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HomeMy WebLinkAboutSusitna Hydro Project Economic and Financial Update 1984u:l===::: =" 0 • '"--------------~--~ ~ ~. c.n=~ 01--~ ---------------------------------~" o=-,. o--il"" 0 ==4' ~ 1\) ~ ~ ====() m 1\)== ... Ill -...J 8 i co===" " co-~~ ==n"' ......&.====• _LI I SUSITNA. HYDROELECTRIC PROJECT E.CONOMIC AND FINANCIAL . . UPDATE DRAFT REPORT FEBRUARY 27, 1984 [ ___ ALASKA POWER AUTHORITY _ __, ~ I T I f" l_ [ [ [ [ G 0 ~ 0 [ [ [ [ [ [ [ I ~ MAR 2 G 1984 ALASKA RE80URCES LTBRARX U.S. DEPT. O:F' INTET~IOR , ECONOMIC AND FINANCIAL UPDATE TABLE OF CONTENTS 1.0 INTRODUCTION •.••••••••••.••.•••••.•.•.••••..•• 1.1 Background and Purpose of Update •.•••••.• 1.2 Contents of this Update •••..••••.•••••••• 1.3 Summary of Observations· and Conclusions 2.0 UPDATE OF ELECTRIC DEMAND STUDIES ••••••..••••• 2. 1 Introduction ............................ . 2.2 Methodology For Electrical Demand· Forecasting .•..........••.•...• ~ .. ·~ ..... . 2~2.1 Petroleum Revenue Forecasting System ........................... . 2.2.2 The Man-in-the-Arctic Program (MAP) Economic Model .••.•.••.••••••••.•. 2.2.3 The Railbelt Electricity Demand {RED) M.odel •••.•••.•.••..•.••••••. 2.2.4 The Optimized Generation Planning (OGP) Model •••.•••••..••••••••..•. 2.3 Future 0 i 1 Prices ....................... . 2.3.1 Sherman H. Clark Associates·- No Supply Distribution (May 1983) .. 2.3.2 Alaska Department of Revenue (DOR) Forecast (December 1983) ..... 2.3.3 Data Resources Incorporated (DRI) Forecast (Summer 1983) ...... . 2.3.4 U.S. Department of Energy (DOE) Forecast (First Quarter 1983) ..... . 2.3.5 Other Oil Price Forecasts .••••..•. - i -ARLIS TK 1-1 1-1 1-4 1-6 2-1 2-1 2-2 2-3 2-4 2-5 2-6 2-7 2-7 2-10 2-12 2-12 2-12 /'il-5 I~~ A ;;L '3 no~ lD~7 Alaska Resources Library & Infonnat10n, Servtces A ncbor~ge, Alaska [ [ [ [ [ [ [ [ 0 ~ 3.0 D [ r L [ [ ,~ u [ l r = L, 2.4 Electrical Demand ••••••...••••••••••.••.. 2-13 2.4.1 Projections Underlying Electric Demand . . . . . • • . . • . • . . . • • . • . • . . . . . . . 2-14 2.4.1.1 Petroleum Revenues 2-14 2.4.1.2 Population and Employment ••••.•••••.•••• 2-14 2.4.1.3 Domestic Use of Electricity.............. 2-15 2.4.1.4 Commercial, Government, and Small Business Use of Electricity •.•••..••.• 2-16 2.4.2 Total Electric Demand Projections • 2-18 2.5 Comparison with Utility Forecasts •.••••.• 2-19 2 . 6 Summa r y • • • • • • . . • . • • • • • • . • • • • . • . • . • • • . . • . • 2 -2 0 UPDATE OF THE SUSITNA PROJECT . • • • • • • • • • • • . • • . • 3-1 3.1 Introduction . • • • . • • • . • . • • • • . • • • • • . • • . • • . • 3-1 3.2 Description of the Susitna Project as F i 1 ed at FERC . . . • . • . • • • • • • . . • • . • • • . . . . . . • 3-2 3.2.1 Watana Development ••..•••.•.•..•.. 3-2 3.2.2 Devil Canyon Development ~ . . . . . . . . . 3-4 3.3 Alternative Susitna Development Schemes .•. 3-5 3.4 Potential Design Refinements .••..•.•.•••. 3-6 3.5 Cost Estimates . . • . • • • • • • • • . . • • . • • • • . • . . • • 3-7 3.5.1 Construction Cost Estimate of Project as filed at FERC •••..••.•• 3-7 3.5.2 Construction Cost Estimates with Refinements . . • . . . . • . . . . . . . . . . • . . . . 3-8 3.5.3 Operation and Maintena~ce Costs ... 3-8 - i i -ARLIS Alaska Resources Library & Informatton Servtces Anchorage, Alaska c [ [ [ c [ [ c 0 8 0 c [ c c [ [ c L 3.6 Reservoir Operation Studies ......•..•.... 3-8 3.6.1 Simulation Model ............••.... 3.6.2 3.6.3 Hydrology Reservoir Data ................... . 3.6.4 Turbine and Generator Data ...••.•. 3-9 3-9 3-10 3-10 3.6.5 Reservoir Operation Constraints ... 3-11 3.6.6 Power and Energy Production ..•..•. 3.7 Environmental Status Update ....•.....•... 3.7.1 Aquatic Programs ......•.......••.. 3.7.2 Terrestrial Programs •.•....•...... 3-12 3-13 3-14 3-15 3.7.3 Social Sciences Programs •.•.....•.. 3-18 3.7.3.1 Cultural Resources ......• 3.7.3.2 Socioeconomics ..•..•..... 3.7.3.3 Recreation .•...•.•... -.... 4.0 NON-SUSITNA GENERATION ALTERNATIVES .•.•...•... 4.1 Introduction ............................ . 4.2 Natural Gas-Fired Options ....•...•....... 4.2.1 Natural Gas Availability and Cost ............................. . 4.2.1.1 Cook Inlet Gas Availability .......••.... 4.2.1.2 Cook Inlet Gas Consumption .....•........ 4.2.1.3 Cook Inlet Gas Price ..... 4.2.1.4 North Slope Gas ••.....••. -iii - 3-16 3-17 3-17 4-1 4-1 4-2 4-2 4-2 4-4 4-9 4-11 [ [ [ [ [ [ [ c 0 § 0 c [ [ [ c [ [ [ 4.2.2 Natural Gas-Fired Powerplants ..... 4-15 4.2.2.1 Simple Cycle Combustion Turbines ................ . 4.2.2.2 Combined Cycle Combustion Turbines ................ . 4.3 Coal-Fired Options ..•.••.•..•..•.••..•.••. 4.3.1 Coal Availability and Cost in Alaska ...••..•.•.••..••.••.••••..• 4.3.2 Coal-Fired Powerplants ..•......... 4.4 Chakachamna Hydroelectric Project Deve 1 opment ••••••••••••••.••••••••••••••• 4.5 Environmental Considerations of A 1 tern at i v e·s ••••••••••••••••••••••••••••• 4.5.1 Natural Gas-Fired Facilities .•..•. 4.5.1.1 Beluga Region ..•......... 4.5.1.2 Kenai Region .••...•.....• 4.5.1.3 North Slope .••........•.• 4.5.1.4 Fairbanks •..•............ 4.5.2 Coal-Fired Facilities ............ . 4.5.3 4.5.2.1 4.5.2.2 Beluga Nenana Chakachamna Hydroelectric Development .•••......•.••.•....•.. 4-15 4-16 4-16 4-17 4-21 4-22 4-23 4-24 4-25 4-·26 4-28 4-30 4-32 4-33. 4-35 4-36 4.5.3.1 Water Resources .......... 4-37 4.5.3.2 Aquatic Communities ......• 4.5.3.3 Terrestrial Communities .. 4.5.3.4 Socioeconomic Factors .... 4.5.3.5 Aesthetic Factors •....... - i v - 4-38 4-40 4-41 4-41 [ l [ c c [ [ [ 0 fj 0 c [ [ [ c c c l 5.0 SYSTEM EXPANSION PROGRAMS . • •• . ••••..• ••• ••. .• • 5-1 5.1 Introduction 5.2 The Existing Rail belt Systems •••••.•...•• 5.2.1 Anchorage-Cook Inlet Area ••••••••• 5.2.2 Fairbanks-Tanana Valley Area •••••• 5.2.3 Total Present System 5.3 Generation Expansion Before 1993 ......••.• 5.4 Formulation of Expansion Plans After .1993. 5.4.1 5.4.2 Reliability Evaluation ••••..•.••.• Hydro Scheduling .••..••••..••.•••• 5-1 5-2 5-3 5-4 5-5 5-5 5-7 5-8 5-9 5.4.3 Thermal Unit Commitment • • . • • • . • . • • 5-9 5.4.4 5.5 1993 5.5.1 - OGP Optimization Procedure •.••.••• 2020 System Expansion ••••••••••••.• Transmission System Expansion .•••• 5-10 5-11 5-11 5.5.2 Generation Expansion·.............. 5-11 5.6 Review of Expansion Plans •• , .•••••••••.•••. 5-14 5.6.1 With-Susitna Expansion Plan........ 5-14 5.6.2 Non-Susitna Expansion Plan .••.•.••• 6.0 ECONOMIC FEASIBILITY ••••.••••••••...•••.•.•... 6.1 Introduction •.•••••..•.•••......•.•••.•.• 6.2 Methodology ••••••••••••• -••••••••....•.... 5-15 6-1 6-1 6-1 6.3 Results of the Economic Analysis •......•. 6-4 6.4 Threshold Values of Susitna Justification. 6.4.1 World Oil Price Forecast ••.••.•••• - v - 6-5 6-5 0 c c c [ [ [ c 7.0 0 8 0 c [ [ [ L [ c 6.5 6.4.2 Discount Rate •.••..•.••••.•.•••••. 6-6 6.4.3 Construction Cost Estimate for Watana Development • • • • • • . • • . • • • . . . 6-6 6.4.4 Real Interest During Construction.. 6-7 Sensitivity Analysis 6-7 6.5.1 Cook Inlet Gas Supply.............. 6-8 6.5.2 Real Escalation of Fuel Costs •••.. 6-8 6.5.3 Utilities' Forecast............... 6-10 6. 6 Conclusions •.•••..•......•.•••••.•.. ·••... 6-12 FINANCIAL OPTIONS.............................. 7-1 7.1 Introduction • • • • • • • • • • • • • • • • • • • . . . • • • • • . • 7-1 7.2 General Approach and Procedures •.•.•••••• 7-3 7.3 Potential Funding Sources ••••••••.•..•••• 7-4 7.3.1 State Equity Contributions ••••.•.. 7-5 7 • 3 • 2 A 1 ask a Permanent Fund • • • • • • . • . . • • . 7-6 7.3.3 Rate Stabilization Fund ·······~··· 7-8 7.3.4 Tax-Exempt Debt................... 7-10 7.3.5 REA Guaranteed Loan Program .•.•..• 7-19 7 .3.6 Other Sources of Funding • • • • • • • • • . 7-23 7.4 I~pact.of WPPSS Default on Susitna F1 nanc 1 ng................................. 7-25 7.5 Financing Options Selected for Analysis... 7-28 7.6 Analysis of Financing Options............. 7-30 7.6.1 Comparison of Options.............. 7-30 7.6.2 Sensitivity Analyses............... 7-33 7.6.2.1 Revenue Bonds............. 7-33 7.6.2.2 Willingness to Pay........ 7-35 -vi - c [ c 8.0 c [ [ [ c D 0 0 c [ c c c c c c 7. 7 Cone 1 us ions................................ 7-36 FUTURE ACTIONS • • • • • . . • • • . • . . . • • • • • • • • • • . . • • • • • 8-1 8.1 Introduction • •• • • • • • . • • • • • •• • • • •• • • • • • . . • 8-1 8.2 Power Sales Agreements •••••••••••••••••.• 8-1 8.3 Final Finance Plan • • • • • • • • . • • • • •• • • • . •• • • 8-2 8.4 Legislative Authoriiation ••.••••.•••••••• 8-4 8.5 FERC License and Other Major Permits ••••. 8-4 8.5.1 8.5.2 FERC License Other Major Permits 8-4 8-5 8.6 Design Completion for Initial Contracts •. 8-6 8.7 External Review Board Concurrence ...••••• 8-7 8.8 Acceptable Labor Agreement • . • • • . . • • . . • . • • 8-7 8 . 9 .A c qui s i t i on of Project Lands • . • • . • • . • • • • • 8-8 a.10 Power Authority Decision to Construct .•.. 8-9 -vii - 0 c [ c [ [ [ c 0 [] D c c [ c c c c D Number 2.1 3.1 3.2 3.3 4.1 6.1 6.2 6.3 6.4 7.1 7.2 7.3 7.4 7.5 Title ECONOMIC AND FINANCIAL UPDATE LIST OF TABLES SHCA-NSD World Oil Price Projections .••.• Cumulative Present Worth of Alternative Susitna·Development Plans •••••••.••••••.. Summary and Cost Estimate •.•••••.•••..••• Potential Minimum Flows at Gold Creek .••• Estimated Beluga Field Coal Costs W i t'hout Exports .••.......••.•••.•.....•.• Results of Economic Analysis ..•••.••.••.• Sensitivity Analysis Using Zero Percent Co a 1 Es ca 1 at ion •••.••.••••••.•..••••..•.• Sensitivity Analysis of Real Escalation of Fuel Costs Beyond 2020 ••.••••••••..••• Economit Analysis Using Utilities' Forecast ................................ . Comparison of State Equity and RS F Cant ri but ions ••••.••••••••..•.•..•••. Disbursement of State Equity and RS F Cant ri but ions .••••••••...•.•••••...•. Sensitivity of Analysis to Exemption and Dedicated Revenues ••••••••••.•..•••.• Sensitivity Analysis Disbursement of Equity and RSF Contributions .•••••..•.••. Sensitivity Analysis of 120 Percent Willingness to Pay ••..••••••••.••••.•••.• -viii - ~ 2-10 3-5 3-7 3-12 4-19 6-4 6-9 6-10 6-11 7-31 7-32 7-34 7-35 7-36 [ [ [ c [ [ [ c 0 0 [ [ [ [ [ [ [ c c Number 1.1 2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8 2.9 2.10 2.11 2.12 2.13 2.14 2.15 2.16 2.17 2.18 2.19 2.20 249/164 Title ECONOMIC AND FINANCIAL UPDATE LIST OF EXHIBITS Checklist of Key Variables Relationship of Planning Models and Input Data MAP Model System RED Information Flow Oil Price Forecasts SHCA-NSD and DOR Mean Oil Price Projections Alternative Oil Price Projections Summary of Input and Output Data fro~ the Computer Models State General Fund Expenditure Forecast · Railbelt Population Forecast Railbelt Households Forecast Electric Energy Demand Forecast Electric Peak Demand Forecast State Petroleum Revenues State and Government Expenditures Population Employment Households Residential Electric Energy Use Per Household Business Electric Energy Use Per Employee Projection of Electricity Requirements -ix - u c [ c [ [ [ c c ~ 0 c [ [ c [ [ c D Number 2.21 2.22 2.23 2.24 3.1 Title Projected Peak and Energy Demand Railbelt Utilities Forecast Chugach Electric Association, Inc. Projections of of Total System Energy Generation Summary of Energy and Peak Generation Projections made by Power Authority and Utilities · Susitna Hydroelectric Project -Operation and Maintenance Cost Estimates 3.2 Area and Volume Versus Elevation -Watana Reservoir 3.3 Area and Volume Versus Elevation -Devil Canyon Reservoir 3.4 Powerplant Data 3.5 Susitna Energy Generation 3.6 Power and Energy Production -Year 2020 Demand Level 4.1 Estimated Cumulative Consumption of Cook Inlet Natural Gas Reserves 4.2 SHCA-NSD Scenario Fuel Costs 4.3 Thermal Plant Operating Parameters and Costs 4.4 Chakachamna Hydroelectric Project Data 4.5 Summary of Environmental Impacts Caused by Alaska Rail- belt Electric Power Alternatives 5.1 Location Map Showing Transmission Systems · 5.2 Total Generating Capacity within the Railbelt System 5.3 Existing and Planned Railbelt Hydroelectric Generation 5.4 Railbelt Installed Capacity - X - 249/164 c c [ c c [ [ [ 0 ~ 0 c [ [ [ [ [ [ c Number 5.5 5.6 5.7 5.8 5.9 5.10 Title Optimized Generation Planning (OGP) Program Information Flows Expansion Plan Yearly MW Additions with Susitna Alternatives Expansion Plan Yearly MW Additions -Non Susitna Alternatives Summary of Railbelt System Generation Mix in Year 2020, Economic Cost of Energy, and Cumulative Present Worth With-Susitna Alternative ~ Energy Demand & Deliveries Non-Susitna Alternative -Energy Demand & Deliveries 6.1 Principal Economic Parameters 6.2 7.1 7.2 7.3 7.4 7.5 7.6 7.7 7.8 249/164 Results of the Economic Analysis of System Expansion Plans Assumptions Used in Financial Analysis Funding Requirements -Base Case Financing Option A -Annual Disbursements Financing Option B -Annual Disbursements Energy Cost Comparison Annual State Contributions for Financing Options A and B Annual State Contributions for Option A Sensitivity Cases Annual State Contributions for Option B Sensitivity Cases -xi - ,D \ [ I [ c [ § 0 [ [ c c L [ [ L I 1.0 INTRODUCTION 1.1 BACKGROUND AND PURPOSE OF UPDATE The Susitna Hydroelectric Project is one of the largest hydroelectric ·projects ever:-brought before the Federa 1 Energy Regula tory Commission (FERC) for issuance of a license. Pursuant to legislative authori- zation, the Alaska Power Authority {Power Authority) has filed for a license to construct and operate the Susitna Project in furtherance of its statutory duty 11 to promote, develop, and advance the general pros- perity and economic welfare of the people of Alaska by providing a means of constructing, acquiring, financing, and operating power projects, .. including hydroelectric projects {ALASKA STAT. § 44.83.070.). The Project is designed to play a major role in meeting the future elec- trical demand of the Alas.kan Railbelt, where over 70 percent of the State's population currently resides. Proceeding with Susitna has not been undertaken 1 ightly or without careful consideration of its feasibility. Beginning in 1980, a detailed study of the economic, engineering, environmental, and financial fea- sibility of the Project was undertaken for the Power Authority by Acres American, Inc. (Acres}. Acres completed the Feasibility Report in April, 1982. With regard to the economic feasibility of the Susitna Project, the Acres• study concluded "that there is a high probability that development of the hydroelectric potential of the Susitna basin 194/169 1-1 L [ [ [ [ [ [ [ c 0 0 c [ r' u E [ [ [ c would provide significant cost advantages when compared to alternative means of meeting projected Railbelt power demands. 11 To ensure an independent and objective evaluation of alternatives, the 1980 State Legislature determined that an independent consultant should prepare a study of Railbelt electrical power alternatives. The Office of the Governor contracted with Battelle Pacific Northwest Laboratories, Inc. (Battelle) to analyze and prepare a series of reports on alterna- tive means of meeting anticipated Rai"lbelt electric power demand, including a forecast of electrical power demand in the Railbelt through the year 2010. In its December 1982 report, Battelle considered various Railbelt energy plans and concluded that the plan which included con- struction of the Susitna Project would provide the lowest cost of power over an extended time period and be the most resistant to inflation. In an 11 Addendum to Executive Summary,11 issued in December, 1982, Battelle noted that there had been a decline in world oil prices during the period January through March, 1982. The report concluded that, . although these lower .world oil prices would make the Susitna Project less attractive economically, it still was the best means of meeting the Railbelt's long-term power requirements. The Susitna Hydroelectric Project License Application was prepared based on data developed in the feasibility and project alternatives studies and, with Legislative authorization, was filed with the FERC on February 28, 1983. Noting the sensitivity of the Project's economic feasibility to world oil prices, the FERC directed the Power Authority 194/169 1-2 [J [ [ [ [ [ [ c c [] c c [ [ c l c [ c to refine the relevant studies in the Application to reflect up-to-date projections of, among other things, world oil prices. The Joint Venture of Harza Engineering Company and Ebasco Services, inc. (Harza-Ebasco), which had been retained by the Power Authority for the design phase of the Susitna Project, performed these analyses. On July 11,_1983, the Power Authority complied with the FERC directive and supplied supplemental data and electric power demand forecasts based on several, revised world oil price forecasts, including a 11 Reference Case 11 developed by Sherman H. Clark Associates (SHCA). As with most world oil price forecasts evaluated, the electrical demand estimates derived from the SHCA world oil prices supported the economic feasi- bility of the Project. The License Application, as supplemented, was accepted by FERC on July 29, 1983. Considering the 1983 drop in world oil prices and the sensitivity of Susitna•s feasibility to such prices, the Power Authority ~card of Directors has instructed that an 11 Update 11 report be prepared on the economic and financial feasibility of the Project. The report is to . take into account the most current data on the key economic variables affecting the Project's feasibility, including world oil prices and the pricing and availability of alternative fuels. It is also to provide options for finan,cing the Susitna Project. This report is supplied in response to the Board's request. 194/169 1-3 c [ [ [ [ [ [ c [j c c [ [ [ [ l [ c [ Beyond the general purpose of providing updated economic and financial data relating to the Susitna Project, this Update has several specific functions. They are: 1. To provide a status report on Project engineering, environ- mental, and planning studies; 2. To provide an assessment of the economic and financial feasi- bility of the Project using current data for ke~ variables, including world oil prices and the cost of alternative sources of power. A summary of current values for the key variables and of threshold values for those variables is presented in the 11 Checklist of Key Variables 11 included at the end of this chapter as Exhibit 1.1; 3. To identify environmental consequences associated with alter- native generation modes; and 4. To identify options for financing the Pr~ject. 1.2 CONTENTS OF THIS UPDATE This Update is organized into eight chapters which follow the methodol~ ogy used to assess the feasibility of the Project. Chapter 2 provides a description of the electrical demand forecasts. It describes the 194/169 1-4 n [ c [ [ [ [ [ 0 D 0 c [ [ [ [ [ L c computer models and the methodology used in linking the oil price forecasts to economic analysis, electrical demand forecast, and optimal system planning. This chapter relies largely upon the work performed in connection with the July 1983 License Application filing. Chapter 3 provides a description of the Project as contained in the FERC License Application. As a status report, Chapter 3 then describes the various design refinements which are under consideration. It also dis- cusses the status of environmental programs relating to the Watana Development. Chapter 4 reviews the Non-Susitna generation alternatives. The costs and performance characteristics of these generation alternatives are updated to reflect the latest available information. The chapter also discusses the availability and cost of natural gas and coal for use in the thermal plant alternatives. Chapter 5 describes the means by which the demands of the future elec- trical system can be met, with and without the Susitna Project. The sizes, types, and num~er of power plants and the installation schedules are developed by a computer model. The annua 1 costs of constructing, operating, and maintaining each supply alternative are presented. Chapter 6 presents conclusions, based upon the preceding chapters, regarding the economic feasibility of the Susitna Project. Benefit/cost ratios are developed for the Susitna Project by comparing the 11 present 194/169 I 1-5 (1 L n [ [ C [ [ [ c 0 0 [ [ [ [ [ [ [ Li worth 11 of the With-Susitna expansion plan with the Non-Susitna expansion plan. Chapter 7 discusses potential sources of financing, and reviews two potential financ~ plans with differing levels of State capital involve- ment. Chapter 8 presents further actions which need to be taken prior to construction. These include: 1) completion of power sales agreements; 2) resolution of finance issues; 3) obtaining legislative authorization; 4) issuance · of the FERC 1 i cense and other permits; 5) completion of design; 6) concurrence of final design by the External Review Board; 7) execution of an acceptable labor agreement; 8) acquisition of Project· lands; and 9) final approval by the Board of Directors. 1.3 SUMMARY OF OBSERVATIONS AND CONCLUSIONS From the economic and financial studies presente~ in this Update; the following observations and conclusions can be made: 0 194/169 Assuming world oil prices as forecast in the SHCA-NSD case, the Susitna Project is economically more attractive than thermal alternative plans. The construction of the Susitna Project would result in a net benefit of $1.06 billion (in 1983 dollars} over the first 50 years of operation. 1-6 [ [ [ [ [ [ [ [ c [j C [ [ [ [ u [ c c 0 0 0 0 r 194/169 The 1983 construction cost estimates for the Watana and Devil Canyon projects as submitted to the FERC are $3.8 and $1.6 billion, respectively •. Engineering design refinements could reduce Watana construction costs by approximately eight percent a The electric energy demand forecast for the Railbelt is sufficient to absorb the output of the Watana project as early as 1993. Based on either of two recommended financing options, will require about $2 billion (1983 dollars) in State equity and rate stabilization fund contributions in order fo~ the initial cost of energy from Susitna to be ·competitive with the cost of · energy from the least-cost thermal alternative. Major changes in economics and in load projections could change the expected net benefits of the . Susitna Project. Events such as substantially lower world oil prices, higher construction costs and higher interest rates than those assumed in the Update, could reduce the net benefits. On the other hand, higher world oil prices, lower interest rates or lower Susitna construction ·costs would increase· the net benefits of the Susitna Project. 1-7 [J [ [ [ [ Oil Price Forecast -$/bbl 1983 (b) [ [ c [ 0 1993 2010 2020 Long Term Oil Price Growth -%/yr 1983-1993 1983-2010 1983-2020 Projection of Energy Generation -GWh/yr 1983 1993 2010 2020 Long Term Load Growth Rate -%/yr 1983-1993 1983-2010 1983-2020 Ol.. Cook Inlet Gas Price Forecast -$/MMBtu 1993 2010 c 2020 2050 Cook Inlet Gas Price Growth -% [~ Cook Inlet Gas Availability -Forecast (b) ~ North Slope Gas Price Forecast -$/MMBtu (i) 1993 2010 r.• 2020 L 2o5o ~ North Slope Gas Availability Forecast [ [ CHECKLIST OF KEY VARIABLES (January 1983 prices) Feasibility Study 38 (c) 46 (c) 65 (c) 65 (c) 2.0 2.0 1.5 3,402 5,126 8,414(d) 4.2 3.4 3.2 6.2 6.2 6.2 FERC License Application 28.95 30.49 50.39 64.48 0.5 2.0 2.2 3,027 4,321 6,280 8,039(d) 3.6 2.7 2.7 3.02 5.00 6.39 9.05 28.95 30.49 50.39 . 64.48 0.5 2.0 2.2 3,088 4,397 6,444 8,312(d) 3.6 2.7 2.7 3.02 6. 97( f) 8.92(f) 12. 62( f) EXHIBIT 1.1 Page l of 4 Threshold(a) 28.95 25.13 33.35 37.62 -1.4 0.5 0.7 (e) (e) (e) (e) (e) (e) 2.45(g) 2.97(g) 4.85(g) 7.58(g) Linked with oil price growth Assumed unlimited NA NA NA NA NA Assumed unlimited 4.22 6.97 8.92 12.62 Assumed unlimited Price dependent 4.22 6.97 8.92 12.62 Available in 2007 (h) 4.00(g) 4.18(g) 4.85(g) 7.58(g) (j) [ [ c [ [ c 0 {:1 u c c c c c c c CHECKLIST OF KEY VARIABLES (January 1983 prices) Nenana Coal Price Forecast $/MMBtu (b) 1983 1993 2010 2020 Nenana Coal Price Growth -%/yr 1983-1993 1983-2010 1983-2020 Nenana Coal Availability Forecast Beluga Coal Price Forecast $/MMBtu (b) (1) 1983 1993 2010 2020 Beluga Coal Price Growth -%/yr 1983.,.1993 1983-2010 1983-2020 Beluga Coal Availability Forecast Real Discount Rate (%) Real Interest Rate ( %) General Inflation Rate (%) Susitna Construction Cost - $ X 10 6 Watana Devil Canyon Capital Cost Escalation Rate -% 1982 to 1985 1986 to 1992 1993 on Feasibility Study 1.9 2.4 3.1 -~ 2.4 1.8 (k) 1.5 2.0 2.7 2.9 2.2 Unlimited 3.0 3.0 7.0 3,805 (o) 1,535 (o) 1.1 1.0 2.0 FERC License Application 1.72 2.17 2.57 2.84 2.3 1.3 1.2 (k) 1.86 2.17 2.57 2.84 1.6 1.3 1.2 Unlimited 3.0 3.0 7.0 3,750 (o) 1,620 (o) 0.0 o.o o.o Update 1.72 2.17 2.57 2.84 2.3 1.3 1.2 (k) 1.86 2.17 2.57 2.84 1.6 1.3 1.2 Unlimited 3.5 3.5 6.5 3, 750 1,620 o.o 0.0 o.o EXHIBIT 1.1 Page 2 of 4 Threshold(a) 1.72 1.72 1.72 1.72 o.o o.o 0.0 (m) 1.86 1.86 1.86 1.86 0.0 0.0 0.0 (m) 5.3 7.4 N/A +33% (n) (n) (n) (n) [ [ [ [ [ [ [ [ c c [ [ [ [ [ [ [ CHECKLIST OF KEY VARIABLES (January 1983 prices) Project Timing Watana NA Devil Canyon Benefit/Cost Ratio State Equity Contribution (1983 $ billions) Wholesale Cost of Energy (cents per kWh) NA: Not Applicable Feasibility Study 1993 2002 1.17 1.9 (p)(q) 14.7 (q) FERC License Application 1993 2002 1.33 1.9 (p)(q) 13.6 (q) Update. 1993 2002 1.19 1.9/2.1 (r) 11.2 (r) EXHIBIT 1.1 Page 3 of 4 Threshold(a) NA NA NA NA (a) The threshold point is that point for each variable at which the Susitna Project has a benefit/cost ratio close to 1:00, holding all other variables constant. In determining the threshold points for prices of oil and natural gas, the values under the June 1983 DOR Mean scenario are used, since the benefit-cost ratio for that scenario is close to 1.00. (b) 1982 Feasibility Study fuel costs were inflated to January 1983 price level using the U.S. GNP index of 6.011;. (c) Based on 2.011; average annual growth rate until 2010, and 011; thereafter as reported in February 1983 Exhibit D p. 0~4-22. (d) Last year of generation expansion planning studies. (e) A large decrease of this variable would be required to arrive at the threshold value. (f) Economically recoverable Cook Inlet reserves are assumed to be depleted in 2007. Analysis further Cook Inlet reserves will be priced equivalent to North Slope gas • (g) Approximate. The threshold value would be lower. (h) No threshold value, because of substitution possibilities. assumes (i) Forecast also represents prices of gas from some other sources such as Cook Inlet after year 2007 to reflect increased prices due to higher exploration and development costs, and associated risks. c [ [ [ [ [ c c c D c [ [ [ c [ [ CHECKLIST OF KEY VARIABLES (j) Unavailability of North Slope gas, when Cook Inlet gas is depleted, could cause major supply problems to the thermal alternatives. No threshold value is available. (k) 1982 Feasibility Study up to 200 MW of coal-fired steam plant. Revised FERC License and 1983 Update up to 400 MW of coal-fired steam plant. (1) Assume Beluga field developed for export market, but prices sold for local needs independent of opportunity price. (m) Unavailability of Nenana or Beluga coal could cause major supply disruption to the thermal alternatives. (n) A large increase would be required to arrive at the threshold value. (o) January 1982 costs escalated to January 1983 using a 4.3 percent factor. (p) Inflated from 1982 to 1983 using U.S. GNP index of 6.0%. (q) Nominal cost of energy in 1993 based on coal expansion plan. (r) Nominal cost of energy in 1996 based on gas and coal expansion plan. EXHIBIT 1.1 Page 4 of 4 [ [ [ [ [ [ [ [ 0 Q c c [ [ L [~ l,i [ [ [ 2.0 UPDATE OF ELECTRIC DEMAND STUDIES 2.1 INTRODUCTION The first step in assessing the economic and financial feasibility of the Susitna Project is to for.ecast future electrical demand in the Railbelt. This chapter uses the same methodology used in the July 1983 FERC License filing to re-examine predictions of Railbelt electrical demand. Essentially, the methodology involves using a series of inter- active models to project electrical demand based on population, employ- ment, number of households and electricity end use data. These economic· factors are, in turn, based on a series of assumptions and forecasts, the most important of which is the projected world oil price. This Update incorporates the most current data regarding key variables in the modeling process, including world oil prices, the relative cost of alternativ~ fuels, expected electric power prices and energy conser- vation data. The conclusion of the analyses is that electric energy requirements in the Railbelt will increase from 2,808 gigawatts hours (GWh) in 1983 to ~,737 GWh in 1990, 4,542 GWh in 2000, and 5,858 GWh in 2010. There are means of predicting electrical demand other than by econo- metric modeling. For example, most Rail belt utilities forecast elec- trical demand on their systems by analyzing past trends in conjunction with anticipated commercial and industrial development and population 195/169 2-1 [ c [ [ [ L [ c 0 g [1 [ [ growth. The Power Authority has also considered the recent forecasts of the Railbelt utilities in this Update for purposes of comparison. The following sections describe the Railbelt market, the basic approach used to develop the demand forecast and the principal variables and assumptions used in the forecast. The electrical demand forecast produced by the models is given and the forecasts of the Railbelt utili- ties are reviewed. The forecast developed by the econometric models is used to develop the system expansion programs described in Chapter 5. 2.2 METHODOLOGY FOR ELECTRICAL DEMAND FORECASTING The electrical demand forecast used in this Update is based upon a broad econometric, end-use approach. As in the July FERC License filing, four computer models were used in developing the updated power market fore- cast and the assessment of alternatives. These models are: a petroleum revenue forecasting model operated by Alaska Department of Revenue (DOR); the Man-in-the-Arctic Program (MAP) model operated by the Insti- tute of Social and Economic Research (ISER); the Railbelt El~ctricity Demand (RED) model operated by Battelle, and the Optimized Generation Planning (OGP) model; owned and operated by General Electric Company. The relationship between the models and their principal input and output data are shown on Exhibit 2.1. A brief description of the interactive relationship of the models follows. 195/169 2-2 !.LASKA RLSOURCES LTB"RAR'i1 U.S. DEPT. OF INTElUOR fJ [ [ 1 . ·-' [ c r .~ c c (J 0 0 c c [ [ [ [ c [ The petroleum revenue model produces State revenue forecasts based upon petroleum price forecasts. MAP converts these revenue projections into projections of State-wide economic conditions, including population, housing, and employment. The RED model then uses MAP model output, along with additional data, to produce an electrical energy and peak demand forecast for the Railbelt. Results of the RED model analysis, plus generating plant cost data, are then used by OGP to produce least cost generation expansion plans. OGP is provided different sets of input to calculate the best plan with and without Susitna. A complete description of these models is presented in Exhibit B of the FERC July 1983 filing. A condensed description is presented below. 2.2.1 Petroleum Revenue Forecasting System Petroleum royalty payments and taxes constitute approximately 85 percent of the revenue of the State of Alaska. For this reason, projections of State oil revenues are generated by a special modei system. The system generates 17-year State revenue forecasts based upon world oil price projections and other factors. The principal model in the DOR forecasting system, PETREV, is an econo- mic accounting model that examines factors that affect State petroleum revenues in order to produce a range of possible State royalties and production taxes. The principal factors influencing the level of petroleum revenues are North Slope petroleum production rates, the world market price of petroleum, and tax and royalty rates applicable to the wellhead value of petroleum. 195/169 2-3 [ [ [ c [ c c 0 Q 0 c c [· c c c c c In preparation of the July 1983 FERC License filing, a sub-model of the PETREV model (MJSENSO} was used to project petroleum revenues based on alternative world oit prices. Similarly in this Update, the oil reve- nues which would be available to the State of Alaska, assuming world oil prices as forecast in the SHCA-NSD case, were derived from the MJSENSO sub-model. 