitna SCA NSD Susitna SCA NSD etc. 1-J-'32 Present Worth of System Costs $ X iO 6 1993-§~ 2020 '"l '---=· 2020 ~--~------~~~ Estimated 1993 2021-2051 2051 a:io E X H 1 B lT B S EC-TICJ ;J .S s-. / )·2. S,3 s-·f/· s-.s- S· C /f? t:> 13 ;;l, -= 5 -STATEMENT OF POWER NEEDS AND UTILIZATION 5.1 -Introduction There are three primary objectives of the power market forecasts: first, to provide estimates of the power needs in the Railbelt system and region under various world price of oil assumptions; second, to present data which characterizes the e.lectric loads as well as measures the effect of conservation and energy prices on those electric demands; and third, to provide required information for the economic and financial evaluations associated with the Susitna Hydroelectric Project contained in Exhibit D. In order to achieve these objectives, the forecasts are presented on an aggregate as well as on a disaggregated basis from 1983 until 2010. Total energy demand and peak load requirement for the Railbelt region are provided each year over the period of reference. Also, the electric forecasts are shown for the load centers, by sector, and by end-use depending upon the availability of data. Because of the important role that world oil prices plays in the Alaskan economy, different electric demand forecasts are developed to cover ct range of expected wor id price of oil projections. 8-~--/ ; w .. i& Section 5.2 describes the electric power system in the Railbelt, including utility load characteristics and conservation and rate structures. Electric power load forecasts and the methodological bases for those forecasts are presented in Sections 5.3 and 5~4e Section 5.3 summarizes the four computer-based models that were utilized in preparing the economic and electric power load forecasts and the generation expansion plan for meeting laods. Section 5.4 presents the forecasts themselves and the key variables involved in producing the forecasts. A key part of section 5.4 is the summary of the base case electric power load forecast that serves as the principal basis for generation planning and project economic and financial analysis. The base case was selected from among several cases each of which corresponds to a set of projected world petroleum prices. Section 5. 5 provides a summary of the power demand forecasts, including a discussion of previous Railbelt forecasts; the impact of world oil prices on power market forecasts, and the sensitivity of the for. ecas ts to key factors other than world oil prices. Section 5.6 summarizes the planned utilization of the Susitna Hydroelecttric Project's power. Three important reference documents provide information in support of the forecasts. Appendix B-2, Fuels Pricing Studies, presents the methods and results of studies relating to alternative energy ! sources 1.n the Rai lbe l t, including natural gas, fuel oil, and coal. Appendix B-3, Man in the Arctic Program (MAP) Model Tech- nical Documentation Report, provides a complete explanation of the economic forecasting model used in developing load forecasts for the Railbelt. Appendix B-4, Railbelt E~ectricity Demand (RED) Model Documentation, provides similar information for the load forecasting model. 5.2 -SYSTEM DESCRIPTION In this section, a comprehensive description of the Railbelt electric power system is presentedft The system description is covered in three parts. The first part describes the inter- connected Railbelt market by characterizing electric utility and other sources of power generation. The characteristics of utility electric loads and conservative programs are discussed in the second part. Finally, historical data covering Railbelt electric demands and State and Rai lbelt regional economic factors are pre- sented to indicate trends and changes that have occurred in the past. 5.2.1 The Interconnected Railbelt Market The Rai lbe 1 t region, shown in Figure 1, contains two electrical load centers: the Anchorage-Cook Inlet Area and the Fairbanks-Tanana Valley area. These two load centers comprise the inter-connected Rai lbe lt market. "'' l_j .. I 3 At the present time, however, the two major load centers operate independently of each other. The existing transmission system b.etween Anchor age and Willow consists, of a network of 115 kV and 138 kV line with inter connection to Pa 1mer • Fair banks 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. Figure 2 illustrates the existing transmission system in the Railbelt region. 5.2.1.1 Characteristics of Electric Utility Systems Anchor age-Cook Inlet Area The Anchorage-Cook Inlet .area has three rural electric cooperative asso~iations (REAs), two municipal utilities, a Federal Power Administration, and two military inst~l- lations. These systems are listed below: Municipal Utilities Anchorage Municipal Light and Power (ML&P) Seward Electric System (SES) Rural Electric Chugach Electric Association, Inc. (CEA) Homer Electric Association, Inc. (HEA) Matanuska Electric Association, Inc. (MEA) U.S. Government Alaska Power Administration (APAD) Elmendorf AFB -Military Fort Richardson -Military The Alaska Power Authority (APA) will be a source of electric power generation in the next few years and should be considered as one of the utilities servicing the Anchorage-Cook Inlet area. All of these organizations, with the exception of MEA and APA have electrical generating facilities. MEA buys its power .from the Chugach Electric Association, Inc. B.EA and SES have relatively small generating facilities that are used for standby operation only. They also purchase their power during normal operations from the Ch.,lgach Electric Association, Inc. In 1981, the level of inBtalled capacity accounted for by the industrial firms in the Cook Inlet Anchorage area was about 114~6 MW. The industrial firms in this area produced about 373 .• 5 GWH in 1981. The major industrial sources of self generation are REA's service area. 1'he main industrial firms with operations in Kenai are listed below: are briefly described in conjunction with relevant customer and energy sales data for 1982. Municipa 1 Light and Power (ML&P) Service Area The service area of ML&P includes most areas within the City of Anchorage except for some sections which are se~ved by GEA. The northern boundary of ML&P's primary service area is indicated by the Port of Anchorage and Elmendorf A.F .B. The eastern boundary is roughly determined by Boniface Parkway extending down to Tudor Road on the south end of the City. Tudor .Road, between Boniface Par k.way and Arctic Boulevard, traces out approximately the southern boundary. Finally, the western boundary of the service area is denoted by ArGtic Blvd.~ until it connects with Northern Lights Blvd., continuing along the Alaska Railroad route tgwarg§ Westchester Lake and Knik Arm. Knik Arm forms the northwest boundary. Because ML&P and CEA are in negotiations concerning an interim inter connection agreement, slight changes in certain portions of ML&P 1 s service area may take place. \ ~~ ! J ,,., __ ,,.. Also, ML&P serves a separate land &Lea which contains the Anchorage International Airport. ML&P has proposed that this area be served by CEA in the future. ML&P provides electrical energy to Elmendorf AFB and .Fort Richardson on a non-firm basis. ~1nicipal Light and Power (ML&P) Customers and Sales ML&P provides service for mainly residential and connner cial customers. Two other customer classes are street lighting and sales for resale. The number of customers and associated sales for each customer class in 1982 are listed below: Customer Class Number Energy Sales (MWH) Residential 14,745 129,010 Connner cia 1 3,229 474,344 Street Lighting 7,663 Total 17,975 611,017 The above list denotes that residential customers are over 4. 5 times greater than the number of commercial customers. However, residential sales represent slightly over one fourth of total commercial sales in 1982. r --.I 7 Chugach Electric Association, Inc. (CEA) Service Area The service .area of CEA includes certain urban and suburban sections of the Anchorage area which are not covered in ML&P's service area. In addition to customers served in the Anchorage area, CEA serves . customers at Kenai Lake, Moose Pass, Whittier, Beluga, and Hope. These areas can be located in Figure 2. Chugach Electric Association, Inc. (CEA) Customers and Sales CEA serves retail customers as well as wholesale customers -REA, MEA and SES. A list of the average number of customers and energy sales by class of service for 1982 is presented below: Class of Service Residential Sales Cammer cial & Industrial (50 kVA or less) Cammer cial & Industrial (over 50 kVA) Public St. & Hwy. Lighting Sales for Resale Total Number 46,560 4,519 359 26 3 51,467 Energy Sales (MWH) 546,736 161,290 214,679 5,216 702,357 1,630,278 It is evident from the above list that the residential sales class has the greatest number of customers and accounts for most of the f!nergy sales to ultimate consumers. CEA had over 51 thousand customers in 1982 with total sales esceeding 1,630 GWH. Sales for resale represent 43 per cent of total sales. Other Utility Service Areas In the Anchorage-Cook Inlet area there are three other electric ~tilities with separate sevice areas: (1) Seward Electric System (SES); (2) Homer Electric Association, Inc. (REA); and (3) Matanuska Electric Association, Inc. (MEA) • The U.S, government sources of generation include those of the Alaska Power Adminis- tration, Fort Richardson, and Elmendorf Air Force Base. Chugach Electric Association, Inc. provides firm power to SES, MEA, and REA, thus supplying their total system requirements. In 1982, REA, MEA, and SES purchased about 347, 326, and 306 WH respectively from CEA. Homer Electric Association serves the City of Homer and other customers on the Kenai peninsula. SES serves ultimate consumers in the City of Seward and MEA has a service area encompassing the Matanuska Valley and related areas. These areas are depicted in Figure 2. The Alaska Power Administration provides firm power to CEA and ML&P. Fort Richardson and Elmendorf AFB has the capacity to satisfy their electrical requirements which were approximately 70 and 87 GWH respectively in 1982. However, both bases have non-irm power agreements with :t-!L&P. Fort Richardson has recently entered into a new contract with ML&P to pur chase about 30 GWTT on an interruptible basis. Fairbanks-Tanana Valley Area The Fairbanks-Tanana Valley area is currently served by one REA cooperative, one municipal utility, a university generation system, and three military installations. These sources are identified in the list below: Municipal and Non-Government Fairbanks Municipal Utilities System (FMUS) Golden Valley Electric Association, Inc. (GVEA) University of Alaska, Fairbanks j:, )·-/D ....... .r--··-·-------·---c.·~-;--··--··--····--·-·· ·~-· ----·· ........... .. '.'), ';~ ~ U.S. Government Eielson AFB -Military Fort Greeley -Military Fort \-Jainwright -Military The industrial sector had approximately 33.4 MW of in- stalled capacity in 1981 with nearly 60 GWH of net generation. Fairbanks Municipal Utilities System (FMUS) Service Area The service area of FMUS encompasses the land area approximately bounded by the city limits of Fairbanks. FMUS serves all of the electric loads within the city limits except for the Aurora and Hamilton Acres subdivisions and an area south of 23rd Avenue. These exceptions are principally residential areas annexed by the City of Fairbanks but served by Golden Valley Electric Association. The Chena River flows through the northern part of the service area with Fort Wainwright Military Reservation providing a border on the east. The downtown business district lies in the northeast corner of the FMUS service area along the south bank of the Chena River. There is an industrial area which is contained in part within the City of Fairbanks. The north bank of the Chena River provides the southern boundary of this industrial area. \ l -· .. .I( ·-· Fairbanks Municipal Utilities System (FMUS), Customers and Sales FMUS serves residential, commercial and government customers. In addition, FMUS provides power to Golden Valley Electric Association for resale. The following list provides the number of customers served by FMUS in 1982 and sales for each associated customer category: Energy Customer Class Number Sales (MWH) Residential 4663 27,758 Cammer cial 1050 68,695 Other Government 144 27,923 Street Lighting 4,911 GVEA and Other Utilities 1 33,479 Total 5858 162,766 The commercial class of customers are significant in number but more importantly in terms of total sales of energy. The residential artd government sectors had about the same level of energy salesin 1982. The second largest category of energy sales is accounted for by sales to GVEA for resale. -·--·-~-~-·-·----·-·-~-----·-····· ..... -... -·»·· s-·-· .. .... ... .. --·-·· ., ·' . t .• ) Golden Valle~ Electric Association (GVEA) Service Area GVEA is a "full service 11 rural electric cooperative responsible for generation of power as wel.l as distribution and sales. GVEA serves some residential areas within the City of Fairbanks. Golden Electric Association, Inc. (GVEA) Customers and Sales In 1982, the average number of customers rece1v1ng service by class of service and the cumulative energy sales for GVEA are as folows: Energy Class of ;Jervice Number Sales (MWH) Residential 16,176 150,487 Cammer cial & Industrial (50 kVA or less) 1~859 43,195 Commercial & Industrial (over 50 kVA) 233 129,394 Public St. & Hwy. Lighting 9 328 l'- < -....) ~~ - .I Union Oil of California Phillips Petroleum Company Chevron U.S .A., Inc. Tesoro-Alaskan Petroleum Corp. Other industr iaJ.. sources having offices in Anchor age include the following: Shell Oil Company Cook Inlet Pipeline Company Alyeska Pipeline Service Company ARGO Alaska, Inc~ Amoco Production Company Marathon Oil Company Sohio Alaska Petroleum Company The service area and customers served by the two main utilities servicing the Anchorage-Cook Inlet area are discussed in the following paragraphs. The . serv~ce areas for the remaining sources of existing power supply :t: ,,AWfl'_; . II Residential customers represent GVEA's most important service class in terms of numbers and total annual sales in 1982. Residential customers account for 88 percent of total customers and 45 percent of total energy sales. " Large commercial and industrial customers (over 50 kVA) lines is GVEA's second largest consumer of electricity. Other Utility Service Areas The remaining service areas are comprised of the University of Alaska at Fairbanks, Fort Wainwri,ght, Fort Greeley and Eielson AFB. With the exception of Fort Greeley, these sources generate their own power requirements. At the present time, Fort Wainwright supplies all of Fort Greeley's electricity needs by having GVEA whell the power on their transmission lines. 5.2.1.2 The Existing Electric Supply Situation The purpose of this subsection is to describe the current electric supply situation. Because electricity is a form of energy which must compete with alternative fuels in the market place, a brief discussion of the demand and supply for energy in toto is provided to provide an overall setting. The electric energy demands experienced - by Railbelt utilities are examined in detail ~n Section 5.2(c). Total Energy Demand and Supply The State of Alaska is a major consumer of energy resources. For example, in 1981, Alaskars energy input was about 543 billion Btus. The largest share of the input can be explained by crude oil input to refineries (44%) followed by natur~i gas (37%) and imported petroleum products (15%). Coal, hydro, and wood res our cce inputs accounted for the residual 4 per cent of total energy input. Table 3 represents the 1981 energy consumption for Alaska and the Railbelt. The total energy consumption for the Railbelt area was 236,000 Billion Btus (BBtus) in 1981. In 1981, Railbelt per capita consumption was about 752 Btus, which is approximtely 5 percent greater than the averag1a Alaskan per capita consumption . . ,.,-I . ~ -.b l' ., ··=•£; ... '/ I Sector Table 3 TOTAL 1981 ENgRGY CONSUMPTION (Billion Btus -BBtus) Alaska Railbelt (BBtus) (%) (BBtus) (%) Transportation 114,672 38 88,715 38 Industrial 64,823 21 44,699 19 Utility 46,344 15 40,115 17 'Military 25,847 9 25,847 11 Residential 26,571 9 19,434 8 Commercial/Public 11,913 4 10,658 5 Off-highway 13,069 4 6,430 3 Total 303,239 100 235,929 100 The Railbelt region accounts for almost 78 percent of the total energy consumption in the State of Alaska. In 1981, the Bush, North Slope and Southeast accounted .for the remaining lOs 4 and 8 percents respectively. The transportation sector is an energy intensive sector as denoted by the high per c1entage of total energy consumption shown in Table 3. Besides transportation, the .i.ndustrial and utility sectors are major consumer sectors of energy. aDoes not include electricity consumption. The total electricity consumption is reported in the utility sector. Source: 1983 Long Term Energy Plan (Working Draft), Department of Commerce and Economic Development, Division of Energy a~d Power Development, State of Alaska. 1983 Figure II-9 p. 11-14. Table 4 provides a breakdown of energy consumption by fuel type fr · "ar 1ous sector s. The dependence of tr anspor tat ion sector on fuel oil is denoted by figures in Table 4. Horeover, this sector far exceeds any other sector in terms of the quality of fuel oil consumed. The residential sector's fuel oil consumption exceeds 40 percent of total fuel consumption. In the transporation, industrial, military, and residential sectors, fuel oil accounts for over 25 per cent of the total fuel consumed in each sector. Natural gas represents the next most important fuel source. In the industrial, utility, and commercial public sectors, natural gas consumption accounts for over 50 percent of each sector's total consumption. Natural gas consumption in the residential sector is sightly less than that of fuel oil. Other primary fuels like coal and wood are of secondary importance. Coal is of some significance in the utility and national defense industries; wood based fuels are similarly of some consequence in the residential sector. !-•, ,-__. .. ~ .,., - .,..,,_,., .... w_wo...,e,_,, .. , l -- TABLE 4 Railbelt 1981 Energy Consumption By Fuel Type for Each Sector (Billions Btus) Sector/Fuel Type Tr anspor tat ion Fuel Oil Coal Total Industrial Fuel Oil Natural Gas Electricity Total Utility Fuel Oil Natural Gas Coal Hydro Total Military Fuel Oil Natural Gas Coal Electricity Total Residential Fuel Oil Natural Gas Coal Wood Electricity Total Connner cial/Pub lie Fuel Oil Natural Gas Coal Electricity Energy Consumption (BBtus) 88,649 66 88,715 13,264 31,435 2,130 46,829 2,152 29,652 5,407 2,904 40,115 15,364 4,590 5,893 2,904 40,115 9,647 8,109 140 1,561 3,745 23,202 2,256 7,333 1,069 3,842 14,500 Per cent (%) 99.9 0.1 100.0 28.3 67.1 4.6 100.0 5.9 73.9 13.5 7 .. 2 100.0 55.8 16.7 21.4 7.2 --100.0 41.6 35.0 0.6 6.7 16.1 100.0 15.6 50.5 7.4 26.5 100.0 Electricity consumption is included in the total for the utility sector. Source: Department of Commerce and Economic Development 1983. (Working Draft 1983 Long Term Energy Plan.) Appendix S, Table S-2. Electric Energy Supply In the following paragraphs, the existing generating facilities and planned additions for each load center are presented and briefly discussed. Anchorage-Cook Inlet Acea Table 5 presents the total generating capacity of the utilities and the two military installations by type of units. A more detailed description of each unit is presented in Appendix I. The Anchorage-Cook Inlet area is almost entirely dependent on natural gas to generate electricity. About 84.5 percent of the total capacity is provided by gas-fired units. The remaining are coal-fired units (8 per cent), hydroelectric units (5 .5 per cent), and diesel units (2 per cent). Fairbanks-Tanana Valley Area Table 7 presents the total generating capacity of the utilities and of thre three military installations by type of units. A more detailed dt.scription of each unit is presented in Appendix I. . . I • 1 ' Table 7 INSTALLED CAPACITY OF THE FAIRBANKS-TANANA VALLEY AREA (1982 ~ MW) Utilit ~s Fairba Uttl y Golden g As so Univet' '-) Alas: Sub tot< Militar T E ie.ls ----_____ QO \.F Fort Gr !1 Fort Wa Subtota Total Sour ~e; Ba Generatj :7 :1~ Region ( Table 5 Simple Comb Steam ut:iiities C.·u £! 1 ~ llig~gJ Ryc1r o _gy.c~e Turbine :::-.7-""..,; Alaska Power Administration 0 0 30.0 0 0 30. Anchorage Municipal Light and Power 33.3 0 0 240.0 0 273. Chugach Electric Association 178.0 0 16.0 143.0 14.5 462. Huiiier El@Gtric A~g~e{_~r-1 on " l ~ Q 0 0 === = =-~ ~ ~ ~---- 1.) 4iiJ" Seward Electric Association 0 5.5 0 0 0 Subtotal 211.0 7.0 46.0 383.0 14.5 Military Installations Elme11cior f AFB 0 2.1 0 0 31.5 Fort Richardson 0 7.2 0 0 18.0 Subtotal 0 9.3 0 0 49.5 Total 211.0 16.3 46.0 383.0 64.0 ~/Total inclltdes 111 MW Regenerated Cycle Combustion Turbine (CEA). Source: Battelle Pacific Northwest Laboratories. Existing Generating Facilities And Planned Addition for the Railbelt Region of Alaska, Volume VI, September, 1982. Table 5 Comb Simple Steam Utilities Cycle:_ Diesel Hydro Cycle Turbine Total Alaska Power Admin is tr at ion 0 0 30.0 0 0 30.0 Anchorage Municipal I ... ight and Power 33.3 0 0 240.0 0 273.0 Chugach Electric 462.~_/ Association 178.0 0 16.0 143.0 14.5 Homer Electric Association 0 1.5 0 0 0 1.5 Seward Electric Association 0 5.5 0 0 0 5.5 Subtotal 211.0 7.0 46.0 383.0 14.5 772.5~_/ Military Installations E lme ndor f AFB 0 2.1 0 0 31.5 33.6 Fort Richardson 0 7.2 0 0 18.0 25.2 Subtotal 0 9.3 0 0 49.5 58.8 Total 211.0 16.3 46.0 383.0 64.0 831.~/ !YTotal includes 111 MW Regenerated Cycle Combustion Turbine Untis (CEA). Source: Battelle Pacific Northwest Laboratories. Existing Generating Facilities And Planned Addition -.~-the Railbelt Region of Alaska, Volume VI, September, 198i~ 1-1-- ' l..,... Table 7 INSTALLED CAPACITY OF THE FAIRBANKS-TANANA VALLEY AREA (1982 -MW) Comb Simple Steam Utilities Cycle Diesel Hydro Cycle Turbine Total Fairbanks Municipal Utility System 0 8.3 0 28.3 29.0 65.6 Golden Valley Electric Association 0 23.7 0 170.8 25.0 219.5 University of Alaska 0 5$5 0 0 13.0 18 5 ---- Subtotal 211.0 7.0 46.0 383.0 14.5 772.5 Military Installations Eielson AFB 0 0 0 0 8.7 8.7 Fort Greeley 0 5.5 0 0 0 5.5 Fort Wainwright 0 0 0 0 20.0 20.0 Subtotal 0 5.5 0 0 28.7 34.2 Total 0 43.0 0 199.1 95.7 337.8 Source: Battelle Pacific Northwest Laboratories. Existing Generating Facilities And Planned Addition for the Railbelt Region of Alaska, Volume VI, September 1982. The Fairbanks-Tanana Valley depends heavily on oil-fired combustion turbines (59 percent), and coal steam turbine (26 per cent). The remaining capacity is provided by diesel units. The proposed transmission intertie between Anchorage and Fairbanks will allow Fairbanks utilities to purchase relatively inexpensive power (generated by natural gas) from Anchorage. It will also allow both load ~:enters to take advantage of the additional peaking capacity :lvailable in the Fairbanks area. ·-.; -~ ~ ' J ·-. ,. -· -----~--.. -~----=~-~~ -I FIGURE 1.1. ,.. PAIRIANU·TANANA VA&.LIY • .. ....... Ratlb!lt Area of Alask• Showing El~ctrtcal Load Centers 1. 3 l ( ' l .. ..._, ., z: ' 1. ···-· 11• I j .,.._,.. •• ..,.('>~"•·~ -~•c • LOCATION MAP LEGE NO \1 PROPOSED OAM SITES ----~ I!IIICV UNI: Al.KEETNA .._-MEA ' ~ -•r .. r-· I '-..-") :J ~· APPENDIX l: EXISTING AND PLANNED CAPACITY DATA J '~ '' "#,£./. ~i&&-- I 0J ' .. :-1 '-;\ ~ I . \)J . () .. ., .. . \~ \.. '- ~.-' ......... '"-! ./ . \ Pl~tnt Unit EXISTING Eklutna PLAN NED .::f.c Priaae Mover Hydro Bradley Lake Hydro Fuel Type --- Fuel Supply Table A.l EXISTING AND PLANNED CAPACITY DATA UTILITY: Alaska Pow~r Administration Nameplate Generating Average ln~tatlation Retirement Capacity Capacity Annual Heat Date Date (MW} @ o•F (MW) Rate' (Btu/kwh) -- 1955 2005 30.0 1988 2038 90 ------------.---'··--------------------------------------------- Forced Haxi•wa Outage Annual Capa- i.atr!. city Factor 0.01 0.01 0.9~/ b/ 0 .. 95=-- ~/Average annual en~rgy production for Eklutna is approximately 147,875,000 kWh. This ia equivalent to an annual lc b/factor of 0.56. . . -Average annual energy production from Bradley Lake is expected to be approximately 347,000,000 kWh. Of thia total Ji5,000,000 kWh will be firm energy and 32,000,000 ~~will be aecondary. The equivalent annual lo.ad factor ia 0.4 1'-7L... ~o~~J.....~~~tft_d_... ~.d?-~ ~if-d.-;_~ \. f ·- .{)\ \ .~ ~ \ v c Table A.2 EXISTING AND PLANNED CAPACITY DATJ~ - UTILITY: Anchorage Municipal Light and Power Nameplate Generating Average Plant Prime Mover Fuel Type Fuel Supply Installation Retirement Capacity Capacity Annual Heat Unit Date Date (MW) ~ o•F (MW) Rate (Btu/kwh) 'EXISTING ~Station #1 Unit #1 SCCT NG/Di st AGAS/LS 1962 1982 14.0 16.25 14,000 Unit #2 SCCT NG/Dist AGAS/LS 1964 1934 14.0 16.25 14,000 .: ~_'v ~J~t 1968 1988 18.0 18.0 14,000 Unit 13 SCCT NGiDist AGAS/LS 1972 1992 28. s 32.0 12,500 ., ' Unit P4 · Diesel l(h) SCCT NG/Dist AGAS/LS 1962 1982 l . 1 1 • 1 1011500 Di~sel Dist LS l 1 Dies e l 2< b) D i e s e 1 D i s t LS 1962 1982 1 . 1 1.1 10,500 , 1st at ion #2 . '. ~ .. J Unit #S SCCT NG/Dist AGAS/LS 1974 1994 32.3 40.0 12,500 1 Unit #6 (c) CCST 1979 2009 33.0 33.0 . it Unit #7 SCCT NG/Dist AGAS/LS 1980 2000 73.6 90.0 llaOOO ~~ !PLANNED)~ ~jc::::=-_./ f1stat ion #2 I 1 Unit # 8 SCCT NG/Dist AGAS/LS 1982 2G02 73.6 90.0 12,500 -------- Forced Haxiaue Outage Ann~al Capa- Rate city Fac~o.!,_ s_oa.en~ 0.10 0.10 0.10 0 .. 10 0.10 0.10 0.10 0.10 0 .. 10 0.10 0.81 0.81 0.81 0.81 0.81 0.81 0.81 0.81 0 .. 81 0.81 l.eaerv• Peak.i• Reserve Peaki -- Black · Uni1 Black Uni. --- I~/ All AML&P S~~Ts are equipped to hurn natur~l gas or oil. In normal operation they ere aupplied with natural ga• froa 1 AGAS. All units have re~e.rt~e oii ~tor:age for operation in the event gaa ia not available. b[rhese a:re black-start unit1 only. They •re not included in total capacity. 1r;" I . • . -, .,.~•-"": ":"":;,"'"',,:,·;?:~·~~"~~r.':l:;~ \ ~- ~..-;_--... ,- 1' c • -..-.. ... ' J \ .J \ '-\ \.. ~\ \ ' ) {/ )-· r:" Plant \ ' 'unit - , lSTING :tuga :unit #1 Unit #2 Unit #3 ,,_Junit ,4 I Un~t 15 Untt #6 Unit f7 n'!ice Lake • ·.Unit Ul \i Unit #2 .Unit #3 ;doper Lake Prime Mover sect· SCCT SCCT SCCT SCCT SCCT SCCT SCCT SCCT SCCT [pnit 11;2 Hydro 'o j 1 ternat ional Unit #1 SCCT (( · Unit 12 seer Unit #3 SCCT \ Fl!el Type NG NG N,. Ju NG NG NG NL NG NG NG NG NG Table A. J EXISTING AJ~D PLANNEU CAPACITY DA1'A UTILITY: Chugach Electric Association Nameplate Gcner~ting Average Fuel Installation Retirement Date Date supetx ----------~ Capacity Capacity Annual Heat (HW) @ o•F (MW) Rate (Btu/kwh) Prod. 1968 1988 14.0 16. l 15,000 Prod,. 1968 1988 14.0 16. l 15,000 Prod. 1973 1993 51 .0 53.0 10,000 Prod. 1976 1996 9. J{a) 10.7 15,000 Prod. 197 5 1995 60.0 58.0 10,000 Prod. 1976 1996 62.0 68.0 15,000 Prod. 1977 1997 62.0 68.0 15,000 AGAS 1963 1983 7.5 8.6 23,400 AGAS 1972 1992 16.5 18.9 23,400 AGAS 1978 1998 23.0 26.4 23,400 1961 1011 16.0 16.0 AGAS 1964 1984 14.0 14.0 40,000 AGAS 1965 1985 14.0 14.0 40,000 AGAS 1970 1990 17.0 18 .,0 40,000 " Forced Haximwa Outage Annual Capa- Rate city Factor_, Co entt 0.10 0.81 0.10 0 .. 81 --- 0.10 0.81 Jet !n&i 0.10 0.81 0.10 0.81 0.10 0.81 0.10 0.81 -- 0.10 0.8i -- Oo 10 0.81 --- 0.10 0.81 0.05 o. 95(b) -- 0.10 0.81 --- 0.10 0.81 0.10 0.81 \].1 ,, ' Table A.) EXISTING AND PLANNED CAPACITY DATA (Cont'd.) ' 4 . -UTILITY: Chugach Electric Associ~tion ~ Nameplate Gen~rating Average Forced Maxiaua P 1 ant t Prime Fuel Fuel Installation Retirement Capacity Capacity Annual Heat Outaae Annual Ccpa- l ---:unit Hover .!1.~ Supply ___ Date __ Date (MW) @ OoF (MW) Rate (Btu/kwhl Rat~ city Factor Ca.aentt ~··-·--- I STING 'tik Arm (c) Unit #1 St NG AGAS 1952 1987 0.5 0.5 ---0.10 0.81 'Unit #2 ST NG AGAS 1952 1987 3.0 J.O ---0.10 0.81 --- Unit #3 ST NG AGAS 1957 1992 3.0 3.0 ---0.10 0.81 -- i • 1957 0.10 0.81 _,-!Untt #4 ST NG AGAS 1992 J.O 3.0 ----~, ... . I Unit #5 ST NG AGAS 1957 1992 ).0 5.0 ---0.10 0.81 -- 1982 2012 54 54 ,rn1ce Lake #4 SCCT NG AGAS 1982 2002 23.0 26.4 12,000 0.10 0 .. 81 --- ., !.Beluga Unit #4 is a jet engine used for peaking only. It is not included in total capacity. !~Ave(age annual energy production for Cooper Lake ia approximately 42,000,000 kWh. Thia ia equivalent to annual load :,factor of 0. 30. :1,Knik Arm units are old and have higher heat rates. They are not included in total. 1·Beluga Units #6,7 and 8 will operate as a unit combined-cycle plant in 1982. When operated in thia .ode. they vill have I• generating capacity of about 178 MW with a heat rate of 8500 Btu/kWh. Thus, Units #6 &nd 7 will be retired fran "aaa 'turbine operation" and added to "gas combined-cycle operations". , ._:;_·:;-. ,.,-~~·-----"''S!l#!JIO!l. ..-,...~tlli \_ ., ,-;r .... - I \ \ ~~~ l.,/·-\·J \ \ . \;-J 0 l cfiSTING · ldovia !.Plant Unit - 'I STING co lo :~ i ! tJANNED -·--- jne I i l 1 I 1 j \ Prime Mover Fut:l Type Oieael Dist. Prime Mover Fuel Type D~esel Dist. Diesel Dist. Fuel Supply LS Fuel Supply LS LS Table A.4 EXISTING AND PLANNEU CAP.iCl'fY DATA UTILlTY: Homer Electric Association Installation Retirement Date Date 1957 1987 N•meplate Gener•ting Averaae Capacity Capacity Annual Heat (KW) @ o•r (MW) Rate (ltu/kvh) 1. 50 1. 50 10.500 Table A.5 EXISTING AND PLANNED CAPACITY DATA UTILITY: Seward Electric Association Installation Retirement Date Date 1965 1985 1976 1996 Nameplate Generating AverAge Capacity Capacity Annual Heat (MW) @ o•F (MW) Rate (Btu/kwh) 3.0 3.0 10,500 2.5 2.5 10,500 Forced Haaim._. Outaae Annual Capa- bte cit% Factor .£01 aentf 0.10 0.81 Forced Maximum Outage Annual Capa- Standby !~te city F~ctor _ Comment• 0.10 0.81 Standby 0 .. 10 0.81 Standby ~2 \ '{/':-) ~-l l·W ·- lant ru • ! Olt !STING i :mendorf AFB l ~ ..i Prime Hover Fuel Type Fuel Supply -~1''.~Jtal Dieae 1 Diese 1 Di ese 1 LS iTotal ST ST NG AGAS j ~rt Richardaon l !Total Diesel Diesel Diesel LS Total ST ST NG AGAS fANNED ,ne \ Table A.6 EXISTING AND PLANNED CAPACITY DATA UTiLITY: Military Installations -Anchorage Are• Installation Retirement Date Date 1952 1952 1952 1952 Nameplate Generating Averaae Capacity Capacity Annual Heat (HW) @ o•y (HW) Rate (Btu/kwh) 2.1 31.5 1.2 18.0 l-u-cnn 1 Juv 12,000 10,500 19,00o- 20,000 Fof'Cecl Kaai•ua Out•&• Annual Capa- ~te city Factor_ Co eat• 0.10 0.81 0.10 0.81 0.10 0.81 0.10 0.81 - -- Cold Sta Unit a Cogenera tioa Uee For Stea Heating ( \ ~ t ~ -l) \'•.) l \ -.. /.J I ly Diesel #1 12 1 2 4 Pri•e Hover ST Fuel Ty~ Coal Dieael Dist. SCCT Diet. SCCT Dist. SCCT Dist. SCCT Diat. SCCT Dist. SCCT Dist. Dieael Diesel Dist. None \ ,-) :t. Fuel Supply HEN LS LS LS LS LS LS LS LS Table A.7 EXISTING AND PLANNED CAPACITY DATA 'J UTILITY: Golden Valley Electric Association Inatallation Retirement Date Date 1967 2002 1967 1987 1976 1996 1977 1997 1971 1991 1972 1992 1975 1995 1975 1995 1960-70 1995 H•meplate Generating Average Cap~city Capacity Annual Heat (KW) @ o•r (HW) Rate (Btu/kvh) 25.0 25.0 13,200 2.75 2.75 10,500 64.7 65.0 14,000 64.7 65.0 14,000 18.4 18.4 15,000 17.4 17.4 !5,000 2.8 3.5 15,000 2.8 3.5 15,000 21.0 21.0 10,500 Forced Maxiau. Outaa• Aanual Capa- l&te city rector CO..e~~· 0.01 0.92 0.01 0.81 0.022 0.81 0.015 0.81 0.10 0.81 0.10 0 .. 81 0.10 0.81 0.10 0.81 o. ~I) 0.81 - Peakin&l I lack Start Uai -- --- -- -~ - - 0 \ . • l ' i UTU .. lTY! Univeraity of Alaska -Fairbanka ·-1 J.-vJ ()"lJ Nameplate Generating Aver•ae Focc:ed Maximua ant Pr-ime Fuel Fue 1 lnatall&tion Reticement Capacity Capacity Annual H~at Outage Annual Capa- Hover T~ Suppll Date Date (HW) ~ o•F (MW) Rate (Btu/kwh) Rate city Factor C011 ••nt• ST Coal NEN ------1. 50 l. 50 12,000 0.10 Oo8l -- ST Coal NEN 1980 ---1.50 1.50 12,000 0.10 0.81 - ST Coal NEN -----10.0 10.0 12.000 0.10 0.81 --- Diesel Diat. LS -----2.75 2.75 10.500 0.10 0.81 -- Dieael Diat. LS ------2.15 2.75 10,500 0.10 0.81 Table A.9 EXISTING AND PLANNED CAPACITY DATA UTILITY: Fairbank• Municipal Utilitiea Syate• Nameplate Generating Averaae Forced MuiiiUII Prime Fuel Fuel Installation Retirement Capacity Capacity Annual Heat Outaae Annual Capa- Mover type Supply Date Date (HW) @ o•F (MW) Rate (ltu/kvh) Rate city Factor Coaaenta fl ST Coal MEN 1954 1989 5.0 5.0 18,000 0.10 0.81 - #2 ST Coal NEN 1952 1987 2.0 2.0 ~t2 ,000 0.10 0.81 -- #3 ST Coal NEH 1952 1987 1.5 1.5 22.000 0.10 0.81 #4 SCCT Dist. LS 1963 1983 ).25 6.6 15,000 0.10 0.81 - #5 ST Coal NEN 1970 2005 20.5 20 .. 5 13,320 0.10 0.81 - #6 SCCT Dial~. LS 1976 1996 23.1 28.8 15,000 0.10 0.81 -. 1 t> i e s-e 1 D i at • LS 1967 1987 2.75 2.75 12.1SO 0.10 0.81 - 2 Dieael Diat. LS 1968 1988 2.75 2.75 12,150 0.10 0.81 - ] Di~ael Diat •· LS 1968 1988 2.7S 2.7S 12,150 0.10 0.81 --- :~ .. ~~&~-~ ' 'c-\) -:;;.r -t;-. ~f··. ,-'~ ~j - ,..,..... ": ' \ "' ~c.J Table A.lO EXISTING AND PLANNED CAPACITY DATA • -C... ......... UTILITY: Military Installations -Fairbank• Nameplat~ Generating Average Forced Ma.xiaua P L.ant Prime Fuel Fuel Installation Retirement Capacity Capacity Annual Heat Outaae Annual Capa- Unit Mover Ty~ Supply Date Date (HW) @ o•F (HW) Rate (Btu/kwh) Rate c i t y ~~f tor _ Coan~ ' ' ,; '';:XI STING :· \ ' , I 1:ielson AFB Sl ,S2 ST Oil LS 1953 ---2.50 ------0.10 0.81 SJ,S4 ST Oi 1 t.S 1953 ---6.25 ---_...,_ 0.10 0.81 'ort Greeley I !ol,D2,D3 Diesc::l Oil -·--------3.,0 ---10,500 0.10 0.81 Stan.c '' D4,D5 Ditsel Oil ---------2.5 ---10,500 0 .. 10 0.81 Stan( :t. Wainwright Sl,S2!S3,S4,ST r.oal NEN 1953 ---20 ---19,000-0.10 0.81 co,ene• 20,000 Uaed Stear Heat S5 ST Coal NEN 1953 ---2 ------0.10 0.81 Stan ,LANNED Nont' -··- ! f I 1 ~=-----::::-·· \ 5.2.,2 Railbelt Electric Utilities 5.2.2.1 Utility Load Characteristics This section first presents historical monthly load profiles for each load center. Then daily load curves are discussed, followed by an analysis of load diversity· between the two toad centers. (i) Monthly Load Profiles Table shows the historical distribution of monthly loads for each load center. The ratios \\Tere derived from the data presented in section 5. 2. 3. Both regions have winter peaks s occur ing in December, January or February • As illustrated in Figures and _, the load demand has its minimum during the months of May through August. The ratio of sunnner to winter peaks varies between 0.55 and 0.65. Also, Table shows that the monthly distribution has remained about the same for the period 1976-1982. (ii) Daily Load Profiles Table --pre·sents typical 1980 weekday and weekend daily load duration data for the months of April, August and December , for the entire Rai lbe 1 t region. r-_ These data were derived from the Woodward-Clyde study (Woodward-Clyde 1980). Figures and present daily load curves for a week in April, August and December 1982. The data were obtained from Chugach Electric Association and Golden Valley electric Association, which represent about ___ percent of the total Railbelt generation. As shown on Table __ , during the month of April, there is usually a morning peak between 7 and 9 a.m., and an evening pee.k between 6 and 8 p.m. Between the two peaks, the load demand 1s more or less constant. The night load is about 70 percent of the daily load. The average daily load factor is about 85 per cent. During the month of August, the load starts to increase at about 7 a.m., but continue to increase slowly until 11-12 a.m., when it decreases slowly. The night load 1.s about 55-60 per cent of the daily load. The aver age daily load factor is about 82 per cent. During the month of December, there is usually a morning peak between 6 and 9 a.m., and an evening peak between 4 and 7 p.m. Between the two peaks, the load is more or less constant. T'::te night load is about 65 per cent of the daily load. The aver age daily load factor ~s about 85 percent. (iii) _,Rail~ett Load n;ver ~ity the analysis of system diversity was done for the peak day in Fairbanks which was u~cember 29, 1981 and the peak day in Anchorage of January 6, 1982. The peak coincident and non-coincident loads were collected from all generating sources and diversity was calculated based on the data. Table shows the hourly load demand for these two peak days. The diversity measure in the total Rai lbe lt ranged from 0. 9 7 to 0. 99. The basic conclusion of the analysis is that based on the peak demand of individual utilities the total interconnected peak load for the Railbelt would probably be within a few percent of the total non-coincident peak demand. 