2.2.2 The Man-in-the-Arctic Program (MAP) Economic Model The forecast State revenues derived from the MJSENSO sub-mode 1 , a long with other key economic financial and demographic data, are placed into the MAP model. MAP is a computer-based economic modeling system that simulates the behavior of the economy and the population of the State of Alaska in each of 26 tegions of the State. The Railbelt consists of six of t.hese regions. The MAP model projects Railbelt economic activity to the year 2010, including factors affecting population, employment and number of households. The MAP model functions as three separate but linked sub-models: the scenario generator sub-model, the economic sub-model, and the regional- ization sub-model, as illustrated on Exhibit 2.2. The scenario gene- rator sub-model enables the user to define scenarios of development in activities that are basic to the ~conomy rather than supportive. Examples of such activities are petroleum production and other mining, Federal government operations, and tourism. The scenario generator sub-model also enables the user to enter into the model assumptions concerning State petroleum revenues, as developed by the MJSENSO model. 195/169 2-4 [ [ [ c c [ [ [ [J g c 0 [ [ c [ [ [ c The economic sub-model produces Statewide projections of economic and demographic data, based on relationships between such factors as employ- ment in industries, State revenues and spending, wages and salaries, gross product, the Alaskan consumer price index, and population. The regionalization sub-model enables the user to break-down the Statewide projections to specific regions of the· State, including the six that make up the Railbelt. 2.2.3 The Railbelt Electricity Demand {RED) Model The projections of population, employment and households generated by the MAP model are entered into the Railbelt Electricity Demand (RED) model to project Railbelt electrical demand. RED is a partial end-use, econometric model that projects both annual electric energy and peak load demand in Railbelt load centers over the period 1983 through 2010. The -RED model forecasts ·annual consumption of electricity for the residential, commercial, small industrial, government, large industrial, and miscellaneous end-use sectors of the two load centers of the Rail- belt (Anchorage-Cook Inlet and Fairbanks-Tanana Valley). The model is made up of seven separate but interrelated modules: the uncertainty, housing, residential consumption, business consumption, program-induced conservation, miscellaneous consumption, and peak demand modules. Exhibit 2.3 shows the basic relationship among the seven modules. The model may be operated in a probability mode to produce a distri- bution of projections, each based on a different, randomly selected set of input parameters. The model may also be operated in a deterministic 195/169 2-5 [ [ [ [ c c c c 0 8 0 c Cl L c· u c [ [ c mode in which only one forecast is developed based on one set of input values. The latter -mode is used in the. Susitna analysis to accommodate input derived from the other models and to accept certain assumptions. The RED model produces projections of electricity consumption by load centers and sectors at five-year intervals. Yearly data are obtained by linear interpolation between the five-year points. 2.2.4 The Optimized Generation Planning (OGP) Model The Optimized Generation Planning (OGP) model uses the output from the RED model, plus data regarding the existing electrical generating system and planned new power plants, to determine the most cost-effective electrical generation system over future time periods. In conjunction with inputting electric demand data into OGP, an impor- tant step in determining the generating capacity that should be instal- led in a future year is to provide the model with the required reliabil- ity of the system expressed in terms of the loss-of-load probability (LOLP). LOLP is the maximum acceptable unplanned outage rate on a system. The OGP model then determines how-much capacity is required and when increments should be installed. Production cost is simulated to compute the operating costs of the generating system with the given unit additions. Finally, the annual investment cost is analyzed considering service lives of equipment and a real interest rate of 3.5 percent. The operating and investment cost analyses enable OGP to project the kind of generation which should be added to the system. 195/169 2-6 c [ ['~ [ [ [ [ c c n [ c [ c [ [ [ c c 2.3 FUTURE OIL.PRICES An important premise of the economic ana lyses presented . in the FERC License Application and this Update is that the State's economy and electrical power demand in the ~ailbelt are linked to the world price of oi 1. In addition to driving the genera 1 economy, oi 1 prices directly affect the State's ability to finance the Project. Accordingly, the necessary starting point for the Update analysis is selection of the world oil price projections. In analyzing the feasibility of the Susitna Project, the Power Authority reviewed several world oil price forecasts. The Power Authority has based its ana1ysis in this Update upon the SHCA-NSD case (the Reference Case in the July 11, 1983 License Application filing). The December 1983 forecast, of DOR, which is very similar to the SHCA-NSD case, is also analyzed. For purposes of this review, the Summer 1983 Data Resources Incorporated (DRI) forecast, the U.S. Department of Energy (DOE) forecast contained in the 1983 National Energy Policy Plan (NEPP), and oil price fore~asts by several other nationally-known organizations are also reviewed. These forecasts are summarized on Exhibit 2.4 and graphically displayed on Exhibit 2.6. 2.3.1 Sherman H. Clark Associates -No Supoly Disruption (May 1983} SHCA speci a 1 i zes in energy and resources economics. Clients include major oil companies, independent oil producers, independent refineries and tanker companies, state, federal and foreign governments, coal 195/169 2-7 c [ [ [ [ [ [ c 0 0 c c [ r-, L [ [J [ [ [ -companies, and electric utilities. SHCA 1 s experience in evaluating and projecting world economics and energy developments has resulted in the de~elopment of an extensive and detailed energy data base which is continuously updated. SHCA annually prepares a detailed 25 to 30 year forecast of the world supply and demand for all types of energy and estimated pricing, titled Evaluation of World Energy Developments and Their Economic Significance. In June 1983, SHCA also prepared an analysis· for the Power Authority titled Long Term Outlook for Crude Oil and Fuel Oil Prices, which extended the oil pricing projections in the annual report from year 2010 to year 2040. The most recent SHCA forecast of world oil prices to 2010 contains three pricing cases based on three different political-economic scenarios: Supply Disruption Case, Zero Economic Growth Case and No Supply Disrup- tion Case. SHCA•s 11 Supply Disruption Case 11 assumes a severe supply disruption in the world oil market in the late 1980 1 s, followed by production-limiting decisions by several key producing countries. These factors result in forecast world oil prices of $40.00 in 1990, $53.76 in 2000 and $87.80 in 2040. · The 11 Zero. Economic Growth 11 scenario assumes no severe supply disruption, combined with zero economic growth in the United States and 0.4 percent growth per year in the free world through 1990. Economic growth after 1990 rises at a rate no greater than 4 percent per year. The forecast oil prices under this scenario are $17.00 in 1990 and 195/169 2-8 [ c [ c [ c [ [ 0 0 c [ [ [ [ [ [ [ [ $45.11 in 2010. Falling between these two scenarios is the 11 NO Supply Disruption 11 (NSD) case. SHCA's NSD case is similar to the Supply Disruption case but it assumes that there is no supply disruption in the late 1980s. Economic growth after 1988 is assumed to be at an annual rate of 3 percent in the United States, slowing gradually to an annual rate of 2.5 percent. Economic growth in the free world is ass~med to be 3.6 percent annually. For the years 1983-1988, forecast oil prices are the same for both the NSD and Supply Disruption case scenarios. From 1988 to 2010, prices increase under the NSD Case at a 3.0 percent annual rate because of the relatively high rate of world economic growth. The rate of price escalation is then assumed to taper off as the oil price approaches the price that will bring forth supplies of alternative fuels. This market condition occurs between the years 2035 and 2040. The SHCA-NSD case was selected as the Reference Case in the July 11, 1983 FERC License filing because its assumptions were consistent with observable events. The NSD case assumes that OPEC will continue operat- ing as a viable entity and will successfully support its benchmark pricing system. It also assumes that economic growth in the United States and the free world will continue at reasonable rates •. In addi- ti on, the NSD case fa 11 s in the middle range of forecasts examined by the Power Authority and, therefore, was determined to be an appropriate- ly conservative forecast for. the economic feasibility analysis presented to the FERC. Similar reasoning, and the fact that the NSD scenario now 195/169 2-9 c [ [ [ [· [ [ c c 0 c c [ [ [ [ [ [ C corresponds closely to DOR's world oiT price figures, s~upports. the appropriateness of using the SHCA-NSD case in this Update. Under the SHCA-NSD scenario presented on Exhibit 2.4, the real price of oil is expec~ed to remain at $26.30 until 1988. From 1988 to 2010, prices increase 3. 0 percent annually. A 1 though price projections for the period 2010 through 2040 are not utiliz~d directly in the modeling process, other than to provide escalation rates, they are presented in Table 2.1. As can be seen, the rate of price escalation is projected to taper off after 2010. Year 2010 2020 2030 2040 Table 2.1 SHCA-NSD WORLD OIL PRICE PROJECTIONS 2010-2040 (1983 $/bbl) $ 50.39 64.48 74.84 82.66 Annual Growth Rate 2.5% 1.5% 1.0% 2.3.2 Alaska Department of Revenue (DOR) Forecast (December, 1983) DOR forecasts future petroleum revenues over a 17-year period to assist in the preparation of State budgets. These forecasts· are updated on a quarterly basis. To develop the revenue forecast, a number of employees of the State's Office of Management and Budget (OMB), Alaska Department of Natura 1 Resources (DNRj, and the Department of Revenue {DOR) each develop one to ten scenarios of future world oil prices, and assign a subjective probability to each scenario. DOR then aggregates these individuals' forecasts and develops a composite probability distribution of future world oil prices. 195/169 2-10 c [ [ [ [ [ [ [ 0 0 0 0 [ [l LJ [ c c [ [ DOR • s forecasts of oi 1 prices are on a monthly basis for the first two years and quarterly for the next three years. Beyond the first five years, DOR forecasts a fixed escalation· rate in oii prices for each probability point. The mean oil price for each period is determined from the composite frequency distribution. Among the oil prices analyzed in the July 1983 FERC filing were those projected in March 1983 by the DOR. DOR's estimates of future revenues are made on a quarterly basis and are used by the OMB in developing and managing the State's budget. A review of the oil prices used in DOR's most recent (December 1983 Quarterly Report) petroleum revenue forecast indicates that the recent mean DOR forecast and the SHCA~NSD case are almost identical. The 17-year projections developed by DOR are presented in Exhibit 2.4. Under the mean scenario, the crude oil real price is expected to. de- crease until 1986 to $25.43 per barrel; then, the real price would increase to $36.57/per barrel in year 2000. A graphic comparison of the SHCA-NSD and DOR mean world oil prices is presented in Exhibit 2.5. To simplify the process and to maintain continuity with the analyses in the FERC License Application, the world oil prices utilized throughout this Update are those developed by SHCA as the NSD case. This approach seems reasonable in light of the similarity of the SHCA-NSD and the most recent DOR forecasts. 195/169 2-11 [ I' LJ [ [ [ [ r, L__) [ [ c [ c [ L [ [ [ [ [ 2.3.3 Data Resources Incorporated (DRI) Forecast (Summer 1983) The projections of crude oil pric.e developed by DRI for 1983 through 2005 are also presented on Exhibit 2.4. Crude oil prices are expected to begin escalating rapidly in the latter half of the 1980's. DRI projects averages of real price increase of about 3.0.percent in the · 1990's, and 1.6 percent for the period 2000 through 2005. The 2005 real price is expected to be $49.47 per barrel. 2.3.4 U.S. Department of Energy (DOE) Forecast (First Quarter 1983) The policy group of the u.s. Department of Energy has developed projec- tions of crude oil price for inclusion in the 1983 National Energy Policy Plan. These projections are presented in Exhibit 2.4. Real prices are expected to decrease unti 1 the mid 1980's, and increase rapidly after 1990. The 2010 real price would vary between $54.60 and $111.46 per barrel. 2.3.5 Other Oil Price Forecasts In addition to the oil price forecasts discussed above, the Power Authority solicited ·forecasts from 17 other sources. These sources included research organizations, universities and oil companies. Ten of the 17 sources contacted had no fqrecast available or did not supply oil price data. The forecasts obtained from the remaining seven sources are presented on Exhibit 2.6, along with the SHCA-NSD, DOR and DOE fore- casts. 195/169 2-12 [ L [ [ [ r-, I __ [ [ 0 0 c· [ [--, .J [ [ [ [ [ [ Inspection of Exhibit 2.6, which portrays the various fo.recasts graph- ically, shows that in the ·early years (1983-1990) of the projections, the SHCA-NSD forecast is in the low range. -In the later years ( 1995-2010) the SHCA-NSD forecast is in the middle of the range of forecasts illustrated. 2.4 ELECTRICAL DEMAND Exhibit 2.7 summarizes the input and output data generated by the MJSENSO, MAP and RED models using the SHCA-NSD world oil price forecast for the period 1983 through 2010, the forecast period for the MAP and RED models. To establish a starting point for analysis, historical data and projec- tions of general fund expenditures, population, household, energy demand, and peak demand are displayed in graphic form in Exhibits 2.8 through 2.12. In summary, the exhibits show that Railbelt population is expected to incr~ase from about 320,000 in 1983 to approximately 530,000 by the year 2010. The corresponding number of households would increase from approximately 110,000 in 1983 to 196,000 in 2010. The electric energy consumption predicted is approximately 5,900 GWh in 2010. The corres- ponding average annual growth rate over the period 1983 through 2010 is 2.8 percent. The peak demand is expected to increase from about 580 MW in-1983 to approximately 1,200 MW in the year 2010. 195/169 2-13 C [ [ [ [ [-, -' [-, [ 0 0 c [ 2.4.1 Projections Underlying Electric Demand Detailed projections of State revenues, economic conditions, and elec- tric energy demand are presented on Exhibits 2.13 through 2.21. 2.4.1.1 Petroleum Revenues Exhibit 2.13 presents projections of State petroleum revenues from each of the primary revenue sources through the year 2010. The first two columns of this Exhibit contain projected royalties and severance taxes, respectively. These projections a.re in nominal dollars, reflecting an annual change in the consumer price index of 6.5 percent. The projec- tions of royalties and severance taxes through the year 1999 were produced by the DOR' s PETREV forecasting model system, adjusted for minor differences in the assumed future rate of inflation. These projections are similar to the DOR mean projections presented in the DOR December 1983 report. Exhibit 2.13 also presents projections of State petroleum revenues derived from corporate income taxes, property taxes, . lease bonuses, and Federal shared royalties. Future revenues from these sources, estimated by ISER, were used along with the projections of royalties and severance taxes as input to MAP. 2.4.1.2 Population and Employment Exhibit 2.15 presents population projections for the State, Railbelt, Anchorage-Cook Inlet area, and Fairbanks-Tanana Valley area. Railbelt population is projected to grow by approximately 67 percent between 1983 195/169 2-14 [ [ [ [ n [ [ c 0 0 0 l~ [ (' L [ c [ [j c and 2010 from 320,000 to 533,000. Within the Railbelt, the Anchorage area is projected to grow by 69 percent, compared to projected growth in the Fairbanks area of 57 percent. The growth of employment, shown on Exhibit 2.16, is uniformly lower than that of population. While Statewide non-agricultural wage and salary employment is proj~cted to grow by 61 percent during the next 27 years, total State employment is forecast to increase by only 51 percent. The Railbelt is projected to experience a higher employment increase, rising by 61 percent, with the Anchorage area growing by 63 percent, compared to 52 percent growth in the Fairbanks area. 2.4.1.3 Domestic Use of Electricity Exhibit 2.17 presents projections of households by the following cate- gories: State total, the Railbelt, the Anchorage area, Fairbanks area, and Statewide by age of head of household. In contra~t to projected employment, households are projected to increase faster than population. Statewide, households are projected to increase by 72 percent by the year 2010, compared to a 75 percent increase in the Railbelt, a 78 percent rise in the Anchorage area, and a 67 percent increase in the Fairbanks area. The effects of demand elasticity are shown on Exhibit 2.18 by adjusting the average consumption per household for conservation and fuel sub- stitution. In the Anchorage area, the average consumption per household is expected to decrease from about 13,700 kWh in 1980 to 12,560 kWh in 195/169 2-15 [ [ [ [ [ [ [ [ 0 0 c [ [ [ c [ [ [ 1990, due mainly to the real increase in the price of electricity which will continue to cause some conversion from electric space heating to substitute fuels. After 1990, consumption is expected to slowly in- crease to about 13,200 kWh in 2010, at an average annual growth rate of 0.25 percent. In the Fairbanks area, the average household consumption is expected to increase from 11,500 kWh in 1980 to 15,200 kWh in 2010, an average annual growth rate of about 0.9 percent. This increase is due to the stabilization of electricity prices, combined with increasing prices of substitute ·fuels. The projected consumption in.year 2000 is similar to the 1975 average consumption. 2.4.1.4 Commercial, Government and Small Business Use of Electricity The employment forecasts obtained from MAP are used in the RED Business Consumption module to derive the electric demand in the commercial- government-small industrial sector. Exhibit 2.19 summarizes the 11 bus- iness use per employee 11 projections. The consumption projections were obtained from a forecast of floor space per employee and electricity consumption per square foot, which was then adjusted for price impacts. Floor space per employee is expected to increase by 10 percent in Anchorage and 15 percent in Fairbanks by the year 2010 to approach the current national average. As a result, in the Anchorage . area the average consumption per emp 1 oyee is expected to increase from about 8,400 kWh in 1980 to 11,500 kWh in 2010, an average annual increase of 1.0 percent. In the Fairbanks area consumption per employee is expected to increase from 7,500 kWh in 1980 to 9,900 kWh in 2010, at an average annual growth rate of 0.9 percent. 195/169 2-16 [ [ 1: [ [ r, - [ [ [ c [ [ [ [ [ [ [ [ l."' _, A breakdown of electric energy demand projections by customer cate- gories, based on the underlying projections of average consumption per household and per employee set" forth in the previous paragraphs, is presented on Exhibit 2.20. Exhibit 2.20 also shows miscellaneous sector usage which includes street lighting, second (recreation) homes, and vacant houses. That sector's usage corresponds to about one percent of the total energy demand. The estimates of industrial loads, including- the large industrial customers which are located in the Homer Electric Association, Inc. service area, and the estimate of the amount of electricity that could be provided by utilities to the military instal- lations, are provided as inputs to the RED model. These loads are projected to increase from about 108 GWh in 1983 to 315 GWh in 2010 for the Anchorage-Cook Inlet area, and from 0 to 50 GWh in the Fairbanks- Tanana Valley area. As most of the large industrial customers are located in the Homer Electric Ass"Ociation service area, the projections of growth in large industrial customers is based on a 1983 power requi.rements study by Burns & McDonnell for that utility. Those projections indicate that electrical demand is expected to increase from 100 GWh in 1982 to 142 GWh in 1990 and 158 GWh in 1995. An annual growth rate of 3.5 percent was assumed after 1995. Discussions with representatives of the two military installations (Fort Richardson and Elmendorf Air Force Base) in the Anchorage-Cook Inlet Region, and the three military installations (Fort Wainwright, Fort Greely, and Eielson Air Force Base) in the Fairbanks-Tanana Valley 195/169 2-17 c [ [ ,~ u [ [ [ [ [ c c c [ [ [ c· [ [ c Region, provided information on their historical and projected electri- city consumption. Continuation of the annual military electricity demand of 150 GWh is expected in each area. Existing power contracts and exchanges with the utilities were reviewed and estimates of the amount of electrical capacity and energy that could be provided by the uti 1 ities were discussed. For load forecasting, ·it was assumed that one-third of the total military electrical demand in each of the two regions, or 50 GWh annually per region, would.be provided by the utili- ties. The military demand is, therefore,. assumed to increase in a linear fashion from 0 ·GWh in 1985 to 50 GWh in 1990 in each region, and remain at 50 GWh thereafter. 2.4.2 Total Electrical Demand Projections Exhibit 2.21 summarizes the annual peak and energy sales projections for each load center and for the total system. This single load forecast was used for all system expansion alternatives described in Chapter 5. A single load forecast for different expansion plans is appropriate because the RED model evaluates consumer conservation of electricity based on price and assumed that the sales price of electricity from the Sus i tna p 1 an wou 1 d not be higher than the price of the therma 1 a 1 tar- native. In effect, this assumption may understate the load forecast for the Susitna expansion plan, since electricity prices would not be as high over the long run for Susitna generated power and conservation would accordingly be less. 195/169 2-18 n [ [' [ [ [ [ [ 0 [ c c [ [ [ [ [ L l 2.5 COMPARISON WITH UTILITY FORECASTS The Railbelt utilities annually produce forecasts of electrical demand for their own respective markets. · Exhibit 2.22 summarizes projections mad~ for the period 1983 through 2001 by the utilities in early 1983, in • . . response to a request from the Alaska Power Administration (APAd). As that Exhibit indicates, the utilities expec_t the average annual growth rate to be about 6. 0 percent for the period 1983 through 1990, de- creasing to 4.5 percent for the period 1991 through 2001. The total energy generation is expected to be 7,662 GWh in the year 2001, which is about 50 percent greater than the model-derived projections. A recent power requirements study done by Burns & McDonnell for Chugach Electric Associat1on, Inc. (CEA) confirms the growth predicted in the APAd survey. The results are summarized in Exhibit 2.23. Three fore- casts of economic activity --low, moderate, and high --were developed for the period 1983 through 1997." Under the Burns & McDonnell moderate forecast, CEA's energy generation projection for the year 1997 is 3,467 GWh, while the utility itself projected 3,428 GWh. The average annual growth rate of electric energy demand projections ~ade by Burns & McDonnell is expected to vary between 3.9 and 6.2 percent for the period 1983 through 1997. Exhibit 2.24 compares the model-derived electrical demand forecast with the current forecasts of the Railbelt utilities. The Exhibit shows that the Power Authority's forecasts are substantially lower. For example, 195/169 2-19 n [ [ [ [ [ [ c [ D c c [ [ [ [ [ [ [ the Railbelt utilities' 1990 energy demand is 4,678 GWh; the Authority's is 4,111 GWh, approximately 12% less. 2.6 SUMMARY Exhibit 2.7 provides the basic data upon which the economic and finan- cial feasibility of the Susitna Project and alternatives are analyzed. Utilizing the world oil price forecast by the SHCA-NSD case (line 1 of Exhibit 2.7), the PETREV/MJSENSO model calculates the petroleum revenues available to the State (lines 5-7). The MAP model utilizes this data as its primary input and calculates State economic conditions over the forecast period (lines 8-13). Using these economic data and other inputs, the RED m~del predicts electric demand in the Railbelt for the period 1984-2010. The result of the models' analysis is a forecast of total Railbelt electric energy sales of 3,737 GWh in 1990 and 5,858 GWh in 2010. ./ 195/169 2-20 PET REV PETROLEUM REVENUE FORECAST FUEL PRICE ---------~-~ ~DUSTRIAL PROJECTIONS ACTIVITY o FUEL OIL ONATURAL GAS oCOAL :--, l ) o~FLATIONRATE------------------------------------------------------------~------------~ ~MODEL ECONOMIC FORECASTS oNATIONAL ECONOMIC PARAMETERS POPULATION EMPLOYMENT RED~ ELECTRIC LOAD FORECAST oRESIDENTIAL/BUSINESS END USE DATA oPRICE ELASTICITIES COEFFICIENTS o INDUSTRIAL LOAD FORECASTS ENERGY OGP MODEL CENERATION AND OPTIMUM ECONOMIC OPTIMIZATION o EXISTINC CENERATION SYSTEM o FUTURE GENERATION SYSTEM o CONSTRUCTION COSTS oOPERA TION AND MAINTENANCE oRELIABILITY· AND AVAILABILITY CRITERIA SUSITNA HYDROELECTRIC PROJECT UPDATE ALASKA POWER AUTHORITY FINANCIAL ANALYSIS OINDEBTEDNESS CRITERIA RELATIONSHIP OF PLANNING MODELS AND INPUT DATA FEBRUARY 1984 c [ c [ [ [ [ c 0 0 [ [ [ [ [ D [ [ [ SCENARIO ~----------41NPUT VARIABLES: GENERATOR MODEL • INDUSTRIAL CASE FILES • PETROLEUM REVENUE • FORECASTS INPUT VARIABLES: r;::======:;--1. U.S. INFLATION RATE EXHIBIT 2.2 I I STATEWIDE •ECONOMIC MODEL • U.S. UNEMPLOYMENT~-.... •ECONOMIC MODULE •FISCAL MODULE •POPULATION MODUI.,E •HOUSEHOLD FORMATION MODULE REGIONAL! ZA TION MODULE RATE • OTHERS PARAMETERS: .__ ..... •STATE FISCAL POLICY PARAMETERS • STOCHASTIC PARAMETERS • NONSTOCHASTIC PARAr,IETERS ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE MAP MODEL SYSTEM FEBRUARY 1984 r [ [ [ [ [ [ c 0 0 c c [ [ [ [ [ c EXHIBIT 2.3 ECONOMIC UNCERT AIN'FT FORECAST MODULE HOUSING -STOCK , It -"" RESIDENTIAL --- , . I -- \ .. BUSINESS -- , L....-. -PROGRAM INDUCED -CONSERVATION - ' LARGE r.HSCELLANEOUS INDUSTRIAL ~ ---ANNUAL SALES ~ t --.. PEAK DEMAND ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE RED INFORMATION FLOWS FEBRUARY 1984 OIL PRICE FORECASTS (1983 $/bbl except as noted) Average Average Average Rate of Rate of Rate of Year Change Year Change Year Change Year 1985 Per Year 1990 Per Year 1995 Per Year 2000 ---( %) ( %) ( %) DOR Mean 25.78 2.6 29.30 1.8 32.09 2.6 36.57 SHCA-NSD 26.30 1.2 27.90 3.0 32.34 3.0 37.50 DRI* 27.77 4.0 33.85 3.2 39.58 2.9 45.71 DOE Low* 21.00 4.0 25.60 3.4 30.30 3.5 36.00 DOE Mid-Range* 2.5. 90 4.3 31.90 7.8 46.50 4.3 57.40 DOE High* 30.50 5.7 40.30 8.1 59.50 6.2 80.30 *1982 $/bbl Average Rate of Change Year Per Year 2005 (%) 3.0 43.47 1.6 49.47 5.2 46 .• 50 6.4 72.20 5.3 104.00 ~ L. J .~ \~ ' J Average Rate of Change Per Year (%) 3.0 NA 3.2 1.3 1.4 Year 2010 50.39 NA 54.60 83.60 111.40 [ [ [ [ [ [ [ [ 0 0 c [ [ L [ [ [ [ [ . -..0 ..0 ....... ~ (W) CX) 0) T- ...J -0 LL 0 w (.) -a: a. 0 ...J a: 0 3: EXHIBIT 2.5 60 I I DOR MEAN -----SHCA~NSD 50 / / / / / / / / 40 ~/ /' / 30 / ...--: ~ ~ /-~/ ~ ~/ . 20 10 0 1983 1985 1990 1995 2000 2005 2010 YEAR ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE SHCA-NSD AND DOR MEAN OIL PRICE PROJECTIONS FEBRUARY 1984 ~- l' ,J I l . l' \J . II .c .c ...... Y7 I ('t) [ co 0) f I T"'" Ll ..J 0 [ LJ._ 0 r w () a: ll a. Q ..J ;J a: 0 l' ~ [ ~ ( ~ l j !I -~ ! l L [ L [ __ 80~~.--------~,-------.~------,-------~----/-./~~ BAH BOOZ, ALLEN, HAMIL TON / 70- CHASE CHASE ECONOMETRICS // DOE DEPT. OF ENERGY I' DOR DRI RAND STAN SRI WB DEPT. OF REVENUE / /' / /' DATA RESEARCH INSTITUTE RAND CORPORATION STANDARD OIL OF CALIFORNIA STANFORD RESEARCH INSTITUTE WORLD BANK 20~-+-------+-------4--------~------~----~ 10~-+-------+-------4--------~------~----~ 0~~--------~------~------~--------~------~ EXHIBIT 2.6 1983 1985 1990 1995 2000 2005 20 1 0 YEAR ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE ALTERNATIVE OIL PRICE PROJECTIONS FEBRUARY 1984 SUMMARY OF INPUT AND OUTPUT DATA FROM THE COMPUTER MODELS Line Item Descrietion 1983 1985 1990 1995 2000 2005 2010 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 World Oil Price (1983$/bbl) 28.95 26.30 27.90 32.34 37.50 43.47 50.39 Energy Price Used by RED (1980$) Heating Fuel Oil -Anchorage ($/MMBtu) 7.75 6.45 6.84 7.93 9.19 10.65 12.35 Natural Gas -Anchorage ($/MMBtu) 1. 73 1.95 2.88 4.05 4.29 4.96 5.38 State Petroleum Revenuesl/(Nom. $xl06) Production Taxes 1,474 1,561 2,032 1,868 1,910 2,150 2,421 Royalty Fees 1,457 1,555 2,480 2,651 3,078 3,799 4,689 State General Fund Expenditures (Nom. $xl06) 3,288 3,700 5,577 7' 729 9, 714 13,035 17,975 State Population 457,836 490,146 554,634 608,810 644' Ill 686,663 744,418 State Employment 243,067 258,396 293,689 313,954 325,186 345,701 376,169 Railbelt Population 319,767 341,613 389,026 423,460 451,561 486,851 533,218 Railbelt Employment 159,147 169' 197 190,883 204,668 214,542 231,584 255,,974 Railbelt Total Number of Households Ill, 549 120,140 138,640 152,463 163,913 177,849 195,652 Rail belt Electricity Consumptionl/(GWh) Anchorage 2,326 2, 561 3,045 3, 371 3,662 4,107 4, 735 Fairbanks 482 535 691 BOO 880 986 1,123 Total 2,808 3,096 3,737 4,171 4,542 5,093 5,858 Rail belt Peak Demand (MW) 579 639 777 868 945 1 ,059 1 '217 Rail belt System Generation (GWh) 3,089 3,406 4,111 4,588 4,996 5,602 6,444 1/ Petroleum revenues also include corporate income taxes, oil and gas property taxes, lease bonuses, and federal shared royalties. II Add 10 percent to obtain total generation. [ [ [ [ [ [ [ [ [ [ [ [ G) 0 ~ .. 2 0 ~ tn w a: :J t:: c z w Cl. X w c z ::) u. . ...J ~ a: w z w (.!) w .... < --------------------..... ------- [ en [ [ [ [ [ EXHBT· 2.8 ~·-50-U! ~--r 'il 28:~ 24. 22 20 18 / 16 / 14 I PROJECTION I / v 12 / 10 / 8 / 6 ~ _..... 4 --------------------------------------· --------------------------------------------------------------------------------------------- ~ 1985 1990 1995YEAR 2000 :t I HIST~RICAL I I 200~2010 _v 1960 1965 1970 1975 1980 1985 YEAR ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE STATE GENERAL FUND EXPENDITURE FORECAST [ [ [' [ f' [ [ [ [ [ [ [ [ [ [ -- EXHIBIT 2.9 ; 700~----~--~~----~----~----~ 600+-----+-~--4-----~----~----~ ~ en ~ PROJECTION < ~ 500+-----+-----+-----4-----~~--~ 0 J: 1- \,.1 z Q 400+-----~~--+-----~----~----~ 1-< _J ::::> a. 2 3001985 1995 20'10 1- _J w CD _J -< 200+-----+---~~----~----~----~ a: 100+-----+-----+-----~----~----~ 0~----+-----+-----~----~----~ 1960 1965 1970 1975 YEARS 1980 -ALASKA POWER AUTHORITY 1985 SUSITNA HYDROELECTRIC PROJECT UPDATE RAILBEL T POPULATION FORECAST FEBRUARY 1984 ,..., (/) 0 z ~ (/) :::> 0 I 1-. ...... (f) CJ _J 0 I w (/) ::> 0 I 1- _J w al _J - <( a: 200 1 yt, 1 0 () 1 2 5 ~ 1! Hl G 100 7 fJ 50 - 'l' ...:.. ~) 0 lHbO I PROJECTION I ~ ------~ ------~ ~ 1990 1995 2000 "' __..,.- YEARS ~ 2005 2010 I HISTORICAL I ~ 1 !H.i!.> 1970 1975 1980 1982 • 1985 YEAI~S ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE RAILBEL T HOUSEHOLDS FORECAST FEBRUARY 1984 ... •','"' ...... 0 r--1 l . ,,I .!: ~ 0 z 0 -t-a.. ~ :::> CJ) z 0 () >- 0 a: w z w _J <( :::::> z z <( I L)(\(1 ----------r------.--------r-----~r--------, to,lllJL) PROJECTION :..0,000 4,000 YEARS 1990 199 5 2000 2005 2010 HISTORICAL I I 2,000 -------·-·· 1,000 YEARS 0 1960 1965 1970 1975 1980. 1982 1985 ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE ELECTRIC ENERGY DEMAND FORECAST FEBRUARY 1984 ~ :-:: :E - 0 z <( :E w 0 ~ <( w Q. 1400r-----------~~-----------,----~------.------------.----------~ 1 <:'00 PROJECTION 1000 t!OO bOO 19t!t. 19!::10 19!::15 2010 ~9~6~0--------~1~96~5-----------1947_0 ___________ 19+7-5-----------.9~8-0--1-98_2 ______ 1~985 YEARS ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE ELECTRIC PEAK DEMAND FORECAST FEBRUARY 1984 m X :r ffi =i [ EXHIBIT 2.13 [ [ STATE PETROLEUM REVENUES (MILLION $) [ Total to Total General Including Fund (Net [ Severance Corporate Property Bonuses of Year Royalties Taxes Income Taxes and Permanent Taxes Federal Fund [ Shared Contri- Royalties but ion) [ 1982 1530.000 1590.000 668.899 142.700 3960.199 3570.549 1983 1456.661 14 73.507 233.969 148.600 3361.836 2985.396 1984 1450.305 1474.080 328.647 153.200 3441.298 3069.956 c 1985 1555.117 1560.529 365.362 158.000 3668.700 3272.498 1986 1724.811 1705.298 398.724 163.456 4020.278 3582.078 1987 1896.215 1857.760 438.776 169.101 4389.691 3908.6 77 c 1988 1997.731 164 7.607 396.949 174.940 4245.582 3739.060 1989 2251.456 1855.795 520.004 180.981 4837.387 4267.234 1990 2480.380 2031.695 591.983 187.231 5321.348 4693.734 0 1991 2352.500 1857.126 668.435 193.697 5102.781 4506.898 1992 2530.291 192 9.692 794.871 200.385 5487.250 4846.672 [ 1993 2657.006 1986.190 906.959 207.305 5790.461 5117.957 1994 2742.898 2006.949 •998.581 214.464 5996.891 5302.664 1995 2651.116 1868.193 1084.124 221.870 5860.301 5188.770 c 1996 2599.817 1737.659 1185.670 229.532 5788.676 5129.719 1997 2 755.836-1856.672 1326.406 237.458 6213.367 5515.156 1998 2865.556 1887.844 1474.798 245.658 6511.852 5785.961 [ 1999 2950.992 1865.044 1649.613 254.141 6758.785 6011.285 2000 3077.885 1909.805 1841.891 262.917 7132.496 6353.023 [ 2001 3210.235 1955.641 2056.580 271.996 7535.449 6722.641 2002 3348.276 2002.576 2296.294 281.389 7970.531 7122.961 2003 3492.2 52 2050.638 2563.949 291.106 8440.941 7557.125 [ 2004 3642.420 2099.854 2862.802 301.158 8950.230 8028.625 2005 3799.044 2150.251 3196.489 311.558 9502.340 8541.328 'lftftL 3962.404 2201.857 3569.072 322.317 10101.640 9099.540 [ 6JVVV 2007 4132.781 2254.702 3985.082 333.447 10753.010 9708.060 2008 4310.492 2308.815 4449.578 344.962 11461.840 10372.220 2009 4495.844 2364.227 4968.219 356.874 12234.160 11097.950 [ 2010 4689.164 242 0.969 554 7.316 369.198 13076.640 11891.850 [ SOURCE: MAP MODEL OUTPUT [ [ EXHIBIT2.14 [ [ S"T;ATE AND GOVERMENT EXPENDITURES [ . (MILLIONS $ ) I [ Unre- stricted Percent of General General Permanent State State Permanent Fund Fund Fund Peraona1 Subsidy Fund [ Year Expendi-Balance Dividends Iacoae Tax Programs Earnings tures Reinvested [ 1982 4601.891 399.200 425.000 o.ooo 634.000 o.ooo 1983 3287.977 478.004 152.608 o.ooo 500.000 0.500 1984 3389.729 616.992 196.738 o.ooo 350.000 0.500 [ 1985 3699.507 700.539 223.721 0.000 350.000 0.500 1986 4031.094 821.113 253.168 0.000 350.000 0.500 [ 1987 4375.941 987.922 286.008 o.ooo 350.000 0.500 1988 4731.574 699.973 322 .• 441 o.ooo 695.501 0.500 1989 5118.008 588.465 361.817 o.ooo o.ooo 0.500 1990 5576.836 506.125 406.085 0.000 0.000 0.500 c 1991 5386.480 506.141 455.185 o.ooo o.ooo 0.500 , 1992 5786.504 506.152 505.111 o.ooo o.ooo 0.500 [ 1993 6528.020 139.531 o.ooo o.ooo o.ooo 0.500 1994 6729.594 139.543 0.000 338.049 0.000 0.500 1995 7729.250 139.563 o.ooo 680.847 o.ooo o.ooo " L 1996 7822.879 139.586 o.ooo 748.723 o.ooo o.ooo 1997 8361.188 139.609 0.000 809.145 0.000 o.ooo 1998 8794.711 139.633 o.ooo 873.359 o.ooo o.ooo [ 1999 9190.000 139.652 o.ooo 941.928 o.ooo o.ooo 2000 9713 .• 740 139.668 o.ooo 1017.188 o.ooo o.ooo [ 2001 10278.2 70 139.691 o.ooo 1098.944 o.ooo o.ooo 2002 10886.180 139.711 o.ooo 1188.241 o.ooo o.ooo 2003 11545.180 139.734 0.000 1287.516 o.ooo o.ooo L 2004 12261.640 139.766 o.ooo 1396.169 o.ooo o.ooo 2005 13034.660 139.789 o.ooo 1513.4 79 o.ooo o.ooo [ 2006 13871.350 139.820 o.ooo 1640~603 o.ooo o.ooo 2007 14777.160 139.852 o.ooo 1778.121 o.ooo o.ooo 2008 15758.890 139.891 o.ooo 1926.802 o.ooo o.ooo 2009 16822.770 139.934 o.ooo 2085.652 o.ooo o.ooo [ 2010 17975.2 70 139.980 o.ooo 2257.400 o.ooo o.ooo [ SOURCE: MAP MODEL OUTPUT [ [ EXHIBIT 2.15 [ [ POPULATION (THOUSANDS) [ Greater Greater [ Year State Rai1be1t Anchorage Fairbank• 1982 437.175 307.105 239.830 67.2 77 [ 1983 457.836 319.767 251.057 68.711 1984 473.752 330.202 259.679 70.523 1985 490.146 341.613 269.300 72.313 [ 1986 505.884 352.187 278.082 74.105 1987 517.431 359.054 283.333 75.723 1988 526.823 364.583 287.969 76.615 [ 1989 538.532 375.007 296.794 78.213 1990 554.634 389.026 308.196 80.831 c 1991 560.786 393.296 311.585 81.7U 1992 581.846 405.991 322.865 83.U7 1993 594.848 413.788 328.521 85.268 0 1994 602.027 420.130 332.694 87.436 1995 608.810 423.460 335.464 87.997 [ 1996 616.422 428.574 339.629 88.945 1997 623.782 434.617 344.561 90.057 1998 630.352 440.001 348.981 91.021 1999 636.928 445.519 353.531 91.988 [ 2000 644.111 451.561 358.441 93.120 2001 651.362 457.835 363.501 94.335 [ 2002 658.994 464.362 368.801 95.561 2003 667.660 471.437 374.626 96.811 2004 676.878 478.925 380.769 98.156 [ 2005 686.663 486.851 387.267 99.584 2006 697.022 495.287 394.168 101.119 [ 2007 707.990 504.091 401.364 102.727 2008 719.644 513.431 408.995 104.436 2009 731.592 522.970 416.755 106.216 2010 744.418 c 533.218 425.1.15 108.104 SOURCE: MAP HODEL OUTt'UT [ [ [ D EXHIBIT 2~ 16 [ c" [ EMPLOYMENT (THOUSANDS) [ State No n-Ag State llailbelt Greater Greater [ Year Wage and Total Total Anchorage Fairbanks Salary Total Total 1982 192.903 231.984 154.033 120.533 33.500 [ 1983 202.237 243.067 159.147 125.221 33.92 7 1984 205.903 246.984 162.259 12 7.853 34.406 1985 216.612 258.396 169.197 133.668 35.528 [ 1986 225.515 267.895 174.818 . 138.324 36.494 1987 230.833 2 73.581 177.412 140.345 37.067 c 1988 234.657 277.669 179.422 142.065 37.357 1989 240.213 283.619 184.211 146.124 38.088 1990 249.654 2 93.689 190.883 151.685 39.198 D 1991 247.908 291.844 191.360 151.958 39.402 1992 264.012 309.031 199.404 158.995 . 40.409 1993 266.941 312.180 202.842 161.351 41.492 D .1994 267.220 312.511 203.630 161.669 41 •. 961 ' 1995 268.534 313.954 204.668 162.466 42.202 0 1996 270.783 316.404 206.258 163.772 42.486 1997 272.935 318.765 208.212 165.401 42.811 1998 2 74.346 320.353 210.041 166.916 43.125 c 1999 276.144 322.3 74 212.025 168.580 43.445 2000 278.729 325.186 214.541 170.645 43.897 [ 2001 281.498 328.141 217.2 83 172.875 44.408 2002 284.643 331.499 220.293 175.333 44.960 2003 288.727 335.859 223.703 178.156 45.546 2004 293.137 340.569 22 7.487 181.265 46.222 [ 2005 297.941 345.701 231.584 184.625 46.959 2006 303.062 351.172 235.985 188.226 47.759 [ 2007 308.504 356.989 240.639 192.025 48.614 2008 314.317 363.203 245.561 196.044 49.517 2009 . 320.082 369.368 250.621 200.146 50.4 75 .. "-• A 326.440 376.169 255.974 204.512 51.462 c -' U I.U SOUP~£: HAP MODEL OUTPUT c c c [ EXHIBIT2.17 [ I \ [ HOUSEHOLDS (THOUSANDS) [ Greater Greater [ Year State Rai1belt Anchorage Fairbanks ! 1982 145.453 106.5 72 83.678 22.894 [ 1983 1S3.141 111.549 88.038 23.511 1984 159.154 115.6 71 91.425 24.246 1985 165.299 U0.140 95.165 24.974 [ 1986 171.192 124.275 98.580 25.695 1987 175.620 U7 .053 100.709 26.344 [ 1988 179.2 87 129.415 102.669 26.746 1989 183.738 133.365 105.994 27.371 1990 189.696 138.640 110.2 67 28.373 0 1991 192.234 140.401 111.662 28.739 1992 199.886 145.348 116.024 29.324 1993 204.788 148.405 118.253 30.152 D 1994 207.695 150.964 119.963 31.002 1995 210.461 152.463 121.197 31.267 [ 1996 213.508 154.590 122.921 31.669 1997 216.470 157.052 U4.921 32.131 1998 219. 161 159.242 126.710 32.532 1999 221.854 161.483 U8.549 32.934 [ 2000 224.751 163.913 130.515 33.398 2001 22 7.670 166.423 132.532 33.891 [ 2002 230.716 169.023 134.636 34.388 2003 234.112 171.820 136.928 34.892 2004 ·237.695 174.758 139.329 35.429 [ 2005 241.468 177.849 141.853 35.996 245.436 144.520 2006 181.121 36.601 E 2007 249.609 184.516 147.285 37.231 2008 254.014 188.100 ·150.203 37.896 2009 258.519 191.748 153.162 38.586 2010 263.323 195.652 156.336 39~316 [ SOURCE: MAP MODEL OUTPUT [ [ L c [ c L~ [ [ [ [ c c Q c c c [ [ [ [ [ L Year 1980 1985 1990 1995 2000 2005 2010 1980 1985 1990 1995 2000 2005 2010 EXHIBIT 2.18 RESIDENTIAL ELECTRIC ENERGY USE PER HOUSEHOLD After Before Conservation Adjustment and Fuel Substitution Adjustment Small Aeeliances Larse Aeeliances Seace Heat Total Total (kWh) (kWh) (kWh) (kWh) (kWh) Anchorase-Cook Inlet Area 2110 6500 5089 13699 13699 2160 6151 4812 13133 12829 2210 6020 4584 12814 12561 2260 5959 4516 12735 12644 2310 5989 4454 12753 12736 2360 6059 4420 12839 12938 2410 6124 4444 12977 13198 Fairbanks-Tanana Valley Area 2466 5740 3314 11519 11519 2536 6179 3606 12321 12136 2606 6453 3873 12932 12736 2676 6667 4050 13393 13329 2746 6795 4310 13852 14009 2816 6839 4536 14191 14626 2886 6888 4656 14430 15180 BUSINESS ELECTRIC ENERGY USE PER EMPLOYEE Before Conservation Adjustment and Fuel Substitution After Adjustments Anchorage-Fairbanks-Anchorage-Fairbanks- Year Cook Inlet Area Tanana Vallei Area Cook Inlet Area Tanana Vallei Area (kWh) (kWh) (kWh) (kWh) 1980 8,407 7,496 8,407 7,496 1985 9,580 7,972 9,212 7,900 1990 10,355 8,327 9,749 8,281 1995 10,918 8,662 10,078 8,665 "2000 11,416 8,958 10,349 9,024 2005 12,090 9,308 10,828 9,446 2010 12,933 9, 711 11 '502 9,929 c ·c c c 0 c c 0 0 0 0 c c c c c c c EXHIBIT 2.20 Year 1985 1990 1995 2000 2005 2010 1985 1990 1995 2000 2005 2010 PROJECTION OF ELECTRICITY REQUIREMENTS RED Model Computations Residential Business Miscellaneous Requirements Requirements Requirements (GWb) (GWh) (GWh) Indust/Military* Requirements . (GWh) Anchorage-Cook Inlet Area 1180 1345 1492 1621 1794 2021 248 310 376 426 482 551 1231 1479 1637 1766 1999 2352 Fairbanks-Tanana 281 325 366 396 444 511 26 30 34 36 41 47 Valley 7 7 8 9 10 11 Area 124 192 208 238 273 315 0 50 50 50 50 50 * Input to the RED Model Total Requirements (GWh) 2561 3045 3371 3662 4107 4735 535 691 800 880 986 1123 ~ c--J C'1 C""J (i"'"J c-J r-J CJ c::J cr:::im L-"""J C-:J c-J c--J c-J r-J· ~ PROJECTED PEAK AND ENERGY DEMAND Anchor.age-Cook Inlet Area Fairbanks-Tanana Valley Area Total System Area Energ;t Peak Energy Peak Enerf Peak Load Factor YEAR (GWh) (MW) (GWh) (MW) (GWh (MW) (%) 1985 2561 517 535 122 3096 639 55.3 1990 3045 619 691 158 3737 777 54.9 1995 3371 686 800 183 4171 868 54.8 . 2000 3662 744 880 201 4542 945 54.8 2005 4107 834 986 225 5093 1059 54.9 2010 4735 961 1123 256 5858 1217 54.9 Note: Figures shown are sales at end-use. Add 10 percent losses to get generation. rJ ~ N ...... CJ c-J C'J r-::-1 ['"7] C-:J C"J CJ L~J L:.~.Jli C'J c-J ["") r-J CJ C"J ~ c-J C.J RAILBELT UTILITIES FORECAST RAILBELT AML&P (1) CEA (1) (2) FMUS GVEA TOTAL Winter Winter Winter Winter Winte·r Energy Peak Energy Peak Energy Peak Energy Peak ·Energy Peak YEAR (GWH) _(MW) (GHW) (MW) (GWH) (MW) (GHW) (MW) (GHW) (MW) 1983 717 140 1854 384 147 29 387 74 3105 627- 1984 786 1152 1966 408 153 30 416 81 3321 672 1985 844 162 2079 432 161 32 447 89 3531 716 1986 915 174 2192 457 165 32 480 97 3752 761 1987' 1053 197 2304 481 168 33 516 107 3974 807 1988 1126 209 2417 505 172 34 603 113 4200 850 1989 1200 221. 2530 529 17.5 35 653 120 4443 894 1990 1270 232 2642 554 183 36 653 128 4678 940 1991 1270 232 2754 578 190 38 706 136 4920 984 1992 1322 241 2867 602 198 39 764 145 5151 1028 1993 1375 251 2979 626 206 41 826 154 5386 1073 1994 1431 261 3091 651 214 42 894 164 5630 1118 . 1995 1489 272 3203 675 225 45 967 174 5884 1166 1996 1549 283 3315 699 237 47 1046 185 6147 1215 1997 1621 294 3428 723 249 49 1131 197 6429 1264 1998 1697 306 3540 747 262 52 1223 209 6722 1314 1999 1775 318 3652 771 275 54 1323 222 7025 1367 2000 1858 331 3764 795 281 56 1432 236 7335 1419 2001 1944 344 3875 620 295 58 1548 251 7662 1474 NOTES: (1) Eklutna is included in AML&P & CEA. (2) CEA forecast includes Matanuska Electric Assoc., Homer Electric Assoc.~ & Seward Electric requirements. AML&P = Anchorage Municipal Light & Power CEA = Chugach Electric Association FMUS = Fairbanks Municipal Utilities System GVEA = Golden Valley Electric Association, Fairbanks Area tz:1 ::< ::c SOURCE: ALASKA POWER ADMINISTRATION, March 1983 H D:l H 1-i N . N N [ [ [ [ [ [ [ [ c c [ [ [ c [ [ c EXHIBIT 2.23 CHUGACH ELECTRIC ASSOCIATION, INC. PROJECTIONS OF TOTAL SYSTEM ENERGY GENERATION* Low Moderate Hish Year Ener8I Peak Enersx Peak Enersi Peak (GWh) (MW) (GWb) (MW) (GWb) (MW) 1983 1,817 412 1,868 426 1,879 429 1984 1,942 432 2,050 463 2,081 469 1985 2,059 451 2,265 501 2,299 510 1986 2,189 470 2,473 533 2,614 515 1987 2,281 491 2,642 568 2,935 654 1988 2,365 513 2,803 606 3,283 745 1989 2,445 535 2,962 646 3,664 850 1980 2,523 559 3,121 689 4,087 974 1991 2,582 515 3,167 699 4,150 978 1992 2,651 591 3,207 706 4,164 969 1993 2,725 606 3,251 713 4,187 961 1994 2,802 623 3,299 721 4,220 954 1995 2,884 639 3,350 729 4,261 946 1996 2,982 660 3,406 738 4,315 938 1997 3,103 680 3,467 747 4,381 931 * Includes Matanuska Electric Association, Homer Electric Association, and Seward Electric System. Source: Power Requirements Study, 1983, by Burns & McDonnell [ c [ c [ [ c c 0 0 c c [ c [ c [ L c EXHIBIT 2.24 SUMMARY OF ENERGY AND PEAK GENERATION PROJECTIONS MADE BY POWER AUTHORITY AND UTILITIES 1990 2000 2010 Power Authority Annual Energy 4,111 4,996 6,444 Peak Demand (MW) 855 1,040 1,339 Utilities Annual Energy 4,678 7,678 9,649 Peak Demand (MW) 940 1,419 1,854 I [I I r 3.0 UPDATE OF THE SUSITNA PROJECT ~ I ~ 3.1 INTRODUCTION r 1 Evaluating the economic feasibility of the Susitna Project and its ~ ~ I ~ I [ t I alternatives requires that an estimate be prepared of the construc- tion/operating costs and energy production capabilities of the Project. This Chapter provides an update of {1) the costs and power generation capacity of the Project as currently designed and set forth in the FERC License Application, and (2) the impact on the economics of the Project of certain cost-reducing design refinements. The Power Authority Board of Directors has given conditional approval to proceeding with certain cost-saving design refinements to the Project so long as implementing those refinements will have no adverse effect on the FERC licensing schedule. On the assumption that these engineering refinements may be accommodated within the existing FERC licensing schedule, the estimated Project costs would be less, as discussed more fully in this Chapter. It should be clearly understood, however, th'at the Power Authority has evaluated the economic and financial feasib-ility of the Project in this Update based on the estimated costs as filed with the FERC. As shown below, implementation of the design refinements would improve the economics of Susitna. The results ·of the assessments in this Chapter are incorporated in the studies of alternative expansion plans to· meet future Rail belt elec- r 196/174 3-1 I trical demand (Chapter 5), economic analyses (Chapter 6) and financial analyses (Chapter 7). 3.2 DESCRIPTION OF THE SUSITNA PROJECT AS FILED AT FERC The Susitna Hydroelectric Project as proposed in the License Application will consist of two major developments on the Susitna River approxi- mately 180 miles ·north-east of Anchorage. The Project will consist of two dams, Watana and Devil Canyon, with a combined maximum generating capacity of 1,620 MW. Watana, which will be built first, provides a major storage reservoir to control the flow of the river, and is planned to consist of-an earth and rockfill dam together with associated diver- sion, spillway, low-leVel outlet and transmission facilities. Devil Canyon wi 11 consist of a concrete arch dam with associated diversion, spillway, low-level outlet and transmission facilities. 3.2.1 Watana Development Watana Dam will create a reservoir approximately 54 miles long, with a surface area of 38,000 acres, and a gross storage capacity of 9,600,000 -acre-feet at elevation ( El.) 2185, the norma 1 maximum operating 1 evel. The minimum operating level of the reservoir is proposed to be El. 2065, providing active storage volume of 3,700,000 acre-feet for normal oper- ation. 196/174 3-2 n [ n [] r-, L_) [ c [J ~ 0 c c [ ·C c [ c [ The dam will be an embankment structure with a central impervious core. The nominal crest elevation of the dam will be El. 2205, with maximum height 885 feet above the foundation and a crest length of 4,100 feet. The power intake will be located on the north bank at the end of an approach channel excavated in rock. From the intake structure, concrete and steel-1 ined penstocks will 1 ead to an underground powerstation housing six 170-MW generating units. The maximum generating capacity of Watana, therefore, .will be 1,020 MW. Low level outlet facilities will be provided so that downstream flow requirements can be met when power releases are insufficient to meet environmental requirements and to provide flood discharge capacity. The main spillway is a safety structure to discharge inflows to the reservoir that exceed the capacities of the other outlet works. The spillway will consist of a gated control structure with an inclined concrete chute leading to a flip bucket. The flip_bucket is intended to reduce river bed erosion when the spillway is used. The spillway could discharge up to 120,000 cubic feet per second (cfs) at reservoir eleva- tion 2193.5. The spillway will have sufficient capacity for the Pro- bable Maximum Flood (PMF) with the reservoir level raised to El. 2201 (four feet below the nominal crest), assuming the low-level outlet , facilities and powerhouse are operated concurrently. 196/174 3-3 n C- C [ [ [ [ c [ ~ L) c [ [ l-; ·-' c [ r: L c [ 3.2.2 Devil Canyon Development Devil Canyon dam will form a reservoir approximately 26 miles long with a surface area of 7,800 acres and gross storage capacity of 1,100,000 acre-feet at El. 1455, the normal maximum operating level. The opera- ting level of the Devil Canyon reservoir controls the tailwater level of the Watana Development. The minimum operating level of the reservoir. will be El. 1405, providing active storaQe volume of 350,000 acre-feet for normal reservoir operation. The dam will be a thin concrete arch with a crest level of El. 1463 and mCJximum height of 646 feet above foundation. It wi 11 be supported by mass concrete thrust blocks on each abutment. Adjacent to the southern thrust block, an earth and ~ockfill dam will extend across a saddle to the south bank. The power intake will be on the north bank and will consist of an ap- proach channel excavated in rock leading to a reinforced concrete gate structure. Concrete and steel-lined penstock tunnels will lead from the intake structure to an underground powerstation housing four 150-MW units. The maximum generating capacity of Devil Canyon is 600 MW. Low-level outlet facilities will be located in the lower part of the rna in dam to assure that downstream flow requirements can be met when power releases are insufficient to meet in-stream flow requirements and to provide flood discharge capacity. The spillway is a safety facility designed to pass 123,000 cfs with the reservoir at norma 1 maximum 196/174 3-4 [ [. [ [ [ [ [ [ c Q !J c [ r-, u [ [ [ [ [ elevation of 1455. The reservoir will surcharge to El. 1466 during the PMF if the spillway, power.house, and low-level outlet works are opera- ting concurrently. 3.3 ALTERNATIVE SUSITNA DEVELOPMENT SCHEMES The· License Application as filed found that the optimum development for Watana corresponded to maximum reservoir elevation 2185, and the Power Authority Board directed that this configuration be used in re-evalua- ting the economic and financial feasibility of the Project. Subsequent studies prepared in connection with this Update have verified the finding in the License Application. Table 3.1 presents the cumulative present worth of costs of alternative Susitna development plans with Watana at various elevations. As can be seen, the maximum net benefit (least cost) is obtained from a Susitna Project with Watana Development at El. 2185. Table 3.1 CUMULATIVE PRESENT WORTH OF ALTERNATIVE SUSITNA DEVELOPMENT PLANS (1983 $million) Case Cumulative Present Worth of Costs 1993 -2050 Watana Elevation 2185, Devil Canyon, and Thermal Generation 5730 Watana Elevation 2100, Devil Canyon, and Thermal Generation 5877 Watana Elevation 2000, Devil Canyon, and Thermal Generation 5931 Watana Elevation 1900, Devil Canyon, and Thermal Generation 6636 196/174 3-5 Net .Increase In Costs Over Elevation 2185 147 201 906 n LJ 3.4 POTENTIAL DESIGN REFINEMENTS [ [ [ [ [ [ Q [ [ [ [ [ [ [ [ [ Engineering review of the FERC License Application .and additional geotechnical investigation at the Watana site have led to certain design refinements which could reduce Project costs without impairing safety. The following list identifies the major design features that have been considered and proposed as refinements: WATANA: 1. Reduction in dam foundation excavation and treatment requirements; 2. Change in dam configuration and composition to reflect available materials; 3. Resizing and relocation of cofferdam and diversion tunnels; 4. Combining of power intake and spillway approach channel; 5. Reorientation of underground caverns; 6. Shortening and reduction in number of power conduits; 7. Elimination of fuseplug spillway; 8. Reduction in transmission voltage of north line; 9. Positive cutoff treatment of relict channel; 10. Elimination of outdoor switchyard and utilization of different switchgear equipment; and 11. Increase in unit speed of generating equipment. DEVIL CANYON: 1. Elimination of fuseplug spillway. 196/174 3-6 [ [' [ [ [ [ [ [ D D D c r L~ [ [ c· [ [ c 3.5 COST ESTIMATES 3.5.1 Construction Cost Estimate of Project as Filed at FERC Table D.1 of the FERC License Application detailed the construction cost estimates for the Watana and Devil Canyon developments in 1982 dollars. As adjusted by an inflation factor of 1.043, the cost estimate (in 1983 dollars) is as stated in Table 3.2. Table 3.2 shows .the current estimate of the construction cost of the Watana Development as contained in the FERC License Application as $3.75 billion; the corresponding estimate for the Devil Canyon Development is $1.62 billion in 1983 dollars. Table 3.2 SUMMARY OF COST ESTIMATE Januar~ 1983 Dollars ~$ million} Categor~ Watana Devil Can~on Total Production Plant $ 2,391 $ 1,111 $ 3,502 Transmission Plant 476 109 585 General Plant 5 5 10 Indirect 461 215 676 Total Construction 3,333 1,440 4,773 Construction Overhead 417 180 597 TOTAL PROJECT CONSTRUCTION COST $ 3,750 $ 1,620 $ 5,370 196/174 3.-7 c [ [ [ c [ [ c [j D 0 c [ [ c [ c c. c 3.5.2 Construction Cost Estimates with Refinements As a result of the potential. design refinements listed in Section 3.4,. the construction cost estimate for Watana can be reduced by about 8 percent ($300 million) to approximately $3.45 billion. The Devil Canyon costs would not be changed by the design refinement. 3.5.3 Operation and Maintenance Costs. Operation and maintenance costs (O&M) account for the personnel, equip- ment, materials, and facilities required to operate the generating plant and to maintain all of the structures and machinery. Under changing Project conditions the annual O&M costs would vary over time. During the first four years of Watana operation, the annual O&M costs are estimated at $8.5 million (1983 dollars). Annual O&M costs are expected to decrease to $7.3 million until Devil Canyon·comes on line. During the first four years of Devil Canyon operation, the annual O&M costs for both dams would increase to a total of $9.8 million. O&M costs are then . expected to decrease to approximately $7.3 million annually. Exhibit 3.1 presents the components of the first four year costs of each development and the total Project O&M costs. 3.6 RESERVOIR OPERATION STUDIES .The economic feasibility of the .Project depends partially upon the amount of generating capacity and energy that will be available for 196/174 3-8 [ [ [ [ c [ c 0 0 0 n '-' 0 [ [ c c [ [ [. sale. To evaluate this aspect of the Project~ operation studies were performed to estimate . the power and energy production capability of Susitna under the operating assumptions set forth in the July 1983 FERC License filing, which provides for the Watana Development to initially operate as a base load facility. Additional studies are now being conducted to determine if the economic benefits of Watana can be in- creased by more closely matching its operation with_ that of the Railbelt ·utilities, while still operating within environmental constraints. Regardless of the outcome of these studies, when De vi 1 Canyon comes on line, Watana will operate to follow load while Devil Canyon will operate as a base load facility. At tha't time the variation in flows from Watana would be controlled by the Devil Canyon dam. 3.6.1 Simulation Model A dual-reservoir computer simulation program was developed during the 1982 Susitna Project Feasibility Study. This program has subsequently been modified to incorporate use of a variable tailwater rating and variable turbine capacity qnd efficiency to study the impacts· of various reservoir operation scenarios. Minor changes in data input requirements and output format were also implemented. The model is used in per- forming the power and energy studies presented in this Chapter. 3.6.2 Hydrology The initial step in simulating reservoir operation is to assess the natural water flow conditions (hydrology) of the river. Thirty-three 196/174 3-9 c [ [ L [ [ [ [ [ c c [ r~ L [ r.-~ l~~ [ [ [ [ years of streamflow data from 1950 to 1982 are avai 1 able and Project operation was simulated on a monthly basis for the entire historical period. 3.6.3 Reservoir Data The relationship of area and volume of reservoirs to the elevation of the Watana and ·Devil Canyon dams is set forth in Exhibits 3.2 and 3.3 • . At the Watana Development's normal maximum pool elevation of 2185, the reservoir surface a rea is about 38,000 acres, and the gross storage volume is 9.6 million. acre-feet. At the Devil Canyon normal maximum pool elevation of 1455, the reservoir surface area is about 7,800 acres, with a gross storage volume of 1.1 mi 11 ion ·acre-feet. The .active storage volumes are 3,700,000 acre-feet for Watana, and 350,000 acre- feet for Devil Canyon. 3.6.4 Turbine and Generator Data The installed capacity of the Watana Development is 1020 MW, provided in six units, each rated at 170 MW. The fifth and sixth units provide no additional energy production in the early years but are available for peaking use and reserve to the degree such operation would conform to stream flow requirements. The operating characteristics for the Watana and Devil Canyon power- plants are summarized on Exhibit 3.4 based on the rated net head at each site. In all cases, generator and transformer efficiencies of 98 and 99 percent, respectively, were used to c·ompute the overall plant effi- 196/174 3-10 c [ [ [ c c [ 0 0 ciency. The head loss incurred in flow of water through the intake, penstocks, and discharge passages of the Watana and Devil Canyon power- plants is assumed to be 1.5 percent of the gross head. 3.6.5 Reservoir Operation Constraints During the early years of operation, energy generation from the Susitna Project would be limited by Railbelt electrical demand. Operation simulations were made for a wide range of Railbelt system demand levels (4000-8000 GWh/year) to establish the relation of system demand to energy production from the Project. Analysis of the Project's economics has assumed operation designed to meet certain energy requirements along with some minimum monthly in- stream flow requirements for· the months of July, August, and September. These flows were delineated at the mouth of Gold Creek (denoted as "Case C" in the FERC License Application) are shown in Table 3.3. A reservoir rule curve is a list of monthly target reservoir elevations which control reservoir operation to achieve a desired result with respect to use of a water re·source. A preliminary Watana rule curve has been developed to maximize average energy generation, maintain a high level of dependable energy and meet . environmental requirements as defined by the "Case C" minimum flows. The Devil Canyon reservoir rule curve is designed to keep the reservoir as full as possible in all cases. 196/174 3-11 D c [ [ [ [ [ 0 0 D 0 0 (i L [ [ C c [ c Table 3.3 . * POTENTIAL MINIMUM FLOWS AT GOLD CREEK (cfs) Month Flow Month Flow October 5000 April 5000 . November 5000 May 6000 December 5000 June 6000 ** January 5000 July 6480 February 5000 August 12000 ** March 5000 September 9300 3.6.6 Power and Energy Production Energy production (GWh) and Project capacity (MW) have been estimated from the reservoir operation studies described above. The studies considered the energy demands for the period 1993 through 2020 for the load forecasts developed in Chapter 2. Exhibit 3.5 sets forth the annual energy production from the Watana and Devil Canyon developments, as compared with annual demand figures for the forecast demand. Exhibit 3.6 summarizes the power and energy production for Watana and Devi 1 Canyon under the 2020 1 oad forecast. The power and energy esti- * As discussed in the FERC License Application, this flow scenario was selected as the Project operation flow regime considering both Project and in-stream flow uses. ** The flow changes by 1000 cfs per day from 6000 on July-25 to 12,000 on August 1 and from 12,000 on September 14 to 6000 on September 21. 196/174 3-12 c [ [ [ [ [' -" c [ c ~ Q [ [ [ [ [ [ f' L [ ·~ mates are based on the modes of operation and constraints previously discussed. 3.7 ENVIRONMENTAL STATUS UPDATE This section presents an update of the status of the principal environ- mental aspects of the Susitna Project, and the activities being con- ducted with regard thereto. As previous sections hQve noted, environ- mental restrictions (e.g., prescribed minimum downstream flows) can limit the maximum energy production which would otherwise be possible from the Susitna Project. Environmental studies have continued since the 1982 Fea.sibil ity Report and the initial filing of the FERC License Application in February 1983. The objectives of the most recent studies have been to prepare specific information required for State, local and Federal permit applications and to assist in the 1 icensing process by responding to FERC Staff inquiries. As .of this time, responses have been prepared and provided to FERC on approximately 350 requests for clarification and supplemen- tary information. In addition, the Power Authority has responded to over 1,000 comments on the License Application in connection with the Environmental Impact Statement process. A list of issues and questions has also been compiled from a comprehensive review of all State, local and Federal agency comments received by the Power Authority during the past four years. Most of these issues have been addressed in submis- sions to FERC; work on others is continuing. 196/174 3-13 n [ [ [ [ c [ c n ..___; 0 n ~ c c·· [ [ c [ c L In addition to answering written requests for information and responding to conunents, the Power Authority has provided many recent studies to FERC, Federal and State agencies in responding to their comments on the License Application. The Power Authority also conducted a tour of the Susitna basin and related areas for FERC personnel during the week of August 21-27, 1983, so that they could better evaluate the Project using first-hand information. tontinuing environmental activities focus on the evaluation of impacts and the refinement of mitigation programs tailored to specific Project needs. These activities cover all aspects of potential Project impacts and are briefly discussed below under the major headings of aquatic, terrestrial and social sciences programs. 3.7.1 Aquatic Programs Potential Project impacts include the possible effects at altered seasonal flow regime on the ecosystem of the Susitna River, including possibly altered water temperature regimes, turbidity and other water quality parameters (e.g., dissolved gas and suspended solids concentra- tions downstream from the reservoirs). The effect of the altered flows on anadromous and resident fish habitats and their associated populations is the major focus of present studies. Five major habitats have been identified which are important ·to fish and will be affected by the altered flows. These are the mainstream of the Susitna River, side channels, side sloughs, upland sloughs and tributary 196/174 3-14 [ [ [ [ [ [ [ 0 c u c 0 [ 1-, L [ L [ [ [ mouths. The principal concerns of potential alterations to spawning habitats of salmon, access to the spawning habitats, and juvenile rearing habitats are addressed through a series of mathematical models relating potential changes in flow to fish habitats. Physical and bio- logical data calibrate the predictive models and relate the physical changes in habitats to the biological impacts. To address the potentia 1 effects of the a 1 tered temperature regime, it is necessary to estimate what changes will occur. This is· accomplished through a series of mathematical models which address water temperature in the reservoirs and in the river downstream. As a part of this analysis, a mathematical model is also being used to analyze ice pro- cesses in the reservoirs and river. Changed turbidity, sediment transport and other water quality parameters are analyzed through comparisons of predicted changes with observed changes at other comparable hydroelectric projects. The Power Authority's environmental analysis also includes effects of changes in discharge from the Project during a single day should Watana be operated under some variation of a load-following scenario in sup- plying the power needs of the Railbelt system. 