5.2.2.2 Conservation and Rate Structure Programs This section presents conservation and rate structure programs initiated by the electric utilities and government agencies. The effects of these existing programs have been incorporated in the forecasting methodology which is described in section 5.3. , 7 .....J 1 .... , ..... ,*"! .. ,; The Anchorage Municipal Light and Power (ML&P) Programs The ML&P program specifically addresses electricity conservation in both residential and institutional settings. I t 1. s a f or m a 1 conservation program as mandated by the Powerplant and Industrial Fuel Use Act of 1978 (FUA). The program of ML&P is designed to achieve a 10% reduction in electricity consumption. To achieve this level of conservation, ML&P provides information on availablH state and city programs. Additionally, it has p~ o gr ams to~ (1) distribute hot water flow restrictors; (2) insulate 1000 electric hot water heaters; (3) heat the city water supply, increasing the temperature by l5°F (decreasing the thermal needs of hot water heaters); and (4) convert two of its boiler feedwater pumps from electricity to steam. (5) convert city street lights from mercu:-~ vapor high pressure sodium lamps; and lamps to (6) convert the transmission system from 34.5 KV to 115 KV . .. ~··. - ML&P also supplies educational materials to its customers along with "Forget-me-not" stickers for light switches. It has a full time energy . eng1neer devoted to energy conservation program development. The proje~ted impacts of specific energy conservation programs are detailed in Table 9 for the period 1981-1987. They are dominated by non-residential public sector programs such as street light . conver s1on, transmission line convers1on, and power plant boiler feed pump conversion. The latter programs are expected to provide 25,408 MWh of electricity conservation in 1 9 8 7 , or 7 2 % o f t h e t o t a 1 p r o g r a mm a t i c en e r g y co n s e r v at i o n . In addition to these conservation programs, ML&P has also projected conservation due to price-induced effects. Table 10 presents the projections. About 60 percent comes from price-induced conservation. After 1983, the rate of increase . l.n conservation declines sharply. The rate of improvement drops sufficiently such that realistic conservation reaches . a max1mum level by 1983. Beyond that time frame, price-induced conservation may be considered as the overwhelming contributor. r 5¥ The Golden Valley Electric Association Program Golden Valley Electric Association, in Fairbanks, provides an education oriented approach to energy conservation programs. To accomplish the education program, GVEA has adapted a plan pursuant to REA regulations. This utility employs an Energy Use Advisor who per forms the following tasks: (1) performs advisory (non-quantitative) audits; (2) counsels customers on an individual basis on means to conserve electricity; (3) provides group presentations apd panel discussions; and (4) provides printed material, including press releases and publications. GVEA also eliminated its special rate for all ele~tric homes, and placed a moratorium on electric home hook-ups in 1977. It has given out flow restrictors. It has prepared displays and presentations for the Fairbanks Home Show and the Tanana Valley State Fair. It coordinates its programs with the state and other programs. The GVEA budget for conservation activities involves 1.8 man years of effort. r'~ "'p'f .~ . .,· = The efforts of GVEA~ combined with price . 1.ncreases and other socioeconomic phenomena, produced a conservation effect as shown in Table 13. Although much of the decline . l.n aver age consu~ption can be attributed to . conver s 1.ons from electric heat to some other source, part of the reduction . l.S the direct result of conservation. The data show a reduction from 17s332 KWh/house/yr in 1975 to a level of 9,080 KWh/house/yr in 1981. The data in Table 13 also show a moderate upturn in electricity consumption per household in 1982, indicating that the practical limit of conservation may have been reached 1.n the GVEA system. Currently, GVEA's load mRnagement program is directed toward commer,.cial consumers. A significant lower rate schedule is available to commercial customers whose demand is maintained at less than 50 kW. Larger power custorr: ·rs are advised on ways to manage their electrical . . . m1.n1.m1.ze load to demands. In addition, seasonal rates are available to those large consumers who significantly reduce their demand during the winter peak season. A program is underway to identify customers who operate large interruptible loads during periods of system peak demand. Various methods of residential load management are under study, but none appears cost effective at this time other than voluntary consumer response to education programs. .. ·"y· ··-·. ·' • ' . ' . I ,l ) I l, 'J'\ . J '· I l• I 1. ( I Other Utility Programs The other utilities . have var 1.ous programs aimed at getting information to the public concerning the dollar ,. sav1.ngs associated with electricity conservation. The utilities rely on market forces, and aid L.i consumer recognition of those forces. No specific rate structure programs bave been implemented. 0 t h e r Co n s er v a t i o n Pr o g r am s (i) The State Program The Conservation Section of the Division of Energy and Power Development (DEPD) is responsible for administration of the United States Department of Energy's low-income weatherization program. ·~ 1 ) ( 2) (3) This program has involved the following activi·:ies: Training of energy auditors; Performance of residential energy audits, which are physical inspections including measurements of heat loss; Providing gran.ts of up to $300/household~ or loans, for energy conservation improvements based upon the audit; (4) Providing retrofit (e.g. insulation, weatherization) for low income homes. ) p;,;qAWM ItS - The key to the program . 1S the audit, which is performed by private contractors. The forms employed are designed to show savings that can be achieved iu the first year, the seventh year, and the tenth year after energy conservation measures have been implemented. The savings demonstrated provide the basis for qualifying for a grant or loan. The audits focus on major conservation opportunities such as insulation and reduction of infiltration (e.g., by weather stripping, eaulking, and storm window application). The DEPD program, overall, achieved a significant level of penetration into the conservation marketplace. Penetration . 1n the state as a whole achieved 24%; and 1n the combined load centers of Anchorage and Fairbanks it also achieved 24%. It . 1S useful to note that the audit program was more effective in high cost energy areas (e.g., Fairbanks) indicating that public participation was based upon market forces at least to some modest extent. The DEPD program has achieved a 4.2% sav1ngs of energy . 1n Alaska, of which 18% Over 80 . 1S electricity (House, 1983). percent of the energy conserved has been in the araa of fossil fuels. This is consistent with the direction of the program towar1s thermal energy savings (Brewer, 1983). . ~ • I •. ',.; T .......... #h4. - Th e DE p D pr o g r am is cur r e n t l y b e i n g ph a s e d o u t , ex c e p t f or low income family assistance, particularly in the Bush Communities (Brewer, 1983). Even in those communities, only 13% of the homes will be treated (at a cost of $2000/house) in the next 3 years (Brew,:r, 1983). Educational efforts, however, will continue (llouse, 1983). If programs are constructed for the future, they will be directed at fossil fuel conservation. Particularly in the remote areas (House, 1983). The City of Anchorage Program The Anchorage Program is the other non-source-specific conservation program operated by the Energy Coordinator for the City of Anchorage. This program also involves audits, weather- i z a t i o n , and e d u c a t i o n a 1 e f f or t s . Cursory walk-through audits have been performed on city buildings and schools, and detailed audits have been performed on selected institutional buildings. According to energy coordinator P. Poray, few cost effective conservation measures were uncovered by the audits (Poray, 1983). The weatherization program is applied in the case of low . ~ncome personnel, and involves giving grants of up to $1600 for materials and incident~l repairs. Labor is supplied from the mprehensive Employment Training Act (CETA) program. ' , 1 \ ~ ........... _-. J - The educational program has involved working with realtors, bankers, contractors and businessmen. It also has involved informal contacts with commercial building maintenance personnel. Finally, it has involved contacts with the general public. .• Table MON'f:W.LY DISTRIBUTION OF PEAK LOAD DEMAND Anchorage -Cook Inlet Area 1976 1977 1978 1979 1980 1981 1982 (%) (%) (%) (%) (%) (%) (%) Jan 94.2 76.8 89.2 90.5 89o9 79.1 100.1 Feb 91.2 91.8 85.8 100.0 84.8 84.8 93.3 March 81.7 75.4 77.5 85.9 72.4 73.1 83.0 April 70.9 69.7 70.6 67.8 60.1 69.1 77.4 May 63.9 59.8 62.6 58.9 55.7 61.3 64.3 June 59.9 55.6 59.7 58.5 52.7 61.5 61.8 July 62.3 54.2 59.4 54.9 54.2 63~0 61Q6 Aug 70.1 67.5 66.1 61.9 58.3 69.7 73.8 Sept 89.2 78.1 81.5 72.7 69.9 78.7 90.9 Oct 100.0 100.0 100.0 99.0 100.0 100.0 95.6 Nov ·'~" -~ Dec ... ---,-.;; w I I ) Fairbanks -Tanana Valley Area '-<) , * 1976 1971 1978 1979 1980 1981 1982 ~ (%) (%) (%) (%) (%) (%) (%) Jan 100.0 74.8 1100.0 88.6 99.8 85.7 100.0 Feb 98.6 74.3 98.8 100.0 79.0 94.6 97.0 March 81.0 73.2 85.4 80.7 73.7 73.1 86.8 April 64.2 61.9 83.4 65.1 63.3 70.2 77.1 May 54.3 51.2 60.6 56.1 58.5 69.4 71.0 June 49u2 47.9 60.4 53 .. 5 56.8 63.9 66.6 July 53.6 46.4 57.7 55.4 58.5 62.9 65.4 Aug 52.4 47.3 57.7 56.5 62.3 65.5 68.5 ' Sept 59.4 55.7 65.5 59.6 63.9 70~8 73.9 i :-\ Oct 81.3 67.4 75.5 66.3 74.2 17.4 85.8 Nov 83.6 87.1 89.9 71.7 79.2 83 .3· 94.7 Dec 96.3 100.0 87.2 87.0 100.0 100.0 94.4 6;~-..• ,_...----~'"'-~". -~"t.lt~~1'!1-~-~>~ \ (•-. SUSITNA JOINT VENTURE SU~E~----------------------------FILE NO. ------ COMPUTED ------- I ·' ~· __ ., ~--~·· ---- DATE _____ _ CHECKED---PAGE _ OF ·-PAGES • F:Ju{U_ -- ~~~ ... ... .. .- .Soo ·-· -" ____c __ -~__;___ ____ --'~------'---· ________ __.:___._:__·__.___:___:___: __ '[: __ ..:....!:_.:__:_ ---·--- SUSITNA JOINT VENTURE ~ ~ '-.J. ~ t Q) ) ~ {50 too ... t l'i8~ Q . (~11 o Lct7! SUBJECT ------·-----------FILE NO. ----- DATE _____ _ COMPUTED CHECKED---PAGE _OF _ PAGES I~ So TABLE 1980 TYPICAL DAILY LOAD DURATION -- SELECTED MONTHS APRIL AUGUST DECEMBER APRIL AUGUST DECEMBER 1.000 1.000 1.000 .942 .871 .945 .990 .990 s997 .917 .868 .944 .983 .988 .979 .897 .858 .927 .981 .977 .968 .882 .846 .911 .978 .970 .948 .882 .845 .893 .966 .965 .918 .880 .842 .868 .963 .959 .915 .870 .837 .862 . 957 .951 .914 .867 .835 .856 ~953 .948 .913 .859 .832 .854 .947 .923 .909 .851 .830 .853 .939 .890 .905 .851 .820 .843 .936 .882 .897 .838 .816 .826 .936 .873 .896 .837 .797 .818 .931 .868 .879 .827 .786 ~782 .888 .834 .873 .805 .724 . 775 .853 . 776 .812 .753 .703 .732 .750 .747 .804 .729 .667 . 724 .769 .666 .747 .724 .623 .723 .712 .657 .710 .689 .616 .680 .698 .612 .702 .673 .595 .672 .683 .590 .675 .668 .580 .661 .672 .581 .668 .667 .564 .655 .670 .581 .664 .661 .555 .648 .670 .560 -.661 .650 .545 .648 Source: Woodward-Clyde, 1980. f ... MJARZA6J EISA$~.@ SUBJECT -·---------~----------------- SUS/TNA JOINT VENTURE COMPUTED ----------CHECKED ··-------- (QQo tu~ ~dt·ty !o~d \ .... __ C /., _, f) _ .. 1 r? / I r .. ' dt -., . I J E/ccl:.i~~ FILE NO .. __ _ DATE ---·----- PAGE _OF __ PAGES ---··-·····-~-~-----... -.--------.... -.. ------------------------... -... ------------------------·------------------------------~ -~. ········1··.~.=- ~U~E~------------~----------- ~M~ED __________ __ CHECKED --- trB~ cbd.lf to~cl Go df~ {/=-rfe;; E /e c!;~. ~~ 13 -J' .. -!:-.-/ .. ,,.. •'---~···-··-. ---,.----"'-' ~- - fiLE NO. ----- DATE ____ _ PAGE _OF ___, PAGES lUI..., TABLE RAILBELT LOADS DECEMBER 29, 1981 Non- Coincident UTILITY 2PM 3PM 4PM 5PM 6PM 7PM 8PM Peak CEA 168.55 170.7 178.7 179.4 182.1 180.8 173.2 182.1 ML&P 107 Ill 110 106 104 100 96 111.0 MEA 52.3 51.4 49.5 49.0 52.2 50.1 47.0 .52.3 REA 48.1 48.3 49.7 50.4 49.7 49.0 46.7 50.4 GVEA 71.8 71.8 75.4 69.1 72.9 72.2 73.2 75.4 Ft.WR. 9.5 11.0 11.7 10.2 9.5 8.8 9.5 11.7 EIELSON 10.3 10.3 10.0 10.0 10.0 10.0 10.0 10.3 U. of A. 5.8 5.8 5.6 6.0 4.9 5.3 r+.4 6.0 FMUS 27.4 26.7 26.7 25.7 24.0 21.1 18.5 27.4 TOTAL 500.7 507.0 517.3 505.8 509.3 497.3 478.5 526.6 Diversity == Coincident Peak = 517.3 = .9823 Non-coincident Peak 526.6 RAILBELT LOADS JANUARY 6, !982 Non- Coincident UTILITY 2PM 3PM 4PM 5PM 6PM 7PM 8PM Peak CEA 175 178 194 202 214 210 203 214 ML&P 109 109 117 115 116 112 107 117 MEA 66 71 71 71 73 74 74 74 HEA 57 56 60 62 62 63 61 63 GVEA 66.5 67.8 69.0 74.6 71.9 74.1 74.2 74.6 Ft .WR. 11.0 11.7 11.7 9.5 9.5 9.5 8.8 11.7 EIELSON 11.0 11.0 11.2 10.9 10.7 10.4 10~4 11.2 U. of A. 6.0 6.2 6.2 6.5 5.7 4.3 5.0 6.5 FMUS 27.4 27.2 29.7 26.2 24.0 23.5 20.4 29.7 TOTAL 528.9 538.3 569 .. 8 577.7 586.8 580.8 563.8 601.7 Diversity = Coincident Peak = 586.8 = .9752 Non-coincident Peak 601.7 ' . ..... J TABLE 9 CUMULATIVE ENERGY CONSERVATION PROJECTIONS (MWH/YEAR) ANCHORAGE MUNICIP~L LIGHT AND POWER Program Year 1981 1982 1983 1.984 1985 1986 1987 Weatherization 586 762 938 1,114 1,290 1,466 !,641 State Programs 879 1,759 2,199 2,68'3 3,078 3,518 3,737 Water Flow 200 464 464 464 464 464 464. Restr icticos Water Heat: 3,922 3ll922 3,922 3,922 3,922 3,922 3,922 Injection . I I \A) Hot Water NA NA 249 249 249 249 249 I Heater Wrap 1 v-Street Light 0 555 1,859 3,307 4,788 6,306 7,861 '; ~ Conversion ti.,," "-.. l.J Transmission 0 0 4,119 8,732 9,256 9,811 10,399 Coover sion \!:;· } ! f Boiler Pump 7 J 1:48 7, 148· 7,148 7,148 7,148 7,140 7,148 Conversion TOTAL 12,735 14,609 20,896 27,619 30,195 31!' 614 35,421 % Change NA 14.7 43.0 32.2 9.3 9.8 8.6 From Previous Year Source: AML&P, 1983 ', .. ,~=-'·-·~'-F'"''___ ...... tiPii ~ TABLE 10 PROGRAMATIC fiS MARKET DRIVEN ENERGY CONSERVATION PR0 1 ECTIONS IN THE AML&P SERVICE AREA Year Progr amat ic Price-Induced Increase From Conservation Conservation Total Previous Year (~fWh) (%) (Ml.Jh) (%) (MWH) (%) (%) 1981 12,735 39.5 19,558 60.5 32,294 100 NA 1982 191,609 34.9 27,243 65.1 41,853 100 29.6 1983 20,896 37.1 35,374 62.9 56,289 100 34.4 1984 27,619 41.1 39,560 58.9 67,133 100 19.3 1985 30,195 40.4 44,536 59.6 74,730 100 11.3 . 8 I· J 1986 32,614 40.6 48,133 59.4 81,015 100 ~~ 0 '(' I 1987 35,421 41.0 50,940 59,0 86,363 100 6.6 • i .. ~ /} ! L "'1 Source: AML&P, 1983 ~~ ·' . ...,..,( 1 .I t:J • J 'V'-. l J v-... I v ... \ TABLE 13 Year 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 AVERAGE ANNUAL ELECTRICITY CONSUMPTION PER HOUSEHOLD ON THE GVEA SYSTEM, 1972-1982 Annual Monthly Consumption Consumption Per cent (kwH) (kwH) Change 13,919 1,160 +5.6 14,479 1,207 +4.0 15,822 1,319 +9.3 17,332 1,444 +9.5 15,203 1,267 -12.3 14,255 1,188 -6.2 11,574 965 -18.8 10,519 877 -9.1 9,767 814 -7.1 9,080 757 -7.0 9,303 775 +2.5 Source: GVEA (Colonel!, 1983) 5.2.3 Historical Data for the Market Area Available economic and electric power data for the State of Alaska and the Railbelt are summariz~d in Table 5-A.. The table shows the rapid growth that has occurred in the state's and the Railbelt's population, economy, and use of electric power. The growth has been especially rapid during the last decade. Between 1960 and 1982, population ~n the Railbelt grew from 94,300 to 231,984, an increase of 146 per cent, or an aver age of 4. 2 per cent per year~ The: n~1mber of households in the Railbelt grew at a faster rat£ during this period, an average of 4.9 percent per year, reflecting the nationwide trend towarr, fewer per sons per household. Much of the population and economic growth that occurred during this period is attribtltable to the tremendous increase in state petroleum revenues and general fund expenditures. State petroleum re,;enues grew from onLy $4.2 million in 1960 to $3.57 billion in 1982, mainly due to the discovery and development of petroleum on Alaska•s North Slope. Between 1960 and 1982 state general fund expenditures rose from less than $100 million per year to $4~6 billiona Consumption of electric power in the Railbelt has r~sen significantly faster than the rate of economic growth. Between 1965 and 1982 total energy ~eneration rose from 467 gigawatt hours to 2,934 gigawatt hours,· a five-fold ~ncr ease~ or an aver age of 11 . 4 per cent per year . Peak energy demand has also risen rapidly in recent years, from 412 megawatts in 1976 to 566 megawatts in 1~82, an average of 4 per cent per year. Tables 5-·B and 5-C present monthly electric power use and peak demand during the period 1976 to 1982 for the Anchorage and Fairbanks load centers. These tables show that while there has been a steady rise in the use of electric power and in pe~k demand, there has been considerable variation in monthly energy use and peak demand from one yt!.ar to the next, mostly due to different weather conditions in the Railbelt. Table 5-D g1ves the net annual generation of each Railbelt utility between 1976 and 1982. The table shows that Chugach Electric Association, which provides power to numerous other utilities including Horner Electric and Matanuska Electric has generated an excess of 50 percent of the electric energy used in the Rai lbel t. Anchor age Municipa.l Light and Po-w·er is the second largest gener.ator, having provided nearly 20 percent of the Railbelt's electric energy in 1982. -~ I •' --,, ! ~ Aln.uw l--., l • II t I i i ·-·~ . l TABLE 5.A HISTORIC ECONOMIC AND ELECTRIC PO - ' ,_ ·-"' I YE~R ITEM 1960 1965 : 1970 197 I ±:lo I State Oil and Gas Revenues to I Genera 1 Fund $ 4. 2 million 11 $ 16.3 •million I $ 938.6million21 $ 88.3 1 State General Fund Exp.end it ur es n. c..: .• $ 82.7 million $ 188.6 million $ 453.3 1l State Population 226,200 265,200 304,700 390 ' ( State Employment 94,300 110,000 133,400 197,~ Railbelt Population 140,486 n.a. 199,670 n. c: Railbelt Employment 3 n.a. 74' 100 88,500 130,4 Railbelt Households 37,062 n.a. I 54,057 n.a Railbelt Electric Energy Generation Anchorage n.a. 369 GWH 684 GWH 1,270 Fairbanks n.a. 98 GWH 230 GWH 413 Total n.a. 467 GWH 914 GWH 1,683 Railbelt Peak Demand n.a. n.a. n.a. 412 ] Railbelt Generation Capacity Sources: MAP Model Data B¥se; Federal Energy Regulatory Commission, Power System Staten 1 Printouts, 1983. 2 Figure is for 1961. 3This figure is unrepresentatively high due to collection of a large petroleum lease bon 4Excludes agricultural workers and self-employed. 5Figure is for 1976. Sum of demand in Anchorage and Fairbanks load centers. r ·. -· .~-· ./ I' ) ... ; Tl ~ .) • . MUN'I LU1 JATA AN\;li Lli~ I\ ~ lN ARE _____.. TABLE 5.A HISTORIC ECONOMIC AND ELECTRIC POWER DATA ~· YEAR ITEM 1960 1965 1970 1975 1980 1982 State Oil and Gas Revenues to Genera 1 Fund $ 4.2 million 1 $ 16.3 million $ 938. 6 mill ion 2 $ 88.3 million $ 2,262.3 million $ 3~567.3 million State Geueral Fund Expenditures n.a. $ 82.7 million $ 188.6 million $ 453.3 million $ 1,172.8 million $ 4,601.9 million State Population 226,200 265,200 304,700 390,000 402,000 437,175 State Employment 94,300 110,000 133,400 197,500 211,200 231,984 Railbe1t Population 140,486 n.a. 199,670 n.a. 275,818 307,107 Railbelt Employment 3 n.a. 74,100 88,500 130,400 132,000 154)033 Railbelt Households 37,062 n.a. 54,057 n.a. 94,210 106,599 Rai1belt Electric Energy Generation Anchorage n.a. 369 GWH 684. GWH 1,270 GWH 2,109 GWH 2,443 GWH Fairbanks n.a. 98 GWH 230 GWH 413 GWH 443 GWH 491 GWH Total n.a. 467 GWH 914 GWH 1,683 GWI4 2, 552 GWH 2, 934 GWH Railbe1t Peak Demand~ n.a. n.a. n.a. 412 MW 539.8 MW 566.1 MW Railbelt Generation Capacity - Sources: MAP Model Data Base; Federal Energy Regulatory Commission, Power System Statement; Alaska Power Administration, Unpublished 1 Printouts, 1983. 2Figure is for 1961. 3This figure is unrepresentatively high due to collection of a large petroleum lease bonus. 4Excludes agrii!ult.ura1 workers and self-employed. 5 Figure is for 1976. Sum of demand in Anchorage and Fairbanks load centers. r·, -,.,-. l , ... ) ('~ I . jl t ·i HONTH January February Harch April May June July August September October November December ANNUAL January February March April May June July August September October November December ANNUAL Source: 1976 159,858.2 151,762.5 145,974.8 126,643.7 117,248.7 102,593.1 108,065.7 110,754.4 120,765,2 144,349.4 153,121.6 172,488.7 ------------ 1,613,625.9 293.1 283.7 254.0 220.4 198.8 186.4 193.9 197.7 218.0 277.7 276.2 311.0 ----·- 311.0 TABLE S.B MONTHLY LOAD DATA-ANCHORAGE/COOK INLET AREA 1976-1982 Y E A R 1977 1978 1979 NET ENERGY (MWH)l/ 1980 1981 163,954.7 197,400.8 209,892.8 221,441.8 198,497.8 143,259.8 167,367.8 209,991.8 181,968.2 186,812.3 164,469.6 172,893.1 , 183,731.1 188,083.2 186,258.4 142,019.6 149,718.6 162,344.2 155,413.5 169,546.4 131,512.2 140,590.7 145,503.9 150,250.3 152,926.4 116,392.9 129,373.5 131,182.0 137,020.4 146,692.3 113,375.0 131,730.1 136,025~1 140,791.6 151,730.6 121,972.4 .iJ1,737.0 137,401.0 143,143"3 157,966.3 134,941.0 139,303.2 141,043.1 151,731.5 165,375.5 158,473.0 168,69°.5 169,443.8 176,803.0 195,024.1 194,791.5 191,300.9 179!1036.5 202,880.3 216,854.0 215,530.2 208,541.0 237,981.0 259,893.3 240,487.8 ------------------------------------------------· .. ·------ 1,800,691.8 1,928,656.2 2,043,576.2 2,109,420.6 2,168,171.9 PEAK DEMAND (MW) 288.4 341.3 357.8 399.4 " 351.8 269.5 328.6 395.1 337.2 377.0 283,0 296.6 339.5 321.9 324.9 26 1 .• 7 270.3 268.1 266.9 307.3 2r.:4 o 6 239.8 232.7 247.7 272.5 208.7 228.6 231.1 234.3 273.4 203.3 227.4 217.1 224.2 280.1 216.3 236.6 219.5 240.8 275.9 253.3 253.1 244.8 259.2 309.7 293.0 312.1 287.4 310.6 349.9 344.1 353.2 316.2 349.7 401.3 375.4 382.8 391.1 444.4 444.7 ------------------------- 375.4 382.8 395.1 444.4 444.7 Aiaska Power Administration, unpublished printouts, 1983. 1/ Includes purchases from Alaska Power Administration • ....... r) J ' I ·-I ' .l ) } 1982 264,468.6 219,800.8 215,098.6 191,709.2 175,709.1 162,177.2 165,315.6 168,632.4 175,021~4 220,744.2 234,249.6 249,739.9 ----------- 2)442,666.7 471.7 4.40 .4 391.5 365.2 303.6 291.4 290~6 298~9 348.4 429.1 445.2 450.9 ----- 471.7 ',.',~ I l l I I I 1 UTILITY 1976 ' Anchorage Mun L&P 444.9 Chugach E lee. Assoc. 1,054.5 AK Power Admin. 118.0 Anch Cook In-118.0 let Subtntall 1,617.4 Fairbanks Mun Util. 123.3 Golden Valley Elec. Assoc. 344.7 Fairbanks Area Sub-totall 468.0 Railbelt Total 2,085.04 TABLE 5.D NET ELECTRIC POWER GENERATION BY UTILITY 1976-1982 Units --Gigawatt Hours YEAR 1977 1978 1979 1980 420.3 443.1 473.1 486.6 1,179.7 1,308.6 1,401.0 1,434.1 203.6 180.1 171.1 184.3 203.6 180.1 171.1 184.3 1,803.6 2,931.8 2,045.2 2,105.0 128.5 124.7 124.7 125.6 353.5 341.5 322.9 317.7 481.7 466.2 447.6 443.3 2, 284 .. 3 2,398.0 2,492.8 2,548.3 Source: Alaska Power Administration, Unpublished Printouts, 1983. 1 subtotals and total shown may differ from column totals due to rounding. '" ,• '· 1981 1982 485.3 579.5 1,467.7 1,718.4 222.7 147.9 222.7 147.9 2,175.7 2,445.8 126.1 140.7 316.9 350.3 I 443.0 491.1 2,518.7 2,936.9 } (, (J II , ::; J ' ,_ ~ ... o~'~ I I i ' { MONTH 1976 January 55,675.0 February 53,313.3 March 43,844.4 April 34,468.6 May 29,811.4 June 27,063./ July 28,328.5 August 28,754.2 September 31,311.0 October 40,298 .. 2 November 42,801.7 December 53,334.5 -------"---- ANNUAL 468,004.3 January 101.0 February 99.6 March 81.8 April 64.9 May 54.8 June 49.7 July 54.1 August 52.9 September 60.0 October 82.1 November 84.5 December 97.3 ----- ANNUAL 101.0 TABLE 5.C MONTHLY LOAD DATA-FAIRBANKS AREA 1976-1982 YEAR 1977 1978 1979 1980 NET ENERGY (MWH)!/ 47,753.3 52,380.1 49,177.2 50,037.5 41,115.2 45,326.6 50,532.3 38,093.0 46.,759.5 45,014.9 42,322.0 38,220.1 37,698.3 36,384.6 35,415.1 32,784.3 32,446.1 32,195.9 29,781.9 30,943.3 28 787.6 29,783.1 28,091.9 28,015.3 28,921.0 30,184.2 29,743.5 30,405.5 30,765.5 30,793.2 29,058.6 30,378.0 31,474.5 32,455.1 31,404.4 32,232.7 41,307.6 40,106.7 36,280.0 36,084.3 53,609.9 44,186.7 37,400.1 40,606.1 61,015.7 47,394.9 48,370.1 55,500.7 -------------------------------------------- 481,654t2 466,206.0 447,577.1 44.3,301.3 PEAK DEMAND (MW) 87.9 95.8 89.2 95.2 87.3 94.7 100.7 75.4 86.0 81.8 81.3 70.3 72.7 70.9 65.6 60.4 60.2 58.1 56.5 55.8 56.3 57.9 53.9 54.2 54.5 55.3 55.8 55.8 55.6 55.3 56.9 59.4 65.4 62.8 60.0 61.0 79.2 72.3 66.8 70.8 102.3 86.1 72.2 7~.6 117.5 83.5 87.6 :;~.J.4 -------------------- 117.5 95.8 100.7 95~4 Source: Alaska Power Administration, unpublished printout, 1983. !/Includes pur chases from Alaska Power Administration. 1981 1982 42,057.2 53,931.0 40,303.0 45,022.0 37,927.8 l•3 '698. 0 35,262.8 38,743.0 32,286.2 35,379.0 30,163.7 32,428.0 30,264.8 34,449.0 30,301.7 34,308.0 33,661.8 35,637.0 39,271.0 42,846.1 41,647.1 45,771.0 48,820.3 49,885.0 ---------------------- 442,967.3 491,097.0 79.8 94.4 88.1 91.6 68.1 82.0 65.4 72.8 64.6 67.0 59.5 62.9 58.6 61.7 61.0 70.7 65.9 69.8 72.1 82.1 77.6 89.4 93.1 89.1 ----·------ 93.1 94.4 r:) ,. ~--·-c r .. ..) -- 5.3 -Forecasting Methodology The purpose of this section 1s to present the methode logical framework used for the forecasts of economic conditions and electric demand in the Railbelt. The first subsection discusses the main ways that world oil prices can affect the need for power. Next, the models used for forecasting purposes are identified and fully explained. Finally, model validation is discussed for the economic model (MAP) and electric demand model (RED). 5.3.1 The Effect of World Oil Prices on the Need for Power World oil prices affect the need for electric power in the Railbelt in four basic ways, each of which is explicitly taken into account in forecasting energy and loads. First, higher world oil pr1ces produce higher levels of petroleum revenues to the State of Alaska, mainly through production taxes and royalty payments that are tied directly to t:he market price of petroleum. Because of the importance of state revenues and spending to the Alaskan economy, changes in the world price of oil have a significant effect on general economic conditions and the rate of growth in the demand for electric power in the Railbelt as well as the / """ .) l.-.... state as a whole. This relationship was considered 1n the econom1c analysis and was factored into foreeasting demands for electric energy. Second, world oil prices affect the degree to which. oil and other fossil fuels may be substituted for electricity in certain applications. Inter-fuel substitution ~r.J its effect on the demand for electricity was explicitly considered in the load for ects ting analysis for the Susitna Hydroelectric ProjeL;t. The third effect that world oil prices has on the need for power lies in their impact on the cost of power generation. Since much of the electricity used in the Rai lbel t is generated using fossil fuels, the price of electricity to the consumer will be affected by the world price of oil. As long as fossil fuels fire a substantial portion of the Railbelt's generation facilities, higher world oil prices will lead to higher electricity prices, decreasing the overall demand for electricity. The cost of fossil fuels in generating electricity is a principal factor. It has been considered in the economic and financial analyses associated with determining the most cost-effective system for meeting the Railbelt' s future electric power demand, the future cost of electricity to the ultimate consumer and consequently, the demand for electricity. .. ' . '! . .. _jJ ... •• ~._..,.,_._.,,,,._~,., __ , __ ,~,,,o<• .~_..w,~~.--..... ._., f ::.' l ..... _ ... ]!": ·~· TO ~ T "< • ,. The fourth effect that we.: ld oil pr~ces have on the need for power occurs through the influence that petroleum prices have on the profitability of exploration and development of petroleum reserves in Alaska. Higher world oil prices provide an incentive for higher levels of oil exploration and development, which in turn leads to higher levels of . . employment and gross output in the petroleum sector as well as support sectors such as tr anspor tat ion, construction, and services. The economic development and population growth associated ·w-ith such activity increases electric power demands in th~ Railbelt as well as other parts of Alaska. However, the economic analysis conducted as part of " forecasting the demand for electric power relied upon a single set of exploration and development projections because of the uncertainties associated with the discovery of economically developable fields and the lengthy lead time required to develop oil fields in Alaska~ The following sections describe in some detail the ways in which world oil price:s were considered in the economic and load forecasting analyses and generation expansion planning. ' .~· ' 1 /r (\ '' / 5.3.2 Forecasting Models 6/i/83 5.3.2.1. Model Overview Four computer-based and functionally interrelated models were used in projecting the market for electric power in the Railbelt and evaluating alternative generating plans for meeting electric power demands. First, a model entitled PETREV, operated by the Alaska Department of Revenue> was utilized to project state revenues from petroleum production based on alternative future petroleum prices. The revenue projections from PETREV and numerous other economic and demographic data were then used by the Man-in-the-Arctic Program (MAP) Model to forecast economic conditions, including population, employment, and households, tor the Railbelt. The MAP model is operated by the University of Alaska.'s Institute of Social and Economic Res.earch. The economic projections, along with electric power end use information, electricity demand elasticity functions, and other electric power data then served as input to the Railbelt Electricity Demand (RED) Model to project demand for electric energy and peak loads in the Railbelt by load center. Finally, the Optimized Generation Planning (OGP) model was used to develop the most cost effective generating plans for meeting projected power requirements. The relationship between the models and their principal input and output data are shown on Figure 1. Figure 1 also shows - . ...,. .. t the role of financial analysis in the selection of the final generation expansion plan. Figure 1 illustrates the. parameters and variables that are common to different models and the interdependency of the models. While the planning process moves generally from the PETREV model through the MAPs RED, and OGP models, there are instances where output from one model is fed back into a previous model. For example, electricity prices are first estimated and used in the RED model to compute e· ectric energy projections. These projections are then used by the OGP model to develop a generation expansion plan and the associated cost of electricity. If there is a signiticant difference between the estimated and computed data, the models are rerun. The followfng sections summarize each of the four principal models, including their respective submodels and modules, key input variables and parameters, and primary output variables. Additional information on the MAP model may be found in Appendix B-3, which presents a detailed description of the model including a complete listing of its equations and input variables and parameters. Appendix B-4 presents similarly detailed documentation of the RED model. ~l·.-·· ·~• 'w"-•-~.M~~~--...~..,_,k,_...,.__,..., __ :--"·..-.,, _jl . ' . 5.3.2.2. PETREV PETROLEUM REVENUE FORECASTING MODEL State petroleum revenues currently constitute approximately 85 percent of total state revenues. For this reason, and because state revenues and expenditures are important determinants of future state economic conditions, state petroleum re~enue projections are generated by a specialized model, PETREV, operated by the Alaska Department of Revenue (DOR). PETREV is structured to take into account the uncertainties associated with forecasting petroleum rev~~nues. Using PETREV, the DOR issues revised petroleum revenue projections on a quarterly basis, using the most current data available on petroleum production, world oil prices, tax rates, regulatory events, natural gas prices, and inflation rates. PETREV is an economic accounting model that identifies sources of state petroleum revenue, examines the factors that influence revenue levels, projects alternative values for those factors, and relates those factors to the sources of state petroleum revenues f-rom pro(J.uction taxes and royalties. The principal factors influencing the level of petroleum revenues are petroleum production rates, mainly on the North Slope, the market price of petroleum, the costs associated with moving the petroleum from the wellhead to market, petroleum quality differences, tax and royalty rates applicable to the wellhead value of petroleum, and regulatory l 1 l&~k .. ,. ~' . '' t ~ . J factors affecting any of the other factors. Wellhead value is estimated by a netback approach whereby the costs of processing and transporting the crude is subtracted from the market value at its destination on the West Coast or Gulf Coast of the United States. A change in thf.;. market pr1ce of petroleum of a g1ven per cent age has a greater per cent age impact on state petroleum revenues. This occurs because the costs of transportation and processing are relatively stable, so the wellhead price, on which state petroleum revenues are based, rises and .falls almost dollar for dollar with world oil prices, producing a larger percentage effect on the wellhead value. Due to the many uncertainties involved in forecasting revenues, the forecasting model projects a range, or frequency distribution, of state petroleum revenues by year, so that for eac.h year a forecasted petroleum revenue figure may be se.lected based on a given cumulative frequency of occurrence. The model accomplishes this by iteratively seleLting a sec of input data from among the alternative input variable values and computing a petroleum revenue figure for each time period. Each projection is computed using a set of accounting equations that simulate the generation of petroleum revenues from each state oil and gas lease for each time period. By selecting the average value - -~-···-· .......... ~ ·--·~·'-'-"-· ··"-·< -····· ·. r-··-~.==;....··-~. ···-. -------~,1JS:46 (II ... of all input data the model produces an aver age petr ole.tnn revenue forecast. Petroleum Revenue Sensitivity Accounting Model Because of the uncertainties 1n projer,.ting petroleum prices and their importance in developing alternative generation plans and load forecasts, it is necessary to examine the implications of several different world oil price projections in addition to the price projections developed by the DOR. This need is accommodated by DOR through a petroleum revenue sensitivity accounting model. This sensitivity accounting model which is in effect a submodel of the PETREV model, utilizies the accounting equations and average values for all input variables other than world oil prices from PETREV, to compute an adjustment to PETREV's average petroleum revenue forecasts based on different assumed world oil price forecasts. By executing the sensitivity model with the alternative petroletnn price projections, alternative petroleum revenue projections are developed for use in the MAP model. Most of the petroleum revenues are available for state expenditures for operations and capital construction. Twenty-five percent of state royalties are, by constitutional ~· . -. .) provision, provided directly to Alaska's permanent fund. The process of projecting state petroleum revenues and the functions of the PETREV model are ~esented in some detail in the quarterly report entitled 11 Petr oleum Production Revenue Forecast. 11 (Alaska Department of Revenue, March 1983). The petroleum revenue projections used in ~eparing the electric power market and economic forecasts are based on the March 1983 average expected values of all factors, including petroleum production, other than petroleum prices. While production rates can be estimated with reasonable accuracy for the next decade because of the long lead time required to put a field into producticn in Alaska, higher world petroleum prices could be expected to result in higher levels of exploration and development and, by the 1990's, higher levels of production. Production rates from the North Slope, the source of most state production taxes and royalties, are projected to be approximately 1.6 million barrels per day (MMB/d) in 1983, to peak at nearly 1.8 l1MB/d in 1987, and to steadily decline to .7 MMB/d in 1999 (Alaska Department of Revenue March 1983). The petroleum production projections assume continued production from operating fields, pr educt ion from fields now being developed, and modest levels of production in the 1990's from new fields (Alaska De.par tment of Revenue March 1983).. The difference between petroleum revenue projections would be greater if diffe~:ent petroleum production levels were assumed to occur due to higher petroleum prices. 