3.7.2 Terrestrial Programs Project impact assessments and proposed mitigation plans regarding· terrestial ecosystems continue to be evaluated as discussed in the FERC 196/174 3-15 [ [ [ c c [ [ c c 0 0 0 [ [ [ c [ [ [ License Application •. Models have been designed to evaluate potential loss of habitat (lost moose carrying capacity and changes in moose population due to changes in carrying.capacity), predator-prey ratios, hunting pressure, and other factors. Modeling components also include browse inventories, plant phenology studies, refined vegetation and wetlands mapping, moose censuses, moose movements, and predation by wolves and bears in controlling moose numbers. This information facil- itates the development of mitigation programs commensurate with Project impacts. The Power Authority continues to monitor movements and habitat use by moose in the riparian zone downstream of Devil Canyon; monitor the movements and herd size of caribou in the Project area; analyze the use of the Jay Creek mineral lick by Dall sheep; monitor bear and wolf movements and habitat use; monitor raptors, particularly golden and bald eagles; and monitor beavers in the riparian zone from Devil Canyon to Talkeetna. 3.7.3 Social Sciences Programs Included within the social sciences programs are cultural resources, socioeconomics and recreation. 3.7.3.1 Cultural Resources Regarding cultural resources, field work in 1983 included continued reconnaissance surveying of the proposed dam sites, impoundment areas, 196/174 3-16 c [ [ [ [ [ [ c c 0 c c [ [ [ r~ l__; [ [ [ and borrow sites (for the purpose of identifying potential historic and archeological sites). In addition, testing of certain identified sites was conducted. A sensitivity mapping of archeological potential was completed for the proposed railroad, access road, transmission line, and Phase I Recreation Plan. 3.7.3.2 Socioeconomics The Power Authority also continues to refine appropriate mitigation plans. Socioeconomic analyses are being refined and updated based upon survey information from adjacent communities. 3.7.3.3 Recreation A Recreation Plan Implementation Report will outline the steps required to implement Phase I of the Recreation Plan·as identified in Chapter 7, Exhibit E of the FERC License Application. This report will include a plan of action for resolving necessary policy and management issues, such as: what Project areas and faciiities will be open to the public; policies regarding access and use of recreation resources; and control by landowners and landmanagers. 196/174 3-17 SUSITNA HYDROELECTRIC PROJECT Labor Power and Transmission 3300 . 2/ Contracted Serv1ces- Townsite Operations 625 Environmental Mitigation Contingency (15%) Total, January l982 dollars Escalation to 1983 dollars (6%) Total, January 1983 dollars OPERATION AND MAINTENANCE ($1000/yr) Watana 1/ Expenses Subtotal Labor 990 4290 625 900 900 180 805 400 1000 1045 8040 480 8520 ~/ For first 4 years of operation of each development. COST ESTIMATES Devil Can~on 2/ Expense Subtotal 500 1125 480 480 55 455 310 2370 140 2510 Total Project Labor Expenses Subtotal 2740 990 3460 1050 1050 285 180 465 1000 895 6870 410 7280 2j Includes annual maintenance services, major maintenance overhaul, helicopter service, and road maintenance. [ [ [ D c [ r-, L [ [ [ [ [ [ AREA AND VOLUME VERSUS ELEVATION WATANA RESERVOIR Elevation Volume (ft, msl) (acre-feet) 1460.0 o. 1500.0 3000. 1550.0 34000. 1600.0 127000. 1650.0 292000. 1700.0 532000. 1750.0 870000. 1800.0 1318000. 1850.0 1877000. 1900.0 2546000. 1950.0 3330000. 2000.0 4248000. 2050.0 5341000. 2100.0 6645000. 2150.0 8189000. 2200.0 10017000. 2250.0 12212000. EXHIBIT 3.2 Area (acres) o. 150. 1100. 2620. 3990. 5620. 7860. 10010. 12270. 14490. 16880. 19850. 23870. 28290. 33940. 39730. 48030. l [ [ [ I' L .. J [ [ [ [ G [ c [ [ [ [ [. [ [ AREA AND VOLUME VERSUS ELEVATION DEVIL CANYON RESERVOIR Elevation Volume (ft, msl) (acre-feet) 900o0 Oo 950o0 2000o 1000o0 7000o 1050 oO 25000o 1100.0 49000o 1150 oO 65000o 1200o0 132000o 1250o0 195000 0 1300o0 292000o 1350.0 456000. 1400.0 707000o 1450o0 1048000. 1500.0 1484000o EXHIBIT 3.3 Area (acres) Oo 70 0 190o 400o 654o 955 0 1360o 1860o 2490o 3565 0 5480. 7600o 9560. [ [ [ [ [ [ [ [ 0 R c [ [~, _j [ L [ [ [ [ Net Head (%Rated) (Feet) 0.850 578.0 0.900 612.0 0.950 646.0 1.000 680.0 1.030 700.4 1.060 720.8 0.850 501.5 0.900 531.0 .. 0 .. 950. 560-.5 - - 1.000 590.0 1.030 607.7 EXHIBIT 3.4 POWERPLANT DATA Reservoir Elevation Plant CaEacit;x: Efficienc;x: (Feet) (MW) (%Rated) Turbine Plant Watana Development 2045.1 834.4 76.9 0.894 0.867 2079.8 915.8 84.4 0.900 0.873 2114.4 999.4 92.1 0.905 0.878 2149.0 1085.1 100.0 0.910. 0.883 2169.8 1131.7 104.3 0.908 0.881 2190.6 1178.4 108.6 0.906 0.879 Devil Can;x:on DeveloEment 1360.5 521.1 76.9 0.894 0.867 1390.7 571.7 84.4 0.900 0.873 . ··1420.7 623.5 92.1 0.905 0.878 1450.8 677.2 100.0 0.910 0.883 1468.8 706.3 104.3 0.908 0.881 c [ EXHIBIT 3.5 [ SUSITNA ENERGY [ GENERATION Susitna c Total Generation Devil Year Demand Total Watana Canyon (GWh) (GWh) (GWh) (GWh) [ 1993 4399 2905 2905 1994 4492 2940 2940. [ 1995 4588 2970 2970 1996 4670 2995 2995 1997 4751 3024 3024 1998 4833 3060 3060 [ 1999 4915 3100 3100 2000 4996 3105 3105 2001 5177 3153 3153 n 2002 5238 4670 2396 2274 2003 5359 4791 2458 2333 2004 5481 4913 2520 2393 0 2005 5602 5034 2582 2452 2006 5771 5203 2669 2534 2007 5939 5371 2755 2616 2008 6107 5539 2842 2697 c 2009 6276 5708 2928 2780 2010 6444 5876 3014 2862 2011 6610 5994 3033 2961 c 2012 6780 6144 3109 3035 2013 6955 6285 3180 3105 2014 7135 6356 3216 3140 c 2015 7318 6338 3207 3131 2016 7507 6329 3202 3127 2017 7701 6496 3286 3210 2018 7899 6661 3370 3291 [ 2019 8103 6736 3408 3328 2020 8312 6766 3423 3343 [ [ [ [ [ r---'l l. "----~ POWER AND ENERGY PRODUCTION Year 2020 Demand Level COMBINED OPERATION MONTH WATANA ALONE DEVIL CANYON WATANA AFTER DEVIL CANYON Average Average Firm Average Average Firm Average Firm caeacitx:(a) Ener~x: Ener~x:(b) Caeacitx:(a) Ener~x: Ener~x:(b) Caeabilitx:(c) Ener~x: Ener~x:(b) (MW) (GWh) (GWh) (MW) (GWh) (GWh) (MW) (GWh) (GWh) Jan 466 346 293 458 340 238 1088 369 247 Feb 426 286 226 450 302 215 999 319 219 Mar 354 263 182 368 273 213 963 281 212 Apr. 338 243 153 368 264 289 928 252 106 May 307 228 139 366 272 188 922 214 94 Jun 261 188 59 366 263 200 975 188 395 Jul 292 217 81 323 240 200 1053 180 133 Aug 468 348 314 364 270 219 1114 249 199 Sep 394 283 274 366 263 263 1144 264 232 Oct 405 301 191 366 249 203 1141 350 308 Nov 554 398 290 458 329 224 1116 371 236 Dec 540 401 366 504 374 256 1080 417 269 (a) Corresponds to monthly plant capacity output that produces the total estimated monthly energy available. ~ :X: (b) Based on driest bistorical hydrologic year. H b:l (c) Based on monthly net head and turbine efficiency. H 1-:3 w . 0\ ' _j _ _j ' _j l l J l ' j ] 1 j J l 1 j 4.0 NON-SUSITNA GENERATION ALTERNATIVES 4.1 INTRODUCTION Several alternative technologies exist that could be used to generate electricity for the Railbelt, either as substitutes for, or as comple- ments to the Susitna Project. The alternatives include_ natural gas- fired combustion turbines, gas-fired combined cycle power plants and coal-fired steam turbines. In addition, the Chakachamna Hydroelectric Project could be a component of a Non-Susitna generating system. These alternatives are analyzed in this Update to evaluate the economic feasi- bility of the Susitna Project. The ability of any alternative to meet Railbelt demand depends on elec- trical demand, the availability and price of fuels for thermal power- plants, and the capacity and flow regimes of hydroelectric plants. These were analyzed most recently in the July 11, 1983 FERC License Application filing. This Chapter provides a summary description of the studies contained in that document. In addition, recently completed studies by the Power Authority regarding the Chakachamna Hydroelectric Project (Bechtel 1983) and the use of North Slope gas, {Ebasco 1983) for the Railbelt are also evaluated. The generation alternatives discussed in this Chapter are used in the formulation of system expansion plans described in Chapter 5. 200/174 4-1 . ~ _j _ _J _J _j l J J J j 4.2 NATURAL GAS-FIRED OPTIONS Natural gas currently fuels generation which serves about 75 percent of Railbelt electric energy demand. Assessments of thermal alternatives should, therefore, logically begin with an analysis of gas-fired options. 4.2.1 Natural Gas Availability and Cost 4.2.1.1 Cook Inlet Gas Availability. The two major known gas resources in Alaska are located at Cook Inlet and the North Slope. Estimates of natural gas resources in the Cook Inlet area have been made by the Alaska Department of Natural Resources (DNR 1983), the Alaska Oil and Gas Conservation Commission (OGCC 1982) and the United States Geological Survey (USGS 1980). Estimates of natural gas are divided into proven and undiscovered re- serves. Proven gas reserves are those reserves whose location is known from wells drilled and whose quantity is estimated from flow rates and specific geologic data. Undiscovered gas reserves are reserves that are located outside of known fields, the volume of which is estimated using geological information. OGCC estimates proven gas reserves by field on an annual basis. Gas volume is estimated using initial wellhead pressure, changes in well- 200/174 4-2 _j ' j _j l J ' ~ j l J J .. ) . , 1 1 j j j j j head pressure during production, analyses of drill cores, and field size obtained from seismic data. The OGCC' s estimate of proven Cook Inlet gas reserves as of January 1983 is 3.5 trillion cubic feet (TCF), the figure utilized in this Update. OGCC does not estimate undiscovered reserves. There is some uncertainty as to the amount of undiscovered gas in Cook Inlet. In 1983, DNR developed an estimate of undiscovered gas resources in the Cook Inlet area using a 11 Play Approach .. , which determines the amount of hydrocarbons in a 11 pl ay 11 , or prospect, through use of reser- voir engineering equations which take probability and risk factors into account. Estimates for various reservoirs are aggregated to create an estimate of the reserves. DNR estimated undiscovered gas resources for both total gas in place and economically recoverable gas. The expected amount of total gas in place was estimated to be 3.36 TCF and the ex- pected economically recoverable gas was estimated to be 2.04 TCF. The USGS estimated Cook Inlet undiscovered reserves using a subjective method in which gas resources were estimated by a team of experts. Geological information and results from other methods were reviewed and weighted by the experts. The weighted average quantity of economically .. recoverable gas was estimated to be 5.72 TCF • The lower DNR estimates of undiscovered reserves are used in this Update for three reasons. First, the USGS estimate was made using data available in 1980. While no exploration for non-associated gas (gas not discovered in connection with oil) occurred during the 1980-82 period, 200/174 4-3 _j 1 ' I ---, J _j l -j _j j _j -oil exploration continued and the DNR had access to additional explor- ation information in preparing its 1983 report that was not available to the USGS in 1980. Second, the Cook Inlet area analyzed by the USGS was larger than the Cook Inlet basin analyzed in the DNR estimate. The larger estimate consists mostly of additional on-shore areas on the Kenai Peninsula and to the west and north of Cook Inlet. Finally, the play methodology (used by DNR} is more subjective than USGS methodology. In any event, the difference between DNR and USGS estimates of undiscov- ered Cook Inlet gas has a relatively minor effect on the economic analy- sis. As shown in a sensitivity analysis presented in Chapter 6, even if the Cook Inlet reserves are unlimited, the With-Susitna expansion plan would still have a net economic benefit over the Non-Susitna plan devel- oped with such a gas supply. 4.2.1.2 Cook Inlet Gas Consumption. Cook Inlet gas is used for house- hold heating, commercial applications, LNG and ammonia/urea production, and electricity generation as shown in Exhibit 4.1. Of the 3.5 TCF of proven reserves, some 1.9 TCF are committed by contract to existing users, and about 1. 7 TCF remain uncommitted. As previously noted, in addition to the 3.5 TCF of proven reserves, there are estimated to be 2.0 TCF of undiscovered reserves which are economically recoverable. The pattern of future consumption of Cook Inlet gas depends on the gas needs of the major users and their abi 1 i ty to contract for needed sup- plies. Since there is a limited quantity of proven gas and the esti- mates of undiscovered reserves in the Cook Inlet area have yet to be proven, gas reserves may be exhausted by the 1 ate 1990's, as shown on 200/174 4-4 J l J l. j l j l =i j _; l ..J Exhibit 4.1. In addition, there probably is a limit to allowable gas consumption by electric utilities because other us~s will be accorded higher priorities either through contract or by order of regulatory agencies. A restriction on such use of gas might be appropriate since coal could be made available for electric generation. To estimate the quantity of Cook Inlet gas available for electrical generation, there- fore, it is necessary to assess the requirements of the major users. These are summarized on Exhibit 4.1 and discussed in greater detail below. Phillips/Marathon LNG currently has 360 billion cubic feet (BCF) of gas under contract and Collier Chemical has 377 BCF. It is highly probable that both entities will obtain enough of the uncommitted gas resources to meet their needs through 2010 because both Phi 11 ips/Marathon LNG and Collier operate established facilities~ They are also owned by Cook In 1 et gas producers who contra 1 part of the uncommitted reserves. Phillips/Marathon LNG and Collier are therefore estimated to consume 62 BCF and 55 BCF, respectively, per year from 1983 through 2010. At present, Enstar has enough gas under contract to serve its retail customers until after the year 2000, but since Enstar also sells gas to the military, Chugach Electric Association, and Anchorage Municipal Light and Power for electric generation, it may have to seek additional reserves to meet the needs of its larger customers. It is assumed, however, that Enstar will be able to acquire sufficient gas to meet the needs of its retail customers (including new Matanuska Valley custo- mers). Further, it is reasonable to assume that its retail customers' 200/174 4-5 _j _j ' I l '1 J l I ::::> _j j needs will have priority over its wholesale sales of gas for electrical generation. Accordingly, retail use is estimated in Exhibit 4.1 to in- crease from about 19 BCF in 1983 to 52 BCF in 2010. Gas used in field operations and the residual, "Other Sales", vary from year to year but together are estimated, based on historical use, to average approxi- mately 25 BCF per year over the period 1983 through 2010. After satisfying all of the above needs, there is still a considerable amount of gas in the near term that could be used for electrical gene- ration. Chugach Electric Association has 285 BCF committed through contract and Enstar has 759 BCF contracted, some of which will be sold to Anchorage Muni ci pa 1 Power and Light and Chugach El ectr.i ca 1 Assoc- iation for electrical generation. Assuming that the Anchorage-Fairbanks Intertie is completed in 1984-85, it is possible that electrical genera- tion using Cook Inlet gas would increase to provide less costly energy to Fairbanks. This would, of course, increase the rate at which Cook Inlet reserves are depleted. An estimate of the quantities of Cook Inlet gas required to meet all Railbelt electrical requirements was made using the estimated load and energy forecast for the Railbelt area. Forecast generation from the existing Eklutna and Cooper Lake hydroelectric units, the proposed Grant Lake and Bradley Lake projects, as well as, generation from the existing Healy coal-fired unit, was subtracted from the forecast electrical re- quirements. The estimated annual gas consumption for power generation under this scenario increases from 27 BCF in 1983 to 36 BCF in 2010. 200/174 4-6 ., __j ' j l _j 9 j = ' _j _j _j _j The forecast annual and -cumulative use of gas for· each of the major users, and the total use of gas for the Railbelt, is shown in Exhibit 4.1. The remaining proven and undiscovered gas resources are also shown. As can be seen, proven reserves (3.5 TCF) will be exhausted by 1998, and proven plus economically recoverab 1 e undiscovered resources will be exhausted by about 2007. Inspection of the Total Cumulative Gas Use column in Exhibit 4.1 shows that currently committed reserves (1.9 TCF) could be exhausted in 1992 under this scenario. The data indicates that relying on gas-fired electrical generation to provide the Railbelt' s needs is problematic in that it depends on the future availability of uncommitted proven and undiscovered reserves of natural gas for electrical generation. This is especially true since uncommitted proven reserves and any undiscovered resources could also be acquired by established entities or entities not shown in Exhibit 4.1, further reducing the availability of Cook Inlet gas for electric gene- ration. Known potential purchasers for the uncommitted recoverable and undiscovered Cook Inlet gas reserves include Pacific Alaska LNG Assoc- iates (PALNG) and the operators of the proposed Trans-Alaska Gas System (TAGS). The proposed PALNG project caul d have a significant impact upon the future availabilit,y-"of gas. The project was initiated about ten years ago, but has been repeatedly delayed by difficulties in obtaining final regulatory approval for a terminal in California. At one time, PALNG had 980 BCF of recoverable reserves under contract. The contracts ex- pired in 1980, but producers have not given written notice of termi- 200/174 4-7 _j l J l ' j ..J .J _j _j .J --, nation, so the contracts have been held in abeyance. Recently, however, Shell Oil Company sold 220 BCF of gas formerly committed to PALNG to Enstar. This reduced reserves committed to the PALNG project to 760 BCF. Implementation of the PALNG project would depend primarily on the avail- ability and price of alternative sources of natural gas for the Lower 48 market, and particularly for the California market. When all factors are considered, it does not appear that the PALNG project will be imple- mented prior to 1995. The remaining reserves originally committed to PALNG may therefore become available to other purchasers such as Chugach Electric Association or Enstar, if the project's sponsors conclude that the potential markets for this supply are too uncertain. 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 Japan and other Asian countries. The proposed project is an alternative method of bringing North Slope gas to market • If the project were implemented, Cook Inlet gas producers might be able to sell their gas to TAGS for liquefaction and sale to Asia, further reducing available supplies for in-State purchase and consumption. Such sale would depend on the ability of the liquefaction facilities to handle greater gas quantities and on whether the market for LNG would require such additional quantities. The price paid by TAGS to Cook Inlet producers might be high enough to outbid competing purchasers, 200/174 4-8 ' --1 j ._l _ _j 1 I ' _) j J l j J . .J j ' ' -, j s i nee the Cook In 1 et gas would not be burdened with the costs of the transmission line from Prudhoe Bay, although some new transmission and gathering lines would probably be required in Cook Inlet. 4.2.1.3 Cook Inlet Gas Price. If current and future Railbelt electrical requirements are to be met with gas generation, new purchases of uncom- mitted Cook In 1 et gas and future purchases of undiscovered resources will be required. The price that will have to be paid for these addi- tional gas resources is important in the evaluation of thermal alterna- tives to the Susitna Project. The actual price that would be agreed upon for uncommitted gas between producers and the utilities is difficult to predict, but an indication is provided by the recent Enstar/Shell and Enstar/Marathon contracts for uncommitted gas resources. Under these agreements, the. we 11 head price is $2.32/MMBtu with an additional demand charge of $0.35/MMBtu beginning in 1986. Severance tax is estimated at $0.15/MMBtu. An additional fixed pipeline charge of about $0.30/MMBtu would be incurred for pipeline delivery to Anchorage • The prices established under these contracts could be a reasonable fore- cast of future Cook Inlet prices if there is no additional competition for Cook Inlet gas from entities who are not current users. Although the possibility of uncommitted Cook Inlet reserves being purchased for LNG export seems to be remote at the present time, conditions may change in the future. The price that producers might be able to obtain if LNG export opportunities exist might then become important. A method that 200/174 4-9 l J l ' ---' ' ---' l J j J j _j _j l J 1 j 4 J ' .J _j _j _j can be used to estimate wellhead prices for LNG export is to begin with the market price for delivered LNG and then subtract shipping, lique- faction, conditioning, and transmission costs to arrive at the maximum wellhead price. The wellhead price of Cook Inlet gas for LNG export calculated in this manner varies depending on the average price of oil delivered to Japan. Based on an oil price of $29/bbl (1983 OPEC Benchmark price), the max- imum price that could be paid to Cook Inlet producers for LNG is cur- rently about $3/MCF. This price is higher than the estimated prices where no LNG export opportunities exist. Therefore, as LNG oppor- tunities increased, the price of Cook In 1 et gas for e 1 ectri ca 1 gene- ration would probably be higher than assumed above, since the utilities would have to outbid potential LNG exporters to acquire supplies. For purposes of this Update, the Enstar contracts have been used as the basis for future Cook Inlet gas prices because they reflect recent nego- tiations for the purchase of that gas. It should be recognized, how- ever, that the Enstar contracts were negotiated when oil prices were softening and there did not appear to be other markets for Cook Inlet gas. The gas price situation could change in the future for the pur- chase of additional gas. Uncommitted proven reserves will be exhausted by_1998 and undiscovered economically recoverable reserves will have to be brought into production through exploration and development that will involve substantially higher costs. The demand for gas could also in- crease, resulting in greater competition for available supplies. With - time, it is possible that natural gas prices might move closer to oil 200/174 4-10 ' _j __j ., j _j _) ...J .J prices than the approximate 40 percent relationship established under the current Enstar contracts. Therefore, the Enstar contracts are a conservative means of estimating Cook Inlet gas prices. The method used to escalate natural gas prices over the forecast period was to correlate the increase in gas prices with the projected rate of increase in world oil prices. This method was selected in recognition of the general substitutability of the two fuels. The recent Enstar contracts are evidence of this pricing correlation, as they provide for / the esca 1 ati on of the gas price based upon the price of No. 2 fue 1 oi 1 on the Kenai Peninsula. -Projected natural gas prices were therefore based on the escalation rate for the SHCA-NSD oil price scenario shown in Exhibit 4.2 • In summary, based upon the limited remaining quantities of Cook Inlet natural gas, reliance on such electric power generation past the year 2000 would seem to entail a considerable amount of risk. 4.2.1.4 North Slope Gas. The vast reserves of natural gas on the North Slope could be moved closer to the Railbelt if either ANGTS or TAGS is built. The ANGTS project would deliver North Slope gas to the Lower 48 states by means of a large diameter pipeline traversing central Alaska and Canada. The ANGTS route is such that it would be possible to construct a lateral line to Fairbanks. The proposed TAGS project would deliver gas to the Kenai Peninsula for liquefaction and export as LNG, principally to Japan. The development of either ANGTS or TAGS depends on the future prices of world oil and natural gas prices and 200/174 4-11 _j "'1 -l ' J l J _j _j .J availability in the Lower 48 states. Even with development of ANGTS or TAGS, it should be recognized that natural gas from the North Slope would be expensive if sold in either Fairbanks or on the Kenai Peninsula because the purchase price of such natural gas would include the costs of conditioning and transporting it to the point of end us·e. As estimated by Battelle, the cost of ANGTS gas in the Fairbanks area would be between $4.03 -$6.32/MMBtu in 1983 dollars in the first year of pipeline operation, assuming the wellhead price of gas was between $0.00 per MMBtu and $2.30 per MMBtu, respec- tively. The General Accounting Office (GAO) recently estimated the delivered price to Fairbanks to be between $2.80 and $5.10/MMBtu in 1983 dollars assuming wellhead prices of between $0.00 per MMBtu and $2.30 per MMBtu, respectively. If the TAGS line were constructed, prices would range from $3.03 - . $4.19/MMBtu in 1983 dollars for delivery to the Kenai Peninsula.* At $3.03/MMBtu the TAGS net-back calculated wellhead price would be a negative $1.34/MMBtu. Obviously, at a negative price, the Project would not be undertaken. The various estimates of North Slope gas projects converge to a price of about $4.00/MMBtu for North Slope gas delivered to the Railbelt and this value would be realistic if either TAGS or ANGTS were to be constructed. * Use of North Slope Gas for Heat and Electricity in the Railbelt, prepared by Ebasco Services, Inc. for the Power Authority, September, 1983. (Hereafter, Ebasco, 1983). 200/174 4-12 ' i __] _j 1 _J ' _j _j _j In the absence of ANGTS and TAGS, two energy development proposals util- izing North Slope gas have been ~nalyzed in a report recently completed for the Power Authority (Ebasco, 1983). The first development involves power generation at the North Slope via simple cycle combustion turbines with attendant electrical transmission from the North Slope to Fairbanks and Anchorage. The second involves electric power generation at Fairbanks using combined cycle plants with transmission lines from Fairbanks to Anchorage. The first alternative would require the con- struction of two 450-mile 500-kV transmission lines from the North Slope to Fairbanks. The second alternative would require transportation of gas to Fairbanks from the North Slope by means of a 22-inch diameter, high pressure pipeline and a gas conditioning facility on the North Slope. The North Slope power generation scenario is not economically attractive and its reliability would be questionable. The study determined that approximately $4.4 billion (1983 dollars) would be required to construct the 1400 MW of new generating capacity and transmission lines necessary to satisfy the Railbelt's electrical demand in the year 2010. Total operation and maintenance costs for the system would amount to a total of $1.1 billion for the years 1993 through 2010. In addition, the pro- posal is subject to some serious technical uncertainties which would require much more detailed study to determine the project's feasibility. North Slope gas could also be made available at Fairbanks via a 22-inch diameter gas pipeline from the gas field. The pipeline design flow of 383 million cubic feet per day would transport sufficient gas to produce 200/174 4-13 ~! _j ~, _i _! _, _j j , J _] _l -, approximately 1400 MW of electrical power and satisfy the projected residential and commercial natural gas demand in the Fairbanks area to the year 2010. It is estimated that the capital investment for the Fairbanks pipeline and its associated gas conditioning facilities would be about $5.8 billion, and that if capital and O&M costs increase at the rate of inflation, a levelized price for the gas would be about $9.90/MMBtu. Other assumptions in this analysis include: 1) private ownership; 2) a wellhead price of $1.00/MMBtu, subject to a 12.5 percent royalty; 3) a real discount rate of 10.0 percent and capital cost escalation rate of 3.5 percent; and 4) a pipeline and conditioning .plant life of 30 years. If ownership and financing of the pipeline by the State of Alaska is assumed, the real discount rate would be 3.5 percent and the levelized delivered price of the gas would be about $7.20/MMBtu. Neither deliver- ed price of gas would be competitive, however, making the scenario of the pipeline to Fairbanks uneconomical. In summary, for North Slope gas to enter the marketplace by ANGTS, natural gas prices in the Lower 48 will have to rise considerably. Implementation of the TAGS project would require a demand for LNG in Asian markets at a price in excess of the current $4.80 to $5.20 per MMBtu. The alternative plans for bringing North Slope gas to the mar- ketplace involve substantial capital investments in pipeline and gas conditioning facilities and potential technical risks which would make electricity generated under such plans substantially more expensive and uncertain than Susitna-generated power. 200/174 4-14 , 1 l j _j 1 _j j J 1 J , J _j ] l _j l J l J -· 1 1 j l 1 1 j J J 4.2.2 Natural Gas-Fired Powerplants Natural gas can be used in the following types of thermal powerplants: simple cycle combustion turbines (SCCT), combined cycle combustion tur- bines (CCCT), and steam turbines. The SCCT and CCCT alternatives are preferred because natural gas-fired steam turbine plants are economical only at very large unit sizes (i.e., substantially larger than 200 MW). In the sizes appropriate for the Railbelt needs, SCCTs and steam turbine are more costly and less efficient than the CCCT. 4.2.2.1 Simple Cycle Combustion Turbines. The SCCT is a well proven system for electricity generation that can be used to meet both baseload and peak demand requirements. Natural gas and air under pressure are burned in the turbine, and the resulting products of combustion are expanded across the turbine. The unit is characterized by rapid start- up capability with no need for a cooling system. The combustion turbine is factory manufactured and supplied in major components that are assembled at the site. These characteristics result in economies of mass production and quick installation. The 75 MW unit size, with a full load heat rate of 11,755 Btu/kWh, was chosen for anal- ysis because it can be utilized effectively in the interconnected Rail- belt system and is less costly on a per kilowatt basis than smaller units. The data demonstrate that the large combustion turbine is a reasonably efficient machine when operating at or near full load. Its efficiency 200/174 4-15 ' _, j ' _ __j ' ____j _j __j J -, j J 1 -' _j l __; l J j _j suffers substantially, however, when it is operated at less than 80 percent of capacity, and when load varies over a large percentage range. Capital and operation and maintenance costs of combustion turbines are summarized on Exhibit 4.3. 4.2.2.2 Combined Cycle Combustion Turbines. The CCCT makes use of the high-temperature (1000°F) combustion turbine exhaust. In the CCCT sys- tem, the exhaust is ducted to a waste heat boiler or heat recovery steam generator. The steam pressure is then raised and the steam is expanded in a conventional steam turbine to produce additional power. Because of both technical and economic gains from scale available at the 237 MW size and because of size of the Railbelt system load, this unit (with a heat rate of 8,280 BTU/kWh) was chosen for analysis.* The CCCT has a thermal efficiency of 41 percent when operating at full load, compared to the SCCT efficiency of 29 percent (11,650 BTU/Kwh) under the same conditions. Efficiency of both types of units drops rapidly at partial loads. Capital and O&M cost estimates for a 237 MW unit are summarized on Exhibit 4.3. 4.3 COAL-FIRED OPTIONS Coal-fired generation is another viable alternative for the Railbelt Region. Coal currently supports 8.3 percent of utility capacity, and is used to generate 13.5 of the electrical energy supplied to consumers in the Rai 1 belt. * The 237 MW figure represents a 220 MW standard unit rated for Cook Inlet conditions. 200/174 4-16 l J _j _; ! ' I J l j l ' j l ' j j J 4.3.1 Coal Availability and Cost in Alaska There are three major deposits of coal in Alaska: the Nenana Field, the Beluga Field and the Kuparuk Field. There are additional smaller de- posits in the vicinity of Nome, in the Matanuska Valley, and on the Kenai Peninsula. These fields contain 130 billion tons of coal resources and 6 bill ion tons of coal reserves. The Nenana and Beluga fields are the most important deposits, as the others have problems that preclude effective large scale exploitation in the near future. The Nenana Field, located near Healy, has a total resource of 7 billion tons and a mineable base of 457 million tons. The Beluga Field, about 75 miles west of Anchorage across Cook Inlet, has identified resources of 1.8 to 2.4 billion tons of coal. Both fields are characterized by thick seams (i.e., thicker than 10ft.), quantities close to the sur- face, and modest quality coal of 7500 -7800 Btu/lb. Coal production in the Nenana field is at the Usibelli Coal Company mine at Healy and current production is 830,000 tons/yr. Currently the coal produced at this mine is sold to the Fairbanks Municipal Utility System, the Golden Valley Electric Association, the University of Alaska at Fairbanks, and the U.S. Department of Defense. This production will increase to 1. 