5.3.2.1 Man-in-the-Arctic Program (HAP) Economic Model The MAl, model is a computer-based econom~c model that simulates the behavior of the economy of the state of Alaska and each of twenty regions of the state corresponding to Bureau of the Census divisions. The Railbelt consists of s~x of those regions: Anchorage~ Fairbanks, Kenai-Cook Inlet, Matanuska-.. Susitna, Seward, and S .E. Fairbanks. The model, which is in the public domain, was originally developed in 1975 by the InstitutE! of Social and Economic Research of the University of Alaska, under a grant from the National Science Foundation. The model has been continually improved and updated since it was origially written, and has been used in numerous econom~c analyses such as evaluation of the economic effects o£ alternative state fiscal policies and assessment of economic effects of development of out~ continental shelf petroleum leases. An important application of the MAP model has been in providing economic forecasts in support of electric demand forecasts. It nas been used since 1980 1n preparing economic forecasts in support of planning and design for the Susitna Hydroelectric Project. The MAP Model Technical Documentation Report, prepared by the Inst1tute of Social and Economic Research, presents a detailed description of the model, including model logic, the historic economic conditions on which the model is based, the complete economic forecasts used in electric power market forecasting, input variables and parameters, the operation of sub-models, sensitivity tests, mcdel validation, and use of the model. The tP.chni cal documentation report allows the reader to reproduce the forecasts prepared for the electric power market forecasts and to make certain changes in economic or policy assumptions to determine the effect such changes would have on econom1c forecasts. However, while the technical documentation report does permit the reader this capability, execution of the model by persons unfamiliar with its logic and specifications would be a tedious task. A more expeditious means for testing the effects of modifying assumptions or input parameters would be to have the model executed by ISER using the user's assumptions. Additional background information on the MAP model may be found in Volume 9 -Alaska Economic Projections for Estimating Electricitv Requirements for the Railbelt, the Railbelts Battelle Pacific Northwest Laboratories, September 1982. ,.;w;qw. Map Model Submodels The MAP model functions in effect as three separate but linked sub-models, as illustrqted 1n Figure 5-~. The scenario genera tor sub-model enables the user to quantitatively define a scenario of development in exogenous industrial sectors; i.e., sectors whose development is basic to the economy rather than supportive. Examples of such sectors are petroleum production and other m1n1ng, the federal government, and tourism. The scenario generator sub-model also,.. enables the user to implement assumptions concerning state revenues from petroleum production. The statewide economic sub-model develops projections of numerous economic and demographic factors based on quantitative relationships between elements of the Alaskan economy such as employment in basic industries, employment in non-basic industries, state revenues and spending, wages and salaries, gross product, the consumer price ind~x, population, and housing. The regionalizati0n sub-model enables the user to disaggregate the statewide projections to each of the 20 separate regions of the state, using data on historical and current economic conditions and assumptions concerning basic industrial development. ·~-... -· Each of the three MAP sub-models exists as a computer program, and each program is supported by a set of input variables and parameters. Each of these programs and the supporting input variables and parameters are discussed briefly in the following sections. Detailed information on each sub-model, including a complete listing of the model and the input variables and parameters used in executing the model, is provided in the MAP Model Technical Documentation Report. Scenario Generator Sub-Model In order to operate the MAP model, the user must make a. number of assumptions concerning the future development of basic industries in the State. Such assumptions are needed because the state economy is driven by interrelated systems of endogenous and exogenous demands for goods and services. Endogenous demands are generated by the resident population and industries that serve that population. Endogenous demands and economic development stemming from such demands are forecasted by measuring and extending the relationships between economic and demographic factors and incorporating discernable trends. Exogeneous demands originate outside Alaska due to the favorable position o.f the state to export goods or services lj to other states or countries. In Alaska, exogenous demands stem from the state's natural resource base, especially petroleum, non-energy minerals, federal property, and tourist attractions. Exogenous demands lead directly to employment in basi~ sectors such as mining, and indirectly to employment and output in industries such as oil field services that support basic industry and industries such as housing and restaurants that support workers in basic industries and their families. The scenario genera tor model permits the user to select, from among a large number of alternative basic industrial cases, those cases that should be assumed for forecasting economic conditions in the state of Alaska and, for purposes of the Susitna Hydroelectric Project, the Railbelt. Cases are in the form of employment projections by sector and region of the state. The scenar1o generator model is also used to select the level of state petroleum revenues that should be assumed available to the state's general fund for expenditure on state government operations and capital investment. As indicated above, petroleum revenues constitute a large proportion of total state revenues which provide the basis for state expenditures, an important component of the Alaskan economy. 1 • .. ,ptM.""' ) . -I' • _i;'j'·zrDmt?WtMftWt""f' '1 7tfMtttit!5t!ii:o:'". Output from the scenario generator model for each of the six petroleum price cases is shown ~n Appendix K of the MAP Model Technical Documentation Report. Statewide Economic Sub-Model The statewide economic model is a system of simultaneous equations that individually and collectively define the quantitative relationships between economic and demographic factors in Alaska. The more than 1,000 equations in the model are made up of dependent variables whose values are computed by the model, input data from the scenario generator whose values can be expected to vary from one execution of the model to the next, and parameters, whose values are generally fixed from one model execution to the next. The equations are solved algebraically each time the model is executed to produce a unique set of values for the ,;::_ dependent variables, some of which are computed only incidentally as part of the mathematical process and others of which constitute projections of statewide economic conditions. While the equations in the statewide econom1c model are solved as a unit each time the model is executed, they are grouped for organizational and conceptual purposes - "- "dfllllllliCtn"HET'ftnztllll•• . 4 ,Q $114 . ·. :-.· ,:· .. into four modules: econom~c module, fiscal module, population module~ and household formation module. The equations in the econom~c module exprese relation- ships between economic factors such as employment in basic industrial sectors and output and employment in supper t sectors. Important products from the economic module include projections of employment and wages. The fiscal module computes the contributions that state expenditures are likely to make to the Alaskan economy. A separate module was created for this purpose because of the significance of state expenditures to the state's economy and the model's periodic application in estimating the economic effects of implementing alter- native state fiscal policies and assum~ng var~ous alternative future state revenue levels. This module plays a key role in examining the fis ca 1 and economic effects of different future world petroleum prices and state petroleum revenue levels. Specific assumptions concerning state spending are implemented in the fiscal module as state fiscal policy parameters~ which are discussed below. The population module expresses the relationships between population and economic factors recognized as key determinants of poputation. Such factors include employment, labor participation rates, fertility and 5 ! I . -.:. J7 I .- mortality rates, and unemployment and wage rate differentials between Alaska and the rest of the United States. ~ Equations in the household formation module express the relationship between the formation of households in Alaska and population by age group, sex, and race. Each age-sex cohort bas its own propensity to form households which, over the last few years has generally increased. This increase is expected to continue. Results from the statewide economic model for each of the six petroleum price cases are listed in Appendix M of the MAP Model 'technical Documentation Repo~-·t. Regionalization Sub-Model Statewide economic and demographic forecasts are disaggregated by the regionalization model, the third sub-model of the MAP economic model. Disaggregation is accomplished by combining statewide projections with regional. industrial development data from the scenario genera tor model and regional parameters based on historical economic and demographic relationships between each region and the state. This process produces projections by region or region group such as f3 -) -/r//" the Anchorage-Cook Inlet and Fairbanks-Tanana Valley . reg~ons. -Input Variables and Parameters As indicated above, input variables are factors whose values are provided by the user to the model and whose values can be expected to change from one execution of the model to the next. Parameter values are generally fixed during the course of successive model exeeutions. Input Variables Sixteen input variables are used by the scenario generator model to define the exogenous economic assumptions for each model execution. Of these 16 variables, listed in Table 5-l, 11 are used to define discrete industrial developments and are therefore region specific. The remaining five input variables are elements of state revenue forecasts. Estimates of future state petroleum revenue from state petroleum production taxes and royalties are obtained from projections generated by the Alaska Department of Revenue based, for purposes of the Susitna Hydroelectric Project, on alternative projections of world petroleum prices. The Institute of Social and Economic Research provides corresponding estimates of future state (t l i j , ... ·--»·. -·-·-·--·"·-· ..... _____ ~~-,-,.,._.---:: .. .,. ... ~~-,..."-··-.. --~r·· .... l !\ Siilt&eiQIQUC ... l , ................ ,__ :r lease bonus pay~ents, state petroleum property taxes, and state petroleum corporate taxes. In addition to factors regarded technically as input variables, several other factors may be varied from one MAP model execution to the next but are generally left con:s tant. These variable parameters include factors such as the U.S. Consumer Price Index and unemployment rate. Table 5-2 summarizes the principal assumptions behind the selection of basic industry, government employment, and tourism input variables for the base or most likely scenario, as well as key national economic assumptions. Additional· information on input variables and assumptions is provided in Appendix K of the MAP Model Technical Documentation Report. Parameters The MAP model utilizes three types of parameters: variable state fiscal policy parameters, stochastic parameters, and calculated parameters. Variable state fiscal policy parameters are used primarily in the fiscal module to represent assumed relations hips between variables such as state revenues and expenditures. These parameters, which may be varied to reflect alternative state fiscal policies or events were left unchanged in preparing the electric power market forecasts for the Susitna Hydroelectric Project. The most important function of these parameters is to quantitatively define state expenditure and revenue policies. In projecting economic conditions for the Susitna Hydroelectric Project, the follmving assumptions were made: o state expenditures for operations and capital improvements in 1983 dollars will rise in proportion to state population as long as revenues can support this level of expenditure; this assumption is in accordance with a 1982 amendment to the Alaska State Constitution setting a ceiling on state expenditures; o when revenues frcrm existing sources cannot support expenditures at the constant real per capita level, earnings from the permanent fund will be made available for operating and capital expenditures; as revenues decline state spending priorities shift from subsidies to capital improvements; o when revenues from permanent fund earnings and other sources are not sufficient to maintain expenditures at the constant real per capita level, a state personal income tax will be reimposed at its earlier rate; ··r o when all of these revenue sources are unable to support expenditures at the constant real per capita level, expenditures will be curtailed s0 that th;ey will not exceed revenues. ~··::ochastic parameters are coefficients computed using regression analysis. They are used primarily in the economic module of the statewide economic model to express the functional relationships between economic factors such as employment, wages and salaries, wage rates, gross product, and other national and regional economic factors ,, such as unemployment and consumer price indices. Stochastic parameters are also used in the population module to express the relationship between population migration into and out of Alaska and wage rate and unemployment level differentials. Stochastic parameters are used where relationsips between variables can be defined with only a limited degree of certainty that a presumed relationship exists. Calculated parameters are generally calculated rates or other quotients, and are used primarily in the population and household formation modules and the regionalization model. Calculated parameters include factors such as percent population by age group and sex, persons per household, and percent heads of household by age and sex. Calculated parameters used in the regionalization model include factors such as per cent of state population, employment, and housing by region. Complete listings of model parameters are provided in Appendices G, H, and I of the Map Model Technical Documentation Report. -MAP Model Output Six sets of economic forecasts through the year 2010 were generated based on the six petroleum price and state petroleum revenue cases and other input variables and parameters described above. For purposes of generating economic projections in years after 1999, the last year for which petroleum revenue projections are available from the Alaska Department of Revenue, petroleum revenue forecasts were extrapolated to the year 2010 using rates of change observed during the 1 at t er 1 9 9 0 ' s • Specific factors used directly as input to the Railbelt Electricity Demand (RED) Model are the following: o population by load center, Greater Anchorage and Greater Fairbanks, by year 1981 through 2010; o total employment by load center by year; o total households in the state by age group of head of household -24 and under years of age, 25-29, 30-54, and over 55 -by year; ~ .. -.. o total households by load center by year; A complete set of these projections, along with Railbelt population and employment totals, state population and employment totals, state petroleum revenues, and general fund expenditures for each of the six petroleum price cases by year is provided in Appendix N of the MAP Model Technical Documentation Report. Projections of additional related economic factors are also included in Appendix N. r-, i . . .. 5.3.2.4 -Railbelt Elctricity Demand (RED) Model -· The Railbelt Electricity Demand (RED) Model ~s a econometric-end. use model that projects both electric energy and peak los£ demand in the Anchorage-Cook Inlet and Fairbanks-Tanana Valley load centers of the Railbelt for the period 1980-2010. The model was originally writ ten by the Institute of. Economic and Social Research (ISER) of the University of Alaska in for the Office of the Governor of Alaska. It was later modifi~d and expanded by Battelle Pacific Northwest Laboratories. Submodels of the RED Model The RED Model is made up of seven separate for interrelated modules, each of which has a discrete computing function within the model. They are the un- certainty, housing, residential consumption, business consumption, program-induced conservation, miscellaneous consumption, and peak demand modules. Figure shows the basic relationship among the seven modules. The model may be operated probabilistically, whereby the model produces a frequency distribution of projections where each projection is based on a different, randomly selected set of input parameters. The model may also be operated probabilistically, whereby only one set of forecasts is produced based on a single set of input variables. When operated probabilistically, the RED model begins by creating the Uncertainty Module, which selects a trial set of model parameters to be used by other modules. These parameters include price elasticities, appliance saturations, and regional load factors. Exogenous forecasts of pop~lation, economic activity, and retail prices for fuel oil, gas and economic activity, and retail prices for fuel oil, gas) and electricity are u&ed with the trial parameters by the Residential Consumption and Business Consumption Modules to produce forecasts of electricity consumption. These forecasts, along with the additional trial parameters, are used in the Program-Induced Conservation Module to simulate the effects of government programs that subsidize or mandate the market penetration of certain technologies that reduce the need for pow·er. This policy-induced component of conservation is in addition to those savings that would be achieved through normal consumer reaction to energy prices. The revised consumption forecasts of residential and business (connnercial, small industrial, and government) -- '"' I\.? . consumption are used to estimate future miscellaneous consumption and total sales of electricity. These forecasts and separate assumptions regarding future major. industrial loads are used along with a trial system load £actor to estimate peak demand. After a complete set of projections is prepared, the model begins preparing another set by returning to the Uncertainty Module to select a new set of trial parameters. After several sets of projections have been prepared, they are formed into a frequency distribution to allow the user to determine the probability of occurrence of any given laod forecast. When only a single set of projections is needed, the model is run ~n c.ertainty-equivalent mode wbereby, a specific default set of parameters is used and only one trial is run .. The RED model produces projections of electricity consumption by load center, sector, and 5-year interval. A linear inter pol at ion is per formed to obtain yearly data. This information may then be used by the Optimized Generation Planning Model to plan and dispatch electric generating capacity for each year. The remainder of this section presents brief descriptions of each module in the RED mode 1. Uncertainty Module. The purpose of the Uncertainty Module is to randomly select values for individual model parameters that are considered most subject to forecasting uncertainty. These parameters include the market saturations for major appliances in the residential sector; the price elasticity .'lnd substitute energy forms and cross-price elasticities of demand for electricity in the residential and business sectors; the intensity of electricity use per square foot of floor space iu the business sector; and the electric system load factors for each load center. D These parameters are generated by a Monte Carlo routine, which uses information on the distribution of each parameter (such as its expected value and range) and the computer's random number generator to produce sets of parameter values. Each set of generated parameters represents a Htrial". By runing each successive trial set of genera ted parameters through the rest of the modules, the model builds disstributions of annual electricity consumption and peak demand. The end points of each distributions reflect the probable range of annual electric consumption and peak demand, given the level of uncertainty. The Uncertainty Module need not be run every time RED is run. The parameter file contains "default" values of the parameters that may be used to conserve computation time. However, the forecast of electric power requirements for the Susitna Hydroelectic Project was done using the certainty equivalent option. The Housing Module. The Housing Module calculates the number of households and the stock of housing by dwelling type in each load center. Formerly, using exogenous state-wide forecasts of the number of households, pousehold headship rates by age, the age distribution of Alaska's population, and regional forecasts of total population, the housing stock module first derived a forecast of the number of households in each load center. Now the MAP model produces estimates of the number of households by census area so the RED model has been modified to directly accept the MAP regional forecast of the number of households. The Housing Module then estimates the distribution of households by age of head and size of household in each load center. Finally, it forecasts the demand for four types of housing stock: single family, mobile homes, duplexes, and multifamily units. The supply of housing is calculated in two steps. First, the supply of each type of housing from the previous period is adjusted for demolition and compared to the demand. If demqnd exceeds supply, construction of additional housing begins immediately. If excess supply of a given type of housing exists, the model examines the vacancy rate in all types of houses. Each type is assumed to have a maximum vacancy rate. If this rate is exceeded, demand is first reallocated from the closest substitute housing type, then from other types. The end result is a forecast of occupied housing '"·""" stock for each load center for each housing type ~n each forecast year. This forecast is passed to the Residential Consumption Module. Residential Consumption Module. The Residential Consumption Module forecasts the annual consumption of electricity in the residential sector. The Residential Consumption Module employs an end-use approach that recognizes nine major end uses of electricity, and a "small appliances" category that encompasses a large group of other end uses. For a given forecast of occupied housing, the Residential Consumption Module first adjusts the housing stock to net out housing units not served by an electric utility for each type. It then forecasts the residential appliance stock and the portion using electr icit.y, stratified by the type of dwelling and vintage of the appliance. Applicance efficiency standards and average electric consumption rates are applied to that portion of the stock of each appliance using electricity and the corresponding consumption rate to derive a preliminary consumption forecast for the residential sector. Finally, the Residential Con- sumption Module receives exogenous forecasts of residential fuel oil, natural gas, and electricity prices, along with "trial" values of price elasticities and cross-price elasticities of demand from the Uncertainty Module. It adjusts the preliminary consumption forecast for both short-and long-run pr~ce effects on appliance use and fuel switching. The adjusted forecast is passed to the Program-Induced Conservation and Peak Demand Modules. Business Consumption l'1odule. The Business Consumption Module .forecasts the consumption of electricity by load center for each forecast year. Because the end uses of electricity in the commercial, small industrial, and government sectors are more diverse and less known than in the residential sector, the Business Consumption Module forecasts electrical use on an aggregate basis rather than by end use. RED uses a proxy (the stock of commercial and industrial floor space) for the stock of capital equipment to forecast the derived demand for electricity. Using employment projections and a trend in square feet of commercial (and light industrial) floor space per employee, the module forecasts the regional stock of floor space. Next, econometric equations are used to predict the intensity of electricity use of a given J' "" J4¥ w . xi a level of floor space in the absence of any relative price changes. Finally, a price adjustment similar to that in the Residential Consumption Module iG applied to derive a forecast of business electricity ccnsumption, excluding large industria 1 demand, which is exogenously determined. The Business Consumption Module forecasts are passed to the Program-Induced Conservation and Peak Demand modules. Program-Induced Conservation Module. Becau~e of the potential importance of government subsidized programs in the market place to encourage conservation of energy and substitution of other forms of energy for electricity, the RED model includes a module that permits explicit treatment of government programs to foster additional market penetration of technologies and programs that reduce the demand for utility-generated electricity. The module structure is designed to incorporate assumptions on the technical performance, costs, and market penetration of electricity-saving innovations in each end use, load center, and forecast year. The module forecasts the additioal electricity savings by end use that would be produced by government programs beyond that which would be induced by market forces alone, the costs associated with these savings, and adjusted consumption in the residential and business sectors. Miscellaneous Consumption Module. The Miscellaneous Consu~ption Module forecasts total miscellaneous consumption for second (recreation) homes, vacant houses, and other miscellaneous uses such as street lighting. The module uses the forecast of residential consumption to predict electricity demand in second homes and vacant housing units. The sum of residential and business consumption is used to forecast street lighting requirements. '" - Peak Demand Module. The P~ak Demand Module forecasts the annual peak demand for electricity. The annual peak load fact2~s were based on historical Railbelt load patterns.-A two-stage approach using load factors is used. The unadjusted residential and business consumption, miscellaneous consumption, and load factors generated by the Uncertainty Module are first used to forecast preliminary peak demand. Next, displaced consumption (electricity savings) calculated by the Program-Induced Conservation Module is multiplied by a peak correction fact0r supplied by the Uncertainty Module to allocate a portion of electricity savings from conservation to peak demand periods. The allocated consumption saving~ arQ then multiplied by the load factor to forecast peak demand savings, and savings are subtracted from peak demand to forecast revised peak demand. Separate estimates of peak demand for major industrial loads are then added to compute annual peak demand for each load center. Input Data. There are five input data files to the RED model. The RDDATA file cont~ins output data of the MAP model, including load center population, households, and employment and state household by age group, and the real prices of fuel oil and natural gas, by load center and end-use sector. The RATE DAT file contains the real prices of electricity by load center and ened-use sector. These prices are deri:.·~d from the OGP results. The PARAMETER file contains the numerical values that describe the distributions of the parameters varied in the Uncertainty module. These vaiiables are: housing de~and coefficients; saturation rate of electrical applicances, floor space elasticities; short-term and long-term own-price and cross-price elasticities for electricity, fuel oil, and natural gas; and annual laod factors. The EXTRA DAT file contain s information on the annual electrical consumption and peak demand of large industrial projects. i/Two sources were utilized in this effort. The first was Woodward Clyde Consultant's 1980 study Forecasting Peak Electrical Demand for Alaska's Railbelt (Final Report), prepared for Acres American, Inc. The second was statistical series from 1970 through 1981 load factors by month for the Anchorage- Cook Inlet and Fairbanks-Tanana Valley load centers. r ··"' J " ·_; ' . . "-·-··------·-•.-·---·~-..• .:.r"\~'~· . . I C .. \\ . . ' •• ~· o0.~·~·--4 ___ , ••• _,.., .• eo~,...,__.W .. 4•' _,_ •• ,• ,-,_,. --• • , ..... ~-· o r---~riiiiiUf...__. .... l .. ····--r .. "'· ... , ) f• .. The CONSER DAT file contains information on the technical e ,· narket characteristics of conservation options, bot:n for subsidized and non-subsidized options. Up to 10 residential conservation options may be specified. Business sector conservation is handled as a single unit .. -Output Data The RED output report contains various tables generated by the program. The main tables are the following: o Number of households for each load center , forecast year (1980, 1985, ---2010), and type of housing (single family, multifamily, duplex, and mobile homes); o Residential appliance saturations for each load center, forecast year, and type of housing; o Residential use per household without price elasticity adjustments for each load center, forecast year , and app 1 iance category (small appliance, large appliance, and space heat); o Business use per employee with price elasticity adjustments for each load center, and forecast year; o Electric energy requirements for each load center, year, and category of consumption (residential, business, miscellaneous, incremental conservation savings, and total which includes large industrial projects); o Peak electric requirements for each load center and year. Additionally, more detailed information about the RED Model is available in Battelle Pacific Northwest Laboratories 1982, and . • • 5.3.2.5 -Optimized Generation Planning The OGP model was developed by General Electric Company (GE). The following description of the mod3} was extracted from the GE descriptive handbook.-The model combines the three elements of generation expansion planning system reliability, operating and investment costs and generation addition analysis. Figure 4 outlines the procedure used by OGP to determine an optimum generation expansion plan. The following paragraphs describe the reliability evaluation, the optimization procedure, and the production costing simulation. A description of the input and output files is also provided. l/General Electric Company, Descriptive Handbook, Optimized Generation Planning Program, March 1983. ! . \ The CONSER DAT file contains information on the technical and market characteristics of conservation options, both for subsidized and non-subsidized options. Up to 10 residential conservation options may be specified. Business sector conservation is handled as a single unit. -Output Data The RED output report contains various tables genera ted by the program. The main tables are the following: o Number of households for each load center, forecast year (1980, 1985, ---2010), and type of housing (single family, multifamily, duplex, and mobile homes); o Residential appliance saturations for each load center, forecast year, and type of housing; o Residential use per household without price elasticity adjustments for each load center, forecast year, and appliance category (small appliance, large appliance, and space heat); o Business use per employee wlth price elasticity adjustments for each load center, and forecast year; o Electric energy requirements for each load center, year, and category of consumption (residential, business, miscellaneous, incremental conservation savings, and total which includes large industrial projects); o Peak electric requirements for each load center and year. Additionally, more detailed informa.tion about the RED Model is available in Battelle Pacific Northwest Laboratories 1982, and . 5.3.2.5 -Optimized Generation Planning The OGP model was developed by General Electric Company (GE). The following description of the mod3} was extracted from the GE descriptive handbook.-The model combines the three elements of generation expansion planning system reliability, operating and investment costs and generation addition analysis. Figur~ 4 outlines the procedure used by OGP to determine an optimum generation expansion plan. The following paragraphs describe the reliability evaluation, the optimization procedure, and the production costing simulation. A description of the input and output files is also provided. l/General Electric Company, Descriptive Handbook, Optimized Generation Planning Program, March 1983. J • \ Reliability Evaluation. The user can specify one of three possible reliability criteria.: daily or hourly loss-of-load probability (LOLP), and per cent reserve margin. A LOLP of 1 day for 10 years was used. Generation Expansion and Production Costing Simulation. In OGP, the fuel and related operating and maintenance costs are determined by an hourly simulation of the system's operation. The basic sequential functions of the operational strategy are outlined in the followig six steps: o Determine load modification based on recogn1t1on of contractual purchases and sales (i.e., reflect firm contracts). o Schedule conventional hydro. o Schedule monthly thermal unit maintenance based on planned outage rates or specific maintenance periods. o Schedule pumped storage hydro or other types of energy storage. o Commit thermal generating units to serve the remaining loads based on economics or environmental factors, spinning reserve rules, and unit cycling capabilities. o Dispatch the generation based on relative production costs and environmental emissions specified by the user. The production simulation performed is for a total utility system or pool commitment and dispatch assumed to have an unlimited power transfer capability between areas or companies internal to the pool represented. The following paragraphs describe how OGP follows the six steps out lined above to determine production costs. It also discusses the commitment and dispatch of units with fuel or energy limits. The hourly loads are initially modified by OGP to consider the firm purchases and sales that exist between the area being studied and entities outside that area~ The power and energy available from any c0nventional hydroelectric project used in the simulation is divided into two types: base load and peak load. The base load energy that must be produced is accounted for by sub- tracting a constant capacity from every hourly load in the month as shown on Figure 6. This capacity value is referred to as the plant minimum rating. After this base load energy is used, any remaining energy available is used for peak shaving. In such situations, the pro- gram uses the remaining capacity and energy of the hydro unit to reduce the peak loads as much as possible. If -· ··~ ....... .. · rmrrrr:mru nm t : n • ontst · · r~· . any excess energy exists at the end of a month, a user-specified maximum storage amount can be carried forward into the next month. Maintenance schedules designed to account for planned downtime, due to activities such as repairs or refueling, are developed by OGP for each generating unit based on user-specified planned outage rates. The peak loads are examined throughout the year, and individual generating units are scheduled in an attempt to levelize the peak load plus capacity on maintenance throughout the year. The system operating conditions involved when pump- storage hydro or other energy storage devices are available must also be considered. Energy storage scheduling algorithms have been included in production costing programs for some time. Although usually referred to as pumped-storage hydroalgorithms, .they have been utilized to study other energy storage devices on electric utility systems such as batteries and thermal storage. After modifications for contracts, hydro, and energy storage operations have been made, the remaining loads must be served by the thermal units on the system. The cost characteristics of thermal generating units are modeled using a single incremental heat rateo Specific unit operating costs are determined by the fuel input curve, fuel cost, and variable O&M cost. Specific unit operating costs are determined by the fuel input curve, fuel cost and variable O&M cost. In order to minimize the thermal generating unit operating expense of a power system, two fundamental objectives must be met: (1) the number of units committed each hour should be minimized, subject to the commitment policy and operating constraints of the power system, and (2) the generating units in each commitment, as determined for the first objective, should be dispatched on an equal incremental cost basis. ~ ... , J ...; _. / -.......; The dispatching function loads the incremental sections of the connnitted units in order to serve the demand at minimum system fuel cost. This dispatch technique is referred to as the equal incremental cost approach (or minimum incrementai cost approach). The incremental loading sections are dispatched beginning with the least expensive unit. When enough incremental loading sections have been scheduled Sy the load is served, the remaining unloaded incremental sections will be the most expensive. Thus~ the system spinning reserve margin is allocated to the generating units so system fuel costs ate minimized. At this point, loading level estab- lished, the hourly energy disposition is scheduled, and the hourly production cost is determined for each unit. -Input Data There are two major input files to OGP: the Generation file and the Load file. The Generation file model is created for use as a data base representing the in-service and on-order generating units. For each unit, the following characteristics are described: o Type of generator o Unit sizes and earliest serv1.ce year allowable o Unit costs o Fuel types and costs o Operation and maintenance costs o Heat rates o Connnitment minimum uptime rule o Forced outage rates o Planned outage rates The Load file is specified by the user to represent peak and shape characteristics which ar,, ~:rejected to occur for the years inc 1 uded in the OGP study. The user supplies the following load shape data: o Annual peak and energy demand o Month/annual ratios o The 0%, 20%, 40%, and 100% points on the peak load duration curve, by month o Typical weekday and weekend-day hourly ratios by month -Output Data Output options have been designed and included in OGP to provide the user with flexibility in the level of detail and volume of documentation received. Complete batch output reports as well as summary outputs are available. 