7 million tons annually when the Sunee 1 exports to Korea begin in 1984. The mine could be expanded further to about 4.0 million tons annually to support electric power generation. The current Usibell i mine uses a dragline and front-end loader-based production 200/174 4-17 1 j . .J 1 j _j l _j -, l _j .. , system. Present production capacity is about 1.7-2.0 million tons an- nually. The existing system would have to be duplicated to achieve doubled capacity. The Beluga Field has not been developed. However, Beluga deposits are in reasonable proximity to tidewater and could therefore have access to Pacific Rim markets. The Beluga Field represents an export opportunity, and both Diamond Alaska Coal Company and Placer Amex are studying the potential for such development. The Diamond Alaska design would produce 10 million tons of coal annually while the Placer Amex project is sized at 5 million tons annually. These facilities are designed to serve the- growing market of Japan, Korea, Taiwan, and other Asian ·nations. Production from the Beluga Field could begin as early as 1988, and could also serve domestic markets. Beluga Field production costs, for 5 to 10 million tons per year export-based project, are estimated to be $1. 70/MMBtu, and the market value of the coal (FOB 1983$ at Granite Point) is estimated to be $1.86/MMBtu. Both costs include the cost of developing an infrastructure to serve an export market. -While the Pacific Rim market is growing, the lack of infrastructure creates major risks in predicting the development of a large Beluga mine. If export mines do not develop; a small scale coal mine could be developed for the domestic market alone. Such a development would in- volve altering production technologies to meet the reduced capacity re- quirements. If the Beluga Field were developed to serve domestic needs, .. 200/174 4-18 [ [ c c [ [ [ 0 0 8 c 0 c c c [ [ 0 c the estimated initial cost of Beluga coal would be as shown in Table 4.1. Mine Produc- tion Rate (tons/yr) 1,000,000 3,000,000 Table 4.1 ESTIMATED BELUGA FIELD COAL COSTS WITHOUT EXPORTS Power Plant Capacity Served (MW) 200 600 Initial Coal Cost {1983 $/MMBtu) 3.20 2.23 These costs include the expenditures required for development of infra- structure at the Beluga Field. The cost of coal is substantially higher than the $1.70 to $1.86/MMBtu cost associated with export market production of 10 million tons per year because of the smaller size mine development. For the purposes of the planning analysis, it is assumed that up to 400 MW of coa 1-fi red steam units waul d be 1 ocated near the community of Nenana. The plant would not be located at the Healy coal field because of potential environmental impacts on the Denali National Park. A mine- mouth price of $1.40/MMBtu in 1983 dollars is estimated for Nenana coal based on current contracts with Gal den Va 11 ey Electric Association and Fairbanks Municipal Utility System, adjusted for changes in production levels and new land reclamation regulations. Transportation costs to Nenana are estimated to be $0.32/MMBtu ($5.00 per ton) in 1983 dollars. Therefore, the tot a 1 cost of the coa 1 de 1 i vered in Nenana wou 1 d be 200/174 4-19 c [ c c [ [ [ n L1 $1.72/MMBtu. The coal has an average heat content of about 7800 Btu/lb. Other than this 400 MW unit installed at Nenana, it is assumed that all other coal-fired units would be minemouth units installed at Beluga. Agreements between coal suppliers and electric utilities for the sale/purchase of coal are usually under long-term contracts which in- clude a base price for the coal with an escalation clause. Several real escalation rates have been estimated for the base price of utility coal in Alaska and in the Lower 48, and they range from 2.0-2.7 percent per year. The coal escalation rates used in this Update are identical to those utilized in the July 11, 1983, FERC License Application. Those rates include a 2.3 percent real increase in the minemouth price of Nenana coal used for domestic purposes through 1993. A 1.6 percent per year real escalation rate was assumed for Beluga coal through 1993 on the assumption that coal from this field would follow the price of coal in the Pacific Rim Market. As in the July 1983 License Application filing, both Nenana and Beluga coal prices are assumed in this Update to escalate until the date a given generating unit enters operation. At that time, the coal price for the unit is assumed to remain constant in real terms until the unit is replaced. In the expansion plan studies, Beluga and Nenana coal prices were escalated at their stated rates until 1993, the first year of coal plant operation. In 1993 the cost from either source is estimated to be $2.17/MMBtu (1983 $). For the remainder of the study horizon (1993-2050), a coal price escalation rate of one percent per year is used. This escalation rate is the result on the total coal 200/174 4-20 c [ [ c [ [ [ 0 0 b 0 c [ c c c c [ [ price forecast of the assumption that coal plants "lock-up" a supply of coal at the time they enter operation. An examination of timing and size of projected coal plant additions as produced by the GOP model indicates that a straightline escalation rate of one percent from 1993 to 2020 would approximate this "lock-up" effect of the individual plants. While these escalation rates are an adequate basis upon which to esti- mate future coal prices for purposes of determining the etonomic feasi- bility of the Project, for the reason noted below, the Power Authority intends to engage in further studies to refine these escalation rates before commencement of the Susitna licensing hearings. To place these further studies in perspective, it should be noted that a sensitivity analysis of coal escalation rates indicates that coal escalation is not a critical variable in the Project's economic feasibility. As addressed in greater detail in Chapter 6, the Susitna Project is economically viable even if a zero percent real coal escalation is assumed. 4.3.2 Coal-Fired Powerplants There are several technologies potentially available for converting coal into electricity. The most favorable of these alternatives is the steam turbine system, which involves burning coal under a boiler to raise high pressure steam. This steam is expanded in a high pressure turbine and, in larger systems, exhausted from the turbine at an intermediate pres- sure and temperature to be reheated in the boiler to 1005°F. 200/174 4-21 0 c c [ [ [ c 0 0 o· c c c c [ c [ c c Technical and capital cost studies indicate that a 200 MW coal-fired steam turbine is an appropriate size for an interconnected Railbelt system. Further, the 200 MW size is about the minimum size for using the most energy efficient technologies. The coal steam turbine system is reasonably efficient, with a fully loaded heat rate of 9,750 Btu/kWh, representing a station thermal efficiency of 35 percent. Partial load efficiencies are somewhat lower. Capital, operational, and maintenance cost estimates for·a coal plant are summarized in Exhibit 4.3. The capital costs are from the July 1983 FERC license Application filing, updated to January 1983 price levels. 4.4 CHAKACHAMNA HYDROELECTRIC PROJECT DEVELOPMENT Chakachamna lake is 1 ocated on the west side of Cook In 1 et, about 85 miles west of Anchorage. The· project as currently conceived would in- volve diversion of water from Chakachamna lake via a tunnel to a power- plant on the McArthur River. A Power Authority report titled, "Chakachamna Hydroelectric Project -Interim Feasibility Assessment Report" dated March 1983, assesses the merits of developing the site's power potential by diversion of water southeasterly to the McArthur River via a tunnel about 10 miles long, or easterly down the Chakachatna Va 11 ey either by a tunne 1 about 12 mi 1 es 1 ong or by a dam and tunne 1 development. 200/174 4-22 n c n c c c c c 0 B 0 0 c c c c c c c The recommended scheme, designated Alternative E, includes a dam and provisions for fish passage at the Chakachamna bake outlet, an intake on the lake and 10 miles of power tunnel to provide water to a powerplant on the McArthur River. The project would have an installed capacity of 330 MW, average annual energy generation of 1,590 GW and is estimated to cost $1,438 billion in 1983 dollars. The project costs and power and energy capabilities are shown on Exhibit 4.4. 4.5 ENVIRONMENTAL CONSIDERATIONS OF ALTERNATIVES The environmental and socioeconomic effects of the alternatives to Susitna are substantial and extremely varied. Exhibit 4.5 presents a summary of some of the en vi ronment-rel a ted ~haracteri sti cs of these alternatives, as compared with the Susitna Project. Although most of the environmental impacts associated with the alternatives can be mitigated, the cost of such mitigation could affect the economic viability of some plants at specific sites. The purpose of this review is to ensure that the Susitna Project with its attendant environmental impacts is compared with alternative projects on equal bases, that is, that the environmental consequences of Susitna alternatives are taken into account in any comparative economic analysis. 200/174 4-23 0 c [ c [ [ [ c c D c 0 [ [ c [ c c [ This section reviews environmental concerns related to the following Non-Susitna alternatives: 0 0 0 Natural gas-fired facilities Coal-fired facilities Chakachamna Hydroelectric Project 4.5.1 Natural Gas-Fired Facilities Cook Inlet fields are already developed. Proven and economically recoverable reserves are expected to be depleted by the mid-1990 1 s. North Slope gas is not yet utilized and would likely require a major pipeline to transport gas to areas of use. In broad terms, environmental and socioeconomic concerns with gas alter- natives are related to four factors: 1. Development of gas fields and required infrastructure; 2. Gas pipeline from the gas field to the power plant; 3. Construction and operation of the power plant; and 4. Transmission lines from the power plant to load centers. If Cook Inlet gas is utilized, a power plant would be located in the Beluga Region. If North Slope gas is developed, a power plant could be located in the North Slope, Fairbanks, or the Kenai region. Environ- 200/174 4-24 n c [ c c [ [ c 0 8 0 c [ c [ c c [ c menta 1 and socioeconomic concerns are discussed be 1 ow for the four possible plant locations: Beluga, Kenai, the North Slope, and Fairbanks. 4.5.1.1 Beluga Region. Development of natural gas-fired facilities in the Beluga Region would involve two 237 MW combined cycle power plants and a 75-mile transmission line from Beluga to the Railbelt grid at Willow. Depending upon plant location, additional support facilities would include access roads, construction water supply,· construction plant, airstrip, marine landing facility, and a construction camp. The natural gas would be supplied from the Beluga River, Lewis River and Ivan River fields. Potential concerns include impacts on air resources, water resources, aquatic communities, terrestrial communities, adjacent Native communities, and aesthetics. The power plant would emit significant quantities of carbon monoxide, nitrogen oxides and water vapor and could degrade local air quality. A supply of cooling water (200-400 gallons per minute) would be required for plant operation. The source would likely be groundwater, since surface supplies are minimal. The plant itself would likely discharge minimal wastewater to the environment, and consequently have insignifi- cant impacts to water quality and aquatic ecology. However, if water injection were necessary to control nitrogen oxides emissions, the required supply of water would double, creating the potential for ad- verse impact on groundwater reserves. 200/174 4-25 c [ [ [ c [ [ ! _) c [j D 0 [J [ c [ [ c [ [ Construction of the transmission 1 ine might impact water quality and aquatic communities. Clearing of the right-of-way for the transmission corridor and movement of construction equipment across watercourses could increase sediment in these streams. The additional sediment in the streams could delay hatching, reduce hatching success, preventing swim-up, and resulting in weaker fry. The major terrestrial impact would be loss and disturbance of natural habitat in the vicinity of the power plant and along the 75-mile trans- mission corridor. Habitat for moose, bear, small game, and trumpeter swan would be affected. The peak construction work force would be several hundred, while per- manent operations personnel would number about 150. The largest village in the area has a population of approximately 250. Consequently, an impact on the local population and its lifestyle would be expected. The power plant and transmission facilities would have adverse visual impacts. Moderate noise would also result from facility operations. 4.5.1.2 Kenai Region. Development of natural gas-fired facilities in the Kenai Region would likely include one or several combined cycle power plants, a 94-mile transmission line from Kenai to Anchorage, and associated facilities such as access roads, construction water and power supply, and a marine landing facility. The facility would use natural gas from the North Slope and would require development of the proposed TAGS pipeline. 200/174 4-26 [ [ L· [ [ [ [ c c 0 c c [ [ E L [ L [ Environmental and socioeconomic impacts would be slightly less than those discussed above for the Beluga Region. Air quality impacts would be substantially the same. Water would be derived from ample ground- water supplies. Water pollutants would not be discharged from the plant, thereby preserving water quality and the aquatic ecosystem. Salmon are present in many streams in the area. Clearing of the trans- mission corridor and construction of the transmission line could in- crease sediment in these streams and affect fisheries. The transmission line crossing of Turnagain Arm would be by buried sub- marine cables. Installation of the buried cables would temporarily disrupt the sea floor and increase local turbidity. Impacts of the power plant on terrestrial communities would not be as significant as the Beluga location. The power plant would be located in an area already experiencing development, thus the wildlife populations are less, due to avoidance, therefore, little habitat degradation would occur. The transmission corridor would pass through various vegetation types but mainly spruce woodlands. The corridor includes habitat for caribou and moose but clearing of the vegetative cover should not affect these animals. The power plant and transmission line would have some adverse visual impacts. 200/174 4-27 [ c c 0 c c [ [ [ [ L [ [ Socioeconomic impacts in the Kenai would be less severe than those at th~ Beluga location. There already is a relatively large population in the area, which is not likely to be adversely affected by a large con- struction work force. The creation of over 100 permanent jobs for oper- ations may be considered a positive impact; however, the demand for housing in the vicinity could possibly exceed supply. 4.5.1.3 North Slope; Development of natural gas-fired facilities on the North Slope probably would include a large simple cycle plant, a 360-mile electric transmission line from the North Slope to Fairbanks, and an upgrading of the Fairbanks-Anchorage Intertie. Associated facilities would include access roads, construction water supply, con- struction transmission lines, and a construction camp. The power plant would be located within the existing Prudhoe Bay indus- trial complex and have moderate environmental and socioeconomic impacts. The new transmission line from the North Slope to Fairbanks, on the other hand, could entail significant impacts to water quality, aquatic and terrestial communities and aesthetics. Air quality in the vicinity of the power plant would be a concern, inas- much as there are several gas-fired units already in operation on the North Slope to support petroleum production. The plant would emit nit- rogen oxides, which are normally controlled by water injection systems. However, water injection systems cause undesirable levels of ice fog in cold climates and are very costly in the Prudhoe Bay area because fresh water is in short supply. 200/174 4-28 n [ [ [ [ [ [ [ c 8 [ [ L [ L [ [ [ [ Water supply for other power plant uses (approximately 50 gallons per minute) waul d be supplied from a freshwater 1 ake through the existing water treatment system in the Prudhoe Bay industrial complex. Fishery resources could be affected by, construction and operation of a water supply intake, pipeline development (water or gas), access road construction, and gravel mining (for construction materials) in rivers. Construction of the power plant, switchyard, and camp waul d directly disturb about 65 acres of land. Since the powerplant would be located within the Pr.udhoe Bay industrial complex, the impact would be less than if the area was undeveloped. Some caribou rangeland would be directly affected. The transmission line from the North Slope to Fairbanks and an upgrade of the Intertie to Anchorage crosses hundreds of lakes and streams that are used for fish migration, rearing, spawning and wintering. Clearing of the right-of-way and movement of construction equipment could increase sediment in these streams and lakes and adversely affect fisheries. The transmission line corridor would also pass through a wide variety of terrestrial ecosystems and would be adjacent to several major federal land areas which are protected, in part, for their wildlife values. The transmission line would have to be routed to avoid peregrine falcon nest sites. The routing would also have to avoid important Dall sheep habi- 200/174 4-29 D [ [ [ [ [ [ c c D c [ [ [ [ L [ [ [ tat, caribou migration areas and bird migration routes. Socioeconomic impacts of the power plant would not be significant. The additional labor requirements for construction of the power plant would not appreciably affect the existing large, transient work force. Socioeconomic impacts related to the construction and operation of transmission facilities between Prudhoe Bay and Fairbanks would have to be strictly controlled as the peak work force would exceed 2,300. The line would be constructed within a designated utility corridor. Con- struction workers waul d be housed at pump stations or permanent camp facilities constructed for the Trans-Alaska oil pipeline. Existing facilities would be used where possible. Permanent facilities for transmission line operation and maintenance would be consolidated at several carefully selected locations. The aesthetic impacts of the Prudhoe Bay to Fairbanks transmission line would be significant. The lines would significantly degrade the pris- tine nature of the wilderness landscapes. 4.5.1.4 Fairbanks. Development of natural gas fired facilities in the Fairbanks area, using natural gas from the North Slope, would probably include several combined cycle plants and an upgrading of the Anchorage- Fairbanks Intertie. Since the Fairbanks area is already developed, only minimal associated facilities such as access roads and construction facilities would be required. The 360-mile gas supply line would, how- ever, constitute a significant impact on aquatic and terrestial com- 200/174 4-30 c [ [ [ c [ [ c c D c [ [ [ [ L [ [ [ munities. A major environmental concern would be impact on air quality in the Fairbanks area. The power plant would emit nitrogen oxides. The use of a water injection system to control emission of nitrogen oxides would worsen the ice fog problem and increase carbon monoxide emissions. The area is presently subjected to extended periods of wintertime ice fogs. The power plant would require about 200 gallons per minute for boiler makeup water, potable supplies and other uses. Ample groundwater sup- plies are available in the Fairbanks area. The potential impact on aquatic ecosystems is significant. The pipeline from Prudhoe Bay to Fairbanks would cross numerous streams that are used for fish migration, rear,ing, spawning, and wintering. Clearing of a 50-foot wide right-of-way, burying the pipeline, and other construction activities could introduce additiona 1 sediment into the streams. The additional sediment could delay hatching, reduce hatching success, pre- vent upstream migration, and produce weaker fry. The construction of additional electric transmission lines may have similar impacts on watercourses along the Fairbanks to Anchorage corridor. A power plant in the Fairbanks area would not have significant ter- restrial impacts as the area is already developed. However, there are potential impacts associated with transmission and pipeline con- struction. Long term terrestrial impacts would result primarily from habitat elimination. Pipeline construction would require clearing of a 200/174 4-31 c [ c [ c [ [ c [ 0 c [ [ [ [ [ [ [ [ 50-foot wide right-of-way. The pipeline compressor and metering stations would require 100 to 150 acres of land. Assuming that two additional transmission lines would be built and the Intertie extended, about 8,700 acres would be cleared, of which 80 percent is forested. Habitat for moose, caribou, grizzly and black bears, Dall sheep, and migratory waterfowl could be significantly affected. Socioeconomic impacts in the Fairbanks area would be insignificant because of the existing large population base. There would be potential socioeconomic impacts in the area between Fairbanks and the North Slope associated with construction and operation of the gas pipeline and transmission.line. Temporary camps would be required along the corri- dors. To minimize impacts to local villages, existing facilities would be utilized and temporary camps would be located far from the com- munities. The power plant would not have significant visual impacts in the Fairbanks area, as the area is already developed. However, the transmission and pipeline corridors would have significant aesthetic impacts on the pristine wilderness landscapes. 4.5.2 Coal-Fired Facilities As discussed earlier in this Chapter, there are two potential locations for development of a coal-fired facility, the Beluga Region or the Nenana Region. In broad terms, environmental and socioeconomic concerns would be related to five factors: 200/174 4-32 c [ [ c c [ [ c 0 D D c [ [ [ [ [ [ [ 1. Development of the coal mine; 2. Transportation and storage of coal; 3. Construction and operation of the power plant; 4. Construction and operation of the transmission line from the power plant to the load center; and 5. Restoration of mined areas. Development of coal would have significant environmental effects. For instance, an open pit mine operation would occupy about 6,000 acres and would consume habitat at a rate of 250 acres/year. Water quality could be affected by runoff from the mine, coa 1 pi 1 e and other construction areas. Underground water supply and quality would be affected. Pit blasting and dragline operations create significant noise, dust, and aesthetic impacts. The environmental and socioeconomic concerns of constructing and opera- ting a coal-fired facility also depend on plant location. The two po- tential plant locations are near the Beluga coal field and near the Nenana coal field. The Nenana plant is assumed to be located near the town of Nenana, rather than Healy, due to Healy's proximity to Dena 1 i National Park. 4.5.2.1 Beluga. Development of a coal-fired power plant in the Beluga Region would probably involve the construction of several power plants and a 75-mile transmission line from Beluga to the Railbelt grid. Asso- ciated facilities would include access roads, construction water supply, 200/174 4-33 c [ c [ [ [ [ c l 0 c c [ [ [ [ [ [ [ construction transmissions lines, airstrip, marine landing facility, and construction camp. Surface coal mining would be a major activity. Potential concerns include impacts to air quality, water resources, noise, earth vibration, geologic stability, aquatic communities, ter- restrial communities, socioeconomics, and aesthetics. Coal, in contrast to natural gas, is not a high quality fuel and can generate unacceptable levels of air pollution in the absence of sophis- ticated control equipment. The determination of air pollution control requirements must be made on a case-by-case basis taking into account environmental, economic, and energy factors; however, it is quite cer- tain that air pollution controls will significantly impact design, con- struction, operation, and maintenance costs of a coal-fired power plant. In areas of high terrain, such as found in most of Alaska, controlling sulfur dioxide to the level necessary to meet the short-term Prevention of Significant Deterioration (PDS) standards may preclude construction of economically viable facilities. Other pollutants which require anal- ysis and control techniques include particulate matter, hydrocarbons, nitrogen oxides, and a host of pollutants defined as hazardous under the federal Clean Air Act. The plant would require up to 4,000 gallons per minute of fresh water for cooling, boiler makeup, and other uses. Potential sources include the Beluga River or groundwater. Water withdrawals could impact local water resources. The plant would be designed to have a zero pollutant discharge configur- 200/174 4-34 c c c [ c [ n L 0 0 0 0 c c [ c c [] [ [ ation and would not significantly affect water quality or aquatic eco- systems. Construction of the transmission corridor and clearing of the right-of-way could affect water quality and aquatic communities as des- cribed previously. A major terrestri a 1 impact would be 1 oss and disturbance of natura 1 habitat in the vicinity of the power plant and along the 75-mile trans- mission corridor. Habitat for moose, caribou, bear, small game, and trumpeter swan would be affected. Socioeconomic impacts would be significant. The only village in the area is Tyonek, with a population of about 250. Construction activities could bring a peak work force of over 500 into the area. Operation of the mine and power plant would require 100 to 200 permanent employees, most of whom would probably live near the site in either a private hous- ing development or permanent camp facilities. The large work force and improved access to the area would have a significant impact on the local population and its lifestyle. The area is presently undeveloped. Development of the power plant and attendant transmission facilities would have adverse aesthetic impacts. 4.5.2.2 Nenana. Development of a coal-fired facility in the Nenana area would probably involve a 400 MW power plant and a 160-mile trans- mission line from the plant to Willow. Associated facilities would include access roads, construction water supply, construction trans- mission line, airstrip, railroad spur, and construction camp. The power 200/174 4-35 c c 0 0 0 c c 0 0 0 0 0 0 c 8 u 0 c c plant would be located near the town of Nenana and receive coal via railroad from the e~isting Usibelli Coal Mine at Healy. The Usibelli Coal Mine currently produces coal from the Nenana field at a rate of 830,000 tons per year. The field furnishes coal to existing plants at Healy, Fairbanks, University of Alaska, and several military installa~ tions. The mine would have t~ be expanded to supply coal to a new plant at Nenana. The concerns for the Nenana plant waul d be simi 1 ar to those discussed previously for the Beluga area (Section 4.5.2.1). However, water with- drawal considerations are not a significant issue at Nenana, since ade- quate surface sources exist in the area. The air pollution concerns for- this siting area are substantially the same as at Beluga with the addi- tional concern that Denali National Park's status as a federal Class I PSD area requires that this area be protected. Such protection caul d involve additional control refinements for sulfur dioxide and particu- late matter. Since the coal mine is already operating, impacts of Nenana mine expansion could be less than those in an undeveloped field. The Nenana site would be near Fairbanks and much of the labor force would live in Fairbanks. Therefore, the socioeconomic effects would be minimal. Aesthetic impacts would not be as severe as those in the Beluga area but have the potential to affect more people. 4.5.3 Chakachamna Hydroelectric Development. The Chakachamna Hydroelectric Development would include dam and fish passage facilities at the Chakachamna Lake outlet, a lake tap, a 10-mile 200/174 4-36 0 [ c c [ [ c 0 0 0 G c c c c [ c c 0 long power tunnel, and a 330 MW power plant discharging to the McArthur River. Associated facilities include a 115-mile transmission line from the site to Anchorage and 40 miles of access road. Potential concerns include impacts to water resources, aquatic communities, terrestrial communities and socioeconomic impacts on the Village of Tyonek. 4.5.3.1 Water Resources. The water resources of Chakachamna Lake, Chakachatna River and McArthur River would be impacted. Construction activities, such as clearing, excavating, spoiling, stockpiling of materials, and movement of equipment, may increase erosion and sediment in the streams and lakes. Streams along the 115-mile transmission cor- ridor could also be affected, as described previously in this Section. Water supply for construction would be pumped from the local streams. During project operation, Chakachamna Lake would be affected by an annual 72-ft water level fluctuation. The maximum reservoir level would be at El. 1155, which is near the historical high lake level. The min- imum reservoir level would be at El. 1083, about 45 feet below the his- torical low lake level. This drawdown would expose lake shoreline and stream deltas that are normally inundated. Additionally, at low lake levels, the tributary mouths would be altered resulting in erosion and sediment deposition in the lake. The development would maintain some flow into the Chakachatna River. The releases, however, would be significantly less than occur under natural conditions. Under natural conditions, the mean annual flow is 3,645 cubic feet per second (cfs). With the development, the mean 200/174 4-37 0 0 0 0 D c c 0 0 0 0 0 [ c c 0 c c c annual flow would be 685 cfs. The McArthur River would receive power plant discharges ranging from a minimum of 4,600 cfs in July to a maximum of 7,500 cfs in December. Current flows in the upper reaches of the McArthur River average about 600 cfs in July and 30 cfs in December. The increased flows on the upper reaches of the McArthur River could cause significant overbank flooding. The higher flows would initially erode the stream bed and banks, and carry 1 arge quantities of sediment downstream. Release of 1 ake water into the McArthur River waul d a 1 so a 1 ter the chemica 1 com- position (water quality) of the river. The ice-formation process on McArthur River would be affected by project operations. Ice formation waul d be reduced or possibly eliminated by the increased quantity of flow and the higher temperature of the water originating in the lake. 4.5.3.2 Aquatic Communities. Construction and operation of the devel- opment would greatly affect the aquatic habitat and associated fishery resources in the McArthur and Chakachatna Rivers, Lake Chakachamna and 1 ake tributaries, and the system of sloughs that connect the 1 ower reaches of the Chakachatna River and the McArthur River. Construction activities probably would result in increased sedimentation in the lake and the streams, which could adversely affect eggs and larval fish. The operation of the reservoir would affect the fish rearing habitat 200/174 4-38 c c c 0 c c c 0 0 0 0 0 [ [ [ c C' c c within the lake. During open water, juvenile sockeye, lake trout, round whitefish, and Dolly Varden are found throughout the lake, with many fish found offshore along steep drop-offs and just under the ice in winter. At high reservoir levels (during October and November) lakeshore areas may be used as spawning habitat by lake trout and sockeye. After reser- voir levels drop, incubating eggs and fry would be exposed to freezing or dessication. Relatively immobile invertebrates which· reproduce in shoreline areas may also be affected. The development would include a fish passage facility which is designed to permit upstream migrants to ascend from the Chakachatna River to the lake and allow downstream migrants to pass from the lake to the Chakachatna River. Sockeye salmon and Dolly Varden are expected to use this facility, as both have been observed to spawn above the lake. Based on 1982 data, it is estimated that over 41,000 sockeye would need to successfully pass through the facility to migrate upstream. Ten to more than 100 times as many sockeye smelt and a smaller number of Dolly Varden can be expected to migrate downstream. The effectiveness of the fish passage facility, however, cannot be assured. If the facility did not successfully allow the migration of sockeye both upstream as adults and downstream as juveniles, some part of the estimated adult spawning population would be lost, as well as a portion of their contribution to the Cook Inlet fishery. 