71 (' AtrSt=z :twt Cr:rs t wm-hnm r , , The output available from the OGP program includes the following information: o Listing of the input data~ o Standard tables, as defined by the user, for various unit characteristics. o Listing of the unit types and sizes available for optimization and their character is tics. o Listing of the Load file for the study period. o Listing of the generating units on the system and their character is tic.s. o Year-by-year summary of the firm contracts input by the user. o Production simulation summaries, listing all of the generating units of the system with their energy output, fuel and O&M costs, fuel consumption, and environmental emissions. These summaries can be obtained on a monthly or annual basis, for all the decision passes or just the optimum system. o Summary of all the expansion alternatives, with their associated costs and reliability measures, evalauated during the optimization. o Summaries of the final system expansion through time and the associated costs. ··r 1 $( '-' ( )_; I (c) Development of Alternative Planning Scenarios The purpose of this section is to trace the alternative assumptions of key variables and particularly the effect of those concerning world oil prices through the model presented in Section 1 and the process outlined on Figure 2. The variables discussed in this section are identified by a letter in parenthesis. These letters correspond to those shown on Figure 2. Figure 2 is a network diagram which identifies the flow of world oil price scenarios through the planning process indicating branches where other parameters are varied. Wo~ ld Oil Price The most significant variable affecting the power market forecasts and the economic and financial feasibility of the Susitna Project is the world oil price (A). The base year world oil price in 1983 is taken at about $29 /bb 1 but several different oil price paths are assumed over the period 1983 through 2010 depending on the forecast adopted. The overall escalation rates for each of the forecasts identified in Section (b) are as follows: 1983-2010 Source Escalation Rate (%) SHCA-base case 3.65 SHCA-NSD 2.01 FERC +2 2.0 FERC 0 0 FERC -1 -1.0 FERC -2 -2.0 All six forecasts will be carried through the planning process to the output of the RED model. Because of the many variables and alternatives which are examined at various stages during the planning process, it has been decided to limit the number of assumed world price of oil projections from six to one for the OGP model and the financial analysis, specifically, SHCA's oil price projection has been adopted. PETREV and MAP Models In general, the future movement of world oil prices would affect the development of new fields and production rates, and DOR has considered this relationship in their model. Therefore, petroleum production variables (B) corresponding to each world oil price assumption case are considered although the impact on petroleum production might be insignificant in terms of the PETREV projections. . 'std1ifS!T?'F?W:r T1ttc . n k:rw h. ··r. __ : 5.3.3 MODEL VALIDATION Both the MAP and RED models are used to simulate future conditions based on alternative assumptions concerning world and state economic conditions and electricity demand in the Railbelt. Measures that havB been taken to ensure that both models simulate economic and electricity utilization conditions and relationships as accurately as possible are summr ized below. 5.3.3ol MAP MODEL VALIDATION MAP Model Validation of the ¥~P Model has been accomplished using two separate but interrelated techniques. First, a standard set of statistics was computed for each of the stochastic parameters used in the MAP model equations. These statistics provide information on the expected accuracy of each coefficient and the probability that each coefficient expresses the correct relationship between variables. Second, the MAP model was tested to determine the accuracy with which it could simulate observed historical conditions. Stochastic Parameter Tests ~~ Stochastic parameters are, as indicated above, coefficients computed using regression analysiss a statistical procedure whereby the quantitative relationship between variables is estimated by one or more computed coefficients. Most of the equations 1n the economic module of the statewide economic model are computed using regression analysis~ In estimating coefficients using regressio~1 analysis a number o£ statistics are computed that indicate the accuracy of the coefficient and the overall efficiency of the equation in estimating the true value of the dependent variable. Among these statistics are t-values and correlation coefficients. They are used both in selecting the best independent variables for estimating a given dependent variable and in determining the expected accuracy of the final equation. Correlation coefficients, t-values, and several other statistics have been computed for each stochastic equation used in the MAP m.;,del. In each equation efforts have been made to obtain the highest possible values for these statistics in order to ensure that the model reflects actual economic relationships as accurately as possible. As a result of this effort all the coefficients used in the MAP model have a relatively high level of statistical significance. Statistics are listed by equation in the MAP Model Technical Documentation Report Appendix H. ---· p ' -JJ-) ,£ztttEretrm c· 'MT · -r ·m· r mao..... Simulation of Historical Economic Conditions Although the MAP model has been in use since 1975, analyses conducted for the Susitna Hydroelectric Project were the first applications of the model in long range projection of economic conditions. Previous applications of the model had been in analysis of economic effects of alternative state policiese It is not possible, therefore, to test the model's projection accuracy using old forecasts. However, the model's accuracy was tested by simulating historcal economic conditions by executing the model utilizing historical data and input variables. Table S-6 summarizes the results of simulation of selected historical conditions. The table shows that the MAP model reproduces historical conditions with reasonable accuracy. More complete results of this test are shown in appendices B and C of the MAP Model Technical Documentation Report. TABLE S-6 SIMULAT~ON OF HISTORICAL ECONOMIC CONDITIONS Factor -- Non-Agriculatural 1965 70,529 70,406 -123 -.174 Wage and Salary 1970 92/'465 88,837 -3,628 -3.924 Employment 1975 161,315 154,893 -6,422 -3 .. 981 1980 169,609 166,281 -3,328 -1.962 Wages and Salaries 1965 721 757 36 4.9 In Alaska -1970 1,203 1 • "I -69 -5.7 ,lJ!+- $million -nominal 1975 3,413 3,408 -5 -0.1 1980 4,220 4,083 -182 -4.3 Per sana 1 Income 1965 827 861 34 ·4.1 In Alaska -1970 1,388 1,309 -79 -5.7 $million -nominal 1975 3,455 3,372 -83 -2.4 1980 5,030 4,972 -58 -1.2 Results based on February 1983 execution of ~HAP Model. '"l .......... --... ---..c ~-·~·· 5.3.3.2 RED MODEL VALIDATION To be completed }) ,-· / / /..:::. -..l -Q . . ~RMiaiiiJIIICM.IIIJlllll ln-. \.'<' r 1 ,J l) 1 1 I' r 1.L ,. Fur,•c.Jst rr lc~ 1'rujC"C'llun~ -.. Fuel Oil Natural Gas .. Coal ----- Pt.THJ:\' .1nd So•ns 1 t 1 v 1 t \ Modt•l s RELATtONSHIP OF PLAHN!NC'HOOElS AND IlfPUT DATA -~--~ _,. Figure 1 r-------------------------------------------------------------State Fund Availability -·-~·---1 r-----------------------------------------------------~ FJ,nancing Planr~ ______ oinflat!on aat• ----~-------~-----------------------~----~ L..,. Pc:lrolcum Rev~nut's HAP HODEL EconC'm!c fort:~.ISt --) .---------P_r..,.ici! of Electricity 4-1 I I RED MODEL OCP !10D~:t. ---Energy --- Population I f.lectric I Gene rca ion toad . and Employment j Peak Load Economic forecast Households Optimization lr-,....-.. t- Optimum CapJci.t.I_ t"innn.:Ltl ,, tl••111l 1\.1 t t•s -Plans n L A1wl ys l !'-Expansion St> 1 ecrted Exp.tn:, ion l' l ;m L o fl~cAJ Spending tulc 1...--. o Discount Ratc--~o Extstinll, Generation Sygt~m o future Cener&tion Sy&tem ,, llhh•htt:JIIt•s~ Critt•ri<t o Higr~tion !::quat l•m lndu8 trial Deve lopl!M"nt.!l o ~~Re Rate Spcciflc~tlonH o A~e/Scx D1atr1bu~1nn Oa o Resident1al/8ustnes• End Use Data o Prict! Elutidt iel'l lei J.__ Coe!f1c1ents ~------------------------------------------Ij ~ o lndu8tr1al Load~ Fortcasts ----------·-------------------------·-~--------~--------------~ j .. -i._.,._ ... ~ .. . The~l Alternatives Coa 1-Ga:t Turbine~' -Ct''ll!lbJ nt•d C).: I,. Non-::••sitna Hydro Alternatives Chakach.1rnna/Bradley Lake/nternwl Sua1tna Hydro Alternatives ~at8na/De~11 Canyon/Therm3l \Jat an,f~·hennal Oevi 1 C•nyon/Thermal o Construction Cosl& o Op~rdtlon anJ Haintenanc~ o tteliabllity •nd Availability CritHl.l ---" .... ~-···~-....... --.""":"·--?"""""#~---.l.,:":t··¥ l .iii t I I I l I I I 5 I i .. t.i-'I' (.... ~; ~ • --' ' ,·.~ •; '-,~::_ >'t~'> c;.j,.·~ ·," ; .. . , • . . . . . .. 11 , '.''' ,.~, •••• <;,? ·~.;..;·,•, •. :.".· ··.·• ~, ·..... . . _· . . . _:;'\; u ·····• ··---·----lit!dtsit'tf't'* n-.'htv~,.,·, r h'ft'ne.·csilor.ihfit.i..;.,'bf'~, ~· .. ;;.>.ii!$i\iiMi"'..:',~d¥~-.... .;.-~.,.,':~!t:*·~--~c:.....-~~ TAuJ..E 5--j_. '·' \J1~r I tl l>,'l l'r ln.· .... ~o·u r ,•..:.as l .. ·-~ ---·---..... ____ -··-·- llELATlONSHIP Ot' PLAJftHNG' HODELS AND INPUT DATA '' --------·---- f'lgurc 1 State Fund Availability I r-------------------------------------------------------------------FJ,nancinst PlanA l't:THE\' anJ S•• ns 1 t 1 v 1 tv HllJt•ls ~oinflation Rate Lt.- P~lrolcum Revl'nucs .. HAP HODEl. --- /Economic t'·nrc~o:.ist ------------------------~----~ r--------------~P_r~ice of Electricity L., Population Employment -- Households _ ~ RED HODEL --- Electric Load Forecast Energy .. Peak Load -.... ~ OGP ~OD~:i. --- Genenn ion and EC'onomic Optimization ~ Opt lmum I CapJdlY Exp;m!-!ion Plans ,...- f'lnan.; La! Arwl y~: 1 ~ L--•' l\1•11d 1\,1( PI' Select~d Exp.tn~ ion l'lnn ,, lrhlt•htcJIIt'Sh Crltt!ri;l ...._ o fiscal Spending lul~ o Migration l:o:quati•m L--o Discount Ratc-L----o Existin~ Generation Systl!m o future GenerAtion Sy&tem • lh.•l rr leo! rruj('C't iun~ ___ .,._ Industrial Development~ o ~Rge Rate Spcclfic~llons o Resldenttal/Busines~ End Uae Data • Thermal Alternatives Colll-Ga:\ Turbines -CnmbJnt•d t:y.:I,• 5 ~ Fuel Oil :. Natural Gas C· Coal ii Ji !I ~ o ARe/Sex Distribution o Price Elasticitiet~ Da tel J_ Coefficients '" L----------------------------------------'1~ o lnduatrial Load J-. ... ' ... Forecast& __ _._ __________ __J Non-Susitn.1 Hydro Altcrnallves Chakach.1mna/Brad ley La~.e /TI1c rnwl Su•itna Hydro Alternatives ~atana/Pevil Canyon/Thermal t.lat ann /'.'hermal Devil C.anyon/Thcrmal o Construction Costs o Operation anJ Maintenance o Reliability .and Avalhbiltty Critl•ria -a LIST uF MAP·MODEL INPUT VARIABLES Employment in Basic (Exogenous) Industrial Sectors: Agriculture Mining High Wage Exogenous Construction (e.g. enclave type pipeline construction) Low Wage Exogenous Construction (e.g. office building construction) High Wage Exogenous Manufacturing (e.g. new oil refinery operation) Sectoral Average Wage Exogenous Manufacturing (all current manufacturing) Exogenous Transportation (e.g. pipeline maintenance) Fish Harvesting T0ur ism Number of Tourists Annually State Petroleum Revenues State Petroleum Production Tax Revenues State Petroleum Royalty Revenues State Petroleum Lease Bonus Payments State Petroleum Property Tax Revenues State Petroleum Corporate Tax Revenues TABLE 5-~ V"' SUMMARY OF EXOGENOUS ECONOMIC ASSUMPTIONS ( Exogenous Employment Assumptions Trans-Alaska Oil Pipeline System Prudhoe Bay Field Emp loyrnent· Upper Cook Inlet Petroleum Production Tertiary Recovery of North Slope Oil OCS Exploration and Development Anchorage Oi 1 Headquarters Beluga Chuitna Coal Production Hydroelectric Projects Operating employment remains constant at 1,500 through 2010. Construction employment developing Prudhoe Bay and Kuparuk fields peaks at 2,400 in 1983 and 1Q86. Operating employment remains at L,502 through 2010 for overall North Slope production . . Employment declines gradually beginning in 1983 so as to reach 50 percent of the 1982 level (778) by 2010. Tertiary oil recovery project utilizing North Slope natural gas occurs in early 1990s with a peak annual employment of 2,000. The current OCS five-year leasing schedule calls for 16 OCS lease sales subsequent to October 1982, including the Beaufort, Norton, and St. Gear ge Sales, which have already taken place (Sales 71, 57, and 70). Development is assumed to occur only in the Navarin Basin (1.4 billion barrels of oil) and the Beaufort Sea (6.1 billion barrels of oil). All other sales are assumed to result in exploration employment only. Several oil companies establish regional headquarters in Alaska in mid-1980s. Development of 4.4 million ton/year mine for export beginning in 1994 provides total total employment of 524. Employment peaks at 725 in 1990 for construction of several state-funded hydroelectric projects around the state. "T" .. - ~ -.... __ SUMMARY OF EXOGENOUS ECONOMIC ASSUMPTIONS Exogenous Employment Assumptions U.S. Borax Mine Greens Creek Mine Red Dog Mine Other Mining Activity . Agriculture For est and Lumber Products Pulp Mills Commercial Fishing-Nonbottomfish Gemmer cial Fishing-Bottomfish The U.S. Borax mine near Ketchikan is brought into production with operating employment of 790 by 1988. Production from the Greens Creek Mine on Admiralty Island results in employment of 315 people from ~986 through 1996. The Red Dog Mine in the Western Brooks Range reaches full production with operating employment of 448 by 1988. Employment 1ncreases from a 1982 level of 5,267 at 1 percent annually • Moderate state support results in expansion of agriculture to employment of 508 in 2000. Employment expQnds to over 3,200 by 1990 before beginning to decline gradually after 2000 to about 2,800 by 2010. Employment declines at a rate of 1 percent per year after 1983. Employment levels in fishing and fish processing remain constant at 6,323 and 7,123 respectively. The total U.S. bottomfish catch expands at a constant rate to allowable catch in 2000, with Alaska resident ·harvesting employment rising to 733. Onshore processing capacity expandi.J in the Aleutians and Kodiak census divisions to provide total resident employment of 971 by 2000. p , __ D -.J ·1·-....___,,,w I ... Jr.-"' . .) .. SUMMARY OF .EXOGENOUS ECONOMIC ASSUMPTIONS • •. Exogenous Employment Assumptions Federal Military Employment Federal Civilian Employment Tourism Assumptions National Variables Assumptions U.S. Inflation Rate Real Average Weekly Earnings Real Per Capita Incoree Unemployment Rate Employment remains constant at 23,323. Rises at 0.5 percent annual rate from 17,900 in 1982 to 20,583 by 2010. Number of visitors to Alaska increases by 50,000 per year from 680,000 in 1982 to over 2 million by 2010. Consumer prices rise at 6.5 percent annually after 1985. Growth in real average weekly earnings aver ages 1 per cent annually. Growth in real per capita income aver ages l. 5 percent annually after 1984. Long-run rate of 6 percent. l" 8 -.) -·/Ji~ 4#4< ;aes;;;:Q MAP MODEL SYSTEM FLOWCHART MODELS Scenario Genera tor Model Economic Scenaril"' J Statewide Economic Model * Economic Module * Fiscal Module r . * Population Module * Household Formation Nodule ~~-~~~------~ State Economic Forecasts - Regionalization Mo,del r-Gutput to L.!.ed Model - l' M*** ' DATA BASE Input Variables: * Industr ~ al Case Files * Petrolel!lm Variable Paramet:er s * U.S. Inflation Rate *U.S. Unemploy- ment Rate * Others Parameters: * Variable State Fiscal Policy Parameters * Stochastic Parameters * Calculated Parameters Calculated Parameters . '"'.I' ECONOMIC UNCERTAINTY FORECAST MODULE .... HOUSING ~ ~ STOCK .. .... :) ... ... RESIDENTIAL K ... 't=') .... --BUSINESS ~ ,.-I .... .... ... A --:> K :: CONSERVATION .... ~ ... \} INDUSTRIAL MISC. J ~ ANNUAL SAI.ES ~ {} ....._ <. ~ PEAK DEMAND ~ < .... RAILBELT ELECTRICITY DE~~ND (RED) MODEL INFORMATION FLO\VS 13-s-- EXHIBIT 4 I EVAlUATE EXHIBIT 5 .--;---""'~ I ~n~OAO I FORECAST ] r'--~G~E~~~;~:~TA~E~~~~O~N~___.] IL. ___ so__,T~ ..... -T_oA_v ___ ... ] EXISTING UNITS 8& HOURLY BASED PEAKS & ENERGIES ALLO\'VABLE TECHNOLOGIES EVALUATE RELIABILITY FUTURE ECONOM•cs !c OPERATING GUIDELINES ALL CHOICES \~JTH uLoOK·AHEAo·· I SELECT UNIT SIZES & TYPES l J STUDY ALL YEARS t fcALCULATE OPERATaNG & INVESTMENT COSTS 1 L USING ··LOOK-AHEAD". ~------~<----1--~----___. CHOOSE LOWEST COST ADDITIONS ,s, CALCULATE CURRENT YEAR'S COSTS • - RESULTANT OPTIMUM EXPANSION PATTERN -----OUTPUT · & DOCUMENTATION OF NEAR-OPTIMUM PLANS OPTIMIZED GENERATION PLANNING (OGP) MODEL INFORMATION FLOHS . /\1 , WEEKO~'( HOUR INITIAL LOAD EXHIBI'i' 6 WEEKEND CAY P 1 • MINIMUM RATING (MW) P • MAXIMUM MINUS 2-f MINIMUM RAnNG {M W) EXAMPLE OF CONVENTIONAL HYDRO OPERATIONS . -' - --·-··-··-···-----~-,'""-·-······----· ····--c:;······~r····-~·-·-· .. ·· ~·--·····--· .. --... ·--·~·-·--·~---..... __ ....... ~---·-~--""'~·--·---.. ·-··-····-·-··-·---~--~-......... -:~·-···~·-·~"'!:."'1':~ ~· ; iJ ttm·· . ' "' .,. -'-:... ' ~~~ ~ -,,' • ( 4 1 \ 5.4 Forecast of Electric Power Demand 5.4.1 Oil Price Forecasts Fort~casting the future world price of oil is uncertain and most previous forecasts have been lacking in accuracy particularly 0'~~7 er the last ten years when oil markets received radical upward price shocks. Some forecasts can be considered to be better than others, however, largely because of the methodology used, the exper1ence level of the forecasters, and the reasoning behind the forecasts . .,This category includes Sherman Clark Associates, Data Resources Inc., and the Energy Modeling Forum. The. forecasts by these entities as well as the forecasts by the Alaska Department of Revenue are presented and discussed in th.e following sections. It should be noted that all prices referred to are in 1983 dollars per barrel and all forecasts are assumed to start from a base price of $28, 95/bb 1 in that year. 5.4,1.1 Sherman Cl.ark Associates Sherman Clark has over thirty-five years of experience in the field of energy including twenty years with Stanford Research ( J -!/( I Institute as Director of Energy and Resource Economics. Sherman Clark Associates (SCA) prepares annually a detailed 25 -30 year forecast of the supply and demand £or energy and resulting, estimated prices. Table 2 shows ScA=s forecasts of crude oil and fuel oil in 1982 dollars. The SCA forecast prices for oil and coal prsently are for three scenarios to which probabilitites of occurrence have been P-Gsigned. SCA's latest scenarios are: Base Case. In this scenario, oil prices decrease from the existing 1983 price of $29.00/bbl to $26.30/bbl in 1983 dollars and remain at that level until 1989 when SCA has assumed a severe supply disruption will occur, causing prices to jump to $40.00. Prices will remain at $40/bbl until 1990. After 1990 the price would increase as follows: Price in Last Year Period. Real Price Increase ($/yr) of Period 1983/bbl) 1990-2000 3.0 53.76 2000-2010 75.75 2010-2020 1.5 87.80 2020-2030 0 0 2030-2040 0 0 -1·:·,£!~:-? .-~~·~~~~ :, :.)!( 1.~.... • ~ •• ' _... ::' 1·~>!..: ·_'::~,·~~-~ .. ,_.:3· . -;-, '='" ~--• ' The severe supply disruption would be an overthrow of the Saudi Arabian government by a radical element that would severely cut back on oil production or a war ivolving Saudi Arabia in which the ability to produce oil was severely damaged. SCA has assigned a 40% probability of occurrence to this scenario. No Supply Disruption Case. This case is similar to the Base Case, but no severe supply disruption occurs. In addition, there is an assumption that more Non-OPEC crude will be found and produced. Estimated prices drop to $26.30/bbl and remain there until 1989 when they rise at a real rate of 3%/yr to 2010, or a price of $50.39/bbl. After 2010 the pri-.:e would increase as follows: Price in Last Year Period Real Increase (%/yr) of Per i od ( 19 8 3 /b b l ) 2010-2020 2.5 64.48 2020-2030 1.5 74.84 2030-2040 1.0 82.66 SCA has assigned a 35% probability of occurrence to this scenario. Zero Economic Growth Case. This scenar~o assumes that there will be no economic growth until 1990. Consequently, prices drop to $17.00/bbl in 1985 and remain at that level until 1990 at which time they begin to rise at a real ratt of 5%/yr to year 2010. SCA has not extended this for2cast beyond 2010. SCA 11as assigned a 25% probability to this scenar~o. 5.4.1.2. Data Resources Incorporated (DRI) DRI is a well-known forecasting orga'ilization which provides forecasts of GNP, economic indicators, and commodity prices including prices for oil and coal. Extensive use is made of economic and other computer models including special energy forecasting models such as the DRI Drilling Model, DRI Coal Model and the DRI Energy Model. Worldwide supply and demand for oil are estimated to arrive at a forecast pric.e for oil. DRI 1 s spring 1983 forecast shows: Pe:riod 1983-1984 198·{j.-1985 1985-1990 1995-2000 2000-2005 2000-2005 · .. ~ Real Price Increase (%) -13.1 7.4 6.5 4.4 3.1 1.1 Price in Last Year of Period (1983 $/yr:) 25.17 27.02 36.99 45.85 53.43 56.54 DRI has not extended their forecast beyond 2005 nor have they formulated other scenarios nor assigned .a probability to its forcast. It therefore is assumed that its single forecast is the likely or most probable outcome. 5.4.1.3. Energy Modeling Forum (EMF) The EMF was created by the Electric Research Institute (EPRI) to improve the use and usefulness of energy models. The EMF is administered by the Stanford Institute for Energy Studies which is in the Department of Engineering Economic Systems and the Department of Operations Research. The EMF operates through ad hoc working groups of energy model developers and users. Each group is organized around a single topic to which existing models can be applied. One of the groups, with members from around the world, addressed issues relating to oil price, availability, and security of supply. The results of their study were reported in an EPRI publication entitled, World Oil.!/ The objective of the study was to analyze world oil issues through the application of 10 prominent world models to twelve ~/EPRI, World Oil, prepared by Stanford University Energy Modeling Forum, Principal Investigator , J. S <' Sweeney, EA-2L~47-SY, Summary Report, June 1982. r --· ' . ) -- !1 l ~ jJ l' .. I -~~."'_-"" __ ·_:. I I i ,, ' . . . : .\ scenar ~os designed to bound the range of likely future world oil market conditions. The ten models used are listed 1n Table 3. The twelve scenarios include a reference or base case which is not necessarily EMF's most likely case but rather is a plausible mean case which can be considered as representative of the general trends that can be expected. In gene:·l"al, EMF exp~cts a soft oil market for the 1980's with little or no real price increase until 1990 unless there 1.s a supply disruption. Beginning in 1990, real prices will increase over the next several decades in either steady upward movememts or in sudden price jumps followed by gradual declines. EMF's reference case shows the following median real price increases: Period 1983-1985 1985-1990 1990··2000 Real Price Increase (%/yr) 2.0 6.0 4.0 Price in Last iear of Price (1983 $/bbl 30.11 40. 29" 59.64 EMF does not extend their forecast beyond 2000. J.- ,. ]::,-•• ~ ....... --"',C~'' '--· ~--~--¥M"' ""'-'""" t? ;,"" ',""-1"" T ll : '" \" ... · ..,.----1$5 .,....._, £ .~ • .,_ •• ~~;A. . 1 . ........ .. The results using the ten models in the twelve scenar1os are a clustering in year 2000 of world oil price in the range of $50 -80/bbl, which brackets the EMF reference case. 5.4.1.4. Alaska Department of Revenue (DOR) The Alaska DOR prepared forecasts of world oil pr1ces to use as an input to their revenue mode 1. The revenue model provides an estimate of the quantity of revenue from oil and gas royalties and other sources that the state can expect co receive annually through 1999. The DOR' s oil price and revenue forecasts are updated quarterly, with March 1983 as the current forecast. The DOR arrives at its forecast of oil prices through the "Delphi" method which consists of questioning per sons knowledgable in the area of energy and oil and attempting to arrive at some sort of consensus of future oil prices. / 7 ... -.. -~t . • ,...-'"':'£ • ,'---.. · .... ~~·--.... ,-,~-----.. --... ,.~------,~~! ,-~.... ? The DOR March 1983 mean forecast projects the pr1ce of oil decreasing from $28.95/bbl in 1983 to $21.95/bbl in 1987, then gradually increasing at an average rate of 1.3 percent per yer to a 1999 value of $25.60/b'ol. 5.4.1.5. Selection of Oil Price Forecast The six (SCA(3), DRI(l), EMF (1), and DOR (1)) all price forecasts described above are shown on Table 1 and presented graphically on Figure 1. Also shown on Table 1 and Figure 1 are-four other oil price forecasts which show real growth rates from an 1983 base price of $28,95/bbl of +2, 0, -1, and -2 per cent per year, these forecasts are included as they will be used to develop power market forecast, described 1n Section 5.4.4 which will be used in economic sensitivity analyses presented in Exhibit D. The Sherman Clark Associates, Data Resources Inc., and Energy Modeling Forum forecasts are based on detailed anglyses of the supply of and demand for oil. All of these forecasts reflect the existing soft market for oi 1 that may continue for several years. However the forecasts also reflect the hir:, ... probability of a ·world economic recover.y from the 1981 - 193'2 recession and the resulting increased demand for oil. In add~tion, the forecasts reflect the fact that oil is a depletable resource and although there are some substitutes, eventually the dwindling world supply should result in higher real pr1ces barring some dramatic technological breakthrough. The DOR forecast of oil is developed by the "Delphi" method, i.e. by questioning var1ous knowledgable persons in the energy field and then using the predominate thinking of the group questioned to develop a forecast. This method depends heavily on the particular persons questioned and may be overly influenced by particular influential individuals 1n Alaska who believe in the imminent breakup of OPEC as the controlling force for the world price of oil. While OPEC appears to have lost some power in the last year, as evidenced by the drop in the official price of oil from $34/bbl to $29/bbl, an acc.:a-d between the OPEC members seems to have been r.eached concerning the quantities of oil produced so that the price appears likely to hold at $29/bbl. The economic recovery that is currently underway in the U.S., which will undoubtedly be followed by the rest of the free industrial world, should support the benchmark price eventually allow OPEC to increase the price as demand for oil 1ncreases. A zero or negative economic growth oil price scenario therefore seems unlikely and comparing the false starts in economic recovery of 1979 and 1981 when inflation was high and unemployment low with the current situation in which inflation is low and unemployment high would appear be erroneous. . -· ........... The most likely future oil pr~ce scneario should therefore lie somewhere within the forecasts of DRI, EMF, and SCA Base and no supply disruption cases. As can be seen on Figure 1, the DRI, EMF and SCA base case forecasts are similar through the years 2000. For the purpose of evaluating the economic attractiveness of the Project, a somewhat more conservative forecast should be chosen as the base case. According to SCA the NSD has a probability of occurance of 75 percent. The SCA No Supply Disruption (NSD) case was therefore selected as the base case. Th~ SCA base case would be used in sensitivity analyses to cover the higher range of forecasts such as the DRI and EMF forecasts. The +2, 0, -1 and -2 percent per year forecasts would be used to cover a range of oil price forecasts below the SCA-NSD forecast including the DOR forecast. Table 2 shows the base case and five sensitivity oil price forecasts for which power market and economic studies -r··ill be per formed. f2 -r ... J-;.....J 5.4.2 Other Key Variables and Assumptions Many variables and assumptions beside world oil pr1.ces are used in the models described in Section 5-3. Table lists these variables by symbol and name. Also listed on Table are the base case value of the variable and its source. Of these variables and assumptions, some have a greater influence on the power market forecasts than others. The following have been identified as key variables and assumptions other than world oil price: Model PETREV MAP Key Variable or Assumption None State Mining Employment State Active Duty Military Employment Tourists Visiting Alaska U. S. Real Wage Growth Rate Price Level Growth Rate I 1. I ~; / : ·. - Model RED Key Variable or Assumption . 1 . 1 I Reg1onal Popu at1on- Regional Household~/ Appliance Saturations Energy Consumption of Appliance Growth Rate of Appliance Consumption Own-price Elasticity Cross-price Elasticit) Region~l Employment!/ l/output from MAP model, petroleum price dependent variables Model RED OGP Key Variable or Assumption Electric Cons. Floor Space Elasticity Regional Load Factor 1/ .Fuel Costs- Fuel Escalation Ratesl/ Thermal Plant Cost Hydro Plant Cost Discount Rate These variables and assumptions are discussed in the appendix which describes each model. The sensitivity of the base case !-B~~,a~k&1pi~~ecaa~easeabpnjeaa~ielH~sua$uea issamesef~noaach of ,.--·, - 5.4.3 Base Case Forecast -Model Output The base case oil price forecast SCA's NSD forecast, was run through the series of forecasting models described in section 5.3. Table shows the output of the mode,ls for the following key variables: World Oil F-e ice Energy Price Fuel Oil N~tural Gas Electricity State Petroleum Revenues Production Taxes Royalty Taxes State General Fund Expenditures State Population State Employment Railbelt Population Railbelt Employment Railbelt Total Number of Households Railbelt Electrical Energy Demand Railbelt Peak Demand (MW) A comparison of this forecast to previous forecasts is presented in Section 5.5. 5.4.4 SENSITIVITY FORECASTS -MODEL OUTPUT The output of the models for the five (SCA Base and +2, 0, -1, and -2 percent) sensitivity forecasts are shown on Tables through _, respectively. - r , A comparison of this forecast to prev1.ous forecasts is presented in Section 5.5. 5.4.4 SENSITIVITY FORECASTS -MODEL OUTPUT The output of the models for the five (SCA Base and +2, 0, -1, and -2 percent) sensitivity forecasts are shown on Tables through _, respectively. ·- ··w:¥/6.~..10~ ·.~~ r l i : ! ' I ! I l l ! Symbol MAP MODEL EMAGRI EMP9 EMCNX1 EMCNX2 EMT9X EMMX1 EMMX2 EMF ISH EMGM EMGC .. , '~ TABLE VARIABLE AND ASSUMPTIONS Base Case Sensitivity Variable Vaiue Value Source Name State Agricultural Employment 1983 203 2010 740 State Mining Employment 1983 9,387 2010 16,282 State High Wage Exog.Const.Exp 1983 3,261 2010 1,056 State Low Wage Exog.Const.Exp. 1983 290 2010 0 State Exog.Transportation Exp. 1983 1,552 2010 3,279 State High Wage Manufac. Emp. 1983 0 2010 0 State Low Wage Manufac. Emp. 1983 10,433 2010 11,617 State ]'ish Harvesting Emp. 1983 6,421 2010 7,096 State Active Duty Military Emp. 1983 23,323 2010 23,323 State Civilian Federal Emp. 1983 17,989 2010 20,583 (?-t. '" )..-~ ) I , t- -l C.:·D ·= Symbol MAP MODEL TOURIST RPTS RPRY RPBS '; ·-···~ RPPS ' I RTCSPX GGRWEVS uus GRDIRPU GRUSCPI LFPART Variable Name Tourists Visiting Alaska State Petroleum Production Tax Revenue State Petroleum Royalty Revenue State Bonus Pa~nent Revenue State Petroleum Property Tax Revenue State Petroleum Corporate Tax Revenue U. S. Real Wage Growth/Year U. S. Unemployment Rate U .. S. Real Income Growth/Year Price Level Growth/Year Labo~ Free Participation Rate TABLE VARIABLE AND ASSUMPTIONS 1983 2010 1983 2010 1983 2010 1983 2010 1983 2010 1983 2010 ;,.~ ._ ... : Base Case Value 730,000 2,080,000 1,480 MM 699 MM 1,430 NM 1,592 Ml1 26 MM 0 149 .MM 564 MM 235 MM 1,601 MM .01 .06 .015 .065 .9338 A'· J ) : / . ..._ (.:;) Sensitivity Value ~\our ce I ' ! l ~i I t ,, "'" ') j I ; ! __::=.:.:,~ I • ,_ TABLE VARIABLE AND ASSUMPTIONS Variable S~bol Name RED Model ·--UNCERTAINTY MODULE N Number of Values to be Genera ted HOUSING MODULE POP HHAt b, c,H AHS BHH p R Regional Population Forecast Regioncl Households Housing Demand Coefficients Average Household Size Military Households Residing on Base Regional Household Size Probability Ratio of Regional to State Relative HSTY r Frequency of Age of Household Head Railbelt Household Stock by Type Period Specific Removal Rat~ v Normal Vacancy Rate -"'· Base Case Value ---,-,-~~ (,"( 0~ )-_" .. ": .~.;;. ~-~·· ) -~ ) Sensitivity Value Sour,1:e l ... • -• -i ~ ~-·-; . --J "" .. *'f' .:; p _5(· / -. . :.: -b 1 -t .. -~ • • '1 ... ~ # \<;" .• ; . ~ -~ .. .:1 c~ .......... ,.;. -~ ~ .. .,., ' ~ .j r . . .• "-~ '··o· ~. . o· .. :" ", . . 4' . ;;.9· . ... . ... i !r~ · ... -r:. ~"t g •j • .,. •• 't\."'ii;. -.... '!"-,;-"' .J.· ... ~ '\:a -• q , - . ' .. -• I !--~ Q , «> -.... ~. .~ .. •• • • t:JI : '· ·,_, ' u--... ' .. _ .. --;.... . -: ' .. , --t e ~. Q - ... ~ ·tR " .t ... •, • • "t L. \· • -' '~ ' ~ • ~ -' . ~ ., t . 0 l" P, " ' • ,;. . -... ' Cl """" I ' • ~-• ·' . . ... •.• ·. ,. ~-' •. <.. •· : ""' ' • .... • '/'"' • .. . " . '·. 2" .· . . ... ' t--·--.p ~ l' ~;:::: --.. • ·" " rf ' 4"-..jf .s If' t Jl. ~ 0 i;,' ) 0 _j l ... • ... '· , .... ¥ ;.,..... ~-'. '\ ----~-' • .... :: i'. .. •• ., <1 ~:.'1 :f!.! . .o\ _£;-~ ~ ~'!"!! ~:_~'~/··: ~~ 'r-~ ~ ~ ~ ~ TABLE VARIABLE AND ASSUMPTIONS Variable Symbol Name RED Model RESIDENTIAL CONSUMPTION MODULE HDTY SAT SE Occupied Househotds by Type of Dwelling Appliance Saturations by Type of Dwelling Base Case Value ~ ~4:....1 ~ ~ S2nsitivity Vallie ~ -.,., ~ ~ Source Housing Module -~ ~ Uncertainty Module Per cent of Households served by Electric Utilities .r I AS d AC z g cs E CE Initial Stock of Appliances Vintage Specific Survival Rates Average KWh G.:>nsu.mption of Appliances Length of forecast periods Growth Rate of K~~ Consumption of Appliances Conservation Standards Target Consumption Reduction Own-price Elasticity Cross-price Ela~ticity ' r/ • ---- . 'I • ,-.... : ( c Uncertainty Module Uncertainty Module ,; ., ~ I ~ ' I i i I ~ I f I i -:1 ~ ~ : -0 t. 1!1 ...,'lq, ~ • (. . J '· " ' ~ -( :-- Symbol RED Model ,_,_ ~ ~ ~ Variable Name ~ ~~'"tl!!"!~.~~""""""'l' vARln.u ... :u~ AJ:-i.., n."3SUt ... L.;: ... ONS - Base Case Value llllc ~'iJ ·~ ... "' ..... Jtj Sensitivity Value BUSINESS CONSUMPTION MODULE TEMP POP CPI KIR99 BBETA E CE Total Regional Employment Regional Population Consumer Price Index~ An=horage Statewide Average Wage Rate Electricity Consumption Floor Space Elasticity Own-price Elasticity Cross-price Elasticity CONSERVATION MOD-ULE THHS TECH COST! COS TO RCSAT ESAT PRES RES CON Total households served Technical Energy Savings Instllation and Purchase Cost of thE Residentia 1 Conservation Device Operation and Maintenance costs of the Residential Conservation Device Residential saturation of the device (with and without government intervention) Residential electric use saturation Expected residential electricity pr~ce Price-adjusted residential consumption 0 •• ,. ¥ , t I.~·~ I""· . . II " '../ ... , ' ~~ ''..;'":1 fl!lfli!JI. ~ ~· ~ Source Uncertainty Module Uncertainty Module Uncertainty Module Residential Module ,. ·:-::--·' ''""""' ~ ... --~ l l I l l l 1 l ~ ·-~ ) l :;;:::= 1 . .. • • • < ·~ .., ~~ ~~ .., .; ~ -~ ~...., •. b.! J!ll,! ~ '.!'!''~~ !=C::::~ '111!::-:""1 ,,..,~ ~ .,_. ~ 1ABL~ VARIABLE AND ASSUMPTIONS Variable Symbol Name RED Model CONSERVATION MODULE (cont'd) PPES Potential proportion of electricity BCSAT COST BUSCON saved in business in new and retrofit uses Business conservation saturation rate (with and without govern- ment intervention) Cost per megawatt hour saved in business Business price-adjusted consumption MISCELLANEOUS MODULE ADBUSCON ADRESCON VACRG Sl sh shkWh Vh Adjusted Business Requirements Adjusted R•esidential Requirements Vacant Housing Street Lighting Proportion of households having a second home Per unit second-home consumption Consumption in vacant housing Base Case Value ; .... J ' I ~ ..... -· ..,[ ~ ·~ Sensitivity Value / . (') .. II\IIIMIIIJIIt ~ ~.~ Source Business Module Conservation Module Conservation Module Housing Module -'~; .,. I l I t • ·t,..~cAL~ ·~ R::!!'-~ ~ l"'"'"'.'".', .~ ~ ~ _.,. ~~ ~ ~ TABLE VARIABLE AND ASSUMPTIONS Variable Symbol Name RED Model PEAK DEMAND MODULE LF Regional load factor RES CON BUS CON ADRESCON ADBUSCON ACF Residential electricity sales before adjustment for subsidized conservation Business requirements prior to adjustment for subsidized conservation Subsidized conservation-adjusted residential requirements Business requirements adjusted for subsidized conservation Aggregate peak correction factor Base Case Value .-) /...:--__ , -.. /' .·) ~ ·~ ~· Sensitivity Value • ,j.'' ~· .... ..... ~ Source Uncertainty Module Residential Consumption Module Business Consumption Module Conservation Module Conservation Module l ... :.~l~}' I Conservation Module ~ . i \ l l l \ 1 ( i ~ I r I 1 t ~ ~9 Symbol OGP Model FUCOST PATFC PLCDKW CAPDl\ INSTDB KRETDB III!!'!'L~ .. ;. .• ''\1 0 • ~-.... ~":":! ~ ir"''""" ~ ~ ~ ~ ~ ~ ~ TABLE VARIABLE AND ASSUMPTIONS Variable Name Base Price of Fuel in 1983, $/MMBtu Nat Gas Diesel Oil Nenana Coal Beluga Coal Pattern of fuel cost escalation rates Plant cost, in $/kW, of thermal units Capacity of thermal units, M¥1 Year of installation, default month is January Year of retirement; defaults to N years after INSTDB, where ~ is specified plant life. Base Case Value a•'~'" J /' 2.38 5 .. 58 1.72 1.86 l J .... J. ' ) ..... '""' ._...., ~- Sensitivity Value ~ -~ ~ -~ Source .. I •, . ~ ' r·'(ff ·-' \ ·~ l ;_t f I I 'I ! I I .· j ~ iB!!"'~ Symbol OGP Model PLCHYD INSTDB KRETDB GMINDB GMAXDB ENGYDB RELENG '' \ ;.;.1 · ..• --~ '-.....----... ' ~ ~ ~~ ~":!~ ~~ "' ~::::::-~ ·-~ ~ ~·"'" ~ TABLE VARIABLE AND ASSUMPTIONS Variable Name Plant cost, $/kW of hydro units Same as for thermal Hydro capacity to be base loaded, MW by month Maximum hydro capacity; (GMAXDB-GMINDB) loaded on peak or intermediate; MW by month Average monthly hydro generation, GWh Reliability energy (firm energy) from hydro, used in generation addition analyses. Base Case Value /~") -.. ~) .... -·"' ·' ~ "· ~ ~- Sensitivity Value ,.,. ~ ~ ~A Source (L I I j, 1 ,..,~ i I I Symbol OGP Model FIXCHG, HYDFCR OMDKW, OMHYD OMDHR, OMVHYD FORATE PO RATE PWRATE SPRES TABLE VARIABLE AND ASSUMPTIONS Variable Name Fixed carrying charge rates for thermal and hydro units, % Fixed O&M costs, $/kW for thermal and hydro units Variable O&M ~osts, ~/kWh, for thrrcmal and hydro units Fixed outage rate, % of time for thermal units Planned outage rate, % of time, for thermal units. Present worth discount rate, % Spinning reserve capacity required. Either in MW or as per cent of peak demand. J ~ Base Case Value . -- I. • ' ,• Sensitivity Value Source ' h.·~ I ! ! i I SUMMARY OF INPUT Am Referencel/ Item Description A World Oil Price (1983$/barrel) Energy Price (1983$) Fuel Oil ($/MMBTU) Natural Gas ($/MMBTU) Coal ($/MMBTU) Electricity ($/KWh) State Petroleum Revenues (Nominal $) Production Taxes Royalty Taxes State General Fund Expenditures (Nominal $) State Population State Employment Railbelt Population Railbelt Employment Railbelt Total Number of Households Railbelt Electricity Demand (GWh) Anchorage Fairbanks Total Railbelt Peak Demand (MW) 1 I Refer to the reference letter of Figure ---- 1983 13 - ( '\ .I: I· -., t:.~~:::, ... "' ------------SCENARIO SUMMARY OF INPUT AND OUTPUT DATA Reference!/ Item Description A World Oil Price (1983$/barrel) Energy Price (1983$) Fuel Oil ($/MMBTU) Natural Gas ( $/Ml-tBTU) Coal ($/MMBTU) Electricity ($/KWh) State Petroleum Revenues (Nominal $) Production Taxes Royalty Taxes State General Fund Expenditures (Nominal $) State Population State Employment Railbelt Population Railbelt Employment Railbelt Total Number of Households Railbelt Electricity Demand (GWh) Anchorage Fairbanks Total Railbelt Peak Demand (MW) lj Refer to the reference letter of Figure -- 0 1983 1985 1990 -~ ·h -,! . / .• ) ) ~ ) ~ . - 1995 2000 2005 -2010 5.5 Evaluation of Electric Power Market Forecasts 5.5.1 Comparison With Previous Forecasts Two sets of previous forecasts have been used in Susitna Hydroelectric Project studies in addition to the power market forecasts presented in detail ~n this section. In 1980, the Institute for Social and Economic Research (ISER) prepared economic and accompanying end-use electric energy demand projections for the Railbe1t. The end-use forecasts were further refined as part of the Susitna Hydroelectric Project feasibility study to estimate capacity demands and demand patterns. Also estimated was the potential impact on these forecasts of additional load management and energy conservation efforts. These forecasts were used in several portions of the feasibility study, including the development stalection study and initial economic and financial analyses described in Section 1 of this Exhibit B. In 1981 and 1982, Battelle Pacific Northwest Laboratories produced a series of load forecasts for the Railbelt. These forecasts were developed as a part of the Railbelt Alternatives Study completed by Battelle under contract to the State of Alaska. Battelle's forecasts were based on updated economic projections prepared by ISER and some revised end-use models developed by Battelle which took into account price sensitivity and several other factors not included in J '""). f _.. ·a the 1980 projections. The December 1981 Battelle forecasts were used in the optimization studies for the Watana and Devil Canyon developments completed early in 1982 and described in Subsection of this Exhibit B. Battelle -- also produced power market forecast in December 1982 based on a reduced projection of world oil prices. That forecast was produced too late for the preparation of the FERC License Application filed in February 1983. These previous forecasts were made for three ele.ctric load centers: the Anchorage-Cook Inlet area; the Fairbanks-Tanana Valley area; and the Glennallen-Valdez area. When these studies were undertaken, it was not decided whether the Glennallen-Valdez area would be included in the intP-rtied Railbelt electrical system. The decision was subsequently made, based on economics, that the Glennallen-Valdez area will not be included in the interconnected area. Therefore, the updated elect! ic load forecasts presented herein do not consider the power requirements of this load center. Both ISER and Battelle produced high, medium and low forecasts for use in Susitna planning studies. The medium forecast was used for determining base generation plans, with the high and low forecasts used in sensitivity analyses. -,_.. .. .·..., 7 -" In addition to the ISER and Battc:l:.e forecasts per formed for tbe purpose of planning the Susitna Hydroelectric Project,. the Railbelt utilities annually produce forecasts for their own respective markets. The bases for these forecasts are not readily available. Table provide~ a summary compar1son of these prev1.ous -- power market forecasts under the medium scenario. While these forecasts are not precisely consistent in the definitions of the market area or in the assumptions relating to the current base scenario, the comparison does provide an insight in the change in perception of future growth rates during the time that the various sets of forecasts were developed. The energy demand forecast of the updated base case scenario is about percent lower than the December 1981 Battelle -- forecast, for the year 2010. The Sherman Clark Base Case projection for year 2010 is about 6 per cent greater, and the FERC 0 per cent case is about per cent lower. The utility forecasts are the highest, although the 1983 forecast is about 20 per cent lower than the 1982 forecast for year 2000. ~ / . ! ,_,.,. .. J [. i .. " ..... ~ I ' i 1 LIST OF PREVIOUS RAILBELT PEAK AND ENERGY DEMAND FORECASTS (MEDIUM SCENARIO) Battelle 1982 Forecast Battelle Revised ISER 1>.:t:telle Plan lA Plan 1B 1982 Forecast Utility Utility 1980 Forecast 1981 Forecast (w/o Susitna) (w/ Susitna Plan 1A 1982 Forecast 1983 Forecast PEAK ENERGY PEAK ENERGY PEAK ENERGY PEAK ENERGY PEAK ENERGY PEAK ENERGY PEAK ENERGY YEAR DEMAND DEMAND DEMAND DEMAND DEMAND DEMAND DEMAND DEMAND DEMAND DEMANJD DEMAND DEMAND DEMAND DEM.A'ND (MW) (GWh) (MW) (GWh) (MW} (GWh) (MW) (GWh) (MW) (GWh) (MW) (GWh) (MW) (GWh) 1980 510 2790 --------521 2551 521 2551 521 2551 1981 --------574 2893 1982 650 3570 687 3431 643 3136 647 3160 615 3000 769 3697 716 3531 1990 735 4030 892 4456 880 4256 924 4482 701 3391 1126 5305 940 4678 1995 934 5170 983 4922 993 4875 996 4894 791 3884 1626 7098 1167 5884 2000 1175 6430 1084 5469 1017 5033 995 4728 810 4010 2375 9067 1420 7335 2005 1380 7530 1270 6428 1092 5421 1073 5327 870 4319 NA NA NA NA 2010 1635 8940 1537 7791 1259 6258 1347 6686 1003 4986 NA NA NA NA 1/Table 5.6-Acres Feasibility Report-Volume 1 or Table B.70-Exhibit B gf License. Inciudes 30% of military loads, and excludes industrial self-supplied electricity. 2/Table 5. 7 -Acres Feasibility Report -Volume 1 or Table B. 71 -Exhibit B of License. Excludes military and industrial self-&upplied electricity. 3/Table Bol2 and B.13 of Battelle Volume 1. Excludes military and industrial self-supplied electricity. 4jpage xv of Battelle Volume 1. Excludes military and industrial self-,supplied electricity. ?_I At plant net generation. Note: The Battel:ie forecasts are for end-use demand, and should be increased by approximately 8 percent for actual ,at plant net generation. i J ~. I ~·-" 1 . / /' 5.5 -Evaluation of Electric Power Market Forecasts 5.5.2 Impact of Oil Prices on Forecasts The prev~ous section (5.4) presented forecasts of oil prices and electric demand in the Railbelt and detailed discussion of the results. The electric demand forecasts contained in that section reflect the impact of oil prices based on separate world price of oil scenarios. The purpose of this section is to summarize the impact of oil prices. An overall assessment of the impact that changes in the ~ice of oil have on the demand for electricty can be obtained by measuring the relationship between the rate o£ growth of oil prices and the rate of growth in the demand for electric energy. Table compares these growth rates for the relevant world price of oil cases. Scenario TABLE B. Comparison of Electric Demand and Oil Prier.~ Growth Rates (1982-2010) Oil Price Growth Rate (%) Electric Demand Growth Rate (%) Sherman FERC FERC FERC FERC Clark (Base) 3.6 2 3.6 3.19 2.9 2.73 2.67 0 -1 -2 A regression analysis was performerl to relate the electric demand growth rates associated with the forecasts in section 5.4 to their corresponding world price of oil growth rates. The estimated relationship ~s as follows: y = 2.25 + 0.25 X where y = electric demand growth rate x = world oil price growth rate The slope of the line provides a measure of the respons~ve- ness of electric demand to oil prices over the planning period (1983-2010). The value of this coefficient (0.25) denotes that expected oil prices changes would have an impact on the growth in demand for electricity but not a significant impa~t. The responsiveness of electric demand to oil prices is based on our results. If we assume that the growth rate of oil prices increases from one percent to four percent per annum, electric demand growth would increase by only one per cent age point. f3-r ~ /'{( .. 'l··· l ··-· 4 <. 5.5.3 Sensitivity to Other Key Variables and Assumptions Sensitivity analyses were conducted in order to determine the extent to which forecasts were affected by varying the values of selected input variables and parameters, other than -vmr ld oi 1 prices. The other key variables and assumptions which were tested in the sensitivity analyses are listed in Section 5-4.2 For the MAP Model, input variables tested included ten industrial development factors, tourism in Alaska, and four national economic variable parameters. The results of the sensitivity analyses, which were conducted in February 1983, are summarized in Table A~ The table shows that of the variables tested, projections of households are most sensitive to mining employment, which includes petroleum production, military employment, tourism, growth in real wages, and growth in the consumer price index. Sensitivity tests were also conducted using selected economic model parameters, including those relating to labor force participation rates, Federal tax rates, and population migration. Results of these tests are shown in Appendix J of the MAP Model Technical Documentation Report • ...... r-· .+ Electric Power Load Sensitivity Tests Sensitivity analyses for the RED Model were conducted for the key variables which were not petroleum price. dependent. These variables are appliance saturations, energy consumption by appliance, growth rate of appliance consumption, own price elasticity, and cross price elasticity. The sensitivity analyses were carried out for the base case oil price forecast. The results are shown on Table B. Sensitivity tests were also conducted for the OGP Model. The key variables other than petroleum price dependent variable which were tested are thermal plant cost, hydro plant cost and discount rate. The sensitivity analyses are described in Exhibit D. ~-IIMMIIrt•nlrll'l'p .,tt& .. - ! .. .., .. ,,,.., ... ,..,..!!l~··~,.q alilaliJ . ·\, I ! <~1 -~ i I I ( l ' ., TABLE A RESULTS OF MAP MODEL SENSITIVITY TESTS! Projected Statewide Value in Year· 2000 Households in Year 2000 Low High Low High % Difference Factor State Agr icult. Employment 21 160 State Mining Emp.-3,990 State High Wage Exog. Constr. Emp. 0 State Low Wage Exog. Cons tr • Emp. 0 State Exog. Trans. Emp. 1,100 State High Wage Manu. Emp. 0 State Low Wage Manu. Emp. 8,205 State Fish Harvesting Emp. 4,536 State Active Du~1 Military Emp.-21 16,892 State Civil Fed. Emp .. -17,800 2,000 19,107 2,000 1,000 2,968 486 16,000 9,192 33,000 21,719 Tourists Visiting AK 1,066,000 2,566,000 U.S. Real Wag2/ Growth/Year-.005 .015 U.S. Unemp. Rate .05 .075 U.S. Real Income Growth/Year .005 .025 U.S. Price Le~71 Growth/Year-.09 .05 215,436 200 ,b,58 212:523 215,119 214,306 215,824 210,106 213,557 209,936 212,372 209,936 211,335 211,161 I 215,493 205,924 217,352 229,782 217,971 217,579 217,223 216,610 220,833 217,744 224,575 217,962 224,575 223,723 222,178 216,272 222,305 lResults based on February 1983 execution of MAP Model. 2Key Variable !" ~· 4 Jf' .-~.,, .. . . ) .. / ~.; •. .9 14.6 2.6 1.1 1.4 .4 5.1 2.0 7.0 2.6 7.0 5.9 5.2 .4 8.0 . . I' ' ------·-· ~....... "'~ ...... ~,J: tt:••l; ~ -~~: '-~~~;:I···!~[I···~~~~ ; . '" ·~ I , '" r·~ ;-_~.: Variable Appliance Saturation Appliance Energy Consumption Growth Rate of Appliance Consumption Own Price Elasticity Cross Price Elasticity Base Case Value TABLE B RED MODEL SENSITIVITY TESTS Sensitivity Values High Low __ I) .,._/ ,,. Railbelt Elec Energy Demand in 2010, ??? Bas~ High Low ' . ") - / .f / ... / /""' .) Per cent age Base Case High Low .': SECTION 5.6 -PROJECT UTILIZATION The purpose of this section 1.s to describe how the power generated by the Susitna Project will be utilized in the interconnected railbelt system. The discussion that follows is based on the Project's operation under the base case power market forecast. The characteristics of the combined railbelt load are discussed in Subsection 5.2.2 Load duration curves are also presented in that subsection as Figure The operation of the Susitna Project as stated in Section 3.7 of this Exhibit will be as follows: the Watana development will operate as a base load project until the Devil Canyon Development enters operation at which time the Devil Canyon development will operate on peak and reserve. The dependable capacity and energy production from Watana opeating alone and with Devi 1 Canyon are presented in Section 4. 3 of this Exhibit. The firm and average annual energy production, and maximum dependable capacity and the year in which it is achieved for the Susitna Project under the base case flow regime, Regime C, are as follows: Per cent age of Rai lbe l t Energy Utility Sales (1982) Chugach Electric Association 20 Anchorage Municipal Light & Power 40 Golden Valley Electric Association 10 Matanuska Electric Association 10 Fairbanks Municipality Utilities System 5 Homer Electric Association) 15 Seward Light Department ) Total 100 : : ,. ··j· APPEND IX B-2 FUELS PRICING STUDIES Introduction There are thermal alternatives to the Susitna Hydroelectric generating facility which would provide the same capacity and generation as Susitna through the use of a fuel or fuels such as natural gas or coal. The economic viability 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 provide 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 ttre other potential fuels such as peat and wood but these are not dis cussed due to the findings of previous studies tr.at these fuels are not economically competitive when compared to natural gas and coal. Multiple data sources were employed including previou~ studies by consultants, information from state and federal agencies, and data, plans and other information from electric and gas utilities in the Rai lbe lt Area. . . . . t:. ProJectl.ons of .future natural gas and d1.st1.lla$e fuel prices were tied to the future, world price of oil. Projections of future world oil prices were obtained from several sources and from these projections, Harza-Ebasco used its judgment in selecting the most likely projected prices • . 4trmcm r•1ri: rnrr Jtrtrns•• ., w · . ~I Results concerning the availability and price of fuels were used as inputs into the Alaska Department of Revenue forecasting model and the Institute of Social and Economic Research's econometric forecasting model. In addition, the results were used as input parameters in the determination of the cost of thermal generating alternatives. Part I -Natural Gas Resources and Reserves Known recoverable reserves of natural gas are located in the Cook Inlet area near Anchorage and on Alaska's North Slope at Prudhoe Bay. Gas 1s presently being produced from the Cook Inlet area. Some of the gas is committed under firm contract and some is for all practical purposes committed, but not by contract. Considerable quantities of gaE: remain u~connnitted and could be used for power generation. There are substantial recoverable reserves on the North Slope that could be used for power generation, but until a pipeline or electrical transmission line is constructed, the gas cannot be utilized. Undiscovered gas resources are believed to exist in the Cook Inlet area and also in the Gulf of Alaska where no gas has been found to date. _;r~ I -COOK INLET Ba8H)ff .... ~ ~ Electrle "••.,. Tre••,.l•ale• Ll,.e •• •tt··· ••• ......... .... ._ • •oquawtlel Albert Jls •• , •• , "'••• e •• ,,.. o· .. ... , .. , : CHICKALOON BA / .~ .. • • • • • • • • • : • • • • : • • ~ : Ge• "'•••"•• l ... • •• •• •• •• •• •• •• ..... Qllea•e' cre-.t •• • w •• , ,.,, ,. •• ... ~ ....... 1111 ..... ~ st.,u,, -"!(';,· •• , ......... 011 Flelfl• Willi G•• Gaa Flelda Estimates of potential gas resources in these areas have been made by the United States Geological Survey and the Alaska Department of Natural Resources. The quantities of proven and potential undiscovered gas from these areas are discussed below. Cook Inlet Proven Reserves The locations of the Cook Inlet gas fields are shown 1n Figure 1. Estimated recoverable reserves from the Cook Inlet fields and the commitment status of those reserves are shown in Exhibit 1. This table is essentially Table 2.2 from the Battelle Study(l) but, updated and rearranged to reflect current conditions. Recoverable reserves a:: u from the Alaska Oil & Gas Conservation Commission's latest . (2) est1mate. New contracts between Enstar and Shell & Harathon are shown(3 ) in Exhibit 1 as well as the five-year extension of the Phillip/s Marathon LNG contract with Tokyo Gas and Tokyo Electric Companies. (4 ) Reserves that were formerly committed to Pacific Alaska Liquified Natural Gas (PALNG) Company* are shown for reference purposes, but are included as uncommitted reserves since PALNG's contracts for the gas expired in 1980, (S) All of the proven gas is not presently under contract as is shown 1n Exhibit 1 where 1,654 Be£ of proven reserves is presently uncotttrt1itted. *see subsequent section entitled; Competition For Gas. ·.··. I 1 <;'<~ ~ """y------·¥-~W" •' , ...... ~--~-..... ~~~~ . ··r 'i'll... 1 .• ~·.__;::; . ' ' !. I I . . I , " ' --• ~ ,~_... ~"~.. ·~~~ .. iPS-. ~-...-! ... ~.; •_,:';-~.~-;.''• ... Exhibit 1 Estimated Cook Inlet Natural Gas Recoverable Resecve 5 and Commitment Status as of January 1, 1982 Pacific Chugach Collier Phillips/ SO CAL Alaska Recoverable Electric Carbon & Marathon ARCO Uncommitted LNG Reserves 1 Ens tar Assoc. AMP&L Chemical LNG Rental Reserves Assoc. -. Beaver Creek 240 2502 ----------0 Beluga River 742 220 285 --------237 404 Birch Hill 11 ------------11 Cannery Loop N/A ----------N/A (3) Falls Creek 13 ---- --------13 Ivan River 26 ------------26 1064 Kaldachabuna N/A -- ------·--N/A Kenai 1,109 256 --{5) 377 250 106 120 ~~ 4 Lewis River 22 -------- ----22 McArthur River 90 -------- ----90 Nicolai Creek 17 --·----------17 North Cook Inlet 951 27 6 ------1107 --814 North Fork 12 ------------12 N. Middle Ground N/A ------ ----N/A Sterling 23 ------------23 Stump Lake N/A ----------N/A (1) Swanson River ------------259 Trail Ridge N/A ----------N/A Tyonek N/A ----------0 West Foreland 20 -------------20 Total 3)541 759 285 --377 360 106 1,654 76oP~ Notes 1. Alaska Oil and Gas Conservation Commission. 2. Part of gas will be taken from Kenai Field. 3. Participant in exploration underway in 1980. 4. Based on DeGolyer and MacNoughten reserve estimate in 1975. 5. Uncertain royalty status. 6. Royalty gas. 7. 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 t -, ~ ~~ ... f~::,~:.~::.~::.:;~:::.: ... ~.::~c~=:~~-'u" .. .,.,F•·"'J"~~MMfA'~M\Q(IM»=- -~.Q <', '1- <, ··-- In addition to proven recoverable reserves 1.n the Cook Inlet area, there is the possibility of additional supplies in the form of undiscovered gas. Cook Inlet Undiscovered Gas Earlier estimates of additional natural gas resources in the Cook Inlet area ranged from 6.7 TCF to 29.2 TCF.(G) These estimates may be high since subsequent drilling by Mobil and Arco in Lower Cook Inlet has resulted in nothing but dry holes. A recent study by the State of Alaska, Department of Natural Resources presents estimates of undiscovered gas and oil versus the b b .l. f f. d. h . . (7 ) . f pro a 1 1ty o 1n 1ng t ose quant1t1es. Summar1es o the estimates are presented in Table 1 and show that there is a probability of 75% that at least about 2.0 TCF of undiscovered gas remains in the Cook Inlet area. The Department also estimated 11 economically recoverable" resources by assuming a recovery factor of 0. 9 and a minimum commercial deposit size of 200 BCF. These are also presented in Table 1 and show that there is a probability of 75% that at least about 1.0 TCF of economically recoverable gas remains in the Cook Inlet Area. "-~-··-~-----.. ------'"·------------~--·-·--·-------------~-------------~--~.-r-·"'":..] -- TABLE 1 Pr.'eliminary Estimates of Undiscovered Gas Resources In Place ~l) Economically Recoverable Gas Resources For the Cook Inlet Basin Qu~ntity of Gas -TCF Probability -%(2 ) In Place Economically Recoverable 99 0.47 0.00 95 0.93 0.22 90 1.24 0.43 75 1.98 0.93 50 3.07 1.76 25 4.38 2.78 10 5.84 4.04 5 6.93 4. 90 1 9.06 6.83 1. Data from letter to Mr. Eric P. Yould, Executive Director, APA from Ron G. Schaff, State Geologist, State of Alaska, Department of Natural Resources, Division of Geological and Geophysical Surveys, dated February 1, 1983. 2. Probability that quantity is at least the given value. Mean ar as e~pected va1uJis approximately 2.0 TCF due to skewed distribu- tJ.on. ~~~~t I North Slope Gas ~stimated recoverable natural gas reserve's from the North Slope are about 29 trillion cubic feet (TCF) for the Sadlerochit Reservoir at Prudhoe Bay. Additional gas from the North Slope is estimated to be 4.5 TCF. (B) The State of Alaska royalty share of Prudhoe Bay reserves is 12.5% or 3.6 TCF. North Slope gas 1.s currentJy either shut-in or reinjected into reservoirs to maintain pressure for oil extraction since there is no pipeline to areas where the gas can be burned&~'\.~ ~ • 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 2). 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. .~.,,,_,,,, ·----.. ~·--~~··'-'"r""'''"'-··~- [J '-. .... I .. ;:.» ;;o..~ ~ e<Q, ' ~1\ I I I 63 .Gulf of Alaska Shelf I !i Gulf of Alaska Slope 16 FIGURE 2 -Areas of Alaska Assessed by the U.S.G.S. For Undiscovered Resourcesu Shading Denotes Offshore Shelf Areas. Source: U.S. Department of the Interior Geological Survey, Open-File Report 82-666A, 1981. • C; I fJ ' ''~. ' b The U.S.G.S. presents its estimates of undiscovered gas in terms of the pro·bability of finding ueconomically recoverable" gas. Economically recoverable resources are those that can be economically extracted under price-cost relationships and technological trends .1. h . f h (9 ) preva1 1ng at t e t1me o t e assessment. For their low estimate, there is a probability of 95% that the estimated value will be exceeded. For t.he high estimate, there is a 5% probability that the estimated value will be exceeded. The U.S.G.S. analysis can also be int·erpreted as having a probability of 90% that the amount of undiscovered gas wi 11 be between the low and high estimates. In addition :;o low and high estimates, the U.S.G.S. also provides a me·an value as the quantity of gas most likely to be found. The U.S.G.S. es~imates for the Gulf of Ala~ka Shelf (to a depth of 200 meters) are~(lO) Low 0.46 TCF High 9.24 TCF Mean 3.14 TCF . The estimate for the Gulf of Alaska Slope which is those Gulf areas with a water depth from 200 meters to 2, 400 meters is: Low 0.36 TCF High 3.70 TCF Mean 1.53 TCF These estimates show that additional gas might, in the future become available from the Gulf for Railbelt electrical generation. Production and Use of Natural Gas Natural gas is produced and used in Alaska for heating, electrical generation, liquified natural gas (LNG) export and the manufacture of ammonia/urea. Host of the production and use (other than reinjection) currently takes place in the Cook Inlet area but the large proven quantities located on the Nor~th Slope and undiscovered potential in the Gulf of Alaska make these areas worthy of consider at ion for future use. Current and potential production from the three areas is discussed below. Cook Inlet Current Production and Use The production and use of Cook Inlet gas for the pa~?t five years is shown in Table 2. Gas that has been injected (or ~~tually reinjected) was not consumed and is still available for heating, electrical generation, or other uses. The use of gas in 'field operations depends on oil production and has beer\fair ly constant over the last five years. LNG sales are for export to Japan and the manufactured ammonia/urea is exported to the lower forty eight states. Both uses of gas have been fairly constant and are expected to remain so in future years. -.r············--·"···················· ' TABLE 2 Historical and Current Production and Use of Cook Inlet Natural Gas QUANTITY -BCF USE 1978 1979 1980 1981 Injection 114.1 119.8 115.4 100.4 Field Operations: Vented, Used on lease, shrinkage 23.5 17.5 28.0 20.6 Sales: LNG 60.9 64.1 55.3 68.8 Ammonia/Urea 48.9 51.7 47.6 53.7 Power Generation: Utilities 24.6 28.2 28.7 29.1 Military 5.1 5.0 4.8 4.6 Gas Utilities 13.5 14.0 15.5 16.2 Other 3.3 4.8 5.1 5.7 Total Sales 156.3 167.8 157.0 178.1 Total 293.9 305.1 300.4 299.1 1982 103.1 21.3 62.9 55.3 30.5 4.7 17.7 9.5 180.6 305.0 Source: "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. -,--··---------"'"'~·-«< ,,,,,,~--···-:-·---'-_, '-·.-'"' "'"~""-'" ' > ' ' ' :.rJit-·eg ~SF?rtPV.iiii'i""'fif'httt' w ', rt'' 7 et·, ., "'· ,, . ._ 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 1ncreases 1n electrical load and to replace oil-fired generation. The military bases in the Anchorage area, Elmendorf AFB and Fort Richardson, use gas to generate electricity and to provide steam for heating~ The military gas use has been fairly constant in the past and is expected to remain so in the future. The gas utility sales shown are made principally by Enstar Corporation and are for space and water heating and other uses by residential, commercial, and industrial customers. These sales grow with increases in population and increased use by existing consumers. The growth is expected to continue in the future and will be increased further when Ens tar begins gas service to the Matanuska Valley. Other sales consist principally of [finish after talking to Alaska Dept. of Natural Resources.] Cook Inlet .Future Use The future consumption of Cook Inlet gas depends on the gas needs of the major users and their abillity to contract for needed supplies. The. major existing users are Phillips/Marathon for LNG export, Collier for manufacture of ammonia/urea, Enstar for retail sales, sales to L4.W .-I electric utilities and the military, and Chugach Electric Assoc., and Anchor age }1uni cipa 1 Light .· d Power for electrical generation. Since there is a limited quantity of proven gas and estimated undiscovered reserves ~n the Cook Inlet area, reserves will be exhausted at some time in the future. In addition, there may not be sufficient gas for electrical generation beyond some point because of higher priorities accorded other uses, either through contract or by order of regulatory agenc~es 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 currently has 360 BCF of gas under contract (Exhibit 1) and it is highly probable that it will obtain enough of the uncommitted gas in Exhibit 1 to meet its needs through 2010. Collier Chemical currently has 377 BCF committed and will probably also be able to obtain sufficient gas to meet its needs through 2010. Both of these entities are established, economically viable facilities, owned by Cook Inlet gas producers who control part of the uncommited reserves. Phillip and Collier are estimated to consume 62 BCF and 55 BCF respectively per year from 1982 through 2010. Ens tar presently has enough gas under contract to serve its retail customers until after the year 2000 but since Enstar also sells gas to the military (for electric generation) and to Chugach and Anchorage Municipal Light and Power for electric generation, it may have to seek d : . ',_. '" ~-~--~··-·~" ~ ..... , .. , -··~·-·---, ... _ -~-~-.,,_ .. .._~.-.. ~ ...... ,_..,., >W a. ; additional reserves in order to meet the needs of those customers. It 1s assumed, however, that Enstar will be able to acquire sufficient gas to meet the needs of its retail customers (including the Matanuska Valley customers) and that those customers' needs will 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. Gas used in field operations and other sales of gas vary from year to year but together are estimated to average about 25 BCF/yr over the period 1982 to 2010. 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 Exhibit 1) and Enstar has 759 Be£ contracted, some of which will be sold to Anchorage Municipal Power and Light and Chugach for electrical generation. ~- Assuming that the Anchor age/Fairbanks inter tie 1.S completed in ~ I ct/'1-ts; ~~ Jl~ ~' the elec'1\/cal requirements of both cities and smaller towns in between could be met with generation using Cook Inlet gas. The quanities of gas required to meet all Railbelt electrical requirements were calculated using the estimated load and energy seA forecast (R/E 1983,\baseJase) for the Railbelt area. Estimated generation from the existing Eklutna and Cooper Lake and the proposed I 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 were assumed to be 15,000 Btu/Kwh until 1995 where the heat rate would decrease to 8500 Btu/Kwh to reflect the installation of high efficiency, combined cycle units to meet base and swingload operations . • """"' The estimated annual gas requirements increase from 35 BcfJ\1983 to 54 Bcf in 2010. The annual and cumulative use of gas for each of the major usf'~r s and the total use of gas for the Railbelt is shown in Table 3. The remaining proven and undiscovered (mean or expected quantity) gas resources are also shown and as can be seen, proven reserves will be exhausted by about 1998, and expected undiscovered resources by about 2007. The estimated use of Cook Inlet proven reserves and undiscovered resources is graphically illustrated in Figure 3. Cumulative uses for the major users were taken from '!'able 3. The major users, Phillips/Marathon for LNG, Collier for Ammonia/Urea and Enstar for gas sales to retail customers are shown as first or priority users. Electrical generation needs for the Railbelt Area using the $(.A Harza/Ebasco,\1983 base case are plotted on top of those priority· users. The data from Table 3 indicates that relying on all gas-fired electrical generation to provide the Railbelts' needs past the year 2000 is somewhat risky. However, if it was decided that the Railbelt's >( ("""; ··, -··id!lili!"ii!Nffililt•~~ .. ~ . ·I .. _ .............. "---·T·---·-.. JL ..... ------- Year End Remaining Reserves Proven Plus .,roverP Mean Undis cover ed7 . .3341. 6 3138.6 3931.4 2721.4 2.507. 5 2291.1 2077.5 1861.3 1642.6 1421.3 119/.4 970.8 741.5 532.9 322.1 107.9 (107.6) 5381.6 5178.1 4971.4 4761 ~4 4547.5 4331.1 4117.5 3901.3 3682.6 3461.3 3237.4 3010.8 2781.5 2572.9 2362.1 2147.9 1932.4 1714.6 1494.5 1271.9 10L~6. 7 818.6 586.8 352.3 113.2 (129.3) oleum Co. and Mr. alley customers Ens tar estimates. er Lake and Bradley . 1982-1985 and 8,500 evenues from Table 1. -1·--.-... , ......... . ' '~~~~·,..·-""' .· - . I f;· 11 3 TABLE% Estimated Use of Cook Inlet Natural Gas By User -All Volumes in BCF Year End Ens tar Field Oper-Electric Generation Total Total Remaining Reserves Phillips/Marathon Collier Retail ations & 3 Gas Cumulative Proven Plus Year LNG/Plantl Ammonia/Ureal Sales2 Other Sale~ Military'+ All OthersS Use Gas ~ ProverP Mean Undiscovered? --- 1982 62 55 17.7 25 5 34.7 199.4 199.4 3341.6 5381.6 1983 62 55 19.2 25 5 37.3 203.5 402.9 3138.6 5178.1 1984 62 55 19.8 25 5 39.9 206.7 609.6 3931.4 4971.4 1985 62 55 20.5 25 5 42.5 210.0 819.6 2721.4 4761.4 1986 62 55 22.8 25 5 44.1 213.9 1033.5 2507.5 4547.5 1987 62 55 23.6 25 5 45.8 216.4 1249.9 2291.1 4331.1 1988 62 55 24.4 25 5 42.2 223.6 1463.5 2077.5 4117 .s 1989 62 55 25.3 25 5 43.9 216.2 1679.7 1861.3 3901.3 1990 62 . 55 26.1 25 5 45.6 218.7 1898.4 1642.6 3682.6 1991 62 55 27.1 25 5 47.2 221.3 2119.7 1421.3 3461.3 1992 62 55 28.0 25 5 48.9 223.9 2343.6 1197.4 3237.4 1993 62 55 29.0 25 5 50.6 226.6 2570.2 970.8 3010.8 1994 62 55 30.1 25 5 52.2 229.3 2799.5 741.5 2781.5 1995 62 55 31.1 25 5 30.5 208.6 3008.1 532.9 2572.9 1996 62 55 32.2 25 5 31.6 210.6 3218.9 322.1 2362.1 1997 62 55 34.4 25 5 32.8 214.2 3433.1 107.9 2147.9 1998 62 55 34.6 25 5 33.9 215.5 3648.6 007. 6) 1932.4 1999 62 55 35.8 25 5 35.0 217.8 3866.4 1714.6 2000 62 55 37.0 25 5 36.1 220.1 4086.5 1494.5 2001 62 55 38.3 25 5 37.3 222.6 4309.1 1271.9 2002 62. 55 39.7 25 5 38.5 225.2 4534.3 1046.7 2003 62 55 '"> .1 25 5 41.0 228.1 4762.4 818.6 2004 62 55 .6 25 5 42.2 231.8 4994.2 586.8 2005 62 55 4· ... 1 25 5 43.4 2~4.5 5228.7 352.3 2006 62 55 45.6 25 5 46.5 239.1 5467.8 113.2 2007 62 55 47.2 25 5 48.3 242.5 5710.3 (129.3) 2008 62 55 48.9 25 5 50.1 246.0 5956.3 2009 62 55 50.6 25 5 52.0 249.0 6205.9 2010 62 55 52.4 25 5 53.8 253.2 6459.1 !Based on historical use from Table 2 and telephone conversations with Mr. Jim Settle of Phillips Petroleum Co. and Mr. George Ford of Collier Chemical. 2Estimate provided by Mr. Harold Schmidt, UP Enstar Co., Feb. 14, 1983. Includes sales to Matanuska Valley customers beginning in 1986. Consumr'"ion from 1991-2010 projected by Harza/Ebasco at average growth rates in Enstar estimates. 3Estimate based on historic use shown in Table 2. 4Estimate based on historic use 'shown in Table 2. Scalculated based on SCA/Basecase load and energy forecast; inclusion of generation from Eklutna, Cooper Lake and Bradley Lake hydro units and Healy coal unit; and assumed average Railbelt heat rates of 15,000 Btu/kWh from 1982-1985 and 8,500 Btu/kWh from 1986-2Cl0. 6Proven reserves of 3,541 Be£ on Jan 1, 1982.. See Exhiblt 1. ?Includes proven J;"evenues of 3,541 Bcf plus expected value for undiscovered economically recoverable revenues from Table L 0 ! iTll1fl!'~.-~ I ' r ' l I l 1 I l l I " ! 1 ~~ ~ ·i I ' ..... .,., I l l 1 i . --. . ._, 1... . J -.-·f/liil -< ... ........ .,..., f' .... ";!:~-if~ .. ..,.,. . ·~·:: ~.co-~~,·---·!!1iilri: ____ ::m::llll ___ li1:2: ----=· .-......:' f:t.l u I=Q I CJ) Ji:.t g; r4 CJ) Ji:.t p::j 7000 / / .. 6000 ; PROVEN RESERVES PLUSS UNDISCOVERED RESERV=..:ES::;.__. ______ ------___________ _ 5000 4000 3000 2000 1000 I ,_ . I I I I ; I ' j_ l l i t ' l L ! .. ""-• 1982 PROVEN RESERVES • . / ./ . / ,;._, .. ,' / . 19.85 ,.. / Hilitary -..... ~. -·-.. ··-··-·~-; c§J~ / . · z,0e ev ~'0-0 ·' ~' ,-#~ ,/ .. · / •.. . / ... / / , ... *·· .· ·0~ '(.,'Y , ..r'O-----/ e'~-..-0-' · Ge~ // '0-)..e ,- . v .. '\. s . '<v-<.. 'Y '\.-"'0-e .,., ~e"' I> 0 / ~ • o-o-0 '0-'(,.'Y <)e."' 0. Ch i.:.._.,.e}; '0~\.eS ·'\. c;~s -a e'C-~'}.. i'-,. }." ~-o.S'(,~ • ..-~t\\t\\o1l:t.a. f\Y~ ea. co1.11-e~- PhilliPS fMarathOU LNG ... •.... ~· .... -~ ...... ''* ,. .. ____ .._ __ ·-·-·--• --~-·--_,._ -·""·-"'--""'-"'" ___________ ,._,_ __ . 1990 ' 1995 I 20105 I 2000 _.,.,/ ,/ '/ ""'~"' /'_, .. _, ..,. ,.... , . .. / -.,.,.-~ I 201(0 ,, t1. I { ~ ~-~'"'~'''"""'~'"'''""-- FIGURE 3 -Cook Inlet Natural Gas Reserves and Estimated Cumulative Consumption ·,~,;-.:-•• -T.-'-~;::->':.:.,.,.:.::...;:~~,..5 ,, ,,#fi~;~::,;; .... ,,~t .·~,-d'*·%~tj;j>.~;r. ~<.\M{~!·..\!'4'>'".'.~lt~-Ci~,~~'i~~~p.~~~.,-"-~ c. ·\' ';<,' needs should be met with thermal generation, it ~s likely that at least one and probably more 200 HW coal-fired generating units would be constructed. These units would be base loaded and would considerably reduce the use of gas• £or electrical generation and thereby pro long the availability of Cook Inlet reserves. There is ~lso the possibility that the uncommitted, proven reserves and any undiscovered resources could be acquired by entities not shown in Table 3, thus reducing or eliminating the availability of Cook Inlet gas for electric generation. This possibility is discussed next. Competition For Cook Inlet Gas ; c Known potential purchasers for the uncomitted, recoverable and undiscovered Cook Inlet gas reserves in addition to those shown in Table 3 are Pacific Alaska LNG Associates and the parties who 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 regulatory approval for a terminal in Cal if or nia. 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, Pacific Alaska had 980 BCF of recoverable reserves under contract. The contracts ~_.au#f%fbt&e·e·rm¥n entt 1 ·ir e ' tr ., t 1r , .. t ' -'eer:=f e;xpired in 1980, but producers did not g1ve written notice of termination so the contracts have been in limbo. Recently, however, Shell Oil Co .. 11old 220 BCF of gas that was formerly committed to PALNG (11) to Enstar Natural Gas Company. This reduced PALNG'S semi-committed reserves to 760 BCF (see Exhibit 1). The FERC has approved the PALNG project, but with the condition that PALNG obtain 1.6 TCF of reserves for Phase I of the project and . (12) 2.6 TCF before Phase II 1s commencedc Pacific Gas and Electric Co., one of the PALNG partners, has ceased accruing an allowance for funds used during construction (AFUDC) on funds already expended. In addition, PG&E does not plan to put any more money into the project and has filed with the California Public Utilities Commission (CPUC) for permission to place the expended funds into its "Plant Held for Future Use" account which will enable the utility to get the funds into its rate base and thus earn a return on them. (l 3 ) 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 1s little chance that the project would begin construction prior to the (14) early 1990s. Implementation of the project would depen~ 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, there are sufficient proven and probable reserves of conventional gas in the Lower Forty (15) Eight states to last fifteen to twenty years. When all of these factors are considered, it does not appear that the PALNG project will be implemented, at least not until 1995 or after. The recoverable reserves originally c~)rumitted to PALNG can, therefore, probabli' be acquired by other purchasers such as Chugach Electric Association and Ens tar. The proposed TAGS project would build a natural gas transmission line from Prudhoe Bay on the North Slope to the Kenai Peninsula (near Nikishka). The gas from the North Slope would be Liquefied and sold to d h A . . (16) Japan an ot er s1an countr1es. If the project were implemented, Cook Inlet gas producers might be able to sell their gas to TAGS for liquefaction and sale to Asia. Sale would depend on the capacity of the liquefaction plant and the market for LNG. The price that could be paid by TAGS to Cook Inlet producers might be high enough to outbid competing pur chasers since the Cook Inlet gas would not be burdened with the costs of the transmission line from Prudhoe Bay (although shorter transmission and gathering lines would probably be required). Any estimate of the probability of whether TAGS will be implemented is difficult at this time, since the report on the project has just been published and there has not been sufficient time for the proposal to be analyzed by many concerned and interested parties. We have, however, attempted to estimate the maximum price that TAGS would probably be willing to pay Cook Inlet ,..