200/174 4-39 0 ' c 0 c 0 c c 0 0 0 0 .. 0 c c D 0 0 c c The fisheries of the McArthur and Chakachatna Rivers waul d a 1 so be - affected; mainly from the changes in flow regimes. The water quality in the McArthur River would be changed, possibly altering fish production. Juvenile salmon imprint on the waters of their origin. As smelt they out migrate to the ocean for the marine stage of their 1 ife cycle. Returning adults seek out their natal waters on which to spawn. The diversion of Lake Chakachamna water into the McArthur River may disrupt the homing patterns of salmon, principally sockeye, returning to tributary streams above Lake Chakachamna. If sockeye salmon were attracted by Chakachamna waters into the McArthur River they would not find ~dequate spawning habitat, and there would.be no rearing habitat. It is necessary to maintain the 41,000 fish escapement of sockeye into Lake Chakachamna in order to assure the viability of this run. 4.5.3.3 Terrestrial Communities. Construction of the Chakachamna Proj- ect would involve removal of vegetation over a relatively small area. The fluctuation in lake levels and increased flow areas in the McArthur River would affect terrestrial habitat that is used by moose in winter and by waterfowl in spring, summer and fall. Development of disposal areas in both the McArthur and Chakachatna flood plains would result in the largest habitat loss, and greatest disturbance to birds and mammals. ' Moose, ptarmigan, small mammals, and passerine birds could be affected. Clearing of the 115-mile· transmission corridor and construction of a 40-mile access road would eliminate a large area of wildlife habitat. Habitat for moose, bear, and small mammals could be affected. 200/174 4-40 [J 0 c c 0 c 0 0 0 0 0 0 c c 0 c c c c 4.5.3.4 Socioeconomic Factors. Socioeconomic impacts would likely be significant. The development would be located in an undeveloped area, near the Village of Tyonek. A construction work force of over 250 would be required. This influx of construction personnel could impact the social and economic structure of these communities. Additionally, the improved access to the area caul d impact the communities. The Native community of Tyonek may seek to maintain its remote condition in order to maintain its Native cultural identity, and it may not welcome persistent high levels of construction and operation work forces. 4.5.3.5 Aesthetic Factors. The potential aesthetic impacts of . the proposed Chakachamna Project are significant, particularly from a visual standpoint. Potential fluctuations in Lake Chakachamna levels would leave exposed lakeshore at certain periods. Significant reduction in outflows would result in the loss of much of the white water reach of the Chakachatna River canyon, as well as noticeable alterations to the floodplain. Disposal areas in McArthur valley would be noticeable, and together with support facilities (roads, transmission line, etc.) will result in degradation of the aesthetic character of wi 1 derness 1 and- scapes. 200/174 4-41 c:-:J CJ CJ CJ CJ CJ c--J c:J 0 OJ] CJ C.".J r-J CJ c-J CJ C:J li. ..... J ESTIMATED CUMULATIVE CONSUMPTION OF COOK INLET NATURAL GAS RESERVES (a) (billion cubic feet) Electric Generation Phillips/ Field Opera-Expanston Total Total Remainin~ Reserves Marathon Collier Retail tions & Planning Gas Cumulative Proven Plus Year LNG/ Plant Ammonia/Urea Sales Other Sales Militar~ Studies(b) Use Gas Use Proven Undiscovered 1983 62 55 19.2 25 5 27.1 193.3 193.3 3157.6 5197.6· 1984 62 55 19.8 25 5 28.8 195.6 388.9 2962.0 5002.0 1985 62 55 20.5 25 5 30.4 197.9 586.8 2764.1 4804.1 1986 62 55 22.8 25 5 29.1 198.9 785.7 2565.2 4605.2 1987 62 55 23.6 25 5 30.3 200.9 986.6 2364.3 4404.3 1988 62 55 24.4 25 5 27.5 198.9 1185.5 2165.4 4205.4 1989 62 55 25.3 25 5 28.7 201.0 1386.5 1964.4 4004.4 1990 62 55 26.1 25 5 29.8 202.9 i589.4 1761.5 3801.5 1991 62 55 27.1 25 5 30.4 204.5 1793.9 1557.0 3597.0 1992 62 55 28.0 25 5 31.2 206.2 2000.1 1350.8 3390.8 1993 62 55 29.0 25 5 33.0 209.0 2209.1 1141.8 3181.8 1994 62 55 30.1 25 5 33.8 210.9 2420.0 930.9 2970.9 1995 62 55 31.1 25 5 34.8 212.8 2632.9 718.0 2758.0 1996 62 55 32.2 25 5 35.5 214.7 2847.6 503.3 2543.3 1997 62 55 34.4 25 5 36.3 217.7 3065.3 285.6 2325.6 1998 62 55 34.6 25 5 37 .1. 218.7 3284.0 66.9 2106.9 1999 62 55 35.8 25 5 37.7 220.5 3504.5 (153.6) 1886.4 2000 62 55 37.0 25 5 38.5 222.5 3727.0 1663.9 2001 62 55 38.3 25 5 39.4 224.7 3951.7 1439.2 2002 62 55 39. 7. 25 5 29.5 216.2 4167.9 1223.0 2003 62 55 40.1 25 5 30.6 217.7 4385.6 1005.3 2004 62 55 42.6 25 5 31.8 221.4 4607.3 783.9 2005 62 55 44.1 25 5 32.8 223.9 4831.2 560.0 2006 62 55 45.6 25 5 24.3 226.9 5058.1 333.1 2007 62 55 47.2 25 5 25.0 219.2 5277.3 113.9 2008 62 55 48.9 25 5 26.3 222.2 5499.5 (108.3) 2009 62 55 50.6 25 5 27.7 225.3 5724.8 2010 62 55 52.4 25 5 28.3 227.7 5952.5 (a) Estimates of Natural gas consumption, with the exception of electric generation from expansion planning studies, proven and proven plus economically recoverable undiscovered reserves taken from FERC License Application, Table D.1.3, Appendix D-1, Exhibit D, July 1983. (b) OGP fuel u1se summary for SHCA-NSD Coal/Gas expansion plan. L ..... U SHCA -NSD SCENARIO FUEL COSTS (January 1983 price level) Crude Oil Cook Inlet Gas North Slope Gas Coal Average Rate Average Rate Average Rate Average Rate of Change of Change of Change of Change Year Cost Per Year Co.st Per Year Cost Per Year Cost Per Year ($/bbl) % ($/MMBtu) % ($/MMBtu) % ($/MMBtu) % 1983 28.95 2.47 4.00 1. 72/1.86 0.5 2.0 0.5 2.3/1.6 1993(a) 30.49 3.02 4. 22 2.17 s.o 3.0 3.0 1.0 2000 37.50 3. 71 5.19 2.33 3.0 3.0 3.0 1.0 2010 50.39 S.OO(b) 6.97 2.57 2.5 2.5 2.5 1.0 2020 64.48 6.39(b) 8.92 2.84 1.5 1.5 1.5 1.0 2030 74.84 7.4l(b) 10.35 3.13 l.O 1.0 1.0 1. 0 2050 91.32 9.05(b) 12.63 3.82 (a) First year of economic analysis. (b) Economically recoverable Cook Inlet reserves assumed to be depleted in 2007. Analysis assumes further Cook Inlet gas will be priced equivalent to North Slope gas. Numbers are shown for the sensitivity analysis of unlimited Cook Inlet gas. N 0 Q 0 c 0 c 0 0 0 0 0 c c c D R u c c EXHIBIT 4.3 THERMAL PLANT OPERATING PARAMETERS AND COSTS (a) Characteristics Nameplate Capacity -MW Heat Rate -Btu/kWh Outage Rates, Percent of Time Scheduled (Immature) Scheduled (Mature) Forced (Immature) Forced (Mature) Immature Period -yrs Construction Period, yrs Unit Construction Costs -$/kW Unit Investment Cost (b) -$/kW Operation and Maintenance Costs Variable O&M costs -mills/kWh Fixed O&M Costs -$/kW/yr Economic Life -Years (a) January 1983 price level Coal-fired 200 9,750 12.0 8.0 8.6 5.7 3 5 2,175 2,370 0.6 17.00 30 Combined Cycle 237 8,280 8.8 7.0 10.0 8.0 2 2 604 625 1.69 7.25 30 Combustion Turbine 84 11,650 3.2 3.2 8.0 8.0 1. 1 500 510 4.90 2.70 20 (b) Includes interest during construction at 3.5 percent interest, escalation not included. c c c c c c c 0 0 0 c c [ [ c c c c CHAKACHAMNA HYDROELECTRIC PROJECT DATA(a) Installed Capacity -MW 330 Total Capital Cost Including 1,307 Transmission (a) - $ million IDC-$ million 131 Total Capital Cost - $ million 1,438 Total Capital Cost -$/kW 4,358 Annual Operation and Maintenance Cost - $ million 2.0 Monthly Power and Energy Production: Minimum Maximum Average Firm Plant Plant Month Ener~~ Ener~x: Rat in~ Rat in~ GWh GWh MW MW January 133 133 177 179 February 114 114 168 170 March 113 113 150 153 April 98 98 135 137 May 94 92 124 231 June 96 86 120 330 July 138 88 118 330 August 228 92 124 330 September 179 98 136 330 October 126 115 155 275 November 128 128 177 179 December 144 144 193 195 Total 1,591 1,301 (~) Chakachamna Hydroelectric Project Interim Feasibility Assessment Report, Bechtel Civil & Minerals, Inc., Alternative E, March 1983. EXHIBIT 4.4 Parameter Hydrology and Water Quality Susitna Hydro- electri~ Jroject, 1620 MW a Impoundment of the Susitna Ri,Ter would inundate approximately 86 miles of river (plus associated tributaries). The reservoirs may alter downstream tempera- ture and flow regimes. Between De'llil Canyon and Talkeetna, peak summer water tempera- tures are 1expected to be decreased and mini- mttm winter ~empera­ tures are ,expected to increase. To avoid or minimize temperature changes, multi-level EXHIBIT 4.5 PAGE 1 OF 9 SUMMARY OF ENVIRONMENTAL IMPACTS CAUSED BY ALASKA RAILBELT ELECTRIC POWER ALTERNATIVES Beluga Coal Field and 400 MW Coal Fired Generator Strip mining could interfere with ground- water flows and degrade water quality. Surface water could be affected by runoff from the mine, coal pile, and other constructed areas. Groundwater could be affected by acid mine drainage and ash disposal pond leachate. Long-term changes in pH, turbidity, and trace metals concentra- tions are expected. Dis- charges would be minimized by compliance with SMCRA and NPDES guidelines. The power plant would require Nenana Coal Field Expansion with 400 MW Coal Fired Generator Because the N~nana mine is already in operation, the incremental impacts of mine expansion may be less than those for the new Beluga mine. Long- term impacts of the power plant would be similar to those caused by the Beluga option. (a) Watana plus Devil Canyon Developments. North Slope to Fairbanks . Gas Line with 400 MW Combined Cycle Generator The gas fired power plant would require roughly 2,200 gpm of fresh water for boiler makeup and miscellaneous uses. The gas pipeline would cross 15 major streams and and numerous small streams. The buried, chilled pipe could disrupt both ground- water and surface water flows. Road cuts for pipeline access could cause disruption of groundwater flows, and also cause changes in surface runoff and soil erosion. n·ameter Susitna Hydr,D- electriy ~roject, 1620 MW a intakes will be provi- ded in the dams which allow for control of downstream t~empera­ tures. A more stable flow regime is e~pected downstream of the Pro- ject with lo11J winter flows increa:sed and high summer flows (particu- larly flood events) decreased. lee forma- tion is expected to decrease, particularly between Talk,ee-tna and Devil Canyon. Sus- pended sediment levels between Talk,eetna and Devil Canyon will be . significantly reduced. Turbidity levels .will be significantly reduced in the summer and slightly increased during ~inter. Down- stream of Talkeetna, EXHIBIT 4.5 PAGI; 2 OF 9 SUMMARY OF ENVIRONMENTAL IMPACTS CAUSED BY ALASKA RAILBELT ELECTRIC POWER ALTERNATIVES Beluga Coal Field and 400 MW Coal Fired Generator roughly 4,000 gpm of fresh water for boiler makeup and miscellaneous uses. Nenana Coal Field Expansion with 400 MW Coal Fired Generator North Slope to Fairbanks Gas Line with 400 MW Combined Cycle Generator CJ (""""""'] Parameter Terrestrial c:J CJ CD Susitna Hydro- electriy Jrojec~, 1620 MW a rr-J project impacts are expected to be less significant due·to the influence (If flows from the Chulitna and Talkeenta rivers. Construction of the Susitna Hydroelectric projects (Watana and Devil Canyon dams and reservoirs) will result in the direct removal of vegetation from an area of approximately 42,000 acres covering a range of elevations from 900 to 2400 feet. An additional 7300. acres of unvegetated areas (mostly existing river area) will be inundated or developed. 84% of the vegetated area to be cleared is forest land. This c-J CJ c::J CD C .. , ... J CJ CJ CJ c-:J EXHIBIT 4.5 PAGE 3 OF 9 SUMMARY OF ENVIRONMENTAL IMPACTS CAUSED BY ALASKA RAILBELT ELECTRIC POWER ALTERNATIVES Beluga Coal Field and 400 MW Coal Fired Generator Surface mining and power plant operation would create long-term impacts on wildlife habitats. For one mining scenario, the ultimate pit bound- aries cover roughly 8 sq. miles and the support facilities would cover roughly 500 acres. Min- ing operations would con- sume roughly 250 acres/yr. of habitat. New roads into the mine area would cause substantial losses in carrying capacity and productivity in the affected areas. Nenana Coal Field Expansion with 400 MW Coal Fired Generator The incremental impacts of the Nenana mine expan- sion would probably be less than operation of the new Beluga mine. Impacts.of the Nenana power plant would be simi- lar to those of the Beluga plant. C:-:J c:J crJ c=J North Slope to Fairbanks Gas Line with 400 MW Combined Cycle Generator Pipeline construction would require clearing of a 50-ft. right-of-way. Construction-related impacts could intermit- tently disrupt wildlife habitats during the 3- year construction period. The pipeline compressor stations and metering facilities would require roughly 100-150 acres of land. The Fairbanks generating station would have a minimal impact on wildlife. 'arameter Susitna Hydro- elec~riy Jroject~ 1620 MW a represents UO% of the forest land within 10 miles of the Susitna River from Gold Creek to the north of the MacLaren River. Removal of "egetation and filling of the ·reservoir will reduce the carrying capacity of the area for wild- life. The presence of the reservoirs and the access roads will potentially impact movements of moose. caribou and other big game in the area. New roads would add access to this pre- sently remote area. The Project. including access and transmission routes. will disturb EXHIBIT 4.5 PAGE.40F9 S~Y OF ENVIRONMENTAL IMPACTS CAUSED BY ALASKA RAILBELT ELECTRIC POWER ALTERNATIVES Beluga Coal Field and 400 MW Coal Fired Generator Nenana Coal Field Expansion with·400 MW Coal Fired Generator North Slope to Fairbanks Gas Line with 400 MW Combined Cycle Generator ~arameter Hr Quality Jeology 11nd Soils Susitna Hydro- electriy ~roject, 1620 MW a 18 recently active raptor and raven nests and 16 or 17 inactive nests. Short-term emissions during dam construc- tion: particles, 1,300 tons/yr.; so2. 300 tpy; NO , 2,300 tpy. Long- te'm emissions after dam completion should b~ minimal. Ambient pollutant concentra- tions should be well below all applicable standards. Dam construction, reservoirs, borrow sites and construc- tion camps·would affect roughly 50,000 acres. Roughly 80-90 EXHI~IT 4.5 PAGE 5 OF 9 SUMMARY OF ENVIRONMENTAL IMPACTS CAUSED BY ALASKA RAILBELT ELECTRIC POWER ALTERNATIVES Beluga Coal Field and 400 MW Coal Fired Generator Short-term emissions would occur during power plant construction. Long- term power plant emissions: particles, 1,800 tpy; so2. 1,700 tpy. These emissions would ·occur for the entire power plant life. Ambient so 2 concentrations would be higher than the short-term concentrations for the Susitna project, and could violate state air quality standards. The Beluga mine and facili- ties would cover roughly 9 sq. miles. Mining opera- tions would impact roughly 250 acres/yr. Topography in the mine area would be Nenana Coal Field Expansion with 400 HW Coal Fired Generator Emissions from the Nenana power plant should be simi- lar to those froa the Beluga plant. However, the Nenana site is located in a Class I PSD area. The air quality impacts of power plant emissions on the protected area would be very significant, and siting of any major power plant to meet very strin- gent PSD regulations would be extremely difficult. The Nenana coal mine is alreaay-operating, so initial expansion would probably·· cause less impact _ -, than would startup opera- tions of the new Beluga North Slope to Fairbanks Gas Line with 400 HW Combined Cycle Generator Short-term emissions would occur during pipeline and power plant construction. Long-term power plant emis- sions: negligible particu- lates and so 2 ; approx. 5,300 tpy of NO • Negligib. X emissions from pipeline com- pressor stations. Ambient pollutant concentrations would exceed those for the Susitna project. The buried pipeline would cause localized soil impacts along the entire right-of-way. Pipeline compressor stations, gas conditioning plants and rameter u~ttic osystem Susitna Hydro- electric Project, 1620 MW\aJ miles of new access roads would be needed. In the reservoir area. existing Susitna River and affected tributary aquatic habitat will change from free flow- ing to a reservoir. Aquatic resources char- acteristic of a large glacially-fed lake or reservoir would develop. Small lakes within the inundation zone would be simi- larly changed. Between Talkeetna and Devil Canyon*. flow alteration is expected to provide a more stable regime and aq~atic habitat with EXHIBIT 4.5 PAGE 6 OF 9 SUMMARY OF ENVIRONMENTAL IMPACTS CAUSED BY ALASKA RAILBELT ELECTRIC POWER ALTERNATIVES Beluga Coal Field and 400 MW Coal Fired Generator permanently affected. The power plant, coal storage, and ash disposal facilities would occupy roughly 75- 150 acres. Some aquatic habitat would be lost due to mining opera- tions. In addition, in- creased siltation, stream- flow reductions. reduced stream pH and increased trace metal concentrations could result from mine drainage and power plant effluent discharges. The adverse water quality im- pacts could reduce fish populations in local streams and interfere with anadromous fish runs, poten- tially reducing marine re- sources in the Cook Inlet region. Nenana Coal Fie~d Expansion with 400 MW Coal Fired Generator mine. Long-term incre- mental mining operations would create impacts simi- lar to those for the Beluga project. The Nenana power plant would create impacts similar to tho~e for the Belug~ plant. Impacts of the Nenana mining activities and power plant operation could adversely affect fish populations and anadromous fish runs in local streams. These impacts would be similar to those caused by the Beluga operation. ..J North SloP.e to Fairbanks Gas Line with 400 MW Combined Cycle Generator the power plant would require roughly 150-200 total acres. The gas P.ipeline would cross numerous,· small streams, as well as 15 major rivers and streams. Considerable mitigative measures would be required to prevent stream blockage due to pipeline freezing, increased stream velocity due to stream diversion. changes in stream tempera- ture caused by presence ~f the chilled pipeline. and prolonged stream freeze- ups that could hinder fish migrations. The Fairbanks power plant would have minimal impacts on the aquatic ecosystem. ,/ J Parameter Susitna Hydro- electriy Jroject, 1620 MW a increased winter flows and decreased high sum- mer flows (particularly floods). Access for adult salmon to sloughs is expected to be hind- ered. However, access is to be maintained by mitigation measures. Temperature regime changes resulting from reservoir releases may alter timing of speci- fic life stages of fish such as time of spawn- ing, incubation time and rearing. Multi- level intakes in the dams are expected to provide collttrol of downstream tempera- tures so as to avoid or minimize this effect. Decrease in EXHIBIT 4.5 PAGE 7 OF.9 SUMMARY OF ENVIRONMENTAL IMPACTS CAUSED BY ALASKA RAILBELT ELECTRIC POWER ALTERNATIVES Beluga Coal Field and 400 MW Coal Fired Generator Nenana Coal Field Expansion with 400 MW Coal Fired Generator North Slope to Fairbanks Gas Line with 400 MW Combined Cycle Generator rameter Sufiitna Hydr..o- electriy ~roject, 1620 HW a downstream sediment loads would be expec- ted to increase ben- thic habitat; however, turb~dity may minimize light penetration. and productivity. Down- stream of Talkeetna, proj.ect impacts are expected to he less significant due to the influence of flows from the Chulitna and Talkeetna Rivers. cioecoriomic Impacts on the Mat-Su Borough should be minor, because most construction workers will be housed at the dam site. The total expected population increase during the Watana construction is 4,700 persons, 3,600 of which will live at the full service town- sites at Watana. EXHIBIT 4.5 PAGE 8 OF 9 SUMMARY OF ENVIRONMENTAL IMPACTS CAUSED BY ALASKA RAILBELT ELECTRIC POWER ALTERNATIVES Beluga Coal Field and 400 MW Coal Fired Generator Construction and opera- tion of the Beluga mine and power plant could have major socioeconomic impacts. Constructfon activities would cr~ate an influx of over 500 workers into an area with low population and minimal infrastructure. Even if a construction camp were established, the presence of the Nenana Coal Field Expansion with 400 MW Coal Fired Generator The Nenana site is situate4 near Fairbanks~ Most of the 500 person labor force would probably originate from and live in the Fair- banks region. A severe boom due to Nenana plant construction and operation would therefore be unlikely. The overall socioeconomic impacts of the facility would probably be minimal. North Slope to Fairbanks Gas Line with 400 MW Combined Cycle Generator Generator construction should have a minimal effect on the Fairbanks region. The estimated workforce for generator construction is. 200-400 persons •. Most construc- tion workers would come from the Fairbanks labor pool. Minimal additional housing and services would be needed. Facility construction would create c::J C ... J Parameter c:J c:J L : . .J Susitna Hydlro- electric Project, 1620 MW\a) [""'""-'] Virtually a~l social services for the 3,600 persons will be pro- vided by the contrac- tor. The t·emaining 1,100 persons are expected to inmigrate to the local towns of Cantwell, Trapper Creek and Talkeetna. This relatively low population influx would increase the utilities and services costs for those towns by only a few percent. The total traffic flow on the existing Parks and Denali Highways will increase by only 30-35 trucks per day plus commuter vehicles. Additional snow re- moval and maintenance will be required for the Denali Highway. LJ c:J CJ C~.-cl c:J EXHIBIT 4.5 PAGE 9 OF 9 c ..... J r-::=J SUMMARY OF ENVIRONMENTAL IMPACTS CAUSED BY ALASKA RAILBELT ELECTRIC POWER ALTERNATIVES CJ Beluga Coal Field and 400 MW Coal Fired Generator Nenana Coal Field Expansion with 400 MW Coal Fired Generator required access roads and other facilities would probably create significant impacts. Operation of the mine and power plant would require between 100-200 permanent employees, most of which would probably live near the site. Considering that the largest local town, Tyonek, has a popu- lation of less than 250, the influx of permanent workers would create major socioeconomic impacts. CJ CJ C":J North Slope to Fairbanks Gas Line with 400 MW Combined Cycle Generator slight short-term increases in Fairbanks' traffic flow. Operation of the power plant would provide addi- tional tax revenues for -the region. For pipeline construction, workers could be housed in existing campsites used for the Trans-Alaska oil pipeline. ! _) .J 5.0 SYSTEM EXPANSION PROGRAMS 5.1 INTRODUCTION The objective of the system expansion studies is to develop long-tenn power supply plans to meet the forecast Railbelt electrical demand, using system configurations with and without the Susitna Hydroelectric Project. The system expansion studies are performed using the OGP computer program and utilize a great deal of information relating to alternative means of electric generation, including fuel prices for thermal alterna- tives, developed in Chapter 4. The forecast of electrical demand· is generated from the MJSENSO/MAP/REO models sequence discussed in Chapter 2, using the NSD world oil price forecast developed by SHCA • The OGP program uses economic planning criteria that are described in detail in Chapter 6. The resultant analyses also provide annual and present worth costs of alternative expansion plans. These results are used in Chapter 6 to draw conclusions as to the economic benefit of the Project using a life cycle cost approach. In this Chapter, the existing Railbelt system is first described. Next, system expansion from 1983 to 1992 is addressed. Since 1993 was pre- sented in the FERC License Application as the earliest date that the Susitna Project would be available for operation, the criteria for 201/174 5-1 0 c c c c u 'l J u ] l J j l J system expansion after 1992 are discussed. The OGP computer model is described briefly, followed by a discussion of alternative expansion plans produced by the study. 5.2 THE EXISTING RAILBELT SYSTEMS The two major load centers of the Railbelt region are the Anchorage-Cook Inlet area and the Fairbanks-Tanana Valley area, which at present operate independently. These two load centers will become the intercon- nected Railbelt market when the Intertie, currently under construction by the Power Authority, is completed. The Glennallen-Valdez load center is not planned to be interconnected with the Railbelt nor to be served by the Susitna Project. The existing transmission system of the Anchorage-Cook Inlet area extends north to Willow and consists of a network of 115-kV and 138-kV lines with interconnection to Palmer. The Fairbanks-Tanana Valley system extends south to Healy over a 138-kV.line. The Intertie which is being built by the Power Authority to connect Willow and Healy will operate initially at 138-kV. The transmission system is illustrated in Exhibit 5.1. 201/174 5-2 n lJ c L ' . ,_j L.J u 5.2.1 Anchorage-Cook Inlet Area The Anchorage-Cook Inlet area has the following major electric utilities and power producers: 0 0 0 0 Municipal Utilities Municipality of Anchorage-Municipal Light & Power Department (AMLP) Seward Electric System (SES) Rural Electrification Cooperatives (REAs) Chugach Electric Association, Inc. (CEA) · Homer Electric Association, Inc. (HEA) Matanuska Electric Association, Inc. (MEA) Federal Power Marketing Agency Alaska Power Administration (APAd) Military Installations Elmendorf Air Force Base Fort Richardson AMLP a~d CEA are the two principal utilities serving the Anchorage-Cook Inlet area. All of these organizations, with the exception of MEA, have electrical generating facilities. MEA buys its power from CEA. HEA and SES have relatively small generating facilities that are used for standby operation. They also purchase power from CEA. The Anchorage;..cook Inlet area is almost entirely dependent on natural gas to generate electricity. About 92 percent of the total capacity is 201/174 5-3 ' l l ..J _j ..J ..J provided by gas-fired units. The remainder is provided by hydroelectric units and oil-fired diesel units. In 1982, the electricity generated by the Anchorage-Cook Inlet utilities was 2,446 GWh, with a peak demand of about 472 MW. Between 1976 and 1982, the demand increased at an average annua 1 growth rate of 7.1 percent, according to figures supplied by the utilities. 5.2.2 Fairbanks-Tanana Valley Area The Fairbanks-Tanana Valley area is currently served by the following utilities and power producers: 0 0 0 0 Municipal Utility Fairbanks Municipal Utilities System (FMUS) Rural Electrification Cooperatives (REAs) Golden Valley Electric Association, Inc. (GVEA) Military Installations Eielson Air Force Base Fort Greeley Fort Wainwright University of Alaska, fairbanks GVEA & FMUS own and operate generation, transmission, and distribution facilities. The University and military bases maintain their own generation and distribution facilities. Fort Wainwright is 201/174 5-4 c c c c c [ [ c n, u D { u interconnected with GVEA and FMUS and provides both utilities with secondary energy. A large portion of the total installed capacity consists of oil-fired combustion turbines (57 percent) and coal-fired steam turbines (30 percent). The remaining capacity is provided by diesel units. In 1982, the total energy generation, including purchases, of the Fairbanks utilities was 491 GWh, with a peak demand of 94 MW. The growth. in peak demand in the past six years has averaged _less than one percent. 5.2.3 Total Present System Exhibit 5.2 summarizes the total generating capacity within the Railbelt system in 1983. The total Railbelt installed capacity amounts to 1123 MW, excluding installations not available for public service at military bases. The 1123 MW consists of 1077 MW of thermal generation fired by oil, gas, or coal, plus 46 MW from the Eklutna and Cooper Lake hydro- . ··electric plants. Average and firm monthly energy estimates for the Eklutna and Cooper Lake hydroelectric projects are shown on Exhibit 5.3. 5.3 GENERATION EXPANSION BEFORE 1993 The Power Authority has begun the construction of an Intertie connecting the Anchorage and Fairbanks load centers with a single circuit 201/174 5-5 n u n u n lj n lJ n LJ 1, u j .., J l l _j transmission line between Willow and Healy. The line, scheduled for completion in 1984, will initially be energized at 138 kV, but can be operated at 345 · kV as loads grow in Anchorage and Fairbanks. The completion of the Intertie will improve the reliability of service for both 1 oad centers and provide opportunities for economy exchanges of energy. Because of their advanced planning status, two proposed hydroelectric plants are assumed to be added to the Railbelt system prior to 1993. These are the Bradley Lake Hydroelectric Project, with 90 MW of generat- ing capacity and 347 GWh of average annual energy, and the Grant Lake Project, with 7 MW of generating capacity and 25 GWh of average annual energy. The average and firm monthly energy estimates for the Bradley Lake and Grant Lake projects are shown on Exhibit 5.3 • FMUS is considering the addition of a 25-30 MW cogeneration unit to replace Chena Units 1, 2 and 3, and Chugach Electric Association is studying the feasibility of a 34 MW combustion turbine at Bernice Lake and an 80 MW combust·ion turbine at Beluga. Although plans for these units appear to be moving forward, they have not been finalized and the units are therefore not included in the Railbelt system for purposes of the Update analysis. 201/174 5-6 D c c 0 c [ c 0 D D D D L 'l L [ c 5.4· FORMULATION OF EXPANSION PLANS AFTER 1993 Capacity expansion studies, such as those· undertaken for the Susitna Project, serve three major functions: (1) reliability (or reserve) evaluation; (2} electricity production simulation; and, (3} capacity expansion optimization. Expansion optimization analyses provide a systematic means of evaluating the timing, type, and system costs of new power facilities, thus permitting analysis of the relative costs of different means of meeting an estimated electrical demand. This Update uses the Optimized Generation Plan (OGP} model to develop expansion plans for the Railbelt. The OGP model was also used in the earlier feasibility studies and in the FERC License Application. Exhibit 5.4 outlines the procedure used by OGP to determine an optimum generation expansion plan. The OGP analysis conducted for this Update· assumes that the Railbelt utilities are fully interconnected, share reserves, and optimize plant operation. In developing an·optimal capacity expansion plan, the program considers the existing and committed units (planned and under construction} available to the system and the operating characteristics of these units. The program then factors in given 1 oad forecast and system operation criteria in determining the need for additional future capaci- ty to attain the specified degree of reliability. The program quan- tifies the amount and installation date of needed additional capacity as load increases over time. 201/174 5-7 0 c c [ c c c 0 0 0 [ c I' L r·" If additional capacity is needed, the program considers additions from available alternatives and selects the available unit best fitting the system•s needs. Unit selection is made by computing ·production costs for the system with each alternative unit included and comparing the results. The unit providing the lowest system production costs is selected and added to the system. The OGP modeling procedure contains several key elements which are discussed below. 5.4.1 Reliability Evaluation The Loss of Load Probability (LOLP) method is used in the OGP program to determine when additional capacity is needed. The LOLP approach recog- nizes that forced outages of generating units would cause a deficiency in the capacity available to meet the system load unless adequate capacity had been installed. In developing an Sdequate reserve margin for the Railbelt three LOLPs were studied, one day in ten years, one day in five years and one day in three years. With LOLP of one day in five years, the reserve margin would normally be in the range of 30 to 50 percent, which is considered appropriate fo~ a system such as the Railbelt, and is the reliability criteria used in the Update. Exhibit 5.1 illustrates the reserve margin for the Non-Susitna and L With-Susitna expansion plans. A spinning reserve of 150 MW is included within the reserve margin for all alternative expansion plans. Spinning reserve is available thermal capacity which can quickly be brought into full production to off-set any forced shut-down of operating units. The costs associated with this spinning reserve are included in all plans. 