-., ~\Ytf?Rltfflf'~M'SMK® (t'~' IWLd' ,, '1 producers for gas delivered to the TAGS liquifacation plant (see the following section entitled, Current Prices). North Slope Gas Over ninety per cent of the North Slope ga.s is currently reinjected. Some ~s used in field operaticns and a small amount is sold to the TAPS, used 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 4 shows North Slope production and use for 1982. The problem in us~ng North Slope gas for Railbelt electrical generation is that a pipeline must be constructed to bring the gas to where its needed, i.e. Fairbanks or Anchorage or an electrical transmission line must be built so that power generated on the North Slope can be brought to load centers. The major proposals for utilization of North Slope gas are discussed below. Alaska Natural Gas Transportation System (ANGTS): This plan would construct a pipeline from the North Slope via Fairbanks and through Canada to the Low~r Forty Eight. The project has been temporarily shelved due to a high estimated delivered price and the resulting difficulty in obtaining financing. The project will prop~ably not be operational before the early to mid-1990s, if ever, so North Slope gas Table 4 Current Production and Use of North Slope Gas For 1982 Use Injection Field Operations: Vented~· Used on shrinkage Sales ' Power generation ( civilian) Gas utilities (residential) Other sales Refineries TAPS Misc. Total Quanity -BCF 671.0 0.4 0.5 0.5 11.9 0.2 734.7 Source: ''Historical and Projected Oil and Gas Consumption Jan. 1983", S~ate of Alaska, Dept. of Natural Resources, Division of Minerals and Energy Ma~agement, Table 2.7. t~ : ,, ,,· ,, ••• "'~, >'• , I ~i.· : ~' ' ' ·.I :-~~' J . from this method can not be counted on to provide Railbelt electrical generation. Trans Alaska Gas System (TAGS): This alternative was recently proposed by the Governor's Economic Committee on North Slope Natural Gas and would construct a pipeline from Prudhoe Bay to the Kenai Peninsula where the gas would be liquified and sold to Japan and other Asian countries.(l 7 ) Some of the gas could be utilized for power generation at Kenai (or conceivably from a tap at Fairbanks although an additional processing plant would have to be installed since the gas is to be piped in an unprocessed state). Implementation of the TAGS is highly uncertain at this time and therefore cannot be counted on to provide gas for electric generation. Pipeline to Fairbanks: In this plan, the North Slope gas would be piped to Fairbanks via a small diameter pipeline where it would be used to generate electricity for the Railbelt Area and also to meet residential and commercial heating needs ~n Fairbanks. Cost studies have shown that this method is economically inferior to other ~!"~posed methods for utilization of North Slope gas and will the~ore probably not be implemented. North Slope Generation: This proposed plan is an alternative to transporting the gas by some means, for the gas would be utilized in combustion turbines located on the North Slope and the electricity : -r~--~-~~~--~-----.-··:·~~-··-----·· -·----········"···· .. ·· ·-........................ ~-----·-· .. ·-··· - . I '.~.'!l'z ·n·n:ru f · ·~--·-"*" ""''"'"'~-· transmitted to the Railbelt Area. Cost studies have been developed, but there do not appear to be any serious proponents of this method. 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. Current Prices of Natural Gas There is no single market pr1.ce of gas in Alaska s1.nce a well developed market does not exist. In addition, the price of gas 1.s affected by regulation via the Natural Gas Policies Act of 1978 (NGPA) which specifies maximum v1ellhead prices that producers can charge for various categories of gas (some categories will be deregulated 1.n 1985). 4. There are some existing contl".\cts for the sale/pur chase of Cook Inlet gas which specify wellhead prices but since there are no existing contracts for the sale of North Slope gas, the wellhead 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. ·-..... ""· L L L L Cook Inlet Currently there are four contracts for the sale/pur chase of Cook Inlet gas where the contracts were negotiated at arms length and the contracts are public documents. These are: (1) Chugach Electric Assn./Chevron, ARCO, Shell contract for 1 . . ld ( 18) pur chase of gas from the Be uga R1 ver F1e • ( 2) Enst ar /Union, Marathon, ARCO, Chevron contract for pur chase f fr h . . ld ( 19 ) o gas om t1e Kena1 F1e • (3) Ens tar /Shell contract for purchase of gas from the J~ Field. (2 0) &..t..h. ~ ( 4) Ens tar /Marathon contract for pur chase of gas from the ~ "-~~ R.., c=t:~r c> c.- Field~ (2 0) The Chugach contract current pr 1 ce 1s about $0. 28/MCF and under the terms of the contract is estimated to increase to about $0. 38/MCF ~n 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 will terminate in 1995 since 285 BCF remained under the contract on January 1, 1982 (See Exhibit 1). -- The Ens tar /Union contract current wellhead price is about $0.27/Mcf and becomes about $0.64/Mcf when delivered to Anchorage because of the addition of transmission costs. The wellhead price remains at $0.27/Mcf until 1986 where the price becomes the average pr~ce that Union/Marathon receives from new sales to third parties. If there are no new sales, the price will remain at $0.27/Mcf until contracted reserves are taken (estimated to be 1990 by Battelle) or the contract expires which is in 1992. Like the Chugach contract, this gas will not be deregulated by the NGPA in 1985. The Ens tar/ Shell and Ens tar /Marathon contracts were both signed in December 1982 and are essentially the same in that they have a base wellhead price of $2.32/Mc: in 1983 with an additional damand charge of $0.35/Mcf beginning in 1986. The base price and the de~and charge are to be adjusted annually based on the price of No. 2 fuel oil at the Tesoro Refinery, Nikiski, Alaska. The contracts terminate in 1997 or whenever the contracted quantity of gas has been taken. The wellhead price of the gas under these contracts will probably not be deregulated ~n 1985 by the NGPA since the No. 2 fuel oil price adjustment mechanism is classified as an ''Indefinate Price Escalator'' and contracts containing these are specifically excluded under Section 121 (e) of the NGPA (see discussion under Deregulation section). The Phillips/Marathon LNG gas is not regulated and appears to have a wellhead price that fluctuates with the delivered price of LNG in Japan which is tied to the world price of oil. Sources have quoted the wellhead price as .$2.07/Mcf in 1980( 2 l) and $2.02/Mcf in 1982. (22 ) Estimated Price For New Purchases: If 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 pr1.ces 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 and thus are not important in the Susitna vs. gas-fired unit alternative analysis which covers the period 1993-2040. 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 somewhat 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 above. The wellhead 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 on the Ens tar /Marathon contract applies to all gas taken under the contract from January 1, 1986 to contract expiration. Under the Ens tar /Shell contract, the demand charge of $0.35/Mcf applies only if daily gas take is in excess of a designated maximum take. Enstar expects they will incur the demand charge because of electric utility requirements that increase the daily take.(2 J) Severance taxes of $0.06/Mcf and a fixed pipeline charge of $0.30 for pipeline delivery from Beluga to Anchorage are additional costs. Future prices (Jan. 1, 1984 and on) are to be determined by escalating the wellhead price plus the demand charge based on the price of #2 fuel oil in the year of escalation versus the price on January 1, 1983. If it were assumed that the generating units were located at the source of gas./ the pipeline charge would be eliminated giving a Jan. 1, 1983 price of $2.38/Mc£. (See Table 5) The price 1n Table 5 seems to represent the best estimate currently available for the cost of Cook Inlet gas for electrical --------~----------r-. _-=.-- ~ .•. p ....... 'tttttttW"St'bfcif&'w··· tt 1 #en""'sss&u,,L- < ' ·· .. ··1.·. TABLE 5 Estimated Base Prices for New Pur chases of Uncommitted & Undiscovered Cook Inlet Gas Without LNG Export Opportunities 1983-1986 1986-1997 $2. 32/Mcf Wellhead Price $2.32/Mcf 0.35 Additional demand charge (1) o.o 0.06 Sever a nee tax 0.06 1 Total (2) $2.38/Hcf $2. 73/Mcf (unesca1ated) Transmission charge (3) 0.30 0.30 Delivered to Anchorage $2.68/Mcf $3. 03/Mcf Demand charge of $0.35 on Ens tar /Marathon contract applies from January 1, 1986 on while demand of $0.35 on Ens tar /Shell contract applies only if daily gas take is in excess of d designated maximum take. 2 Prices are escalated based on the price of No. 2 fuel oil at the Tesoro Refinery, Nikiski, Alaska beginning Jan. 1, 1984. 3 E . d . . $ 3 I f st~mate transm~ss~on charges would be about 0. 0 Me . Per telephone conversation with Mr. Harold Schmidt, VP Enstar . .... ~.· ' generation. Therefore this price was used as the cost of fuel for gas-fired generation in the thermal alternative to Susitna over the period 1993-2040. Since the price is tied to the future price of oil, it was escalated based on the estimated future price of oil to obtain pr1ces f~ 1993 to 2040 (See Projected Gas Prices Section}. Although the possibility of unconnnitt.ed Cook Inlet reserves being purchased for LNG export seems to be remote at the present time, it is interesting to speculate as to what price producers might be able to obtain if LNG export opportunities existed. A method that can be used to estimate wellhead prlces for LNG export is to begin with the market price for delivered LNG and then subtract 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. LNG would compete with imported oil in those markets and its price would therefore be dependent upon the world pr1ce of oil. An example of this LNG/oil price competitiveness• is the existing contract between Phillips/Marathon' and the Tokyo Gan a~\d Toyko Electric Companies where the delivered price of gas is equal to the weighted average price of oil imported to Japan. ( 24 ) For an imported oil price of $34/bbl, the equivalent LNG price would be about $5.85/Mcf (1000 Btu/Ft3 gas) and for an oil price of $29/bbl~ $5.00/Mcf. -l-· ~ _,.. __ Conditioning, liquefaction, and shipping cost estimates were recently developed fby the Governor's Economic Committee in their study of a ~ans Alaska Gas System (TAGS) which would transport North Slope gas to the Kenai Penin$ula via pipeline, then liquefy and ship the LNG to Japan.<25 ) These estimated costs are based on the large volumes of gas available from the North Slope. An LNG facillity for Cook Inlet gas only would be considerably smaller and there might be some ecouomies of scale in going from a small to a large facility. These economies are not believed to be large however. In addition, its just as likely that 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, liquefaction, and shipping of $2.00/Mcf from the TAGS study are therefore believed to be representative for estimating the wellhead price of Cook Inlet gas where LNG export opportunities exist. The estimated, net back, wellhead price of Cook Inlet gas for LNG export is shown in Table 6. The price would vary depending on the average price of oil delivered to Japan S.\O prices based on $34/bbl and $29/bel 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 with no LNG export opportunities shown in Table 5. Therefore, if LNG opportunities did exist, the price of Cook Inlet gas for electrical generation would be higher than the price we have adopted (Table 5) since the utilities would have to outbid potentia.l LNG exporters. l f • - TABLE 6 ~stimated 1983 Base Prices for Nsw Pur-chases of Uncommitted & Undiscovered Cook Inlet Gas With LNG Export Opportunities . ( 1) LNG Pr1ce -Japan $5.85/Mcf $5.00/Mcf Less: ( 2) Conditioning 0.34 0.34 Liquefaction 0.95 0.95 Shipping 0.71 0.71 Subtotal 2.00 2.00 . . d (3) Max1mun Pr1ce to Pro ucer $3.85/Mcf $3.00/Mcf 1 Based on oil pr1ces of $34/bbl and $29/bbl. 2Based 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 Reference 1~ 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.) 3neliver ed to LNG liquefaction facility. Transmission costs assumed to be negligible. ··~~-~··-~-·~·-.. ···~·--···-.. --..... ,·~··-··-·· .. ·------------·· --·--· ·-. -,.·----·:__. .. :zt 'fW1Wtttre•urtrtf t1 ~ r rr · r rr~r-crmre 'tt · t,,'t. =~-· •• s . -,;. North Slope The relevant pr1.ce of North Slope gas for use in Railbelt electrical generation is the "delivered price", that is, the price of gas delivered to generating units located near the electric load centers or if generation were to take place on the North Slope, the equivalent price for electricity delivered to the load centers. The delivered pr1.ce is dependent upon the wellhead pr1.ce that must be paid the North Slope producers and the cost of delivering the gas (or elect.:ricity) to the Railbelt load centers. The price that producers would accept 1.s unknown but it is evident that they don't have a large number of alternatives to utilize the gas. They can shut the gas in or reinject as they are presently doing or sell to some entity that will transport the gas (or electricity) to market. There is a maximum price that the producers can charge since the gas 1.s regulated by the Natural Gas Policy Act of 1978 but the only minimum would seem to be the value obtained from reinjection. One method of estimating a North Slope wellhead price 1.s to begin with a known or estimated pr1.ce that the gas would brir'tg in a g1.ven market and subtract the estimated costs to deliver the gas to that market. Since the sales price depends on the market to which the gas is delivered and the costs depend on the distance and method of delivery, it is best to discuss the North Slope wellhead price and l"~·~····~.=: ~~*itsttt¥1 -~(?:t 7ttrtltrt""i&t'i&'· r+r·t -~ ~ ~ .. ..... - the cost of using the North Slope gas for electrical generation by the transportation method employed. This is done below for those trans- portation methods described under the section, "Production and Use o£ Natural Gas". Alaska Natural Gas Transportation System (ANGTS): The ANGTS o..l proposee was to deliver North Slope gas to the Lower Forty Eight but . ~ the line passes close enough to Fa~rbanks ~ that some gas could be used there for electric generation (and heating). Battelle estimated (26) the transportation costs to be about $3.80/}fMBtu. Even at a zero wellhead price, the gas cost for electrical generation would be well above the cost of Cook Inlet gas and at the maximum wellhead pr~ce I n"bv of*~~/=(~ 1983) the delivered price would be f;.1~.,JMM13tu. Because implementation of this project is doubtful, its estimated gas costs are not considered to be reasonable prices to use as imputs 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 and the costs that electric utilities would have to pay to buy the gas can be estimated from information in the TAGS report. This information is presented in Table 7 for the total TAGS system and Phase I of the system. A low tar iff which would provide a 30% after tax return to equity investors and a high tar iff which would provide 40% are shown for both the total system and Phase I. r t -*"·-·--- - TABLE i' Estimated Cost of North Slope Natural Gas for Electric Generation at Kenai Assuming Implementation of the Trans Alaska Gas System (TAGS) Total System ____ P_hase I System __ _ Estimated 1983 {l) LNG Price per MM Btu Less Costs :(J.) Shipping Liquefaction Subtotal . . . (3) M1n1mum 1983 pr 1 ce -.(I~ Condition' Costs Pipe line Costs <.cJ-) Wellhead Price(~) .!,. J. Low Tariff $5.85 0.71 0.95 $1.66 $4.19 0.34 2.04 1.81 $5.00 0.71 0.95 $1.66 $3.34 0.34 2.04 0.96 High Tariff $5.85 0.71 1.18 61 og y~.u $3 .. 96 0.42 2.79 0.75 $5.00 0.71 1.18 $1.89 $3.11 0.42 2.82 (0.10) L0W Tariff $5.85 0.71 1.00 $1.71 $4.14 ~.42 2.82 0.90 $5.00 0.71 t.OO $1.71 $3.29 0.52 .L86 0.05 High Tariff $5.85 0.71 1.26 $5.00 0.71 1.26 $1.97 $3.88 $3.03 0.51 0.51 3.86 3.86 (0.49) (1.34) (l)LNG prices are delivered prices to Japan and are equivalent to $34/bb1 oil (2 ;or the.$5.85/MMBtu price and $~9/bbl.oil for the $5.00/~1Btu price. Costs 1n the report are shown 1n nom1na 1 1988 dollars wn1ch were con- (3Jerted to 1983 dollars using the study's inflation rate of 7%. Minimum price TAGS would accept from utilities .for purchase of gas at c41NG gas conditioning facility. (5 )For pipeline from North Slope to Kenai Peninsula. lv!aximum 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 Comrn:i..tt;:ee on North Slope Gas, January, 1983. See Exhibits C1 and C2 and pgs 18 and 46 of the Marketing Study Section~. The price that electric utilites would have to pay is dependent upon the LNG sales price in.Japan so prices o£ $5.85/MBtu and $5.00/ MMBtu have been shown. These correspond to oil prices in Japan of hbl bbl $34/~ and $29/~ 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 ·~n be seen, prices vary from $3.03/MMBtu to $4.19/MMBtu but the lower prices may not be realistic since they may result in low or negative wellhead prices to the producers. In addition~ at an estimated sales price of $5.00/MMBtu the TAGS would probably not be implemented. SubtractiDn 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/}'IMBtu or above, that the total system would be constructed and that some point between the low and high tariff was -t4)r-S acceptable to inv~3 and North Sl~pe producers, then lhe price of gas ~t"w" to electric utilities at Kenai would be $3.96-$4.19/m.iBtu.* These *This would provide investors an after-tax return on equity between 30 and 40% and North Slope producers a wellhead price between $0.7 5 and $1.81/MCF. ··r··-·-- ~ .......... f ... ... I I' I' ! (, I assumptions seem to be reasonable and a 1983 cost of North Slope gas of $4.00/MMBtu for electric generation will therefore be assumed. Pipeline to Fairbaks: Transportation costs of a small diameter -.. '~ pipeline to Fairbanks have been estimated to be about $4.80/MMBtu for l . l . (27) e ectr~ca generat~on. Using the average of the reasonable TAGS wellhead prices discussed abcve of $1.28/M...~tt.. (ave. of $0.75 aml $1.81/MMBtu) provides a delive~ed cost in Fairbanks of $6.00/MMBtu. '• This cost is considerably higher than the estimated cost from TAGS and was therefore not used in the analysis of thermal alternatives. North Slope Generation: This alternative uses the North Slope gas without incurring tr anspor tat ion costs for the gas. However, the generated electricity must be transmitted to the Fairbanks load center thereby requiring the construction of an electrical transmission line. The capital costs and O&M costs of this line have also been estimated d h b 8o al f h • • 1 . ( 28) -' an t ey are a out ~~ o t e gas tr ansJ.:USSlon ~nes. Base a en this, an equivalent "gas" transportation cost would be $3.89/MMBtu (0.8 x $4.8/MMBtu) which when added to a wellhead price of $1.28/MMBtu would res":..llt ~n an "equivalent delivered" cost of gas of $5.12/MMBtu. This is less than the small diameter pipeline alternative but still considerably more than the TAGS delivered cost. This price was therefore not used in the analysis of thermal generation alternative~. The estimated delivered cost of gas to Railbelt load centers based i) on transportation costs and assumed wellhead prices are shown in Table 8. The only cost used as an imp~ to the ~ ~ ~~~~ ~ P-e-~ ~ -f--_;t4 TAGS' ~ ,_(.;J. ~ ~ ;t,.. A~· .r?-f.OO/.MifAIJ-{:r./...,;.. ;qg-3 ~. ·r .. ·· ----c-,~. -~-~-.. ----···,-·~·--·---. --···~ .... -• .J(~ ' I' ' ' '• ' < ' .-, ~ ~ .. ...J! •• L.;u~~~-""'-""~~......-... ,,._,,,.!,l,~~ ................ • ·~ y/1 t ·-. ,, TABLE 8 Estimated 1982 Delivered Cost of North Slope Natural Gas For Railbelt Electrical Generation Delivery Method ~ ANGTS(l) TAGS(~) Pipeline to Fairban~s(~~ North Slope Gener a.t1.on ., ) Estimated Cost $/MMBtu 4.03-5.30 3.96-4.19 4.80-6.08 3.84-5.12 Value Used $/MMBtu 4.00 1cost 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. 2costs estimated using a "netback" approach. of $4.00/MMBtu selected as reasonable val~e alternatives analysis. See Table 7. Value for thermal gener a.tion 3 . d . . 1 d fr f 27 Costs est1.mate us1.ng cap1.ta an O&M costs om Re erence . 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&H costs from Reference 27. 1'hese costs are "equivalent11 costs for the gas would be burned on the North Slope and the etectricity delivered to Railbelt load centers via an electric transmission line. The ''equivalent" costs were determined by comparing the costs of the electric transmission line with the costs of the gas pipeline to Fairbanks. The $3.84/MMBtu assumes a wellhead price of zero and the $5.12/MMBtu a wellhead price of $1.28/MMTbu. \ ·' ····T· } / I~ 1 TABLE 8 Estimated 1982 Delivered Cost of North Slope Natural Gas For Railbelt Electrical Generation _Delivery Method ~ ANGTS(l) TAGS(~) Pipeline to Fairbanks())\ North Slope Generation(+,~ Estimated Cost $/MMBtu 4.03-5.30 3.96-4.19 4.80-6.08 3.84-5.12 Value Used $/MMBtu 4.00 1 cost of $3.80/MMBtu in 1982$ ~ assuming a zero wellhead cost was estimated by Battelle. This was adjusted to 1983$ to provide the $4.03/MMBtu. The $5.30/MMBtu includes an assumed wellhead cost of $1.28/MMBtu. 2 costs estimated using a "netback11 approach. of $4.00/MMBtu selected as reasonable val~e alternatives analysis. See Table 7. Value for thermal generation 3 . d . . 1 d fr f 27 Costs estLmate us1ng cap1ta an O&M costs om Re erence . The cost of $4.80/MMBtu assumes a wellhead price of zero while the $6. 08/MMBtu 'price assum.~s a wellhead price of $1. 28/MMBtu. 4 . d . . 1 d £r f 27 Costs est1mate us1ng cap1ta an O&M costs om Re erence . These costs are "equivalent" costs for the gas would be burned on the North Slope and the electricity delivered to Railbelt load centers via an electric transmission line. The "equivalent" costs were determined by comparing the costs of the electric transmission line with the costs of the gas pipeline to Fairbanks. The $3.84/MMBtu assumes a wellhead price of zero and the $5.12/MMBtu a wellhead price of ~i.28/MMTbu. · · ·· • .--"h·c l--. ·c• .. ;::.,., ~··-"1?"'"'-----·-........ .._,"->./<_ ::~ -v-~--.... ---:::i"'-"'~-···· ~-... ,_, .... ,. """'---~--~·,r-·-.... ··~·---·~ .... ..-~ .. ~·--,, ~~Iiiii~~ ~-:_·.,' ~ 4~:;:=:: :Pet l l \ 4 i L t. c.. .. •~ on transportation costs and assumed wellhead prices are shown in Table 8. The only cost used as an input to the thermal alternative analysis, however, is the cost derived from the TAGS study and found to be about $4.00/MHBTU in 1983 do:.lors. Projected Gas Prices The estimated 1983 costs of Cook Inlet and North Slope gas w·ere 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 tie the price of natural gas to the world price of oil s~nce the two fuels can be substituted in many cases and particularly si{clje the recent Ens tar gas pruchase contract price 1.s tied to the price of oil. The Enstar price was used as the 1983 eF:.timated price of gas ff{j the Cook Inlet area and it is assumed to be representative of future contracts for Cook Inlet uncommitted and undiscovered gas. If North Slope gas is sold as LNG to Japan or Korea, the delivered price will probably be t led to the world pr i'ce of oil in the same manner as the existing Phillips/Marathon LNG contract. Electric utilities who purchase gas from the LNG exporters will probably also have t;fpay a price which is adjusted to the world oil price "'!"!"' JJ4. 4% (see Table 7). Therefore, it ~s assumed that future pr~ces of North Slope gas for electrical generation will also fluctuate with the world pr~ ce of oil. The oil pr~ce forecast that is selected to project future Cook Inlet and North Slope gas prices is therefore critical in the analysis of thermal generation alternatives. The following sections review a range of forecasts. Oil Price Forecasts Forecasting the future world pr~ce of oil is a perilous task at best and most previous forecasts have been l3cking in accuracy particularly over the last ten years when oil markets received radical upward price shocks. Some forecasts can be considered to be better than others, however, largely because of the methodology used, the e. exper~ence level of the forecast~rs, and the reason~ng behind the forecas;ts. In this category, we would include Sherman Clark Associates, Data Resources Inc., and the Energy Modeling Forum. We have re\riewed the forecasts by these entities as well as the forecasts by the Alaska Department of Revenue. The forecasts are presented and discussed in the following sections. Sherman Clark Associates Sherman Clark has over thirty-five years of exper~ence in the field of energy including twenty years with Stanford Research Institute as Director of Energy and Resource Economics. Sherman Clark Associates (SCA) prepares annually a detailed 25 -30 year forecast of the supply and demand for energy and resulting, estimated pr1ces. The SCA fore- cast prices for oil and coal presently are for three scenariqs to which probabilities of occurrence have been assigned. SCA's latest scenarics are: Base Case. In this scenar1o, oil pr1ces decrease from the existing 1983 price. of $29.00/bbl to $26.30/bbl in 1983 dollars and remain at that level until 1989 where SCA has assumed a severe supply description will occur, caus1ng prices to jump to $40.00. Prices will remain at $40/bbl until 1990 where they will increase at a real rate of 3% until 2000 and then at a 3.5% real rate until 2010. The severe supply description envisioned would be an overthrow of the Saudi Arabian government by a radical element that would severely cut back on oil production or a war involving Saudi Arabia where the ability to produce oil was severely damaged. SCA has assigned a 40% probability o.f occurrence to this scenario. From 2010 to 2020 SCA estimateSa rea 1• rate of increase of 1. 5%/ yr. and from ;_020 to 2040 a real rate of 0%. No Supply Description Case. This case 1s similar to the Base Case, but no severe supply description occurs. In addition, there is an assumption that more Non-OPEC crude will be found and produced. Estimated prices drop to $26.30/bbl and rema~n there until 1989 where they rise at a real rate of 3%/~· to 2010. SCA has assigned a 35% probability of occurrence to this scenario. For 2010 to 2020 SCA estimates a real rate of 2.5%; 2020 to 2030 a rate 1.5%; and 2030 to 2040 a rate of i.O% Zero Economic Growth Case. This scenar~o assumes that there will be no economic growth until 1990. Consequently, prices drop to $17.00/bbl until 1990 where they begin to rise at a real rate of 5%/yr to year 2010. SCA has assigned a 25% probability to this scenario. SCA has made no estimated projections past 2010 for this case. Data Resources Incorporated (DRI). DRI is a well-known forecasting organization which provides forecasts of GNP, economic indicators, and commodity prices including prices for oil 1 %d coal. Extensive use ~s made of econometric and other computer models including special energy forecasting models such as the DRI Drilling Model, DRI Coal Model and the DRI Energy Model. Worldwide supply and demand for oil are estimated td arrive at a forecast price for oil. DRI's spring 1983 base case forecast shows a negative 13% real change for 1984, a 7.4% real change from 1984-1985, about a 6.5%/yr. real increase from 1985-1990, a 4.4%/yr. real ~ncrease from 1990 to 1995 a 3.1%/yr. real increase from 1995-2000, and a 1.1%/yr real increase from 2000-2005. Assuming a 1983 price of -···~·-··-·····-···-·······----~·-· :d) ... ·~·-, ..... -~~~-"'~--~~---" ""''""'·--~ . -····"!- ./arm t lrurlflilll~lllllilil11 rrr r rrtl .... ·-·--·--.. --. $28.95/bbl, the price in 2000 would be about $53/bbl and if the 1.1%/yr. rate of price increase was assumed to continue until 2010, the price at that point in time would be about $60/bbl in 1983 dollars. DRI has also formulated low and high pr~ce scenarios but has not assigned a probability to any of the forecasts. It therefore is assumed that its base case forecast is the likely or most probable outcome. Energy Modeling Forum (EMF). The EMF was created by the Electric Power Research Institute (EPRI) to improve the use and usefulness of energy models. The EMF ~s administered by the Stanford Institute for Energy Studies which ~s ~n the Dept. of Engineering -Economic Systems and the Dept. of Operations Research. The EMF operates through ad hoc working groups of energy mode.l developers and users. Each group 1s organized around a single topic to which existing models can be applied. One of the groups, with members from around the world, addressed issues relating to oit price, availability, and security of supply. The results of their study were reported in an EPRI publication entitled, World Oil.29 The objective of the study was to analyze world oil issues through the application of lO prominent world oil models to twelve scenarios designed to bound the range of likely future world oil market conditions. The ten models used are listed in Table 9. The twelve scenarios include a reference or base case which is not necessarily EMF's most likely case but rather 1.s a plausible mean case which can be considered as representative of the general trends that can be expected. The twelve scenarios are listed in Table 10. In general, EMF expects a soft oil market for the 1980's with little. or no real price increase until 1990 unless there is a supply disruption. Beginning in 1990, real pr 1.ces wi 11 increase over the next several decades in either steady upward movements or in sudden price jumps followed by gradual declines. EM's reference case shows median real price increases of 2% annually between 1980 and 1985, 6% annually for ' 1985 to 1990 and 4% for 1990 to 2000. Star tir.<5 from a J.983 pricP level of $28.95/bbl, this results in a price of $30/bbl in 1985, $40/bbl 1.n 1990, and $60/bbl in the year 2000. If the 4%/yr. real increase continued to the year 2010, the price would be about $88/bbl in 1983 dollars. EMF's other eleven scenarios result, of course, in prices different from the reference case. The relative outcome of the other eleven scenarios is illustrated in Figure 4 which shows the estimated world oil price in the year 2000 for all ten models for e9.ch of the TABLE 9 Models Used in the World Oil Study Hodel Gately-Kyle-Fischer lEES-OMS (International Energy Evaluation System-Oil Market Simulation) IPE (International Petroleum Exchange) Salant-ICF ETA-HACRO WOIL Kennedy-Nehring OIL TANK dpeconomics OILMAR Organization(s) New York University Imperial Oil Ltd. U.S. Department of Energy Massachusetts ~nstitute of Technolog~· U.S. F~de~al Tr1de Conmission ICF, Incorporated Stanford Univers~ty U.S. Department of Energy/ Energy and Environmental Analysis, In corpora ted University of Texas Rand Cor por at ion Chr. Michelsen Institute British Petroleum Co. Ltd. Energy and Power Subcommittee, U.S. House of Representatives II TABLE 10 Scenario Descriptions ---·------------------------------------------------------------ Scenario 1. Reference Case 2. Oil Demand Reduction 3. Low Demand Elasticity 4. Oil Demand Reduction- Low Demand Elasticity 5. Low Economic Growth 6. Restricted BAckstop 7. Disruption 8. Technological Breakthrough 9. Disruption-Low Demand Elasticity 10. Optimistic 11. Disruption-Oil nemand 12. High Oil Price Description base case for analysis agressive import reduction program in the OECD reduction in demand elasticities to 5/8 of reference case agressive import reduction program in low elasticity world reduced GNP growth rates throughout the world 50% reduction in availability continuing 10 MMBD reduction in OPEC capacity in 1985 sudden and indefinitely continuing 10 MMBD reduction in OPEC capacity rr du ced cost and incr e,':l.sed availability of nonconventional energy 10 MMBD OPEC capacity reduction in low elasticity world aggressive import reduction program; more availability of nonconventional ene.r,;y; increased OPEC capacity 10 MMBD OPEC capacity reduction in pre;:;ence of agressive import reduction program oil price 50% higher than values determined in reference case I ' ' d ~· ~--·" ..,,,..,...,__,~ ---•~-.-..-..•~· C'"'""-':'"'"'._,."'._~-•·•-·u •-.~.,....__..,.-~..._.,_,_, - .~.' .. "'~ ---! I ' 1 ! ~ '-0 th:! --" -----,-:--' 7 ~ Scenario 1. Reference 0 20 W9rld Oil Pr!ce in Yea.r 20'00 l198l dollare per barrel) JIO 60 80 100 120 i40 r-------~~ • B C G I W S K 0 160 A E _l___ ______ _1__~---L _________ L____ t _ _ 1 l • I 1 2. Oil Demand Reduction C I W A 0 E 3. Low Demand Elaeticity a o s K I I B WIG S C E ;\ ! L_ ,_, ___ l_---! 4. Oil Demand Reduct.ion-B W I C A S E 0 LQw Demand Elaetici ty G K l ___ _l___~ _ _ _j_ ___ _ _ ___l_ _ _____ __L_~ ____ __L___~J-~~ __ J I 5. Low Economic Growth B I C 0 li: G W S K I ! I ' 6. Rtletricted Backstop \1 S A E 0 I K I • ___.1. __ _ 7. Dbruption B 0 C W I S K A E 0 I , I I I C S E A W K 0 8. Technological Breakthrough -J ~ ___ ___j__ ____ __j___ I ! I I __ _ 1 B w G ~ S i 9. Disruption-Low Demand Elasticity I I I I I I 10. Optim.htic 11. Di~ruption-011 Demand Reduction 1 SWK GE 0 I L_ , 1 IA I__ J~----' B c G W I K A 0 E s I _ _ _ _ 1. ______ ---~~ l _ I L_ __ J I L ____ , L__ _ L _______ l Models: G : Gately, I : IEES-OHS, 0 • OILHAR, E = OILTANK, C = IPE, A a ETA-MACRO, K & Kennedy-Nehring, W z WOIL, S & Salant-ICF, B : Opeoonomioe Note: For all modeh other than IEES-OHS and IPE, the average of price:s between 1995 antS 2005 h given. For IEES-01-tS, the 1995 price b presented; for IPE, average:~ between 199S and 2000 are t~reeented. Several projections are higher than $160/bbl and thus do not appear above. The~e include: for the low demand ela3t1city scenario, Kennedy-Nehring ($175) and OILMAR ($177); for the dieru~tion-low demand elasticity :!Cenario, OILTANK ($1811), IPE C$198)1 Kennedy-Nehring ($217), and OILHAR ($1117). :FIGURE 4 -World Oil Price Forecasts For Eleven Scenarios Using Ten Different Energy Forecasting Models ·~-":<-'_. -.:r-r--:-"~"f n ~ ,-, '.J .,......~.,..·-~-.,...,-~--~~~~;";'.-.r# .. pt~:_,"'·~~""::-~;----~~~~,.,~~,.~~~iir~~~~_..,_...- I i { f' [· I . [1; I i- t •\ r l_· .• L l-' ~ . I, l ! . J· l~~· !tl. lt. __ w_ ~:~ ... , t b \\ ,, I ~-~ f" !. J ___ .... ~ twelve scenarios. The price is shown in 1981 dollars, and if converted to 1983 dollars would be about 10% higher •. (The director of EMF has indicated, however, that if the estimates were redone in 1983 they would be 10-15% lower.) The significance of Figure 4 is that the results using the ten models in the twelve scenarios are a clustering in year 2000 of world oil price in the range of $50 -80/bbl. Alaska Department of Revenue (DOR). The Alaska DOR prepares forecasts of world oil prices to use as an input to their revenue model. The revenue model provides an estimate of the quantity of revenue from o1.l and gas royalties and other sources that the state can expect to receive annually through 1999. The DOR's oil price and revenue forecasts are updated quarterly. The Alaska DOR arrives at its forecast of oil prices through the "Delphi" method which consists of questioning persons knowledgable in the area of energy and oi.l and at tempting to arrive at some sort of consensus as to what future oil prices will be. £he DOR forecast results in the lowest oil prices by the year 2010 although the SCA Zero Economic Growth estimate has lower forecast prices from 1983 -1998. The DOR's forecast oil pr1ces decrease from $28.95/bbl in 1983 to a low of $'!2/bbl in 1987 and then increase at an average real rate of about I l 1.3%/yr. from 1988 -1999 resulting in a price of about $26/bbl in 1999. If the 1999 DOR price is escalated to 2010 at the same 1. 3%/yr. rate, the price becomes about $30/bb l. Discussion and Recommendation. The Sherman Clark Associates, Data Resources Inc., and Energy ~~!odeling Forum forecasts seem to be based on detailed analyses of the supply of and demand for oi 1 over the forecasting period. All of these forecasts reflect the existing soft market for oil that may continue for several years. However the forecasts also reflect the high probability of a world economic recovery frum the 1981 -1982 recess~on and the resulting increased demand for oiL In ad~ition, the forecasts reflect the fact that oil is a depletable resource an0. at though i...her e are some substitutes, eventually the dwindling world supply should result in higher real prices bar~i~6 some dramatic technological break through. The DOR forecast of oil is developed by the 11 L'elpbi" method, i.e. by questioning various knowledgeable persons in the energy field and th0n using the pr~dominate thinking of the group questioned to develop a forecast. This method depends heavily on the particular persons questi-:>ned and may be overly influenced by particular influential indiv·duals in Alaska who believe in the imminent breakup o£ OFEC as the .. :;jntrolling force for the world price of oil. While OPEC appears to have lost some power in the last year, as evidenced by the drop in the official pr~ce of oil from $34/bbl to $29/bbl, an accord between the OPEC members seems to have been reached concerning the quantities . ~--A~ ~~~-· of oil produced sa that the price seems likely to hold at $29/bblA The relatively strong economic recovery that is currently underway in the U.S. ,.,ill undoubtedly be followed by the rest of the free industrial. world ~nd should support the benchmark price and eventually allow OPEC to increase the price as demand for oil increases. A zero economic growth oil price scenario therefore seems unlikely and comparing the false starta in economi~ recovery of 1979 & 1981 where inflati6n was fl :1igh ·and une1~plo:yment low with the current situation where inflation is lo~1 and unemploym.ent 'bi.gh would appear to involve speclous reason~ng. We believe that the most likely future oil price scenar1o shoJld therefore lie somew·here within the forecasts of DRI, EMF, and Sherman Clark Associates. Ignoring the Sherman Clark ZEG scenario which we believe to have a probability considerably less than 25%, the future price of oil in the year 2010 should fall somewhere betweeti $50 and $75/bbi. This price range would seem to be substantiated by the twelve scenar-t.os run by the EMF (see Figure 1) which show the prices 1.n the year 2000 lo be group1ng in the range of $40 to $80/bbl. Taking the approximate middle of these estimates would seem to be I a reasonable approach to obtaining an estimate of future oil prices. This would equate to a constant price of $28.95/bbl from 1983 through 1986, a real rate o£ increase of 2.9%/yt:. from 1987 through 1998, and a J f . . , ' --·---~--------·-··--"-1 ......... ~, .. -... ~ ... ""''''"'"''-·'~ -·---··---·-.. ·---·-·---.. -.