201/174 5-8 n c c !' I c u n n _j _,J. 5.4.2 Hydro Scheduling In the OGP simulation, the size and timing of hydroelectric units are provided as input around which thermal units are added. For purposes of the OGP runs done. for this Update, the Watana Development initially operates on base load in order to maintain nearly uniform discharge from the powerplant. When Devil Canyon begins operation, Watana. operates as load-following while Devil Canyon operates on base load. The operating mode of the Watana Development will be subject to more detailed analysis by the utilities, environmental agencies, and the Power Authority as planning proceeds. 5.4.3 Thermal Unit Commitment After deducting hydroelectric plant output and thermal unit maintenance, the remaining loads are served by the thermal units available to the system. The units are added to the system to minimize operating costs, which consist of fuel costs and variable Operating and Maintenance (O&M) costs for each unit. Fixed O&M costs do not affect the order in which units are committed. The unit operation logic determines how many units will be on-line each hour and which units are selected, with the 1 east expensive increment being added first. 201/174 5-9 D c c c D c [ D D D D D n u n n u c [J c n 5.4.4 OGP Optimization Procedure For each year under study, OGP evaluates system reliability to determine the need for installing additional generating capacity. If the capacity is sufficient to maintain the desired LOLP of one day in five years, the program calculates the annual production and investment costs and pro- ceeds to· the next year. lf additional capacity is needed, OGP adds units from. the list of suitable additions until the given reliability level is met. Among the issues considered in determining suitability is the size of a potential unit relative to the size of system load and cost. For a combination of units the program calculates annual costs for a 10-year 11 look-ahead 11 period and selects the most economical installation. The OGP logic utilizes an 11 overbuild 11 feature that develops annual costs over a 10-year period for combinations of units to determine if addi- tions of new units larger than those needed to meet reliability require- ments would reduce system costs. If a gel]erating unit is ·found to reduce system costs, it is selected and the cost calculations for that unit become part of the present worth of the expansion plan. 201/174 5-10 _j _j u .... J . . 5.5 1993-2020 SYSTEM EXPANSION 5.5.1 Transmission System Expansion Transmission system expansion for the With-Sus i tna expansion p 1 an has been studied in detail, and the costs have been estimated and included as part of the Project. Transmission system expansion costs associated with Non-Susitna expan-· sian plans are added as a separate item to those alternatives. To simplify the transmission system analysis, $220 million in transmission costs is assumed to be necessary for coal-fired and/or combined cycle plants at Beluga, while $117 million is assumed to be required for a coal-fired plant at Healy. These costs provide for new lines to the existing transmission system and for increased capacity within the present transmission system. A preliminary review of the year-by-year transmi~sion requirements for several specific Non-Susitna alternative expansion programs indicates that the cost estimates for the Non-Susitna transmission system are reasonably in line with, but slightly lower than, detailed year-by-year estimates. 5.5.2 Generation Expansion Using OGP, alternative expansion programs were developed for the period from January 1993 to December 2020 to estab 1 ish the 1 east-cost system 201/174 5-11 c c D c c [ n u n u n LJ c n u r u r L '' for that period with and without the Susitna Project. In the With- Susitna case, it was assumed that Watana would start operation in 1993 and Devil Canyon in 2002. This assumption was placed as input into the OGP model. All of the Susitna Project•s energy would be absorbed in the system by about the year 2020. In the Non-Susitna alternative plans, coal-fired and gas-fired thermal generation and. the Chakachamna Hydroelectric Project are . added to the existing units. Four basic Non-Susitna alternatives were developed to meet the forecast electrical demand. The plans are as follows: 0 0 0 0 Plan A includes natural gas-fired combined cycle plants, coal-fired steam plants, and combustion turbines. Plan .B includes only natural gas-fired combined cycle plants and combustion turbines. Plan C includes coal-fired steam plants and natural gas-fired combustion turbines. Plan D includes the Chakachamna Hydroelectric Project, coal- fired steam plants, natural gas-fired combined cycle and combustion turbines •. For the four plans, proven and economi ca lly-recoverab 1 e, undiscovered reserves of natural gas from Cook Inlet are assumed ~o be depleted by about 2007. At that time higher-priced natural gas for generation of 201/174 5-12 n : i L_j n J _j ' i _j J l _j electricity is considered to be available from undiscovered Cook Inlet reserves or from the North Slope via ANGTS or TAGS, for reasons more fully discussed in Chapter 4. The total costs for the Non-Susitna alternatives include all costs of fuel and the O&M costs of the generating units. In addition, the production cost includes the annualized investment costs of any plant? and transmission facilities added during the period. Costs common to all the alternatives, such as investment costs of facilities in service prior to 1993, and administrative and customer services costs of the utilities, are excluded. The annual costs from 1993 through 2020 are developed by the OGP model and are converted to a 1983 present worth. The long-term system costs {2021-2050) are estimated from the 2020 annual costs, with adjustments for fuel escalation, for the 30-year period. The With-Susitna and Non-Susitna expansion plans are then compared on the basis of the sum of present worths from 1993 to 2050. As discussed more fully in Chapter 6, present worth analysis is a means of comparing the value of benefits realized and costs incurred over different timeframes, discounted to the same base year. Such analyses recognize the fact that, at any given point in time, money that must be spent immediately has a "cost" greater than the same amount of money that must be spent later, since the funds to meet the future commitment can be invested and earn interest until the time they must be spent. 201/174 5-13 D < . < c D [ -c c c D _.J 5.6 REVIEW OF EXPANSION PLANS 5.6.1 With-Susitna Expansion Plan Exhibit 5.6 shows the yearly additions for the With-Susjtna expansion plan. When Wata·na begins operation ·in 1993, it is assumed that all Railbelt utilities will be interconnected and will share reserves. It is further assumed that the Bradley Lake and Grant Lake hydroelectric projects will be in operation by 1990, and scheduled retirements of existing plants will be delayed so that sufficient reserve will be available to meet the system demand prior to 1993. After 1993, a LOLP of one day in five years is used. As shown in Exhibit 5.6, before D~vil Canyon starts operation, three combustion turbines will be required to meet the reserve criteria. Ten years after Devil Canyon starts opera- tion, additiona 1 ·combustion turbines and one combined cycle plant will be required to replace retired units and to meet the load demand and reserve criteria. Based upon recent analyses, indicating that 1996 might be a more realis- tic date for commencement of full operation, an OGP analysis was done of the expansion plan which would be necessary under those circumstances. In that case, it is estimated that the reserve capacity prior to 1996 would become inadequate without additions of new capacity. To meet a LOLP of one day in five years, five combustion turbines would need to ·be added prior to 1996. The OGP program adds four combustion turbines in 1993, although in practical terms, these units would be added during the period 1984-1993. Eleven years after Devil Canyon starts operation, 201/174 5-14 c c u c c n I , LJ u 0 n u D c n ' " additional combustion turbines and one combined cycle plant would be required to replace retired units and to meet the load demand and reserve criteria. 5.6.2 Non-Susitna Expansion Plans Exhibit 5.7 shows the four Non-Susitna alternative plans. As the OGP program pegins in 1993 with only the existing Railbelt capacity {plus Bradley and Grant Lakes)., its first action, in order to meet the pro- jected load growth and maintain reliability criteria, is to add a large amount of capacity in 1993. Exhibit 5.7 shows Plan A beginning with a two-unit combined cycle plant in 1993. In a "real world 11 situation it could be expected that these two combined cycle units or a combination of three combustion turbines and one combined cycle would be added by utilities over the 1984-1993 time period. After 2000, coal-fired plants -are added and additional combustion turbines are brought on-1 ine in Plan A to replace those added in earlier years. This Plan was developed by the OGP process of comparing the economic advantages of various mixes including combined cycle, combustion turbine and coal-fired alterna- tives. The OGP program was also run with the forced addition of a coal-fired plant in 1993 and no combined cycle plants {Plan C), and with the use of only gas-fired generation {Plan B). Those expansion plans were found to be less economical since they resulted in higher cumula- tive present worths than Plan A for the period 1993-2050. As can be seen in Exhibit 5.8, which presents a summary of the alterna- tive expansion plans, Plans A and D are very close in having the lowest 201/174 5-15 c c c c c [ c D D D D c r Li [ c 1983 present worth costs, with Plan D being slightly less costly than Plan A. However, the environmental impacts assbciated with the Chakachamna· Project suggest that Plan D is less likely of bein9 imple- mented as an alternative to Susitna than Plan A. The latter plan, which r~lies upon bQth gas and coal units for future Railbelt generation is, therefore, selected as the least cost, practical Non-Susitna alternative for comparison with the With-Susitna expansion plan. Exhibits 5. 9 and 5.10 compare the contribution of energy production between the With-Susitna plan and Non-Susitna plan. As shown by these two exhibits, the Railbelt system will continue to be dominated by oil and gas-fired generation over the next 10 years. By 1993 a very large share of the gas and oil-fired generation can be replaced, if Susitna is in operation. Otherwise, natural gas will continue to be the principal source of fuel for the Railbelt through the end of this century. Beyond year 2000, coal-fired generation becomes more significant in the Non-Susitna plan. The economic conclusions which can be drawn from these expansion plans are presented in the following chapter. 201/174 5-16 c c n c c ~ L L n J LOCATION MAP LEGEND \1 PROPOSED DAM SITES ----PROPOSED 138 KV LINE -EXISTING LINES 20 0 20 ----SCALE IN MILES OCA TION MAP· SHOWING TRANSMISSION SYSTEMS EXHIBIT . 5. 1 60 ..: .-• ':l J l l l J 1 _j l J ] J --, EXHIBIT 5.2 TOTAL GENERATING CAPACITY WITHIN THE RAILBELT SYSTEM in Megawatts Abbreviations Railbelt Utility Installed Capacity (a) AMLP CEA GVEA FMUS MEA SES APA U of A TOTAL Anchorage Municipal Light & Power Department Chugach Electric Association Golden Valley Electric Association Fairbanks Municipal Utility System Matanuska Electric Association Seward Electric System Alaska Power Administration University of Alaska (a) Installed capacity as of 1982 at 0°F 311.6 463.5 221.6 68.5· 0.9 5.5 30.0 18.6 1122.8 (b) Excludes National Defense installed capacity of 101.3 MW (b) EXISTING AND PLANNED RAILBELT HYDROELECTRIC GENERATION Average Energy-GWh Firm Energx-GWh Existing Plants Proeosed Plants Existing Plants Proeosed Plants Eklut-Cooper Bradley Grant Eklut-Cooper Bradley Grant Month na (a) Lake (a) Lake (a)(b) Lake (b) Total na (a) Lake (a) Lake (a) (b) Lake (b) Total (30 MW) (16MW) (90 MW) (7 MW) (143 MW) Jan 14 4 31 2 51 13 4 35 2 54 Feb 12 3 28 2 45 12 3 32 2 49 Mar 12 3 28 1 44 9 3 24 1 37 Apr 10 3 23 2 38 10 3 26 1 40 May 12 3 26 2 43 11 3 31 1 46 June 12 3 27 2 44 8 2 21 2 33 July 13 4 30 2 49 9 3 22 2 36 Aug 14 4 32 3 53 8 2 23 1 34 Sept 13 3 28 3 47 9 3 23 2 37 Oct 14 4 31 2 51 9 3 25 1 38 Nov 14 4 31 2 51 8 2 22 2 34 Dec 14 4 32 2 52 12 3 31 2 48 Total .154 42 347 25 568 118 34 315 19 486 ~ II: H b:l (a) Source: 1982 Feasibility Study. H ~ (b) Assumed to be scheduled on line in 1988. \JI 0 w 3000 ~------~------~--------~------------- SYSTEM i CAPATCITY ~ 2000 · SUSITNA SYSTEM CAPACITY NON-SUSITNA 0 19~84~-----19~9-2------2-o~o-o-. ----.-.2-o~o-a·-._-----.2-0~1-e--~ YEAR ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE RAILBELT INSTALLED CAPACITY FEBRUARY 1984 EXHIBIT 5.4 n [j c l --, 1 EVALUATE ALL CHOICES LOAD FORECAST HOURLY BASED PEAKS & ENERGIES GENERATION SYSTEM EXISTING UNITS & ALLOWABLE TECHNOLOGIES IXMI8tT5.5 STUDY DATA FUTURE ECONOMICS & OPERATING GUIDELINES ~---------------~---------------~ OPTIMIZED GENERATION PLANNING lOGP) . ~ I EVALUATE RELIABILITY 1---. I ' SELECT UNIT SIZES & TYPES WITH "LOOK-AHEAD" ~ STUDY ~ CALCULATE OPERATING & INVESTMENT COSTS ALL YEARS USING "LOOK-AHEAD" -I .. CHOOSE LOWEST COST ADDITIONS & CALCULATE CURRENT YEAR'S COSTS I • RESULT ANT OPTIMUM EXPANSION PATTERN ~--- & DOCUMENT AT ION OF NEAR-OPTIMUM PLANS ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE OPTIMIZED GENERATION PLANNING (OGP) PROGRAM INFORMATtON FLOWS FEBRUARY 1984 ~ OUTPUT L ... J L. J L J 1.. ... J L ... J L J l . .J L .... .J l ....... J LL.JJ l .. ",J l ... J L J L J L .. J L, J l .... J C: .. J L .. ".U Year 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 (a) Pool Total Peak Ener¥ "(MQ) {GWh 915 4399 935 4492 955 4588 972 4670 989 4751 1005 4833 1023' 49l5 1040 4996 1065 5117 1090 5238 1114 5359 1140 5481 1165 5602 1200 5771 1234 5939 1269 6107 1305 6276 1339 6444 1373 6610 1408 6780 1444 6955 1481 7135 1519 7318 1558 7507 1598 7701 1639 7899 1681 8103 1724 8312 EXPANSION PLAN YEARLY MW ADDITIONS WITH-SUSITNA ALTERNATIVES Watana (1993) + Devil Canyon (2002) Watana (1996) + Devil Canlon (2002) Combustion Combined Total(a) Combustion Combined Total (a) Turbine &wle Susitna caeabilitl Turbine &wle Susitna caeabilitl {MW) ) {MW) {MW) {MW) ) {MW) {MW) 539 1433 336 1230 1432 1230 1362 84 1243 84 1358 539 1694 84 1376 1628 1350 1602 84 1434 1602 1433 1601 1433 1601 635 1926 635 2094 1926 2094 1926 2094 1905 2073 1905 2073 1905 2073 1905 2073 1905 2073 49 1954 49 2122 1809 1977 168 1799 1799 1799 420 1883 84 1883 84 1967 1870 237 2107 237 2023 2107 168 2107 2107 2107 84 2191 84 2107 2191 84 2191 84 2275 Includes existing generation plants less retirements. f:J ::I: H b;j H ., IJ1 . 0\ EXHIBIT 5. 7 EXPANSION PLAN YEARLY MW ADDITIONS NON-SUSITNA ALTERNATIVES Plan A Plan B Plan C Plan D Pool Total Combustible Combined Total (a) Combustion Combined Total (a) Combus.tion Total (a) Combustion Combined Total. (a) Year Peak (nerfY Coal Turbine ~cle Ca~abilitl Turbine ~cle Ca~abilitl Coal Turbine Ca~abilitl Coal Turbine Clcle (yd)o Ca~abilitl (HW) GWh (MiiT (MW) MW) (MW) (MW) MW) (MW) (MW) (MW) (MW) CMiiT (MW) (MW) . (MW) . 1993 915 4399 474 1369 474 1369 200 168 1263 237 195 1327 1994 935 4492 84 1453 84 1453 84 1347 84 1327 1995 955 4588 1382 1382 84 1360 84 1340 1996 972 4670 168 1462 168 1462 84 1356 84 1336 1997 989 4751 84 1480 84 1480 200 1490 84 1354 1998 1005 4833 1454 1454 1454 1412 1999 1023 4915 1454 1454 1464 1412 2000 1040 4996 200 1653 84 1537 1463 1411 2001 1065 5117 1653 1537 1463 200 1611 2002 1090 5238 200 1711 237 1632 200 1522 84 1553 2003 1114 5359 '1711 1632 1522 1553 2004 1140 5481 1711 1632 84 1606 200 1753 200.5 1165 5602 1691 84 1696 1585 1732 2006 1200 5771 200 1891 1696 1585 1732 2007 1234 5939 1891 84 1780 200 1785 200 1932 2008 1269 6107 200 2091 1780 1785 1932 2009 1305 6276 2091 1780 1785 1932 2010 1339 6444 2091 237 2017 1785 1932 2011 1373 6610 200 2146 84 1956 200 1840 1788 2012 1408 6780 1958 237 2015 168 1830 474 2084 2013 1444 6955 1968 2015 400 2062 200 2284 2014 1481 7135 84 1968 84 2015 1978 2284 2015 1519 7318 200 2155 237 2239 84 1965 2187 2016 1558 7507 84 2071 84 2155 168 2049 2103 2017 1598 7701 168 2155 168 2239 2049 200 2219 2018 1639 7899 2155 2239 2049 200 2335 2019 1681 8103 84 2239 2239 84 2133 2335 2020 1724 8312 200 2439 168 2323 84 2217 2335 (a) Includes existing generation plant less retirement. L . J L. L ... J l J l J l J L .J L.J L.~.J l." •... J l ..... J l ... J L J J L ... J [L J l . ~J J L ... " ... .J SUMMARY OF RAILBELT SYSTEM GENERATION MIX IN YEAR 2020, ECONOMIC COST OF ENERGY, AND CUMULATIVE PRESENT WORTH NON-SUSITNA ALTERNATIVES WITH-SUSITNA ALTERNATIVES Watana (1993) Watana (1996) PLAN A PLAN B PLAN C PLAN D Devil Canyon (2002) Devil Canyon (2002) OPG 1D LXEl LRA9 LTKl LOG9 LCM3 LMG5 2020 Capacity -MW Coal 1400 0 1400 1200 0 0 CT 420 756 672 84 588 672 CCCT 474 1422 0 711 237 237 Hydro 143 143 143 143 143 143 Susitna 0 0 0 0 1223 1223 Chakachamna 0 0 0 195 0 0 Total 2437 2321 2215 2333 2191 2275 2020 Reliabi 1i ty Peak Demand 1724 1724 1724 1724 1724 1724 % Reserve 41.5 34.7 28.6 35.4 27.1 32.0 LOLP -D/Y 0.025 0.124 0.077 0.082 0.085 0.085 Economic Cost of Energy (mills (kWh) 1993 35.48 35.48 40.20 38.64 53.10 39.87 2010 60.12 72.90 58.02 53.13 44.32 45.45 2020 63.65 91.01 62.37 59.05 46.64 47.12 Annual Cost ($ X 10 6 ) 2020 529.2 756.5 518.4 516.6 387.7 391.7 Cumulative Present Worth ($ x 106) 2020 3873 4448 3962 3854 3658 3633 t:z:l :><: 2050 6791 8945 6823 6676 5730 5725 :::t: H b:l H ~ VI . 00 --, EXHIBIT 5.9 10~------~--------~--------~------~ WATANA WATANA AND DEVIL CANYON LEGEND ~ OILANDGAS-FIRED l\\\::::::_,:;'f_'J COAL-F! RED 2000 YEAR 2020 ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE WITH -SUSITNA ALTERNATIVE -ENERGY DEMAND & DELIVERIES FEBRUARY 1984 c c [ [ [ [ [ c c 0 [ [ c [ [ [ [ [ [ i ~ § -6~-------+------~~----~~~ I z 0 ..... <( a: w ffi 4~----~~~~~~~~~ ~ ~ ~ a: w z w EXHIBIT 5.10 1980 2000 YEAR 2020 LEGEND ~ OIL AND GAS-FIRED COAL-FIRED ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE NON -SUSITNA ALTERNATIVE -ENERGY DEMAND & DELIVERIES FEBRUARY 1984 ~ u 1: L_J D c c c c D n I • u 1 I L.J ., 6.0 ECONOMIC FEASIBILITY 6.1 INTRODUCTION Based upon the preceding five chapters, this Chapter summarizes the methodology and key variables used to analyze the economic feasibility of the Susitna Project. The conclusions as to the economic feasibility of the Project are then presented. Specifically, Section 6.2 contains a discussion of the methodology used in the economic analysis. Section 6.3 contains the results of the economic analysis expressed in terms of benefit-cost ratios and net benefits. . The remaining two ·sections contain information on the threshold and sensitivity analyses performed to measure the impact on economic feasibility of changing key variables. 6.2 METHODOLOGY The economic analysis compares the costs of alternatives during the planning period 1993-2050. The year 1993 was presented in the FERC License Application as the earliest date of Watana operation. Recent analyses of the licensing and construction schedule, however indicate that a 1996 date for Watana might .be more appropriate for planning purposes. The results of the analyses indicate that the difference in the cumulative present cost worth of the Project between a 1993 and 1996 Watana on-line date is approximately $5 million. This difference is within the range of error of the modeling process and, therefore, no 202/169 6-1 0 c c c c Q [ 0 0 0 0 c [ c 0 c c [ c distinction is drawn in the economic section of this Update between a Watana on-1 ine date of 1993 and 1996. As noted in Chapter 7, a 1996 date has been assumed for purposes of developing finance plans. Exhibit 6.1 summarizes the principal economic parameters that were used in the economic analysis. The economic 1 ife of each generating plant type used in the economic analysis is based on 20 years for combustion turbines, 30 years for combined cycle and steam turbines, and 50 years for hydroe 1 ectri·c p 1 ants. Transmission 1 i nes have an economic 1 i fe of 40 years. The With-Susitna and Non-Susitna alternative expansion plans discussed in detail in Chapter 5 are utilized here to assess the economic benefits of the Susitna Project. Benefits are based on the difference between the costs of the least-cost Non-Susitna alternative and the With-Susitna alternative {"net benefits"). For the Susitna Project to be considered economically feasible, the benefit/cost ratio of the With-Susitna alternative over the Non-Susitna alternative must be greater than one. The Benefit/Cost {B/C) ratio is determined using the following formula: Total Present Worth of System Expansion B I C = Plan Without Susitna {benefits) Total Present Worth of System Expansion Plan With Susitna {costs) Costs for each expansion alternative include three main items: invest- ment, fuel, and O&M costs. Investment costs include construction costs {described in Chapter 3), and interest on funds used during construc- tion. A real interest rate {adjusted for inflation) of 3.5 percent was 202/169 6-2 0 c c c 0 c c c 0 0 D D c c c 0 D c D used in estimating interest during construction. Fuel costs are for the coal or gas used yearly in the thermal plants (as described in Chapter 4). O&M costs also are expended each year. To determine the benefit/cost ratio and net benefits, all costs (or benefits) must be adjusted to a comparable present worth. Costs are adjusted to their present worth by discounting, which gives costs in earlier years more weight than costs in later years. This concept is based on the theory that money, until it is needed to pay costs, can be invested profitably. The 3.5 percent discount rate used in this economic analysis was provid- ed by a survey of financial experts and economists. The total present worth of each expansion plan was obtained. by calculating the present worths of each future annual cost. It is important to note that costs ,. are being evaluated; hence, the alternative having the lowest present worth is the most economically attractive. 202/169 6-3 c D c c c c 0 0 0 0 c c c 0 u c c D 6.3 RESULTS OF THE ECONOMIC ANALYSIS The results of the economic analysis of alternate system expansions are presented in Exhibit 6.1 and summarized in Table 6.1. As reflected in Table 6.1, the total present worth of the With-Susitna expansion plan is $5.73 billion for the period 1993 to 2050. The total present worth of the Non-Susitna system expansion plan is $6.79 billion for the same peri ad. Thus, the With-Sus i tna expansion p 1 an has a net benefit of $1.06 billion and a benefit/cost ratio of 1.19. Total Present Worth Net Benefits Benefit/Cost Ratio Table 6.1 RESULTS OF ECONOMIC ANALYSIS {1983 $billion) With-Susitna Expansion Plan 5.73 1.06 1.19 (N/A indicates not applicable) Non-Susitna Expansion Plan 6.79 N/A N/A As shown on Exhibit 6.2, the annual costs of the With-Susitna plan are less than the annual costs of the Non-Susitna plan after year 2003. That year represents the "cross-over" point from which time the With- Susitna plan's annual costs drop below those of the Non-Susitna plan. Thus, in year 2020, the With-Susitna annual costs are about $162 million (1983 $) less than the Non-Susitna costs. The total cumulative present worth of the With-Susitna plan is less than the Non-Susitna plan after year 2010. 202/169 6-4 c c c c 0 [ 0 0 0 fJ 0 0 c c 0 c 0 c D With the potential design refinements described in Chapter 3, the construction costs of the Susitna Project could be reduced by about 8 percent. These construction cost savings would reduce the total present worth costs of the With-Susitna alternative by about six percent, and the net benefits would increase from $1.06 billion to about $1.36 billion if such design refinements are ultimately implemented. 6.4 THRESHOLD VALUES OF SUSITNA JUSTIFICATION A threshold value is that value of a parameter at which the total present worth of the With-Susitna expansion plan is equal to that of a Non-Susitna plan. That is, the benefit/cost ratio is equal to one and there are zero net benefits. Under such circumstances the Sus i tna Project could not be deemed to be more economically feasible than a Non-Susitna alternative, although there might be other reasons justify- ing its construction. A threshold value was computed for the following four key parameters: 0 0 0 0 Oil Price Forecasts Discount Rate Construction Cost Estimate for Watana Development Real Interest During Construction 6.4.1 World Oil Price Forecast World oil price forecasts greatly influence the economics of the With- Susitna alternative; therefore it is necessary to identify the threshold 202/169 6-5 [ [ c n L 1 ) 'l 0 value of forecast oil prices. The threshold forecast oil price is very near the mean oil price forecast by DOR in June, 1983. As noted previ- ously, DOR has substantially raised its oil price forecasts since that time and use of this approximation of a threshold case is not intended to tie DOR to outdated forecasts; it is used because it approximates a threshold oil price only. It is important to recognize that the threshold oil price forecast is a price 1 i ne rather than a single va 1 ue, and the 1 i ne does not have a constant rate of change. The critical oil price is, however, $27.45 per barrel (in 1983 $) in 1999. This price was assumed to escalate at 1.5 percent for the years beyond 1999. Should all reliable oil price forecasts drop to this level, serious questions might be raised as to the economic viability of the Project. 6.4.2 Discount Rate The discount rate at which the present worth of the With-Susitna expan- sion plan becomes equal to that of the least-cost Non-Susitna expansion plan is 5.3 percent. That is, should the non-inflationary value of money be greater than 5.3 percent, there might be no economic advantage to the With-Susitna expansion plan. 6.4.3 Construction Cost Estimate for Watana Development The estimated construction cost of the Watana Development is $3.75 billion (January 1983 prices). The threshold value for Watana 202/169 6-6 0 c c c c c c c c 0 0 c c [ c u D c c construction cost, using a 3.5 percent discount rate, is $5.0 billion. Hence, if the construction cost of the Watana Development were to increase by 33 percent, the cumulative present worths of the With- Susitna and Non-Susitna expansion plans would be equal. 6.4.4 Real Interest During Construction A real (adjusted for inflation) interest rate of 3.5 percent was used to calculate interest during construction in the economic analysis. The threshold value for real interest was estimated to be 7.4 percent. That is, the real interest rate for Watana construction funds would have to increase to 7.4 percent in order for the With-Susitna present worth to be equal to the Non-Susitna alternative•s present worth costs. 6.5 SENSITIVITY ANALYSIS ·Economic ana lyses require numerous assumptions. Typically, a single value (i.e., a best estimate) for a key parameter is used in the compu- tations, yet that single value lies within a range of possibilities. To evaluate the effects on Project economics of such a selection, economic analyses are often performed using a range of possible values for each of several key parameters. This analysis is termed 11 sensitivity analy- sis, .. as its objective is to determine the sensitivity of the results of economic analyses to assumed changes in one or more key variables. Sensitivity analyses were performed in preparing this Update for Cook 202/169 6-7 D c c c c c c 0 0 0 c c c [ 0 c [ [ [ Inlet gas supplies, real escalation rates of fuel costs and utilities' demand forecasts. 6.5.1 Cook Inlet Gas Supply As explained in Chapter 4, the DNR forecast of Cook Inlet gas supply was used in the economic analysis, However, if an unlimited supply of Cook Inlet gas is assumed and it is further assumed that its price will follow world oil prices, the cumulative present worth of Non-Susitna Plan A would decrease from $6791 to $6510 million. -The resulting bene- fit/cost ratio of the With-Susitna plan would decrease from 1.19 to 1.14. Hence, the exact estimate of undiscovered Cook Inlet reserves does not materially effect the economic analysis. 6.5.2 Real Escalation of Fuel Costs The sensitivity of the Non-Susitna expansion plan to coal price esca- lation was analyzed using the January 1983 coal prices of $1.86 per MMBtu for Beluga and $1.72 per MMBtu for Nenana. A scenario of zero escalation on the price of coal for the entire planning period of 1983 through 2050 was analyzed, and the results are presented in Table 6.2. As indicated there, the With-Susitna plan still has a positive bene- fit/cost ratio. 202/169 6-8 D c c c c [ c 0 n '' u q I~ u n lJ J u Total Present Worth Net Benefits Benefit-Cost Ratio Table 6.2 SENSITIVITY ANALYSIS USING ZERO PERCENT COAL ESCALATION (1983 $ x billion) With-Susitna Expansion Plan Non-Susitna Expansion Plan 5.73 0.11 1.02 5.84 The Susitna Project would supply about 80 percent of the Railbelt areas electricity requirements by the year 2020. Therefore, long-term fore- casts of fuel prices and escalation rates critically influence Project economics. A special analysis of long-term oil prices was prepared by SHCA ~uring the preparation of the License Application to support the estimation of long-term system costs (2021 -2050). A real annual escalation rate of 1.5 percent was estimated for the period 2021 through 2030 and 1.0 percent for the period 2030 -2050 •. Escalation of the natural gas price was assumed to follow that of oil. A sensitivity analysis was conducted to compare the net benefits of the With-Susitna expansion plan against the least-cost Non-Susitna expansion plan with no allowance for real escalation of fuel costs after 2020. The results of that analysis are summarized in Table 6.3. 202/169 6-9 c c c c c [ c D D n u n u n u u Table 6.3 SENSITIVITY ANALYSIS OF REAL ESCALATION OF FUEL COSTS BEYOND 2020 Present Worth of System Costs (1983 - $ billion} With Fuel Without Fuel Escalation Escalation System 1993-2021-1993-Net 2021-1993- Ex~ansion 2020 2050 2050 Benefit 2050 2050 Non-Susitna 3.87 2.91 6.79 2.72 6.59 With-3.65 2.07 5.73 1. 06 1. 99 5.65 Susitna As indicated, without fuel escalation, the net benefits of the With- Susitna plan would decrease from $1.06 billion to $940 million. 6.5.3 Utilities' Forecast The Railbelt utilities annually produce 20 year forecasts for their respective markets. As shown on Exhibit 2.22, the forecasts indicate that energy generation is expected to increase from 3105 GWh in 1983 to 7662 GWh in 2001. For purposes of a sensitivity analysis, the utili- ties' forecasts were extended to 2020 using the same annua 1 rate of electrical demand increase after 2001 as obtained from the Power Author- ity forecast. All other parameters were kept constant to those used in the Power Authority analysis. Table 6.4 presents the results of the economic analysis using the utilities; forecasts. The OGP analysis of the systems necessary to meet the utilities' fore- cast demand shows that construction of Susitna would replace a signifi- cant amount of thermal generation capacity. Under the Non-Susitna 202/169 6-10 Net Benefit .94 c c c c c [ [ c 0 D 0 0 c [ [ c- c c [ expansion plan, two combined cycle plants (237 MW each) are constructed in 1993. Gas turbines are then added until 1998. After year 2000 a total of 10 coal-fired plants are constructed. With Susitna, the combined cycle plants are delayed (until 1995 and 2000) with only three coal-fired plants installed between 2012 and 2017. Calculating the cumulative present worth costs of the expansion plans indicates that the With-Susitna expansion plan would have a net benefit of $2.96 billion assuming load growth as predicted by the utilities. That figure is $1.90 bill ion greater than that for the With-Susitna expansion plan using the Power Authority estimate of electrical demand. The Susitna benefit-cost ratio using the utilities forecast would increase to 1.45. Table 6.4 ECONOMIC ANALYSIS USING UTILITIES' FORECAST (1983 $ x billion) Present Worth of Annual Costs Net Benefits Benefit/Cost Ratio With-Susitna Non-Susitna Expansion Plan Expansion Plan 6.57 2.96 1.45 9.54 The conclusion which can be drawn from this analysis is that if elec- trical demand is greater than the forecast produced by the models used in this Update, the economic benefits of the Susitna Project increase 202/169 6-11 0 c c c D [ c c D 0 c c [ [ c c C· c c accordingly. Conversely, if el ectri ca 1 demand is 1 ower than the Update forecast, a reevaluation would be necessary as to the appropriate timing of the Watana Development. 