~ ..... ·~·-·--d . -~r-~ -~---······.-...... -----.-----------~-~-... , .... _ .. __ 00 ... ~··--~---~~-·--:-........ ~.~. f I 3 .0%/yr. real rate of increase from 1999 to the year 2000a This forecast translates into an oil price of about $44/bbl in the year 2000 and $5H/bbl by 2010. This forecast, entitled the "reference case", and the other scenarios discussed above are shown in Table 11 and are graphed in Figure 5. Forecast-s Past Year 2010 The evaluation of thermal alternatives relative to Susitna requ1re that an econom1c evaluation period over the estimated life of the longest lived alternative be used. The alternative with the longest lif~ is Susitna which is conservatively estimated to be 50 years. r~ _I Assuming Susitna was on-line in 1993, the economic evalution period would end in year 2043. Therefore, fuel prices for the thermal alternatives must also be provided for the years 2010-2043. SCA is the only forecaster who has forecast oil pr1ces past the year 2010. Attempts to forecast that far into the future are probably not much better than guesses. It is generally accepted wisdom, however, that as the price of oil increases in real terms, alternatives become economically competitive. Thus oil and gas from coal will probaly become competitive at an oil price of $70-$80/bbl (1983$). Heavy oil, oil from tar sands, oil from shale, and gas and oil from unconventional deposits such as gas from geopressurized wells and low-permeability reservoir gas will probably be available at real 9,.···· '~ .. -·-·,~i . I l 1 l I I ! 1 l ! f I ; 1 --.I I ·- f I ll ' ' i' I >;l I ' I .. 'f' 1~ -J ~. • p • _.,.. ~ 1983 4 5 6 7 8 9 1990 1 2 3 4 5 6 7 8 9 2000 1 2 3 4 5 6 7 8 9 2010 -~ -....... -..... -·.-.r ..... .... -TABLE 11 ALTERNATIVE PETROLEUM PRICE PROJECTIONS lttf'!J ... .1.010 1983 DOLLARS Sherman Clark Sherman Clark DRI Har za/Ebas co Base Case NSD Case Spring 1983 Reference Case $/bbl %Ch[:_ $/bbl %Chg $/bbl %Chg $/bbl %Chg 28.95 -4.6 28.95 -4.6 28.95 -13.1 28.95 0.0 27.61 -4.7 27.61 -4.7 25.17 7.4 28.95 0.0 26.30 0.0 26.30 0.0 27.02 6.5 28.95 0.0 26.30 0.0 26.30 0.0 28.77 6.5 28.95 2.9 26.30 0.0 26.30 0.0 30.64 6.5 29.79 2.9 26.30 52.1 26.30 3.0 32.62 6.5 30.65 2.9 40.00 0.0 27.09 3.0 3L~. 74 6.5 31.54 2.9 40.00 3.0 27.90 3.0 36.99 ~t·+ 32.46 2.9 41.20 3.0 28.74 3.0 38.61 4.4 33.40 2.9 42.44 3.0 29.60 3.0 40.31 4.4 34.37 2.9 43.71 3.0 30.49 3.0 42.08 4.4 35.36 2.9 45.02 3.0 31.40 3.0 43.92 4.4 36.39 2.9 46.38 3.0 32.34 3.0 45.85 4.4 37.44 2.9 47.77 3.0 33.31 3.0 47.27 3.1 38.53 2.9 49.20 3.0 34.31 3.0 48.74 3.1 39.65 2.9 50.68 3.0 35.34 3 0 50.26 3.1 40.80 3.0 52.20 3.0 36.40 3.0 51.82 3.1 42.02 3.0 53.76 3 ·9S" 3-;-f l·•t 37.50 3.o s1 ~.43 43.28 3.0 55.64 3.5 38.63 3.0 54.04 1.1 44.58 3.0 57.58 3.5 39.78 3.0 54-. 65 1.1 45.92 3.0 59.58 3.5 40.98 3.0 55.27 1.1 47.30 3.0 61.66 3.5 42.21 3.0 55.90 1.1 1+8. 71 3.0 63.81 3.5 43.47 3.0 56.54 1.1 50.18 3.0 66.04 3.5 44.78 3.0 57.33 1.1 51.68 3.0 68.34 3.5 46.12 3.0 58.13 1.1 53.23 3.0 70.73 3.5 47.50 3.0 58.95 1 .1 54.83 3.0 73.20 3.5 48.93 3.0 59.77 1.1 56.47 3.0 75.75 3.5 50.39 3.0 60.61 1 .1 58.17 3.0 *EMF and DOR forecasts extrarolated by H/E after 2000 & 1999 respectively. ,... ~ 16111111 -- Energy Department Modeling of Revenue Forum Mean $/bbl %Chg $/bbl %Cbg 28.95 2.0 28.95 -17~ 29.53 2.0 23.96 -5. 30.11 6.0 22.67 -1.4 31.94 6.0 22.35 -1.8 33.82 6.0 21.95 1.3 35.85 6.0 22.15 1.3 38.02 6.0 22.34 1.3 40.29 4.0 22.55 1.3 41.88 4.0 22.79 1.3 43.57 4.0 23.04 1.3 45.29 4.0 23.32 1.3 47.14 4.0 23.63 1.3 49.02 4.0 23.96 1.3 51.00 4.0 24.31 1.3 53.03 4.0 24.71 1.3 55.15 4.0 25.14 1.3 57.37 4.0 25.60 1.3 59.64 2.0 25.93 1.3 h • 0 60.84 2.0 26.27 1.3 62.05 2.0 26.61 1.3 63.30 2.0 29.96 1.3 64.56 2.0 27o31 1.3 65.86 2.0 27.66 1.3 67.18 2.0 28.02 1.3 I; -~ ,·, 1..- 68.52 2.0 28.39 1.3 69.89 2.0 28.76 1.3 71.29 2.0 29.13 1.3 72.71 2.0 29.51 1.3 ·- I I I I I I I I I I I I I I I I SCA Basecase -4/83 EMF -1982 DRI Spring -5/83 Harza/Ebasco -5/83 SCA NSD -4/83 ____________. DOR Mean -4/83 -------· 2010 $) r-1 ,0 ..0 --<.rr ('I') co ('}'\ .-i M ·ri 0 4-1 0 (]) C) ·ri H ~ "d M H c !3: 70 60 ' 50 40 I -------~ 30 ! I 20- 10 ./" ~~ ~ I ~·-- ../"' ~ EMF -1982 DR! Spring -5/83 Harza/Ebasco -5/83 SCA NSD -4/83 DOR Mean -4/83 0 . -' 2010 1983 1985 1990 1995 2000 2005 FIGURE 5 -Alternative Oil Price Projections -$/bbl (1983 $) s il pr1.ces above $80/bbl. In addition, electrical energy from fufion may become economically available as well as energy from unforseen new technologies. Who, for example, foresaw the potential contribution of nuclear power to present world energy requirements in 1935? The period 1935-1983 covers forty eight years which is a shorter period than that covered by the present forecast, 1983-2043. Since the factors of oil substitutability and new technological . developments in energy, will probably tend to mitigate future, tl r continuing real increases in the price of oil and natural gas, we recommend tapering real rates of increase in the "t¥orld price of oil according to the following schedule: Period Real Oil Price Increase 2010-2020 2%/yr. 2021-2030 1%/yr. 2031-2043 0%/yr . Table 12 shows the SCA forecasts from 2010-2040 and the other forecasts which have been extended using the real increases presented above or the last escalation rate used by the estimator. L C ¥ & ~, :,., ~'ABL~.~ ~" .. 111 ~ IW' .. ; iWf, 1.111{, .. ALTERNATIVE OIL PRICE PROJECTIONS .J.CJ/0-,;/.04-0 1983 DOLLARS 2010 1 2 3 4 2015 6 7 8 9 2020 1 2 3 4 2025 6 7 8 9 2030 1 2 3 4 2035 6 7 8 9 2040 Sherman Clark 1 Base Case $/bb %Chg. 75.75 76.89 78.04 79.21 80.40 81.60 82.83 84.07 85.33 86.61 87.80 87.80 87.8U 87.80 87.80 87.80 87.80 87.80 87.80 87.80 87.80 87.80 87.80 87.80 87.80 87.80 87.80 87.80 87.80 87 80 87.80 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1--:--:'1 0-0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1 Sherman Clark NSD Case $/bbl %Chg 50.39 51.65 52.94 54.26 55.61 57.00 58.42 59.88 61.38 62.91 64.48 65.45 66.43 67.43 68.44 69.47 70.51 71.57 72.64 73.73 74.84 75.59 76.34 77.10 77.88 78.65 79.44 80.23 81.03 81.84 82.66 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.0 1.0 1.0 1.0 1.0 1. 0 1.0 1.0 1.0 1.0 1.0 DRI J,. Spring 1983 $/bbl %Chg 60.61 61.28 61.95 62.63 63.32 64.02 64-.72 65.43 66.15 66.88 67.62 68.36 69.11 69.87 70.64 71.42 72.20 73.00 73.80 74.61 75.43 76.26 77.10 77.95 78.81 79.68 80.55 81.44 82.33 83.24 84.15 l.i 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1 .. 1 1.1 1.1 1.1 1.1 1 .1 1.1 1.1 1.1 1 .1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 ~~ Sherman Clark's own estimates. J/ DRI projected at last DRI projection rate of 1.1%/yr. 41 H/E estimated rates. See text for discussion. -EMF projected using H/E estimated rates. EMF estimate made iq 1983 it would be lower (approx. 10-15%). This would give a lJ DOR projected using last DOR projection rate of !-%%/year. /·3 3 Har za/Ebas co Reference Case $/bbl %Chg 58.17 59.33 60.52 61.73 62.97 64.22 65.51 66.82 68.16 69.52 70.91 71.62 72.14 73.06 73.79 74.53 75.27 76.03 76.79 77.55 78.33 78.33 78.33 78.33 78.33 78.33 78.33 78.33 78.33 78.33 78.33 2.0 2.0 2.0 2,0 2.0 2.0 2.0 2.0 2.0 2.0 1.0 1.0 1.0 1.0 1. 0 1. 0 1.0 1. 0 1.0 1. 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Energy Modeling + Forum $/bbl %Chg 72.71 2.0 74.16 2.0 75.65 2.0 77.16 2.0 78.70 2.0 80.28 2.0 81.88' 2.0 83.52 2.0 85.19 2.0 86.90 2.0 88.63 1.0 89.52 1.0 90.41 1.0 91.32 1.0 92.23 1.0 93.15 1.0 94.08 1. 0 95.02 1.0 95.97 1.0 96.93 1.0 97.90 0.0 97.90 0.0 97.90 0.0 97.90 0.0 97.90 0.0 97.90 0.0 97.90 0.0 97.90 0.0 97.90 0.0 97.90 0.0 97.90 0.0 Department of Revenue Mean S $/bbl %Chg 29. 51 ,. 3 29.89 30.28 30.68 31.07 31.48 31.89 32.30 32.72 33.15 33.58 34.02 34.46 34.91 35.36 35.82 36.76 36.23 37.72 38.21 J8.71 39.21 39.72 40.23 40.76 41.29 41.82 42.36 42.37 42.92 42.48 /. 3 f e.:~~i• ... "''e M:tS' in 1982 and EMF indica~ if~made 2040 price of $83-88/bbl. -:,:' ,, I World Price Projections Gas pr~ces are projected from 1983-2043 using selected oil price scenarios. The base prices of gas for 1983 are $2.38.MCF for Cook I Inlet gas (Table 5) and $4.00 for North Slope gas (Table 8). The oil I price snenarios selected from Table 11 and 12 were the SCA base case and the SCA no scenar~os disruption (NSO) case. These scenar1os were I selected because they are the only forecasts where the forecaster extended his forecast to 2043 and in addition, the two scenarios bracket a wide range of plausible future oil prices. In additi0n, ~ DRT1 IJDA ~ forecast scenarios of 4%, 0%, -1%, and -2.0% real rates per year were also employed to illustrate a wide range of possible future oil pr~ces I and resulting projected Cook Inlet and North Slope gas pr~ces. I The projected gas pr~ces are shown in Tables 13 and 14 and were used as I gas price imports to the thermal generation analysis. I. Effect of Gas Price Deregulation I I l .J: . J I. '~~ , . ! fi:fJ?L'. ~~${ I ! j l f d . ' ---i I f ! i i ' l ,_ ,,.sr~--~ ;~ 1983 4 5 6 7 8 9 1990 1 2 3 4 5 6 7 8 9 2000 1 2 3 4 5 6 7 8 9 2010 1 2 3 4 5 6 7 8 9 0 1 • • --. ., ~~-.,__. -_ ·_, --•/ _ ..... ~ ~ ~ llJII..i-'!1 ~E 1~ ~ ~ PROJECTED COOK INLET WELLHEAD GAS PRICES 1983 DOLL\RS Sherman Clark Base Case 2.38 2.27 2.16 2.51 2.51 2.51 3.82 3.82 3.93 4.05 4.17 4.30 4.43 4 .. 56~ 4.70f 4.84 4.98 5.13 5.31 5.50 5.69 5.89 6.09 6.31 6.53 6.76 6.99 7. ZL!- 7.34 7.46 6. 68 7.80 7.91 8.03 8.15 8.27 8.40 8.40 8.40 ~A Sherman Clark ( NSD Case .1 2.38 2.27 2.16 2.51 2.51 2.59 2.66 2.74 2.83 2.91 3.00 3.09 3.18 3.27 3.37 3.47 3.58 3.69 3.80 3.91 4.03 4.15 4.27 4.40 4.53 4.67 4.81 4.95 5.08 5.20 5.33 5.47 5.60 5.74 5.89 6.04 6.19 6.34 Reference Casey +2%/}1r. 2.38 2.43 2.48 2.88 2.94 3.00 3.06 3.12 3.45 3.80 4.20 4. 6!.~ 5.12 5.65 ~ JII!!IIIIMi ~ ICfi'J ... 2..a+o Reference Case 0%/yr. 2.38 2.38 2.38 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 2.73 .2. 73 :2.73 :2.73 ~ f¥ii!@4A\t Reference Case -1.0%/yr 2.38 2.36 2.33 2.66 2.63 2.60 2.58 2.55 2.43 2.31 ?.10 ............ 4.U~ 1.98 1.89 ~ ~ ~ Referenc Case e -2.0%/yr 2.38 ~ 2.33 2.29 2.58 2.53 2.48 2.43 2.38 2.15 1.95 1.76 1. 59 1.44 1.30 ,, . :-.f:'1""4~.it'!ili*i:Jfl'1"'~~~~<1~~~-~·--~--' - I l t ~ I 0 ' • ~ ' . ..___ __ , .... . ~ . ~' -~ ~ , -, ' ~ ·~~~~ ·"'::::;::-,t I ~ .~ Y:llllilm.~ -~ rn~ .:•~ ~ .. <.! .. __..~._,.,t •• Rli 'llllllli!llll'. ~ 2024 5 6 7 8 9 2030 1 2 3 4 2035 6 7 8 9 2040 TABLE 13(cont'd) PROJECTED COOK INLET WELLHEAD GAS PRICES /'1 i"J-;Jo+O 1983 DOLLARS Sherman Clark Base Case 8.40 8.40 8.40 8.40 8.40 8.40 8.40 8.40 8.40 8 .. 40 8.40 8.40 8.40 8.40 8.40 8.40 8.40 ~A Sherman Clark l NSD Case 6.73 6.83 6.93 7.04 7.14 7.25 7.36 7.43 7.51 7.58 7.66 7.73 7.81 7.89 7.97 8.05 8.13 Reference Case +2%/hr. ---· '· 'rf 7.r,1 B·4D Reference Case 0%/yr. ..t,. ~~ ~ <· 73 iitl! • ·ill[ loif1 Reference Case -1. 0%/yr' 1·1 'f J.....H J. I/ .L.r-% j.(,2.. ()..;-% j. ~·'t .ikf51 • it. "'WW.; .. Reference Case -2.0%/yr. /. /7 /. 0 (, tJ.Cj(, tJ • 'i: '1 (~~Est~m~ted 1983 price of Cook Inlet gas from ~able~-. . ( Add1t1onal demand charge of $0.35/MMBtu appl1es from 1986 forward and 1s escalated by pr1ce of oil change. -~ l I I l ( I ' I ~ A 111M l 'j ' ·-~ ~------~-- 1 .I I, ..• · :r I.- 11 .. u. 15 '' ~----~~--------------~----------t; ~5 1; ( ,... - . --·tt· -·-·-~· -----· ~--·-----. ----~----. ·--------,.,. :l c. ~~ -,,,.-~,.-; __ ....,....,_i.J------··--·~ .......... ---~~·~-~--,_,.. ___ _ • 3 •: :3 ,. 2~ 2! ·; .... ~ .. :3: :4: :s ! ·~ -· 27 ~3' :3 JO' 31 ., ,;; 33 J~ "S:: .J,.; ', ~" ,a J t7 ~' ;a ~f l :g ; -Hl ;A d '! lf----···------... J.OOO ____ .. !! ., __ ---------I .. ;~ ~ .. \ .. . !t , . .. ., ).. i• ,I 9 rl0/0 J ..( II I· ,I a r II " jl il !I II l' -l 'I II ~-!I !I II II !1 ~ 1 ~j I •i '• '• j !~ ,I 'j ,, _I 'f ~4 H ~I I ·l ,, j '! ·• ~ .t.L71 LJ ·-~+ . < ...., . 0/ . ' I r::-~ .. v $~~~ s.J;;.__ ' s.J~ + S-·4f: s.SD 6-.S.h S'.(p).. S · Gg s ,74 .s. 8: r ·S7 .u . s_,9.3 (; ,oo C?. ~07 & . 13 - AW'!'f 11 l! ' ,l ., , . I .. il ~! ~ t !, i :I H .l ; I •! •• " ., .. ' •' .. ~-· s']- ;{ .. 7 I ,, ,, l lj ;:j I .l rl lj' I, ll 'l ., :i >I .. I ~ ' .. ··i .. +-•••·• ·--· ···--·-·---. i I ' ~ <l ·j -· 1 •• I I •! '! .. .. ! I I .. " .. ' r_. 9 ~~ rl TABLE 14 Projected North Slope. De1;i.vered Gas Prices In 1983 dollars per MMBtu 'I ~13 Sherman Sherman l Reference Reference Reference Reference Clark Clark Case Case Case Case I YEAR Base Case NSD +2/yr 0%/yr. -1.0/yr. -2.0%/.y 1983 4.00 4.00 4.00 4.00 4.00 4.00 1984 3.82 3.82 4.08 4.00 3.96 3.92 1985 3.64 3.-64 4.16 4.00 3.92 3.84 1986 3.64 3.64 4.00 1987 3.64 3.64 4.00 I 1988 3.64 3.75 4.00 1989 5.53 3.86 4.00 1990 5.53 3.98 4.59 4.00 3.73 1991 5.69 4.00 rl 1992 5.86 4.00 1993 6.04 4.00 1994 6.22 4.00 1995 6.41 4.61 5.07 4.00 3.55 1996 4.00 1997 4.00 'i 1998 4.00 1999 4.00 2000 7.43 5.35 5.60 4.00 3.57 2001 4.00 2002 4.00 2003 4.00 2004 4.00 11 2005 8.82 6.20 6.18 4.00 3.21 ~ 't 'L ~.' 2006 4.00 2007 4.00 2008 4.00 2009 4.00 2010 10.48 7.18 6.83 4.00 3.05 2011 4.00 2012 4.00 2013 4.00 2014 4.00 2015 11.29 8.13 7.54 4.00 2.90 2016 4.00 2017 4.00 2018 4.00 2019 4.00 2020 12.16 9.20 8.32 4.00 2.76 2021 12.16 4.00 2022 12.16 4.00 2023 12.16 4.00 2024 12.16 4.00 2025 9.91 9.19 4.00 2.62 I I TABLE 14 (continued) Projected North Slope Delivered Gas Prices In 1983 dollars per MMBtu ~IJ Sherman Sherman t Reference Reference Reference Reference Clark Clark Case Case Case Case YEAR Base Case NSD +2/ 0%/ 1.0/ -2.0%/ 202 12.1 .00 I I 2027 12.16 4.00 2028 12.16 4.00 2029 12.16 4.00 2030 12.16 10.67 4.00 2.49 1.55 I 2031 12.16 10.15 4.00 2.49 1.55 I 2032 12.16 4.00 2033 12.16 4.00 2034 12.16 4.00 2035 12.16 11.22 11.20 4.00 2.37 1.40 2036 12.16 4.00 I 2037 12.16 4.00 2038 12.16 4.00 2039 12.16 4.00 2040 12.16 11.79 12.37 4.00 2.26 1 ')t. ·-'-' I 1) Estimated 1983 price of North Slope gas from Table 8. t ; f f /.:~r~-~ ' •. ;! ~\, ,' ----------------------------------~----~~------ .... . I 13' ;J ")• "' ---~-,--£1!.:;-~; ----.-----Lq_f:_~---·--·---· --·I I ------.. --~-·~-----·------·--~. ~-·........-; i :; ,) ~-------#---------------------------------------~ .! •• !' .. ; I 'l " 3 t --. ' ·-----~, ,_ -~--·-··-.. ----.... --·-i: ·---.f..-----·----··~ ;o - .................. _.... • ·f.--·+- •' ' • ·-·+ • ----------~-·•· .-; 1\ ., 3 ... ~' : ... •t ., "'~.;:: t l •w'~------------------------------------------------------.----~:·~--------------------~----------------~--~~--------------------~---------------------- .. 7 :f: I 33 q !I 39 : ·' : •I " j " .. .. ol .. ,, •t:; '" '" .. ) . ., .... q '! •. w: ;:}" l i i l 1 •. _ ..... _...,._ ~~-~ '""""'""' .. ---~-.... , . .._.,,.._,_0 . ..,.._ • .," ----~--~-----·---+t"""'"--·~--~ .... ---..... -,_ _ _... . .,_._ ---·~~.-... -., .... ,.. __ ,._:,.! _______ -··-....... ~, ..... -.--..-,-.--'"~'-""~<--<,_...,.,.."*__,., •· 'i --. ;t :1 14 . ;!:;======:=1===============:::....-========:!:':::. !! \ '! .J I I REFER.l REFERENCES AND NOTES 1 . Battelle Pacific Northwest Laboratories. Railbelt 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 Connn~·.s.•ion, 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. Telephone conversation with Ken McLean, Pub lie Affairs Manager, Pac~:fic Alaska LNG Association Co. February 9, 1983. Actually, these contracts are in limbo, because cancellation requires written notice by each producer and none (except Shell Oil Co., which sold 220 BCF to Enstar) have given notice. ·' , ' ·; ~, .. -, I ~t. page 2.6 and Erick Natural Gas and Electric Power: Alte~.1ves For · lati'~ ~f · A Leg1s~v a1rs gency ps 13-15. ---Alaskri State Legislatu~, 6 .. Sweeney,~ al., Natural Gas Demand & Supply to the Year 2000 1n the Cook Inlet Basin of the South-Central Alaska, Stanford I Research Institute, November 1977, table 18, page 38. I I . . . 7. Letter from Mr~ Ross G. Schaff, State Geologist, Department of Natural Resour~es, Division of Geological and Geophysical Surveys, t:o Mr. Eric P. Yould, Executive Director) Alaska Power Authority, February 1, 1983. 8. Historical and Projected Oil & Gas Consumption, January 1983, .. State of Alaska, Department of Natural Resources, Division of Minerals and Energy }fanagement, p. 4.3. 0 .I Geological Survey Circular 860, Estimate of Undiscovered Recoverable Conventional Resources of Oil and Gas in the United S~ates, 1981. 10. U. S. Department of the Interior Geological Survey, Conditional Estimates and Marginal Probabilities for Undiscovered Recoverable I Oil and Gas Resources By Province, Statistical Background Data for U.S. Geologica 1 Survey Cir cul gr 860, Open-File Report 82-666A. I 11. Telephone conversation with Mr. Harold Schmidt, Vice President, Enstar Gas Company, F~bruary 9, 1983. 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 al., CP74-160, et al., CI78 .... 453, al'ld CI78-452, August 13, 1979. 13. Telephone conversation with I~. Gordon Smith, Treasurer, Pacific Gas & Electric Co., February 9, 1983. 14. Telephone conversation with Mr. Bill Cole, Vice President, Gas Supply, Southern California Gas Co., February 11, 1983 15. Joyce, Thomas J., "Future Gas Supplies", Ga.s Energy Review, American Gas Assn., Vol. 7, No. 10, July/August 1979, p.8. 4Ch.\ == : 'if,._ I ... J[p ~ Trans Alaska Gas System: Economics of an Alternative for North Slope Natural Gas, Report by the Governor'~ Economic Committee on North Slope Natural Gas, January 1983. 11. A~ /fJ?. I See reference 15. Energy Review, Winter 1982-1983, Data Resources, Inc., p. 51. Battelle, Op. Cit., pages 6.1 and 6.4. 18. Battelle, Op. Cit. p.A.2 19 . Batte 11 e, Op • Cit . p • A. 10 20. See Reference 3. 21. Battelle, Op. Cit. p.A.3 22. Reference 8, p.A.3. 23. Telephone conversation with Mr. Harold Schmidt, Vice President Ens tar, April 1, 1983 24. Anchorage Daily Times, January 4, 1983. 25. See Reference 26. Battelle, Op. Cit. p.6.5 I I I Iii lj 27. 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 repo~t. However, us1ng the reports estimated capital and O&M costs and estimated average pvt gas through~ produces a rough estimate of about $4.80/MMBtu). 28. See reference 27. 29. EPRI, World Oil, prepared by Stanford University Energy Modeling Forum, Prinicipal Investigator, J. S. Sweeney, EA-2447-SY, Summary Report, June 1982. ·.·",·· ::'(;~;;?:r::;.,:.:.7(:··· .. , ;>.::;) -- _/()~I£ -COAL This analysis of coal availability and cost in Alaska has been developed to provide the basis for evaluating a thermal alternative 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. Critical literature included the Bechtel (1980) report executive summary, selected Battelle reports (e.g.1 Secrest and Swift, 1982); Swift, Haskins, and Scott, (1980) and the U.S. Department of Energy (1980) study on transportation and marketing of Alaskan coal. Numerous other reports were used for data confirmation. The most current data were obtained by contacts with the following individuals: Mr. Joseph Usibelli, Usibellj Coal Co.; Mr. Robert Styles, Diamond Alaska Coal Co.; Mr. C. E~ McFarland, Placer Amex, Inc.; Mr. William Noll, Suneel Alaska, Inc.; Mr. W. Baker, Golden Valley Electric Association; and Mr. Keith Sworts, Fairbanks Municipal Utility Systems. Resources and Reserves wJ IL J Alaska has three major coal fields: Nenana, Beluga, and Kukpowruk (see Figure 1). It also has lesser deposits on the Kenai Peninsula and in the ~atanuska Valley. Alaska deposits, in total, contain some 130 billion tons of resources (Averitt, 1973), and 6 billion tons of reserves as is shown in Table 1. The Nenana and Beluga fields are the most economically promising Alaska deposits as they are very large and have favorable mining conditions. The Kukpowruk deposits cannot be mined economically, and also face substantial environmental problems (Kaiser Engineers, 1977). The Kenai and Matanuska fields are small and present additional mining difficulties (Battelle, 1980). The Nenana Field, located 1n central Alaska, contains a reserve base of 457 million tons and a total resource of nearly 7 billion tons as is shown in Table 2. Its subbituminous coal ranges in quality from 7400-8200 Btu/lbs is high in moisture content, is low in sulfur content and is very reactive (see Table 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 bi lllon tons -i- • I, ' (Energy Resources Co., 1980). The quality of this sub- bituminous coal varies according to report. Several analyses are shown in Table 4. Beluga deposits typically are in seams greater than 10 ft in thickness (Energy Resources Co., 1980) (Styles, 1983), and may be up to 50 ft. thick in places (Barnes, 1966). Stripping ratios from 2.2 to 6 are commonly found. Present and Potential Alaskan Coal Production Currently, there is only one significant producing m1ne 1n Alaska, the Usibelli Coal Co. mine located in the Nenana Field. This unit produces 830 thous~nd tons of coal/yr for use by local utilities, military establishments, and the University of A 1 ask a-Fairbanks • These user s operate 8 7 M·e g a w at t s ( MW) of electrical generation capacity, as shown in Table 5, and plans exist at Fairbanks Municipal Utility System (FMUS) to increase the total coal-fired electric generating capacity to 108 MW (Swarts, 1983). The FMUS capacity shown in Table 5 also serves the Fairbanks district heating system. To p~oduce the 830 thousand tons/yr., Usibelli Coal Co. employs a 33 yd3 dragline and a front end loader-truck system. This mine, with its existing equipment, has a production capacity of 1.7-2.0 million tons/yr. (Usibelli, 1983). Much of that capacity would be employed if, and when, the Suneei Alaska Co. export contract for 880 thousand tons (800 thousand metric tons) I yr becomes f u l 1 y ope r at ion a l • That con t r act c a l l s for full-scale shipments, as identified above, to the Korean Electric Power Co. beginning in 1986 (Noll, 1983). Production at the Usibelli m1ne ultimately could be increased to 4 mi 11 ion tons/yr (Department of Energy, 1980; Battelle, 1982; Usibelli, 1983). The mine, which has been in operation since 1943, has 300 years of reserves remaining at current rates of production (Usibelli, 1983). 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 (Ebasco, 1982) due to proximity to the Denali National Park, may be shipped to various locations v 1 a the A i ask a Ra i l road . The Beluga Field, which totally lacks infrastructure, currently is not producing coal; however, several developers have plans to produce in that region. These developers include the Diamond Alaska Coal Co., a joint venture of Diamond Shamrock and the Hunt Estates; and Placer Amex Co. Involved in their plans are such infrastructural requirements as the construction -2- ~~-----~---~~ -~ 'l --= .. ;;_ '" .$$ • I; of a town, transportation facilities to move the coal to tidewater, roads, and other relat~d sys~ems. These are necessary if one or more mines are to be made operational. Diamond Alaska Coal Co. holds leases on 20 thousand acres of land (subleasing from the Hunt-Bass-Wilson Group), with 1 billion tons of subbituminous resources. Engineering has been performed for a 10 million ton/yr mine designed to serve export markets on the Pacific Rim; and the engineering has involved a mine, a 12 mile overiancl conveyor to Granite Point, shiploading facilities at Granite Point, town facilities, and power generation facilities (Styles, 1983). The mine ints.e1f involves two drag!~~es plus power shovels and trucks. The target timeframe for production is 1988-1991 (Styles, 1983}. Placer-Amex plans involve a 5 million ton/yr mine in the Beluga field, ~ls~ serving the export market (Department of Energy, 1980). 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 (Styles, 1983), that Alaskan coal 1s more competitive than lower 48 U.S. coal (Swift, Haskins, and Scott, 1980), and that policy decisions in Japan and Korea favor the exporting of Alaskan coal (Swift, Haskins, and Scott, 1980). There are reasons to believe that exporting may be difficult to accomplish, however. Alaskan coal is of relatively low quality for the export market (Noll, 1983) and does not meet the Japanese coal specifications (Swift, Hasins, and Scott, 1980). The world recession dampened the need for coal on the Pacific Rim and set back the export development timetable (Noll, 1983). ThP stabilization and decline rn the world price of oil has reduced the incentive for converting from oil to coal in the Pacific Rim countries (McFarland, 1983). It is feasible to develop the Beluga Field at a smaller scale for local needs, however. This potential is recognized, inferrentially, by Olsen, et. al. (1979) of Battelle and s u p p or t e d e x p 1 i c 1 t 1 y b y Us i b e l l i ( 1 9 8 3 ) a n d P l a c e r -Am e x (McFarland, 1983). Diamond Alaska Coal Co. currently is performing detailed.engine~ring studies on a 1-3 milion ton/yr mine in this field (Styles, 1983). As a consequence, it is reasonable to conclude that production in both the Nenana and Btduga fields could be used to support new coal fired polr;er generation in Alaska. -3- I· of a town, transportation facilities to move the coal to tidewater, roads, and other related systemso These are necessary if one or more mines are to be made operational. Diamond Alaska Coal Co. holds leases on 20 thousand acres of land (subleasing from the Hunt-Bass-Wilson Group), with 1 billion tons of subbituminous resources. Engineering has been performed for a 10 million ton/yr mine designed to serve export markets on the Pacific Rim; and the enginee~ing has involved a mine, a 12 mile overland conveyor to Granite Point, shiploading facilities at Granite Point, town facilities, and power generation facilities (Styles, 1983). The mine intself involves two draglines plus power shovels and trucks. The target timeframe for production is 1988-1991 (Styles, 1983). Placer-Amex plans involve a 5 million ton/yr mine in the Beluga field, ~lso serving the export market (Department of Energy, 1980). 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 ccmpete on a cost basis with Austrailian coal (Styles, 1983), that Al~skan coal ts more competitive than lower 48 U.S. coal (Swift, Haskins, anq Scott, 1980), and that policy decisions in Japan and Korea favor the exporting of Alaskan coal (Swift, Haskins, and Scott, 1980). There are reasons to believe that exporting may be difficult to accomplish, however. Alaskan coal is of relatively low quality for the export market (Noll, 1983) and does not meet the Japanese coal specifications (Swift, Hasins, and Scott, 1980). The world recession dampened the need for coal on the Pacific Rim and set back the export development timetable (Noll, 1983). The stabilization and decline in the world price of oil has reduced the incentive for converting from oil to coal in the Pacific Rim countries (McFarland, 1983). It is feasible to develop the Beluga Field at a smaller scale for local needs, however. This potential is re~ognized, inferrentially, by Olsen, et. al. (1979) of Battelle and sup p or ted ex p 1 i c i t I y by Us i be l 1 i ( 1 9 8 3) and P lace r -Am ex (McFarland, 1983). Diamond Alaska Coal Co. currently is performing detail~d,engineering studies on a 1-3 milion ton/yr m1ne in this field (Styles, 1983). As a consequence, it 1s reasonable to conclude that production in both the Nenana and Beluga fields could be used to support new coal fired power generation in Alaska. -3- !) (I Current Alaskan Coal Prices The issue of coal prtces 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. 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 market. These concepts are employed separately for Nenana and Beluga coat. e: . N~nana Coal Prices Coal pricing 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 longterm contract at a price of $1.16/million Btu (Baker, 1983), and to FMUS at a mine-mouth price of $1.35/ million Btu (Swarts, 1983). The current average tipple price for Usibelli coal is $23.38/ton of 7800 Btu/lb coal, or $1.50/million Btu (Usibelli, 1983). This value is based, to a large extent, on labor productivity of 50 tons/man day as reported by Usibelli (1983). That is a slight decline in productivity, as Usibelli had achieved 60 tons/man day (Usibelli, 1983), a value confirmed by the National Coal Association (1980). The $1.50/million Btu reflects the price of coal from the Usibelli mine operating at about 50 percent of capacity. Usibelli (1983) estimates that if production were increased to 1.6 million tons/yr, coal prices would decline to $20/ton ($1.28/million Btu). Usibelli (1983) also estimates, however, that 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/million Btu The Usibelli m1ne could be expanded to 4 million tons/yr. given the reserve base available. At such production levels, .. -4- I! I ~. w; r Usibelli (1983) states that the additional 2 million tons of production would exhibit the same prices as the current m!ne when operating at full capacity. The pricing perspective of Usibelli, however, is not universally shared. The Department of Energy coal transpor- tation study (USDOE, 1980), estimates that coal from the additional 2 million tons/yr. will cost $1.88-$2.03/million Btu in January 1983 dollars ($1.62-$1.75/million BTu in 1980 dollar s). Because there 1s mn apparent disagreement on coal prices from a second unit of production, and because the Suneel. contract is not yet in place ,the $1.40/million Btu is used as a conservative base price for Nenana Field coal at the mine mouth; however, such coal must be transported to market by railroad. FMUS, for example, pays $0.50/million Btu for rail shipment of Usibelli coal (Sworts,. 1983). Battelle (1982) developed railroad cost functions for coal tran$port and, on this basis, the following charges should be added to Usibelli coal (Secrest and Swift, 198Z); De s t i n a_t i o n Nenana W i I Low Matanuska Anchorage Seward Charge (1983 $/million Btu) 0.32 0 e 51 O.oO 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 plqnts f~~t~~ py P§ib~lli coal would be in the communities of Nenan~ or Willow [Ebasco (1982) projected a Nenana location]. These are the appropriate base prices for use in power plant analysis. Beluga Coal Prices The approach of the price of coal .from the Beluga field depends, in large measure, on whether or not the e~pQtt market for Alaskan coal develops in the Pacific Rim. If that market exists, then both marketing 3nd prgdu£tign cost analyses apply. In the absence of that market, product ion costs must be estimated for smaller mines. -5- -l·· ·,, t ' i ·- \ r ·j . .. . c . ' ~ ...:--.~"'._.. ..... -..... ~,~---~----~~--------...:.-....:-· ~-. ..........:... ............. .,.. ___ ..,,~-' --:-.·· The qualitative arguments for and against projecting an export market for Alaskan coal have been previously discussed. In this ~ection the existence of the export market is assumed. Esti~ates 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 valu~s are shown in Figure 2 for Japan and Korea. As this figure illustrates, the projected total market in Japan alone could exceed 100 million metric tons by the end of this decade. The data from MRI a~e shown in Figures 3 and 4, with particular emphasis on the use of coal in electric utilities. MRI forecasts a smaller total coal market in Japan in 1990, some 72.7 million tons (vs. Sherman H. Clark's 108.1 million tons). MRI estimates that the U.S. share of that Japanese market is 11.1 million tons, as is shown in Table 6. 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. In that they are consistent with the date from Swift, Haskins, and Scott (1980). This market is potentially highly available to the Alaskan mines due to transpo~tation cost differentials (Swift, Haskins, and Scott, 1980). Transportation cost differentials are based upon the distance to market, as illustrated in Figure 5. Levy (1982) argues this point most strongly ~hen 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. Because of this strong :?vidence for an export market, particularly 1n Japan (MRI, 1982), it ts essential to place a market value on the Alaskan 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 simila'i'. The value of coal in Japan is based upon the FOB price of coal at ports in the competing nations of Australia, Canada, and South Africa obtained from Clark (1983), and the transportation charges associated with that coal as obtained from Diamond Shamrock Corp. (1983). The va.lue of coal in Japan, therefore, is $2.40-$2.50/ million Btu as is shown in Table 7. Deductions are taken from this value to reflect the lower quality of Alaskan coal, and to reflect the transportation costs from Alaska to Japan. The market value of Alaskan coal FOB Granite Point is $1.81-$1.95/million Btu, as is shown in Table 8. -6- -·r.· . l ' '< - L ~' t r r I \i Frequently it 1s argued that the market value FOB mine is substantially lower than the market value FOB Port. In arguing this case, all capital and operating charges associated with transporting the coal from mine to tidewater have to be deducted from the $1.81-$1.95/million Btu. However if the market value of coal assumes exports, then it necessarily assumes that the coal transport facilities are in place. The assumption of such transport facilities being in existence means that all capital costs must be treated as sunk costs, and that the only charges to be netted out are incremental O&M costs associated with whether the spe~ific 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 $1.81-$1.95/million Btu are assumed to hold. Production cost estimates for Beluga coal also have 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 NW). Production cost estimates have been made for large mines serving the export market, an~ these are reported in Table 9. The lower bound values range from $1.16/million Btu to $1.27/million Btu and the higher bound values range from $1.65/million Btu to $1.74/million Btu. The average of these est i mates , taken as a group, i s $ 1 • 4 5 I m i L l ion Btu. For the purposes of deriving a coal cost estimate assuming exports, the difference between the market value and the production cost value must be addressed. Battelle approached reconciliation by simple averaging (Secrest and Swift, 1982). That approach is shown here as well, with the average of the market values ($1.88/million Btu) being averaged with the production cost of $1.45/million Btu to achieve a price of $1.67/million Btu. While this 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 $1.88/mi ll ion Btu FOB Port, and if there were few cost savings to be achieved by not transporting the coal to tidewater, then there would be no reason to sell at some average price. Rather, assuming the export of 5-10 million tons/yr at 7200-7800 Btu/lb coal, such a practice would result in decreased revenues to the coal operation of $15.1-$32.8 million per yedr. These decreased revenues graphically display -7- ··-l~· ~.-.. ~ ,j. • 4 I I ' I_, I the concept of opportunity cost. value of coal 's assumed. For this reason the market The Beluea 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. Certainly, there has been substantial optimism expressed for such marketing (see Beluga Coal Company and Diamond Alaska Coal Company, 1982; Styles, 1983; Swift, Haskins, and Scott, 1980). 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 considerede Prodoction costs for smaller mines have been reported by varius potential vendors, at $!.50/million Btu (Diamond Alaska Coal Co. value quoted by Griffith 1983 to $2.00/million Btu (Placer-Amex value quoted by McFarland. 1983). Initial order-of-magnitude values have been developed based upon the coal mine eosting model of the McLean R e s e a r c h C e n t e r ( 1 9 8 0 ) a n d t h e p r i c i n g f or m u 1 a o f K a i s e r Engineers (1977). These values are $1.65/million Btu to $1.80/million Btu, not including infrastructural costs, and are shown in Table 10. These values are within the range cited by the vendors. Production cost numbers have been derived independently by Paul Wier and Associates (Schaible, 1983). These costs assume that a 3-seam operation would be developed at 1 million tons/yr. and at 3 million tons/yr. In both cases, the coal would be mined by truck and shovel technology rather than dragline technology. It would be crushed and delivered to the power plant. At the one million ton/yr size, transport to powerplant would be accomplished by trucks and at the three million ton/yr size it would be accomplished by conveyor belt. In both cases town development costs would be shared between the coal mine and the power plant, and the coal mine po~tion wouLd be capitalized with the mine. Using a 100% equity assumption and a 17% Return on Investment (ROI) due to risk, they estimate the cost of coal from small mines in the Beluga field at ----- Coal prices in Alaska, then, are assumed to be $1.72 - $1.91/mi Ilion Btu for Nenana coal delivered either to the town of Nenana or the town of Willow; and $1.88/mi llion Btu for Beluga coal if exported. If coal is produced for domestic purposes only the expected price is $ /mi Ilion Btu. -8- ,., ._ U,¥, I ; Real Coal Price Escalation Agreements between coal suppliers and electric utilities for the i.t3le/purchase of coal are usually Long term contracts which inctu~e a base price for the coal and a method of escalation to provide prices in future years. The base price provides for recovery of the capital investment, profit, and operating and maintenance costs at the level in existence when the contract was entered into. The intent of the escalation mechanism is to recover actual increases in labor and material costs from operation and maintenance of the mine. Typically the escalation mechanism consists of an index or combination of indexes such as the producer price index, various commodity and labor indexes, the consumer price index which applied to operating and maintenance expenses» and or regulation related indices. The original capital investment is not escalated, so the price of coal to the utility tends to increase with general inflation, but at a real rate of increase of 0%/yr. 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 thes~ real changes until the existing contract expired and was renegotiated, or a contract for new or additional quantities of coal was executed. Several escalation rates have been estimated for utility coal in Alaska and in the lower 48 states, and they range from 2.0-3.0%/year (real) as is shown in Table 11. Several more generic rates have also been developed by Sherman H. Clark and Associates and by DRI, and these are shown in Table 12. These rates can be compared to the real rate of increase experienced by Golden Valley Electric Association, calcuLated to be 2.3% since 1974 (Diener, 1981). 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 provisions of the Coal Mine Safety Act of 1969 were being incorporated into the price of coal. The generic estimates of Sherman H. Clark and DRI appear to be based more upon supply-demand analyses than upon extrapolations of historical data. Consequently there are distinctions in coal quality, as shown in Figure 6, taken from Sherman CLark and Associates. -9- -~-------~-~-------· ···-· ~·· ., ...... , ... , ----··· .,.-&!t:i•i!l't""'Wif'#.t=n au tt& 1r .-·;,;-· "·~ ............. ._.·~-" r t . . . " l r. f I l f l l I l' I I L Because the fotecasts of DRI and Sher~an H. Clark are based upon supply-demand factors, they are used her~ and are to be applied tt) the base contract price of coal. The 2 •. 6% real rate of increase is applied to the mine-mouth price of Nenana Field (Usibelli) 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 ovor time are shown in Table 13. For the Beluga Field there is sufficient evidence to support the use of an export market driven value that a base price of $1.88 is used. Because this is u~ed the export-specific escalator of 1.6% is app\ied. The resulting fuel prices are shown )n Table 14. As a consequence of these calculations the real escalation rates for the delivered base price of coal experienced by utilities at various locations are as follows: Utility Location Coal Field Escalation Rate Nenana Nenana 2. 3 W i l I ow Nenana 2.2 Beluga Beluga 1 • 6 It is also useful to note that the export market could fail to develop. In such a case the Beluga Field coal would esclate at a rate more comparable to the Nenana Field coal, since the mtne would be geared to serving the same market. In this case, base coal costs would be as follows: Year Coal Cost ($/Million Btu) 1983 (base) 1 • 7 5 1.80 1 • 8 5 l . 9 0 1990 2.09 2. 15 2. 2 I 2,.27 2000 2. 7 1 2. 7 8 2.86 2.93 2010 3.50 3.60 3.69 3.79 While there is some correlation between export coal prices and world oil prices 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 correlations must accommodate significant differences in market -10- ., ....... ·-·--····--~-----.~--··~-1 ~ 1 .• i I '· f ~ f L J I t~ .. • cO flexibility and market opportunity between coal and oil suppliers. For these reasons it is necessry to treat coal pt'ices as being independent of world oil prices. -11- REFERENCES AND BIBLIOGRAPHY Arthur D. Little, Inc. 1983. Long Term Energy Plan, Appendix B. DEPD, Anchorage, Alaska. Averitt, P. 1973. Coal in United States Mineral Resour~es. u.s. Survey Professional Paper 820., U.S. Government Print- ing Office, Washington, D.C. Baker, W. 1983. Personal communication with GVEA Production Superintendent, Mar. 30, 1983. Barnes F. 1967. ~124 2 -B. Coal Resources in Alaska. USGS Bulletin 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. B~luga 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 1 Vol. 11. Menlo Park, CA. Coal Task Force. 1974. Coal Task Force Report, Project Inde- pendence Blueprint. Federal Energy Administration, Washington, D.Co, November. 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, ~ashington, D.C. 4 d ' " -··-·---------· "'!'""- I '~;·. REFERENCES AND BIBLIOGRAPHY (Continued) Diamond Shamrock Corp. 1983 Diamond Chuitna Project. Presentation Materials on the DSCSC February. Diener, S. 1981. Working Paper, Susitna Hydroelectric Project: Fuel Pricing for Thermal Altenatives. Acres American Incorporated. Diener, s. 1982. Memorandum to G. Warnock, Jan 18. Subject: Update on Coal Opportunity Values. Ebasco Services Incorporated. 1982. Coal-Fired Steam-Electric Power Plant Alternatives for the Railbelt Region of Alaska. Vol XII. Battelle Pacific Northwest Laboratories, Richland, WA. Ebasco Services Incorporated. for Heat and Electricity 1983. Use of North Slope Gas in the Railbelt. Belleveue, 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). Griffith, M. 1983. Personal Communication to D. Augustine, Feb. 15. Heye, C. 1983. Economy. Forecast Assumptions in Data Resources, Inc. Integ-Ebasco 1982. Project Description. Plant. Ebasco Services Incorporated, Review of the U.S. 800 MW Hat Creek Vancouver, BaC. 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. McFarland, C.E. 1983. Personal Communication with V. P., Placer-Amex in the form of a telephoen conversation, April 22. McLean Research Institute. 1980. Development of Surface Mine Cost estimating equations. Fol. U.S. DOE. McLean, VA. 0 ··'I- t --t ~ .. .Jf'et 't tnt ei1nwne¥i<f!N1Yw-i-t·"t··w t .;. ·• ( _ .. ___ _ 1·.· l ' REFERENCES AND BIBLIOGRAPHY (Continued) 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. Noll, W. 1983. Personal communication in the form of an interview with the Suneel Vice President, Mar. 29. Olsen, M., et. al. 1979. Beluga Coal Field Development: Social Effects and Management Alternatives. Bettelle Pacific Northwest Laborato~ies, Richland, WA. Resource Development Council for Alaa.ka, Inc. 1983. Policy Statement No. 6: Coal Development (draft). Reviewed by RDCA, Mar. 29, 1983, Anchorage, AK. Sall, G. 1983. Personal communication by telephone. Inter- view with this official, Office of Planning and the Environment, Office of Fossil Energy, U.S. Dept. of Energy, Germantown, MD., April 22. Secrest, T. and W. Swift. Alternatives Study: Forecasts. BAttelle Richland, WA. 1982. Railbelt Electric Power Fossil Fuel Availability and Price Pacific Northwest Laboratories, Scott, J. et.al. 1978. Coal Mining. The National Research Council/National Academy of Sciences, Washington, D.C. Stanford Research Institute, 1974. The Potential For Developing Alaska Coal Fo.r Clean Export Fuels. Menlo Park, CA. (For the Office of Coal Research). Styles, R. 1983, Personal communications in the form of an interview with the Manager, Diamond Alaska Coal Company, Apr • 4. Swift, W., J. Haskins, and M. Scott. 1980. Beluga Coal Market Study. Battelle Pacific Northwest Laboratories, Richland, WA. Sworts, K. 1983. Personal Communication in the form of an interview of the Production Superintendent, FMUS, March 30. \) ' r REFERENCES AND BIBLIOGRAPHY (Continued) U.S. Department of Energy. 1980. Transportation and Market Analysis of Alaska Coal. USDOE, Seattle, WA. Usibelli, J. 1983. Personal communication with Usibelli Coal, President in the form of a telephone conversation, Apr i 1 2 2. . ; . . ~: . I ~~ I I· Table 1. Type of Anthracite Bituminous De mo n s t r a t e d R e s e • ,~ "' B a s e i n A l a s k a a n d t h e U • S • b y T y p e of Co a I • (values in millions of short tons) Coal Alaska Total u.s. 7 341 • 7 697.5 239,272.9 Subbituminous 5,443.0 182,035.0 Lignite 14.0 44,063.9 Total 6,154o5 472,713.6 Per cent of Total 1 . 3% 100% Source: Demonstrated Reserve Base of Coal in the United States on January 1, 1980. 4 ,. 'f ... ·l ' Table 2. Reserves and Resources of the Nenana Field. Reserve/Resource Type Reserve Base Resources Measured Indicated Inferred Total Q.uantity (tons x 106) 457 862 2,700 3,377 6,938~1 ~/Totals do not add due to rounding on measured and inferred. Source: Energy Resources Co., 1980. _;,uxmtr:II'I!Biirf'l!:r&t N 3 e risen · · r ll r Table 3. Proximate and Ultimate Analysis of Nenana Field Coal Proximate Analysis Moisure Ash Volatile Matter Fixed Carbon As Received Ultimate Analysis (wt %) Hydrogen Car bon Oxygen Nitrogen S u 1 fur Cb 1 or i ne Moisture Ash Higher Heating Value (Btu/lb) Weight Per cent 26.1 6.4 36.3 31 • 2 3.6 47.2 1 5. 5 l. 0 5 0. l 2 26.1 6.4 7,950 Source: Hazen Laboratory Analyses for Fairbanks Mun~~ipal System. ~-trt-t~MiiiilliB'ntlilli·'?liiliiN!IIliilr' 'illliS '!l!'ili'. ""iliiol,tM?iiiiiii~·a;..,· ..... ,:._Oiliii'"""tw""'' ........ ., ........ -.. ~--------r-~~~ -·---- r·. I !: . \) ,_, .. ", .:·,-;.~r;,?;::r~~~~-. I . . ·~ -~.·-·· Table 4. Ultimate Analyses of Beluga Coal Value Analyses (wt %) Batteileb/ DiamondC/ Stanford~/ Res ear c h Ins t • (Waterfall Seam) Alaska Coal Co. Carbon 44.7 Hydrogen 3.8 Nitrogen 0.7 Oxygen 15.8 Sulfur 0.2 Ash 9.9 Moisture 24.9 Higher Heating 7200 ~/Stanford Research Institutes 1974 ~/Swift, Haskins, and Scott, 1980 ~/Diamond Shamrock Corporation, 1983 45.4 ---2.9 ---0.7 14.4 0. 18 0 • 1 !~ 16.0 7.9 21.0 28.0 7536 7800 [ Table 5. Coal Fired Capacity in Alaska. Owner Golden Valley Electric Assn. University of Alaska U.S. Air Force F t • W a i n wr i g h t Fairbanks Municipal Utility System Total He. at Location Rate Healy Fairbanks Fair banks Fairbanks N/A (Btu/kWh) 13,200 12,000 20.000 13,300- 22,000 13,000- 22,000 Capacity (MW) 25 13 20 29 87 Source: Battelle, Vol VI, 1982. ···-~-~1--.. ·----··--_ ................ ~--.. _ ........................... ~---------·· ---.-----,------. ·;r~------_--,....--.~---"""--~·------------.....,~------~·-·---··"""<:--:dJ.-~. - ~ // ~, / . . - • r ,...,... . I [ [ I (J Table 6. Projected National Shares of Japanese Coal Market For Imports in the Year 199oa; Market Share Nation Percentage Million Tons Australia 41.8 30.4 Canada 1 1 . 9 8.7 United States 15.3 1 1 . 1 China 16.0 11 • 6 USSR 5.6 4. 1 South Africa 4.2 3.0 All Others 5.2 3.8 'l'otal 100.0 7 2. 7 Source: MRI, 1982 ~/ Includes steam coal and metallurgical coal. .. "'~···-··· -·-·· .... ··l·-· ..... ' ···-~. ·~-...... . ' - FRw;a I ' : t ~ t' ' . r ~ i ~- t ' ' : ,, i ·, I r r 11 11 [ (; Table 7. The Value of Coal Delivered in Japan By Coal Origin (Jan, 1983 Dollars) Nation of Coal Origination Australia South Africa Canada Value of Coal (FOB Port) $45.00 37.50 45.00 Shipping Cost ($/ton) 10.50 15.30 10.35 ~/From Sherman H. Clark and Associates, 1983 b/From Diamone Shamrock Corp., 1983 ~/Assumes 11,160 Btu/lb per Japanese Specification in Swift, Haskins, and Scott, 1980. Value of Coal ($/ton( $/mi i 1 ion Btu) $55.50 $2.49 52.80 2.37 55.35 2.48 I I; L- r r i.L [ I C· Table 8: The Market Value of Coal FOB Granite Point, Alaska (Jan 19$.3 Dollars) The Va l u e o f Co a l in Japan.:-_/ Price Discount Based upon the impact of 1 ower qua l it y on plant capital costs (1.6%)bj Net Value of Coal in Japan Cost to Transport CoalC/ Net Value of Coal at Granite Point :!_/From Table 7 Low $2.40 $0.04 $2.36 $0.55 $ 1 • 81 Value of Coal (~/Million Btu) High $2.50 $0.04 $2.46 $0.51 $ 1 • 9 5 bjsee Swift, Haskins, and Scott (1980) analysis on Waterfall -Seam Coal, pp. 7-5-7-6. CfCost is ~8.00/ton. Low value column reflects 7200 Btu/lb coal and high value column reflects 7800 Btu/lb coal (see Table 4). I (~ [ ~1¥. e.-"F-M~, ,;. r.,J -4,. Table lO.j\Production Cost Estimates For a 2 Million ton/yr Mine in the Beluga Coal Field (1983 Dollars, Jan 1.)* Parameter Initial Capital Investment Deferred Capital Investment Total Capital Investment Annual O&M, Costs Cost Per Ton @ 15% ROI Cost Per Million Btu (7200-7800 Btu/lb) *Not including infrastructive. NOTES TO PRODUCTION COST TABLE a/Eauation is -. C1 =4.391 RT + 3.259T Cost $73,315,000.:_/ $22,470,000~/ $95,785,000 $38,349,000..:_/ $27.72d/ $1.65-$1.80_:_/ Cr=Initial Capital Investment (Lower 48, 1980$ x 106) R = Stripping Ratio (Taken at 4.4) T c Annual Production (Million tons) Alaska Factor For Capital z 1.4 Escalator • 1.094 x 1.06 = 1.5964 c 1 =(4.391 X 4.4 X 2 + 3.259 X 2) X 1 X 106 X 1.4 Y. 1.5964 = $73,315,131 (Say $73,315,000) !:1 Equation is Cn= ,1712 RT + 8.268T 20.577 ' Co= {0.1712x4.4x2+8.268x220.577) x 1.4xl.l5964xlxl06 =22,469,671 (Say $22,470,000) ~/Equation is CA=9.262 = 4.555T Alaska Factor = 1.8 CA=(9.262 + 4.555 X 2) X 1 X 106 X 1.8 X 1.15964 = 38,343,830 (Say $38,349,000) Equations From: McLean Research Center, Alaska Factors From: Usibelli, 1983 1980 t l r [ r [ ~ ' . I NOTES TO PRODUCTION COST TABLE - 2 d I E q u a t i o n a ar e S• 1 (CA + 1.33 (CI + Co -D) .Blr:) PWF D•O.l (C 1 + Cn-D) PWF • 6.566 @ depreciation 15% ROI S/T • $/Ton s -1 (38,439,000 + 1.33 ( .0815 S= $51,441,000 95,785,000-9,579,000) 6.566 $/ton • $51,441,000/2,000,000 • $25.72 ~/ 25.72/15.6 • $1.65(@ 1800 Btu/lb coal) 25.72/14.4 = $1.79(@ 7200 Btu/lb coal) Equations For Annuity Coal Pricing From Kaiser Engineers 1977 Coal Heat Contents: Diamond Alaska Coal, 1983 Stanford Research Institute, 1974 Table 11. Some Protected Escalation Rates for Coal P~ices. Foreca~tor Coal Rattelle (1982)~/ Beluga We:n.il'i'1a Acres ( 1 981 )!>../ Beluga Nenana Acres (1982)£.1 Beluga Nenana a/ -' S e cr e s t a n d S w i f t , 1 9 8 2 .. b/D. -1ener, c/ . -Diener, ' 98. 1 l • - Real Escalatit:.~n Rate (%) to 2010 2. 1 2.0 '1 6 4 • 2. 3 2.5 2.7 "! isSWF• Table 12. Coal Price Real escalation Rates Author Coal Types DRI New Coal Contracts Sherman H. New Co a 1 Contracts C 1 ark and Spot Market Coal F1 West Coal Lignite R' ,, Coal Exports u Sources: DR!, 1983; Clark, 1983. Long Term Real Escalation Rate 2.6% 2.9% 2.3% 1.6% Table 13. Nenana Coal Transportation Co~ts -1983 From Healy to Plant Location ($/MMBtu) Plant Location (l Year Nenana Willow Matanuska Anchorage Seward 1983 0.32 0.51 0.60 0.70 1984 0.30 0.48 0.57 0.67 1985 0.30 0.48 0.57 0.67 1986 0.32 0.49 0.58 0.67 1987 0.33 0.50 0.58 0.68 1988 0.33 0:50 0.59 0.69 1989 0.34 0.51 0.60 0.70 "1990 0.34 0.52 0.61 0.71 1991 0.35 0.52 0.62 0.72 1992 0.35 0.53 0.63 0.73 1993 0.36 0.54 0.64 0.74 1994 0.36 0.54 0.64 0.75 1995 0.36 0.55 0.64 0.75 1996 0.37 0.55 0.65 0.76 1997 0.37 0.55 0.65 0.76 1998 0.37 0.56 0.66 0.77 1999 0.37 0.56 0.66 0.78 2000 0.38 0.57 0.67 0.78 2001 0.38 0.57 0.67 0.79 2002 0.38 0. 57 0.68 0.79 2003 0.39 0.58 0.68 0.80 2004 0.39 0.58 0.69 0.81 2005 0.39 0.59 0.69 0.81 2006 0.40 0.59 0.70 0.82 2007 0.40 0.60 0.70 0.83 2008 0.40 0.60 0. 71 0.83 2009 0.41 0. 61 0. 7 2 0.84 2010 0.41 0.61 0.72 0.85 Notes: Transportation cost equations: (1983) Healy to.: Nanana = $0.23 + 0.09 ( 0 i 1 escalation w i 1 low = 0.36 + 0. 15 ( 0 i 1 escalation Matanuska = 0.42 + 0. 1 8 ( 0 j 1 escalation Anchorage = 0.49 + 0.7.1 ( 0 i 1 escalation Seward = 0.55 + G.23 ( o i I escalation 1----~-~:r-,-------~--. -----~ - '/ tt lt • ~ ... ~ .......... ~,.~-· --,-·---~----·-·····. , .. , .. J ...,_., ...... -- 0.78 0.74 0.75 0.76 0.77 0.78 0 .. 79 0.80 0.81 0.82 0.84 0.84 0.85 0.86 0.86 0.87 0.88 0.88 0.89 0.90 0.90 0.91 0.92 0.92 0.93 0.04 0.95 0.95 rates) rates) rates) rates) rates) '.?.1 Table 14. Estimated Delivered Base Prices of Coal . Alaska by ~ ' 1n Year (in 1983 $/Btu xto6 ~ Year Nenana Field Coa 1 Delivered Beluga Field Coal li to l~ Mine Mouth Nenana willow Mine Mouth r~ ! ' 1983 1. 40 1 • 7 2 1. 91 1. 88 t 1984 1.44 1.74 1. 9 2 1. 91 f 1985 1. 4 7 1.77 1.95 1 .. 94 f 1986 1 . 51 1.83 2.00 1 • 9 7 1987 1 • 55 1. 88 2.05 2.00 1988 1.59 1.92 2.09 2 .. 04 1989 1 . 6 3 1.97 ·2. 14 2.07 1990 1.68 2.02 2.20 2.10 1991 1 • 7 2 2.07 2.24 2.13 1992 1 • 7 6 2. 11 2.29 2. 1 7 1993 1 . 81 2.17 2.35 2.20 1994 1 . 8 6 2.22 2.40 2.24 1995 1 • 91 2.27 2.46 2.27 1996 1 • 8 5 2.32 2.50 2.31 1997 2.01 2. 38 2.56 2.35 1998 2.06 2.43 2.62 2.39 1999 2. 11 2.48 2.67 2.42 t 2000 2. 1 7 2.55 2.74 2.46 2001 2.22 2.60 2.79 2.50 I I 2002 2.28 2.66 2.85 2.54 I 2003 2.34 2.73 2.92 2 .. 58 ! 2004 2.40 2.79 2.98 2.62 l I 2005 2.46 2.85 3.05 2.67 2006 2.53 2.93 3. 12 2. 71 2007 2.59 2.99 3.19 2.75 2008 2.66 3.06 3.26 2.80 2009 2.73 3. 14 3.34 2.84 2010 2.80 3. 2 1 3. 41 2.89 1 ~: 1 I I I t L ___ ~ ' i I HARZA · EBASCO SUSITNA JOINT VENTUiff ·. r ' .. .'. : ·t· ... I • •. f l ... • .. -~ .. . . .:. :-·. ~ ........... , . ~ . .. .. . ' .. · ~·-:t. • •. ' . J' ~ -. • • • " .... .f. &,.:. 1 SUaJICT FILE NO. OAT£ COJIWUT£0 CHECKED ,AGE ftAGES . -'~--~-________________________________ __. -·. ·~ . ·o EBASCO SERVICES INCORPORATED BY ___ _ DATE----SHEET OF--------DEIIIT. CHKO. ey __ _ DATE----OFS NO.-----NO.---CLIENT-------------------------------PROJECT---------------------..,____----------SUBJECT ------------------------------ 58tlfH!I1 I I r. r l ·'' l. av _____ _ CHKO. BY --- ·, EBASCO SERVICES INCORPORATED DATIE---- DATE---- SHEET--OF--- DEPT. OFS NO·-----NO.--- CLIENT----------------------------------- PROJECT ___________________________________ -_____ _ SUBJECT 581/8·81 +=k~£~7""4'J> ~0/?£ r/2$~ £~.=-er;:/~/Y}-~t£NI,e;Jifr/~ /.tiC/' ?/fe./;;-/~ ??/~ ~~~#T/Z/Ii'S.I /1~-z~~~ ("&w~~) r-----~5=~=~~~==-~ I I I . ,, b: .. r· EBASCO SERVICES INCORPORATED BY ____ _ OATE----SHEET OF-- DEPT. CHKO. BY __ _ DATE----OFS NO·-----NO.--- C:..IENT ------------------------------- PROJECT------------------------------- SUBJECT Fit-4. /--71 I.. 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A"'-M--f / ~ ~ u-t , /~ r..__'" ~, ~~ ~ ~ ./l~A.L~#'.~ .,/1-GR.~~~o.--{. ~ ~ P~ 4--~~_,/ a-~ ~ ~ _/-V!---. .JL-J7,_/t; . ./ _,/..-?(/__<-/?F :J ~~ ~._ ~ . 1~ . ~ 11 ? .; -:z (} f-0 I -·· ~-" ·T·---~~---···=-·--.--..... . ~--· ' "" ·-----~-------,. ··-·---~ ·-~·"-"··~·· ..... , .. ~·-· ~.~ ..... ~""""' --~.__. .... _ .. ~ .... ~------.... __,_.,._~~-"--......... -~~-~~-· .. --·. ~ ..... ~ ...... ..._ .. " ..... ~ ......... ____ _. _ _,.,,,, • J ~IIIIIIMIIII4 .. ; lA 4 ' ~·· r r -' J. Jl L n ' l ft t r . ·:r t - '-·- f. t I, I l·. ! r ! r I t j MEMORA JUM LOCATION .t\nchorage DATE June 6, 1~_8_3 ______________ _ TO FROM ~ Robin~suoun ______________________ __ NUMBER 6. 2. 4 .1 Attached for H-E Internal review is the response to the que~y No 1 in Schedule A. Unfortunately Acres did not perform the studies necessary to answer the deficiencies relative to the spillway fuse plugs and the Devil Canyon· arch dam thrust block on the right bank. A complete answer for the former will require computer analyses which have b.een initiated" The results are expected by June 13. In the latter, manu~l computation have been initiated and are slated for completion during this week. N. M. Hernandez NHH/ml ·. •• f f ' l j l I I . ' ' T I dJ .. , .. .,.,,_,:-"-·~ .v·~ . J .. . r { ' r-: I. I ' l r. P· ,~ 1 l EXHIBIT F QUERY NO. 1 SCH.EDl.JLE A . FERC RESPONSE Stability and Stress Anal 'lses Provide su:TL:iaries of stability and stress analyses for the following structures; 1·:atana Dam, Devil Canyon Arch Da:u and' trbust block abute- ne.nts, Devil Canyon Saddle dam, l·:atana and Devil Canyon main spill'\o;'ay gate structure, and the \·;atc:ma and Devil Canyon t::mergency spillv:ay fuse plugs. Given t.he different structures to ,;hich this question applies the re- sponse "-"ill be in two parts. Part 1 1vill cover tbe embanl::ment structures of 1·latana Dc=..m, 'D:=.vil Canyon Saddle dam and the \-Jatana .and Devil Canyon t::mergency spill~ay fuse plugs. Part 2 will cover the concretP structures of the Devil Canyon Arch Dalil, its' thrust blocks at tb= abutments, and spill~ay gate structures, and the \·latana main spillway gate structure. -.. ,,_, __ ~ ' I J.! I 'I ,, '! " /,\· '- l,_; .• !!tfillfttl ....... ~-llilllili-~b~~~~t..t.lli ... !lllilio£""""""--~~~~.a~..., .. __ "'---'-~:.._-::.._~c:._--J;;'>--~'.--i.c;~~.:..· ~--i.~.--..:::::....~,~-~~· ..;..__ _ _,.~-_....._~-~__._...;;..~~~~ ............ ,.,-,_.::..·~~-(J~", ·, Query No. 1 Part I To comply with the deficiencies to the ~aterial to be covered in this part, it is suggested that an Appendix be incorporated in the Exhibit F. Attached is a draft of the appendix. You will note that paragraphs 1. 3 a and b dealing v;ritb the spilh.~ay fuse plugs is inco;nplete. This deficient work, which was not included in the original sub~itt~l to FERC, is now being made in Barza 1 s Chicago office. T:~e results of these studies -..;ill be avail able for inclusj on in the appendix during :-he ,,·eek of 13 June 83. t i' r l ' I . t ' f I ! I : . . • "7 -. ' . . ~ ~ ~ ·~ • ' -l-:; : ' . . . . • . . . • . I ·--y-·:--·-· l - D~,!l1Ci4 4 .A..PPEl\i])IX F13 I ,, I I I l I I I I l I dJ ·: -·-····· ·-........ , '',"'"_, __ "<t_ . ' I ,, ·, . 4 . . . APPEJ\1)IX FB -\~ATNA MTD DEV!L CAJ\'TJ.'ON E!-!:BA!\JG1ENT STABILITY A.~ALYSES 1 -Preliminary Design 1.1 General Early stage stability c:nalysis for the 1·~atana Hain Da:n and the Devil Cany.?n Saddle Dam emba:tb::.ents have been ccnducted in sufficient detail to s~tisfy project feasibility. these eYa]uations along -v."Ti th subsequent studies of the spill1.;ay fuse plug ~~ban1=ents for both da~s. 1.2 -Hatana Hain Dam and Devil Canyon Saddle Dam Although the \•Jatana main dam L:aximum cross-section .. ;:"las been analy~ed, the safety factors also apply to the Devil Canyon Saddle Dam, which bas a much lm..;er height. The e!ilbankment design (cross-section anC. foundation treatment) is identical for both embanb-nents (Plates 1 and 2 ) • It should be recognized tbat the quoted safety factors derived from the ±830 foot bigh main dam are conservative for tbe ±150 bigh saddle dam. a. Static Analysis Loading Conditions and Factors of Safety The following conditions were analyzed: Case Construction Normal }1a.ximum Operating Maximum Reservoir Drawdown Naximum Reservoir Level During PMF Required Ninimum Factor of Safety (3) 1.3 l .• S 1.0 1.3 Calculated Factor of Safety U/S Slope D/S Slope 2.0 1.7 2.0 1.7 1.8 1.7 2.0 1.7 The calculated factors of safety as sho~u in the above table indicate no general slope stability problems und~r static loading. b. Seismic Stability Evalu~tion The safety factor evaluation of the emban1anent seismic stability was based on a comparison of available shear strength to the earthquake ind·uce.d shear stresses. A shear st):'ess e:xceedance ratio 'Was utilized to represent an indication of the stability of the embankment slopes. :Based on this comparison, a ratio less than 1. 0 indicr:tes an ample margin of safety., - •• --;Qq I r ·! l I I I I l l I '- Results Figur-es ~ > 5 > 6 and 7 are plots of the drained shear stress exceeda11ce and undrained shear stress exceedance for the soft and stiff core, respect- ively. These plots show zones of shear stress exceedance on the surfaces of the embankment> however, the overall stability of the enb~1~ent is apparent. Conclusions The above results indicate limited zones of shear stress exceedance adjacent to the toe of the U?Stream shell, near the upstream crest, and in the surface lay~r of the do~~stream shell. Since they are localized zones not extendin,:s into the err.bankwent, the overall ewbank..-;Jent 1·:-ill be stable under seismic loading. 1.3 Spill~ay Fuse Pl~g Embankwents The emergency spillway fuse plug e~bankments utilize exterior slopes and fill materials similar to the dam ewbankments (Plates 2 & 3)~ It sheuld be e~phasized that although the fuse plug dike ~~11 co-exist with a reservoir operating pool, it is designed to breach and wash out when overtopped by pools exceecing the maximum operating level. (a) Static -~alysis (b) Seismic Evaluation -., l 1 rr l ~ I 'l • I ~ . ' .. .•. . . i' ', .. ~,..._" ...._ . .,..____.=, ·-:-~ -·· -. -.. ··- ,• ' .... j' ' I a· .. .l t .... J r ,, .; '1'', ,, '. ' j. ~\, ~ ,.,. I 1 ... r r ' 'I ... ... \ .. L .. ~··J L~J { .:·J ~ I I ''~·~ ...... .... ··.-.,, ..... \ '• CREST EL.UO!I \oc~m onm~ "~ conE ~OnAVELfiL7 .. ~!'aiD~ . " • ~0 'fal~l~lllbil . ·--~-_, ____ ..._._._ . ...........,_--~---..--................ 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"' •----------------------~--------------------------------~-----I i i l ' 1 ... .,• i : . L: . .. . "• ' . .. . . .· -----------------------------------~· ... ..._ .... , §[Ql!ON TllflQ!lg!.L§~Q.QLE DAM AT MAXIMUM IIEIGIIr .. -..... . 't. .· .. 't .. ....,.-.--·-----~~-. --·---------~· ·-----~ .... -~--·-- • 0 30 GO FEET iCALE L ~ -I II IHCII • !10 rHT I . fWrl1 ALASKA POWEn AUTIIOniTY . SIIS!_!!!A IIYOflO~UCllliC PI10J£Cf DEVIL CANYON SADDLE DAM SECTION EXIIIOIT F I PLATE 2 -. -~ ......., '• --,,--.~........2 ., ~ ~·~~~ ~~- f l J ' I. ~ f I t r t I fl I l . ! l \' J\ ' __.r \ l.(j 1'-· l l f I l l f. I ~.· I \ l { __ j - <Ji'f -~ t ~ -·i: . I I ~ ! ,. ' '* l A ' 'toP .. or_ \ · 1 ' ., ROCK ~~ t • 1 ---=---....... ~~ --------....... .. . ~~t11~ ,.,~~ )· :t:,', : ~:l;!;:~i :=:;: :~-!!:!~;;!~. :_: .. f'.:ILO:..:.T...:.CI-I:_:AN=NE:_L ----I . ' zzo' ____ .. lECTION scAtE'A" A::_8 (PLATE F57) 3!1' ~ ___ ....;.,;,__ -j I ,_, ........ ,.~ I , -ROAD BRIDGE • ArPRAP "\ s• F'lllE FILTER \I "' ..., ., ... •• f •• 1.5 1 . • cnu;.III:D STOll~ ,,<' on GRAVEL 3/1\ TO I I~ • ~· .. EL 11\J-4 'I ' , '~ j • •,,"11~ I .. <.: . . ; i. :t • . r-· 1 I ' t . ~ ",•. \ .. ..,, ··~~ . •·.;.- * I I / " ;7 . . ~-~ S'lll§llre ' 'S"~Je' I J / 14,"1 ! 10.0' 4 ' 2.0 1 HIIC:K ~ cnliSHF.:O STotlE-----------------· -------..-·-crt\JSIICil SlONE../-j.:l:!Lf CONCRETE LI~No-t:!l CRIIVCL • ol\ G!MVEL nNE ra.rtR 1 • <4 to Jt-4" , ~ c 4 10 314• • \._ F'INE FILTER ---------------· ..,.,. _ __.. _______________________________ _ SECTION THR9UGH FUSE PLUG IPLATE f!17l SCALE D .• t 0 10 20 FEET SCN. £ ll r --::---, (I IHCH • IO rt£T I 1jju1l ALASKA POWER. t.UIHORITY. DEVIL CANYON EMERGENCY SPILLWAY SECTIONS EXHIBIT F l_ _ -~LA!_E ...,_-~ -~ J ~ -• '-·-· I -... ~-~\""' -:r-------I ~ .. -..,...,...........·-···' • 0 r: - 1:.f.1 t, . r--:;-... '-· .. · .. 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Exhibit F Que:r;y No. 1 In compliance with this portion of the non conforming iteu1 it is suggested that Section 4.2(e) (iii) of the Supporting Design Report be corrected to read as follows: (iii) Stability Analysis See Reference--No. 2 Appendix BS The arch dam has • • • • • • also diagrams indicating the stresses at nodal points for the loading cases will be incorporated in PLATE F45 of Exhibit F~ see attacr~ent. ·. 1 r j ! ! 1 l I l I 1 I, l ~· [' r f l ! ): r I . r;:ccc:oo:_"~.;, j I i: ' /! I 'I 1J ll _; ,~:. I i L\ Part 2 E.xhibit F Query No. 1 The following pages present proposals for addressing the deficiencies posed for the following concrete structures: a) Devil Canyon Arch Dam b) Devil Canyon Arch Dam Thrust Block Abutments c) Devil Canyon Arch Dam Spillwav Gate Structure d) Hatana Dam Spillway Gate Structure _--:.- .· .· '~-...... ~~~.,~ ! \ l I l l r 11 '( l l 11 ,, l'i jf I •I 'l I l I f l I 1 l J ' .1 ' ,, i ! l ! l I ' ! ' l , I i 1 ' I . I 1 I I ] .! i I; ,--... 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"j'"";··. j'':- Ji.. ::::-·.: ...... ::·-.~:~ :~!." ..-~! _.)~~ ~ •'::~.::: ~~.:::-j;;·-~i ' • I ·t .... lffi-.::t t!!! " ..::: f"';~-!":: ~::: •;:: :;-}...N.,Ith '' t t I 1 I l •/ ....... .;s-~ -.::,-~' -·:~!-•!!!-!;:~ .. _.~~ ::: -.. ~ .. -.~: ,.._,, jt T ~,• ~Ju -;•/uu ~!!-···-= --..... ~ •U u' I '-~-------... _..~..--. __ •. .L~i!..L"-:.~,..,.,.:;.__...!..., __ !--.1.-!..--__ ,,IJ ... r t·-i-·-r---r-r -f-~-~-;-'!i·T· ·~-·n . .., ...... _ ... ,, ....,.,...:,..•-:t-t•---•"--H•_:nt-.:••.,, .. t_ ~::: -·P• "''\ ,, i •;• ·r ·~ ·~· ·:' ';' m ·,·· ~i.. I t!t_ fl --•'H ___ ut -~·tit __.!ttJ...__:H._.,:•t .,_~t••-• t_!:: _1M ... , ·:· ·r lr ·;· ·:· ·r T -·:· /... 1 :~, ... ·:;: ·---:!!_..:::--.:.:!:--::;:-::::-::H·: 1··- ,' . I 1 • i / -:!:--!\~ -4 ::: -'!~ -:1I ,._f '-.1:.. __ :~_1.._.~. _.L .... ..J:/ 1-t•t_S~.," ... ~ -~JH ;s--:.~!\··::,--·:.::-:.:::-":::-;;: r· "i.'<~:-;f--:~)( r ••• •1-... ~" t•••c ~•·-c. .-......... , ........ _, -'·h _.!,_ ~·~/ It ••tl II ••• ------L-.J.-~,_.----~ ... -----~-"-c:, __ -l.-..~-L--'-'-' .;:.•_ .. ,. _ _:! .{ '--'---'---'-__._:~L~. I J -= l 1.. ~ j ~ : ::! ::: :: :: :::. : : :: !."\.~.C,~t1ttL;;.,":"•·~.!!..'::l..."'"'L.t-... :-t >-:.:._, .. _ ~C.!i".!J ~ ... ~-_.,u tr•.- /.,..-''""""'"••-"-- , . .._ .. .., ..... ,_ .. u·--, .. ...._,,._u.,_:tt. ___ ., ... _..,. ! i !~'f~~~~i~ l4••..:..1,l!.1 1 "t-i1~··.....J.~;"'l..!~J..J::.!'-"~··::. ..... .C'l•'IJ .\ SECTION E-E __ _;S::;E,.;C=..T.:..~~. ~-·· . _:~-~ECTION _Qt 0 '00 1000 90(' BOO DAM PROf.!!::£ -~-----··---.·-··-------~--~--·--~--- "'-------·---'"'"----·---~·----... --------]-· SCALE f! 200 FEEr ·a:::n:--~ (liNCH • 100 FEET) ~-......_~-,'>4-"--o-''~-·- -----"~-.... ---· lf!~r,;;;iTI ---;~::-:==------·-··· __ .. ,_ ... ~ •• ~ ... •~v r~ .;r;·iiJR::.C..,. - -"'-·-----·-.,._..-~, .--1.:£.::::!.. illTION C-C DAM SECTIONS (PARAPET NOT SHON~l ·-----.... _ . ..,___.... ""'\;._...._;-· .'7--...... . ,FEED·· ~ r;• . .. •,...,..-\..o· ........ ~-.:....--...... ~· ""-.... -'~~ .. .,~-....,.__~----~--.-..-...._._. DEVIL CA.\T)"ON li.RCH DAM THRUST BLOCK AEUTHENTS In compliance with this portion of the non conforming item we suggest the incorporation of a table~ summarizing factors of safety for the load- ing cases3 on PLATE F46 of Exhibit F~ see attachment. -l ~ '1 •-' "• V'''" ""~~"'+-" """"'•~w, """ft>'--' "'""""'-•i-'"'" -~...-••'-' __ ...,..,.._., \i I I l ,j l l l I J 1 l l l t ~ ' !· ; " 1 I ! j l l l l i J r I l ! - .· . - : .. • ! .. :-.:"*' ..... . ........ - ·.• .. .. .. ! .I . . J ! • 1 j •• 1 I • t ' ' ' / , r>s / r>E 2.0' .t:.CCESS SHAFT EL 1463 ~8 ' '\. '/EL. 1380 I '\.. •N AT EL. 1466 PLAN AT El PAR APE' rARCH OA.M ~E~l=·~l4~6=6=;====~==~~------------r--------jF==~====T~O=P==O=F~PA=R=A=P=E=T==El=·='=~=66========~~ EL.I~63 ~~L_--~--------~·7~6~·---- 1 I I I I I I I I -L---t-----------. .-+-----.---.L..------. I I GROUTING A I I l__...-1- ELI-466 I 2.00' SECTION ARCH ' '~GROUTING/DRAINAGE GALLERY 0 30 SCALE C::: -= 60 FEET ;;AIIIJ (I INCH • 30 FEET) r.:::;J ALASKA POWER AUTHORITY ill!IDr------:---------..----___, SUSITNA HYDROELECTRIC PROJECT ' ' SECTION B-B . ' DEVIL CANYON MAIN DAM THRUST BLOCKS EXHIBIT F PLJI.TE F45 mau ~ ! ./ I ~ ! { l I \ ! t L v· ~.·· I .1 12 11 "'l••• ~----Ll_ ___ ,:.,~ _ _.... __ .~---~......._,....__.., .... ~-..... ....... ._..._ ______ ,...._._..~.-----~_. ... ___ ' __ ._..._ .... __ -~ ..... _,_.......:...;.,~;.~., .. ~..,j,v.rti-t;.,~~,__ .... .....,~·-·_: I I r r .I ' ! ~ .i J.l I I 1 ·.~ .. ,.-' ' .. · ,4 1 . n· l t '"' ___ j r l\ 4! n ... -..~ !-:, .,· .. :-.. ..:-.. : ... ,. < • • .• ·~ :;. -~: .. ..• ·. ' j l • 1 l t t ij •. u· l, rt R r> e /_./ / /. PARAPET~ / {i~ I D r>c ® (/fJ ~ I A ,, I ,JI,--------.-L~/1/j.f ! ~...-=---d - -·----, s -.=::=::: ·:..::.. _.:::::r~ I S..-Jf---=-------25.------A .It; ·r--,-~-·.=-.:::=-.:~-""" ----!J.. n:t.., -----.. ---· • <~:: ~tl.l -<-=·-----------~ _____ ::_·c··,; -----' 1•u 463 ::r 1 -;------::.=:.=..J.::· ----•• ·--:JT:= • ....L.-1-.. r r "t'CI4? ______ .-~H 0"\A --~ _£ SADOLt OAII E::;~':.!_c!_f;A!ll.!~ 1 .. \J.~~~~J:!.~Ei,l!:Zl.ZL : '£\'lt t~:)c:; JJt:: rA . .'·! :"': ~.t:sr ..:!.o::J~ J!-r~;:.·,rs 20' ACCESS SHAFT --------- I:> a ~ I . ~ f.>c PLAN A-:f. EL ··......._ /TOE . ___,__!lli "<..... LOt.:. c. •:nno~ licr.a1 K~--1Ce OF SAt h~t"""' ti=:l•:;ual<e (o._e SEE) /PARAPET _f.l.~,!l f~ ·-:· rJ.?.CH~-77![--:jl_:::: ,=:=~-. ------.--.:~ m':t:i"",..,.~-_!Ib· 147o I ___ ,_.----ns• ~ ·~·~··' -·-1 I -· -~ ____ , ----~iAOOLt OAI.I I I . . I \~PERVIOUS I l- 1 I I I I I I ~ -~--~-----·--i£~140~ I ; ': I I NO ORAJH,1GE G;;-Li:'e:"R·i--J_l,;_llli I I rGRounN'GI." _____ _ I ·~7-~ I I-~---· ~zp,o' --.""'""']·~0 -4-L --·-·--,--- I I I I I I I I I .§l!CTION A-A -1 lu urr F.lCHT s1 :t~ns _,_,!:: ~aT·-!~:~i.,.t sen-~l s~:;r----r~~Ur~· rJ,=.:atic.~ ·- :it:ict3.en 7'tict1:on 1: .J.... t~ .. !;r, 6.37 !;..t,_ N.A. 1 • .04 6.45 N.J.. !~~s.ic~~~ei's '!and -.613 Tlln; t. • 200 psi "-__ .,_,_,,__ -_ .. _ .. __ \ \_r_ n~-i v.:-.:;.~ ' .u• ,J_~ E~--~- f --f I ~!lQN B-8 SEC.ll.QN C-C LEFT ABUTM,S_NJ_1J:!!liJ§J..:.~.~Qg L-----------·------------·--------... ,,..,.__,_. ___ ~-~---.._~-" D ~ I..?E PLAN AT EL. 1466 .[·--]1[ I.J~l.IID466. I I I I I I I I I I I I I I I I I I I I I I I I I 1 I I I I 1 ~-~~-J ~ -~ _ _j l_ . : _ ....--:=1£P_.QL..P.!!!£fL_n.l•ss Et..l~63 I I I I I I I I I I .E.L~?~. -~~ c==;.r)(,,;;;;.;,: ( ) " ' ' 'a• . :( SPil.LWAY THRUST BLOCK, ·~':';, = 1 7;' 1 ~==--..... GROUTJNG/ORAIN"-GE ' ' ", ,, ' GALLERY ' .._ '-.._ ARCH DAM ' .... SECTIOI~ 0-0 '~GllbUTitiC/IlRAIN4GE >-. GALLERY ~ PARAPET f.\:,!~.6 2.5' u:-:.~ . -~· LiO~~,t.,tlD~ERGE I I EL1~63 r-··<-~-- _ ... _ ... _ I \,.~ \tU]~~ ----·"-'·'-~~ s EC..!.!.Q!L H RI~HT ABUT.MENT THRUST Bh2.8£ SCALE 0 30 _ ._!0 FEET ~::: .. ..::::.:-...; (liNCH • 30 F£ETI WNJ C ~_~:::~"M • vuo...n "'V • nvru 1 I J ~USITNA HYORnl='t t:'f"'TD•" ,.. ... _ .... I . . t ' • '. ·' '-I,Y:· •_.-.' -·. ?" -! ? " ... :m.r.eMt·':W~~~~ U£• ~-·,...., ..• ~,.-. .._.._~~~~~~~""'-·.· -~~~~-·~-~~--·---· 1. f . 4 l I 1 Jl c • ) D1VIL CAJ\TYON MAIN SPILLWAY GATE STRUCTURE . Exhibit F Quex:y No. 1 In compliance with this portion of the non conforming item it is suggested~ that the follwoing tables summarizing the stresses and factors of safety for the loading cases 3 be incorporated in PLATE F55 of Exhibit F. . . -· . , ·---···d CONCRETE APRON U--------··-· ~9 lot:; ----------------~ 11 ':::""":.-:'-'~~-~~~ _,_ _ __,_,._,~..._-v,.._ ~.~--,~~ ~GAT£ HOIST , i" DEVIL CANYON ARCH DA.li SPILLI:AY CATE STRUCllJRE SllilliARY of STABILITY ANALYSES ·D 0 [l I u·, IIOISTI~OUSIHG u.-: 0 0 0 . I u I + '....--r"C '--r-*"'"_.__,_ Load Condition .!!9.r.!:!!!. Includes ice load t!nusual ; n l4£G_Priin plugged E:xtreo:e Ear rhqtiike Peo.·JJ..I:rl•u'l 6.~iil~~ (psi) n/ 56 161 47 -4s·/m Xcg (fc) 5.~ 9.3 38.9 . FACTORS of SAFETY Slidin& SheiiT"F'ioatai.fo:.:n_Ov_e_r-turnins; Friction N.A. 7.4 5.0 N.A. 6.7 2.4 N.A. 2.5 s.o -:r:~+=.:r:~= ' . ·-J30:·1_)' 2.5 1 7 \~·-· ' ... --:..:.=......,.__:! 1.2 .;> I lw'·o" (ROLL WAY --=r-----··-·--=c::-:;:a-:!:::;~ ·...::;:t_:."".;..J.~--:=EF'f:~:-·:t-F· • t I I I _ ____,1 IF-··----.1 I l3C'-:o· I tROL\.WAY ~- 1 I =4:.:::.:""£·±~ _,,-Cw (O,SSEE) Physical para~eters .. eft 2 31.5" + i I c • 100 psi l A JOO~cll"_ -·----~T_il.:_':!!~~J.~.~------·- ---------------.,-------·--~ --_____ .., ___ ..... ,_,.-... ~,.------•r..,·-_,_,. SECTION A-A ARCH CAM-- Tl!RUST BlOCK -t T -~ I . , ... CREST Eb1~"4 - j -.1·-~il --~J::'__:;- .! • :_·~:.::_ ... ::_~·· J-·. ·-~ ~ V-~--:f ·-:---.-: . I · 1 ==:.. . -=--. . . ~ r --_ ::.::Y_. _~.:...:.::.:... · --. =-"'? i' ______ :.::r~---~-· ~--=-T. -1' . 1""':"~~~'---t ill_37_!! ----'-. . --I --~---__.!.._ -------I Iff\-_ --I ----·Jiii-~~ _l_ ---r ----t------' ---·------~l-----L---:;~;---= -EL1~55 -'-----------·--·--• ~--- ·----st·o: -------···· -' -· "'---~ . ., .. NORMAL MA~II.IUM OPERATING LEVEL EL14~5 ~""'-•T-'<-<-~~- ELE'{ATI~ --1 eo':_!l: --------·-EL~JL --~-------.---- F I I ,. I STORAGE VAUlT '---· -· •• .J SlOP LOG STORAGE L ___ _ L ~ o·ORAJ~AGE -7'o~J.i-· ANO G<">O.ITI GAI.LERY NG 'J.~·?.<r -. f' f.~.r,..;,.~,. .. i\---jf:~,r;,.Jii ill!J.9.!:!..f~ j 0 !G ~z FEET SCAlE C -_.;-=;:;;;I ( 1/IG INCH • I FEET I ~~;~~ L ><~w·~::...:.==---·---,---._:..1 ~ ---·. • . ,._._.,. ... roo .-... •n•"" .-tn,.. or",..T i' _., . "' ·) .. ·~ ~> .• ~''.;··-~ ~ t ;~ ~- :------r------------~----------...._ .... ___,.-.-~. . , __ .. -.-.~...-. ''""' .. ------------------· f J I f I -I I 1 1. I I I I! I . ' !: I • ~ I I _, .. d.) l'>1ATANA 1-1AIN SPILLHAY GATE STRUCTURE ' . Exhibit F Query No .. 1 In compliance with this portion of the non conforming item it is suggested; that a table summarizing the stresses and factors of safety for the loading cases_, be incorporated in PLATE Fl3 of Exhibit F, see attachment. ---· .. . .. .. ,... ' . .. . . ,. ...... ~.-·--· -~·-._ ....................... ~ ... --~ ....... _____ -T. . . . ··---.. "·-·-·-·· "· . -M &n\A 4( · .. ' I I l I ! lc I i I > ii. ~l:l .,1 J I 0 -I I I I -~~ \ I ,. r• 'I I' \~-1~ ill ~ . I·; ! r .J rl IJ .IJ i I!L21!!5 .f A £t..212!1 }5 ~ 11 ---..,.-:.-...--:.;'"~".,_.~ ~-. ~0 "' · ' Nt:'iii>C"Mix-.----- lli'!IUTI!oG LEVEL El.. Z18!i .....--~ -- CONe APRON ti"S:Jn=i 1.;>-o r>c :1 .. c ... 0 .. ~ ACCESS ROAO \ ' t 1 ----------~-- Load Condition ~al Includes ice load Unue••al n~in plugged Extreme Earthquake llATANA DA!{ SPlLLIIAY CAT£ STRUCTURE • Slm".ARY of STAlliLlTY A.'IAl.'JSES FACTORS of SAFETY ' • ~·m.hllu"'J sh·<s~ "'U.S/D. S Sliding Shear Floatation (pr.i) Xcg (ft) Friction .. 21 ·/s2 s.s . N.A. 5.3 4.3 2,5 19 j' 42 6.7 4,8 2.5 • 1.8 • N.A. . . -29.j-10B 30.4 N.A. 1.5 4,3 ••• '1:4 (O,BSEE) Physical para~eters . ~ •41" e • 30 psi I . ~Z.t l A 0 HOIST ITUSI~ 0 r lfiOLLWAY \~1 ; I· -·-r=· ----"\,_ ;----I I I -,~!\i;9'-±<--·-..------+ ..;l'~~s-r _.,,stl@ I ~-----' ~19-~ 1 ' ~ ' I .; .. cr::;;,.'lfROOr -:-1 \. v.,g; ~.1\d.b;,Q i ~.:-~~.:H.-~~~~~~~~---------• f:=D:A•N.:~~LE ~B00:Q' __ -----1 \; ,........!--~-- ...... --TO FOUNOATION GROUT 1Nr ANO ORA! NAG!:. GALLERII'.S SECTION 8-8 SECTION C-C ~ii~slP . I UNOE!lFLOOR DRAINAGE ~1._219~ ~--~ t4o'-o:_ ··-------------~ ~------------------· . G~ I ...._ f t !ttl I I jt-d:titl I . I I: , .... 25--~,.,,._.,._.-_.---------.. --~ ---< 1 : l II l.J ---< '--... --< ' __ --1 :1: I ·-'(ROCK ANCHOIIS ·-------... --.---· El,__2~2~--···-------------~~·11 8 'o b ~___E~TROL STRUCTURE ~ .Eb!l'%--!f ,.,,,. __ .. >_ .. --------__ , ____ .. _ 0 16 32 FEET SCALE ~~ (1/16 INCH •I FEEO SECTION 0-0 -·-·-- ---~·---· 'b "'!!! II II II 11 11 ------------·------------~ -----I 1: lr 'l!! - w----~-~-,! _._ __ --.:..y.-_ V" I ---v"-_~· _,li.•----------- A-A t t .. ·----··-.,--~-· ~-·~ -·~·~ .::.-.,._--~"----:;!'~· -~--~-·-·~---; •. -~" :dJ .. ,. I 1 @ J FOLD .a: l FEED( i ':;:'' .l