6.6 CONCLUSIONS Although stated in various terms throughout this Chapter, the conclusion of the OGP analysis of Railbelt expansion plans, comparing the With- Susitna plan (which includes some thermal generation) against Non- Susitna alternative plans (which includes minor amounts of hydroelectric power), is that the Susitna Project would have a positive benefi.t/cost ratio (a ratio greater than 1.0) over the planning period of 1993-2050. Stated simply, using the most current data, it is the conclusion of this Update that the Project remains economically viable. 202/169 6-12 D c c c c [ [ c 0 0 ' 0 0 [ c [ c c c c EXHIBIT 6.1 PRINCIPAL ECONOMIC PARAMETERS 1. All Costs in January 1983 Dollars 2. Base Year for Present Worth Analysis: 1983 3. Electrical Load Forecast: 1983 to 2020 4. Discount Rate: 3.5 percent 5. Inflation Rate: 0 percent 6. Economic Life of Projects: Combustion Turbines: 20 years Combined Cycle Turbines: 30 years Steam Turbines 30 years Hydroelectric Projects 50 years Transmission Lines 40 years 7. Annual Fixed Carrying Charges 20-year 30-year 40-year 50-year Life Life Life Life Cost of Money 3.50 3.50 3.50 3.50 Amortization 3.54 1.94 1.18 0.70 Insurance 0.25 0.25 0.25 0.10 Total 7.29 5.69 4.93 4.36 '1 L_J c lj L: c YEAR n L_; 1993 1994 [ 1995 1996 1997 I' 1998 Lj 1999 2000 2001 c 2002 2003 2004 n 2005 [: 2006 l_j 2007 n 2008 2009 u 2010 2011 r] 2012 l_; 2013 2014 r' 2015 u 2016 2017 ~, 2018 -2019 2020 2050 ~-· ,..., L-" 11 u n Li r i u ~~ ,__; RESULTS OF THE ECONOMIC ANALYSIS OF SYSTEM EXPANSION PLANS ( 1983 $ million) EXHIBIT 6.2 Annual Cost Cumulative Present Worth Non-Susitna With-Susitna Non-Susitna With-Susitna 156.0 215.0 110.6 152.4 165.3 216.9 223.8 300.9 172.1 221.7 337.7 447.6 184.7 228.7 455.8 593.9 194.6 233.5 576.0 738.1 201.5 237.3 696.3 879.8 208.7 243.6 816.7 -1020.2 229.3 248.1 944.4 1158.5 237.3 252.9 1072.2 1294.6 261.5 267.7 1208.2 1433.8 267.1 267.7 1342.4 1568.4 275.5 267.7 1476.2 1698.3 282.8 267.3 1608.9 1823.7 314.2 265.3 1751.3 1944 .o 351.9 265.3 1905.4 2060.2 368.8 265.3 2061.4 2172.4 377 .I 268.1 2215.6 2382.1 387.7 265.3 2368.7 2386.9 406.3 267.4 2523.8 2488.9 415.7 277.7 2677.0 2591.3 425.8 281.9 2828.7 2691.8 437.4 298.9 2979.3 2794.6 455.9 304.0 3130.9 2895.8 464.7 322.4 3280.2 2999.3 479.0 328.8 3429.0 3101.4 492.0 332.2 3576.5 3201.1 512.1 346.1 3725 .o 3301.4 529.2 367.3 3873.1 3404.3 619.4 420.0 6790.7 5730.1 0 c c c c [ c 0 [J 0 c 0 c c 0 c c c c 7.0 FINANCING OPTIONS 7.1 INTRODUCTION The -purpose of this Chapter is to explore the relative merits of various funding sources and develop financing options for the Susitna Project. Implementing financing options for the Project will require certain policy decis-ions and commitments by Alaska decision-makers, including the Legislature. One purpose of this assessment, therefore, is to bring thes-e necessary decisions to the attention of the Legislative and Executive branches of the State of Alaska. Based upon continuing review and analysis conducted by the Power Author- ity since the filing of the July 11, 1983 FERC License Application, several potential: funding sources have been identified. In this Chap- ter, these funding sources are reviewed on the basis of legal, practical and cost of energy considerations. The legal review examines the existing requirements, apparent constraints and legislative action that should be taken into account to utilize each of these sources. The practical considerations address the marketability and similar factors associated with each source. The cost of energy analysis is utilized to determine the size and mix of the proposed funding sources in order to give assu ranee tha_t the projected who 1 esa 1 e cost of Sus i tna energy under the selected financing options is competitive with the cost of energy from the least-cost thermal alternative in the first years of operation. 161/169 7-1 c [ c c c [ c 0 c 0 0 c c c c [ [ [ c After a review of the above considerations., two financing options are selected for detailed analysis as the most feasible approaches to the financing of the Project. These options are: Option A: Tax-Exempt Revenue Bonds combined with State Equity and Rate Stabilization Fund. Option B: REA Guaranteed Loan and Tax-Exempt Bonds (SO/SO) combined with State Equity and Rate Stabilization Fund •. During the past several months the Power Authority has been conducting extens-ive negotiations with the intended purchasers of power to be generated by the 11 Four Dam Pool 11 which is comprised of the fall owing hydroelectric projects in various stages of completion: (1) Lake Tyee near Petersburg and Wrangell, (2) Solomon Gulch near Valdez, (3) Swan Lake near Ketchikan, and (4) Terror Lake near Kodiak. These negotia- tions and related hearings on necessary 'legislative changes are in process as the first maturity date of interim construction notes becomes imminent. It should be noted that the State•s ability .to deal with the Four Dam Pool situation will largely determine investor willingness to participate in the Susitna bond financing program. Future investors will respond favorably to a coordinated response by the Power Authority, the utilities and the Legislature to the need to refund the short-term indebtedness for the Four Dam Pool. By the same token, potential Susitna bond purchasers will long remember any failure by these Alaskan entities to solve the problem and avoid delays in retiring the short- term notes. 161/169 7-2 u c n LJ n I , ~~) 1 LJ l u l j J 'J I "-u 'l I j u 'l I ' ._; n u 7.2 GENERAL APPROACH AND PROCEDURES A fundamental ass~mption in the analysis of Susitna financing options is that the wholesale cost of energy from the Project must be competitive with the wholesale cost of energy from the least-cost Non-Susitna Alternative in the first years of operation. Generally, the Rail belt uti 1 ities are not expected to enter into contracts to purchase Susitna generated power if the rates are significantly higher than the rate that would be available from alternative generation sources. Therefore, each of the options examined below is constrained to give assurance that the wholesale cost of Susitna energy is competitive with the least-cost thermal alternative during its firs.t years of operation. Because of the projected long-term benefits of the Susitna Project, it has been suggested that the Rai)belt utilities might be willing to pay a premium price for Susitna energy over a short period of time. While no definitive analysis has been made, the hypothesis of the "willingness to pay" of the Railbelt utilities suggests that Susitna energy might con- ceivably be priced at a wholesale rate as much as 20 percent greater than the least-cost thermal alternative during the early years· of operation and still be marketable in the Railbelt. Ii is estimated that the resulting retail cost of energy would be approximately 10 percent greater, after con~idering costs of distribution, administration, trans- mission and other costs. Therefore, a sensitivity analysis was run for both of the financing options examined herein to allow wholesale Susitna costs to be 20 percent greater than the thermal alternative cost during the first years of Susitna operation. Should such premium rates be 161/169 7-3 0 c c [ c c [ c 0 0 c c [ [ c c [ [ [ agreed upon with the utilities, it would allow a significant reduction in the necessary amount of State assistance (see Table 7.5} •. Before the allowable wholesale cost of Susitna energy can be determined, it is first necessary to develop. the cost of energy for the least..:cost thermal alternative. The cost of energy o-f various thermal alternatives was computed from Optimum Generation Planning ("OGP"} output summaries. The least~cost thermal generation scenario described in Chapter 5 results in an average cost of energy in the Railbelt of 11.2¢ per kWh in the first year of operation of Watana {1996). This figure assumes that the thermal alternatives would be financed by the individual utilities using 75 percent REA 1 oans and 25 percent tax-exempt revenue bonds on the assumption that the State will not provide equity funding or loan subsidies for thermal generation alternatives. 7.3 POTENTIAL FUNDING SOURCES There are several different sources of funds potentially available to finance the Susitna Project. Because of the large size of the financing requirements of Susitna, however, one source may not be able to provide all necessary funding. The financing options presented in Section 7.5, therefore~ draw on several funding sources. This Section discusses in general terms the types of funding sources potentially available to Susitna. 161/169 7-4 0 c D c c c c D 0 R G 0 0 n I ~ u q I • u C· 7.3.1 State Equity Contributions The State Legislature cou'ld appropriate money from the s.tate•s General Fund to be utilized in the construction of the Susitna Project •. The appropriation could take the form of a direct grant or a loan to the Power Authority or some combination of the foregoing. All financing options which have seemed feasib)e or possibly feasible over the course of the on-going review of Susitna have involved large levels of State assistance. It is clear that Susitna will have to be one of the State's highest capital funding priorities in order to achieve the required equity contribution. Precise estimates of the required amount of State funds vary among the financing options analyzed. A continuing commitment to provide State funds in the form of grants or loans over a period of several years to the Susitna Project would be required. A legal constraint in making this commitment is Section 7, Article IX, of the Alaska Constitution, which prohib·its one Legislature from making binding commitments on future Legislatures through a prohibition against dedi~ating funds. Thus, although State monies might be provided by one Legislature, there is no assurance that continued funding would be approved by subsequent Legislatures. This lack of legislative authority to make long-term commitment of grants or loans would impose considerable financial risk on the Project, a risk which would probably be perceived by other potential investors as too great, thus rendering necessary non-State funding more expensive, if not impossible. 161/169 7-5 c [ [ c [ r~ L [ c n I: u ., I ; u .__) . . A means of reducing tne investor's risk and establishing long-term State funding for the Susitna Project would be the proposed Major Projects Fund. As proposed, this fund would operate in a manner similar to the current Permanent Fund ... An amendment to the Alaska Constitution would provide for setting aside 10 percent of the State's mineral revenues i·nto a speci a 1 account which would be ava i 1 ab 1 e for energy deve 1 opment projects in the State. In broad philosophical terms, it would be the goal of this fund to .utilize a portion of the State's wealth derived from non-renewable energy sources to fund energy projects (either through equity contributions, rate stabilization .funds or both) which utilize renewable energy, such as hydroelectric, geothermal, and solar projects. Grants or loans from the Major Projects Fund to construct the Susitna Project would be consistent with this stated philosophical goal. One advantage of this approach is that· it would provide non-State investors in the Susitna Project with assurance that, to the extent of available pledged resources ("a dedicated revenue source"), the State would fulfill its funding obligations to the Project, thus eliminating the fear that future Legislatures would not authorize sufficient funds. Exhibit 7.6 indicates the portion of this special account which would be required for Susitna under both financing options analyzed. 7.3.2 Alaska Permanent Fund Another possible financing option is the utilization of the investment capacity o:f the Alaska Permanent Fund, which was created by a 1976 amendment to the State Constitution. It is a separate fund composed of the revenues from at least 25 percent of all annual mineral lease ren- 161/169 7-6 __) _) __) _) 1 -~ _) tals, royalties, royalty sale proceeds and federal mineral payments received by the State, plus earnings on these payments. An Alaska Permanent Fund Corporation was established in 1980 to provide a means of conserving this portion of the State's revenues, derived from mineral resources, to benefit future generations of Alaskans. The Corporation is a public corporation organized within the Department of Revenue whose primary purpose is to manage and invest the Permanent Fund assets. A Board of Trustees appointed by the Governor has the responsibility of. ensuring that judgment and care are applied in investment of these assets, considering the "probable safety of capital as well as probable income." The statutory obligations for management and investment of the Fund's assets are specific, as are the types of investments and the designated percentage of the Permanent Fund which may be invested in each type of investment. The Permanent Fund has been suggested by some as a potential source of financing for the construction of the Susitna Project, either as a source of loans through purchase of bonds or as a means of guaranteeing other forms of financing with the view that the construction of the Susitna Project is a means of preserving the State's mineral resource base. If Susitna is not constructed, natural gas, diesel fuel and other fossil fuels will probably be used for generation which otherwise would have been provided by Susitna to meet electric power demand within the State. In this context, use of the Permanent Fund as a financing source for Susitna could be viewed as consistent with the purpose of the Fund, i.e., "conservation of the State's revenues from mineral resources to benefit generations of Alaskans." 161/169 7-7 L_l I , L__j I c_) '1 L "'] I::; u 1 -~ ._j u I • u Pursuant to Articles IX and XV of Alaska•s Constitution, the Permanent Fund • s principal may be used only for 11 income-providing investments specifically designated by law ••• 11 The assets may thus presently be invested only in specific types of government securities, corporate stocks and bonds and real estate, all at market rates. Investment in below-market yield or no-income investments with Fund assets (even though long-term benefits could be argued) would probably require a Constitutional amendm~nt in light of the conservative vi.ew typically given to the types of permissible investments in such a Fund. Further consideration of this funding source has not been given because: (1) for this source to be competitive with Option A for the financing of Watana, an interest rate of approximately 10 percent per annum would be required assuming the same approximate level of State .equity; current yields available to the Permanent Fund are approximately 3 percent per annum greater for similar maturities and credit risks inasmuch as the Permanent Fund has no incentive to acquire tax-exempt debt instruments, and (2) in order to fully fund the financing of Watana by loans from the Permanent Fund (without any State equity), an interest rate of approxi- mately 3 percent per annum would be required, which is approximately 10 percent per annum below yields otherwise available to the Pennanent Fund. 7.3.3 Rate Stabilization Fund Although not a form of financing in and of itself, a Rate Stabilization Fund (RSF) is a means of allowing other sources of financing for Susitna to be used more effectively by holding down energy costs during 161/169 7-8 u .., 1 1 ; l u I : Li co i • u I u Susitna • s early years of operation when it is most difficult for hydro costs to be competitive with thermal alternatives. A· RSF could be funded by either the issuance of additional bonds, by State appropria- tions, or from a dedicated revenue source such as the proposed Major Projects Fund. Bond proceeds are commonly used for this purpose, often in the form of capitalized interest. The RSF concept was developed by the Power Authority for the Four Dam Pool financing plan • . The RSF is a rate subsidy during the early years of operation. The cost of energy from the Susitna Project, based on a given. financing plan, would be offset by transfers made to the accounts of the Railbelt utilities by the bond Trustee. This would result in a projected net cost of Susitna energy equivalent to the projected Non-Susitna Alterna- tive in the early years. The cost of Susi tna energy after the RSF period would be expected to be less than the least-cost thermal energy alternative during Susitna•s latter years of operation, because of the high level of fixed costs associated with hydro. Because the RSF provides State assistance in the time period most needed, it reduces the level of permanent commitment of State funds required in the form of equity. The RSF concept is included in the base case of each financing option. As in the equity contribution approach, the RSF could present problems of continuity. Although one Legislature may agree to an RSF program, there is no assurance that subsequent Legislatures would provide further appropriations to an RSF which would be necessary over a period of years 161/169 7-9 'l j if the initial appropriation was not adequate. For purposes of analysis of the financing options, it is assumed that RSF funds would be provided as needed by a dedicated revenue .source not subject to Legislative approval. A sensitivity analysis was made assuming that the under- writing standards of any debt market would require that the full amount of rate stabilization funds needed over a period of years be provided "up front" before the bonds could be sold. 7.3.4 Tax-Exempt Debt Public power projects are commonly financed with tax-exempt debt. This type of debt can be an obligation of a state, or political subdivision of a state, the interest on which is generally exempt from Federal income taxes. This tax exemption enables states· and their political subdivisions to issue debt at lower interest rates than would otherwise be the case. For example, long-tenn municipal bonds for public power projects were marketed in January 1984 at interest rates of 10 percent to 10.5 percent, whereas taxable corporate bonds of the same maturity and credit rating were being sold at interest rates of approximately 13 percent to 13.5 percent. Public power projects are ~enerally financed on a tax-exempt basis with revenue bonds, as distinguished from general obligation (11 G.O.") bonds. In the case of the Susitna Project, revenue bond financing would mean that the first and primary source of payment for the principal and interest on those bonds would be the revenues derived from the Susitna Project itself. G.O. bonds, on the other hand, are backed by the full 161/169 7-10 1 l '---' '1 l-_J I '· u u '1 u u u 0 faith and· credit, including the taxing power, of the issuing govern- mental entity. Revenue bonds have two principal advantages over G.O. bonds; one being fewer procedural steps prior to bond issuance, and the other that revenue bonds do not directly affect the G.O. rating of a state. However, under _the Internal Revenue Code (the 11 Code 11 ), not all obliga- tions of states and their political subdivisions are exempt from Federal income taxes. If the proceeds of otherwise tax-exempt bonds are made available to 11 non-exempt persons 11 (entities other than states, their political subdivisions and charitable organizations described in Section 501 (c)(3) of the Code), those bonds could be classified as Industrial Development Bonds (11 10Bs 11 ). The Internal Revenue Service considers bonds to be lOBs if the bond proceeds are expected to be used in the trade or business of a non-exempt person and to be secured by payments made by such non-exempt person. Interest on lOBs is not exempt from Federal income taxes unless the size of the bond issue is below a certain level (far smaller than the needs of the Susitna Project) or unless the bond proceeds are used to fund certain types of exempt facilities (which in the case of hydroelectric projects include only projects for which the output is used in no more than two counties or their political equivalent). In other words, since Susitna does not meet the two-county rule test, if a portion of the bonds issued to . finance the Susitna Project met the definitional test and were classi- fied as lOBs, under current Federal laws, the interest on that portion of the bonds deemed to be lOBs would not be exempt from Federal income taxes and the cost of financing the Project would be correspondingly higher. D c c c c c c 0 0 0 0 c c c 6 u 0 c· c It· is expected that roughly 75 percent of the energy from the Susitna Project will be sold to REA cooperatives. These cooperatives, while genera 11 y exempt from Federa 1 income taxes, . are not inc 1 uded in the definition of 11 exempt persons 11 under Section 50l(c}{3) of the Code. The REA cooperatives would accordingly be classified as 11 non-exempt per- sons ... The Treasury Regulations and IRS rulings dealing with power generating facilities contain detailed rules for determining whether the sale of energy to 11 non-exempt persons 11 will cause bonds issued to finance those facilities to be classified as lOBs. In very general terms, such bonds waul d be lOBs if 11 non-exempt persons 11 entered into power sales ag-ree- ments covering more than 25 percent of the capacity of the power· gene- rating facilities, and those contracts required the 11 rion-exempt persons 11 to make payments covering a pro rata portion of debt service regardless of whether any power was in fact delivered. This type of power sales 'contract (known as a 11 take-or-pay 11 contract) is the standard in the utility finance industry, whether in the tax-exempt or corporate market and will probably be nec·essary for the financing of Susitna. Because of the desirability of take-or-pay power sales contracts with the REA cooperatives as well as the exempt users, tax-exempt finandng for the Susitna Project in its . entirety might not be available under existing law. For several years, this issue of the availability of tax- exempt financing has been the subject of on-going research and analysis by the Power Authority and its advisors, as well as by· the Governor's Office in Wa.shington, D.C. and the Congressional delegation. The 161/169 7-12 D c c c c [ c 0 0 0 0 l [ [ c u [ [ [ problem has become even more significant with the introduction in October 1983 of H.R. 4170, the Tax Reform Act of 1983, which is dis- cussed below. Three possible solutions to this problem which would enable the Susitna Project to be financed on a tax-exempt basis would be to either change existing State law, modify existing Federal law or modify the planned sales to REA cooperatives. The concept of amending State law was first introduced to the Board of the Power Authority on April 18, 1983 as a possible financi.ng option for the Anchorage-Fairbanks Intertie Project, which also involves a heavy concentration of non-exempt users. The concept, known as 11 direct billing 11 , is that a Legislative amendment would allow the Power Author- ity to pass-through its debt service for various projects directly to utility consumers. The utilities could contractually serve as collec- tion agents utilizing a separate 1 ine item category in their monthly billing statements to their customers. With such a broad rate base, no power sales contracts would be necessary to market the bonds. Since the ultimate power consumers would not constitute 11 trades or businesses 11 under the Internal Revenue Code, bonds issued for projects utilizing this concept should not be deemed to be IDBs. While legal advisors to the Power Authority have expressed some level of comfort with this methodology of achieving tax-exemption, no decision has been made as to the necessity of obtaining ·a Revenue Ruling from the Internal Revenue Service. The Power Authority plans to introduce a bill to the current Alaska Legislature to provide for the 11 direct billing .. concept. The bill is enti.tled 11 An Act relating to the direct sale of power by the Alaska Power Authority to retail customers 11 • 161/169 7-13 n u n l_j n l_, r u n n I i u n u I' L Existing Federal law could be amended in any number of ways; either narrowly, to limit tax-exempt status solely to Susitna, or more broadly, allowing other power generation facilities _to qualify for tax-exempt status. Three examples of narrow changes to existing law would be: {l) to amend current Federal law to provide that bonds issued for the construction and operation of the Susitna Hydroelectric Project would be tax-exempt; {2) to amend current Federal law to exclude bonds issued for purposes of constructing Susitna from the definition of IDBs by expa~d­ ing the Section 103 definition of 11 exempt persons 11 to inc)ude REA cooperatives or specifically the purchasers of power from Susitna and (3) to amend Section 103 to broaden the definition of 11 qualified hydro- electric projects 11 which are tax-exempt to include Susitna. A less-narrow approach involves broadening an existing list of bonds that, although IDBs, are tax-exempt. Tax-exempt IDBs include bonds issued for purposes relating to 11 the local furnishing of electric energy or gas.11 (26 U.S.C. Section 103(b){4)(E)). As currently defined by the IRS, 11 local furnishing•• exists only where two or fewer contiguous counties are involved {hence the term 11 two-county rtJle 11 evolved as a synonym of 11 local furnishing exemption 11 ). Since the Susitna Project would serve several Alaska boroughs, it appears that it would not fall within the current definition of 11 1 ocal furnishing. 11 This could be altered by amending Section 103 of the Code to define 11 local furnishing 11 for purposes of Alaska as involving the entire State. It is important to note that although it may be simple to identify the sections of Federal law to be amended and to draft the necessary lang- 161/169 7-14 0 c [ [ c [ [ [ 0 0 c c [ [ [ [ c [ [ uage, it is never easy to p·ass amendments benefiting a single project. A further possible constraint on tax-exempt status for Susitna bonds is the aforementioned Tax Reform Act of 1983, which would place a state-by- state limit on the amount of lOBs each state could issue. The limit currently proposed would be a $150 per person per year "cap" on tax- exempt lOBs (and student loans) allowed to be issued by each state. The pendency of this legislation, ~ith its January 1, 1984 effective date, has created a practical moratorium on issuance of lOBs which would otherwise be classified as tax-exempt. Because of its small population, the State of Alaska would be authorized to issue a relatively small amount of tax-exempt lOBs if the Tax Reform Act. of 1983 passes as currently written. There would not be sufficient IDB capacity under the cap to fund the Susitna Project along with other projects seeking similar tax-exempt funding in the State. At the time of this writing, it is expected that a compromise will be reached between those forces in Congress seeking to "cap" tax-exempt lOBs and local government forces attempting to maintain this method of financing project.s beneficia 1 to the pub 1 i c; however, pub 1 i c power projects have not yet been included in the list of exclusions from the cap. The approach of modifying the contemplated sales to REA cooperatives so as to obtain tax-exempt status for the revenue bonds might require restructuring the Railbelt electric system. One approach would be for the municipal electric systems in the Railbelt to purchase the non- exempt utilities in the Railbelt. There are a number of legal, politi- cal and practical difficulties with this re-organizational approach. 161/169 7-15 D [ [ [ c [ c c G D D c [ c D D D [ c Inasmuch as the Power Authority does not currently control the assets or activities of any Railbelt utility and has no statutory authority to become a public utility, it is unlikely that changes could be made in the Railbelt electric system in the necessary timeframe to allow Susitna bonds to be classified as tax-exempt under current law. A practical consideration of tax-exempt financing is that debt service coverage is often r_equired to market bonds. For example, the Power Authority might be required to maintain revenues from. the Susitna Project equal to some percentage (possibly 10 to 25 percent) in excess of the current year's debt service. However, mitigating any coverage requirement is the probability that the covera~e will be retained in the flow of funds on the Project and thereby be made available for funding of reserves, improvements to the system or early retirement of debt. For purposes of analysis, it is assumed the excess coverage, after required reserves are established, is held and invested along with required reserves at a rate of 11 percent. This treatment produces a result essentially the same as retiring debt. Another treatment of coverage would be to assume the market will accept a "rolling-coverage~• concept whereby certain reserve fund balances, exclusive of debt service reserves and other special purpose funds, may be included as available revenues in the setting of power rates and thus the net effect is to eliminate the coverage factor from the cost of power. Because of the use of coverage within the system or the possible elimination of cover-· age as described above, coverage in and of itself does not appear to be a major detriment to tax-exempt financing. 161/169 7-16 0 c [ c c [ c 0 D 0 c C c c [ c D u Of more concern in the tax-exempt area is the likelihood that a market saturation scenario could develop with regard to the sale of bonds for ~ project the size of Susitna. In such a case, bonds of succeeding series might conunand increasingly higher yields by comparison to similarly rated competing issues of the same type and_ maturity range but which do not have an overexposure to the market. For this reason, it is impor- tant to develop several financing options and to explore combinations of options to help prevent the risk of market saturation. Another concern relative to the marketing of revenue bonds (whether tax-exempt or not) is the considerable magnitude· of the obligations assumed under the power sales agreements by the Railbelt utilities as compared to their financial strength. Also their ability to perform might be jeopardized in the event of a prolonged Project outage or if the financial disability of one of the participating utilities shifts ' the burden to other participants. This problem has been dealt with in the Four Dam Pool negotiations, mentioned in the introduction to this Chapter, by modifications to standard take-or-pay language. The modi- fications shift certain risks, not covered by insurance proceeds or other available funds, from the utilities. to the State's "moral obli- gation".· The term "moral obligation" refers to the procedure of at least annually notifying the Legislature and Administration if a de- ficiency exists in the required Capital Reserve Fund (generally one year's debt service) associated with a bond issue. After such notifi- cation the Legislature may, at its option, restore such deficiency. 161/169 7-17 _j _j l ) J 1 j -1 l j ..J .J _j ' i While the 1 iteral wording of this· moral obligation language does not give any assurance of assistance from the State, a view generally held by investors is that a state could not in good conscience, or by using prudent business judgement acting in its own best interest, allow one of its agencies to default on a debt obligation. There are, Of course, investors who do not share this view, or at least not to the extent that they would purchase bonds secured to any significant degree in .this fashion. There are many investors, however, who would place reliance on the .moral obligation to cover the risk of extraordinary and highly remote "doomsday scenarios". In summary, the State's wi 11 ingness to assume a contingent responsibility for certain catastrophic events could be a meaningful credit enhancement for the debt portion of the financing for the Project because the State's resources appear to be commensurate with the financial obligations. The moral obligation availability would also be helpful in power sales agreement negotiations with utilities. However, it must be emphasized that the resolution of the Four Dam Pool situation is essential to any investor reliance in the future on the moral·obligation of the State of Alaska • Because of the uncertaint~ regarding the tax-exempt status of a portion of Susitna revenue bonds, the financing options involving tax-exempt bonds will include sensitivity analysis assessing the impact of financ- ing a portion of the Project with taxable bonds. 161/169 7-18 D c c c c [ c c 0 D 0 n L 7.3.5 REA Guaranteed Loan Program A potential source of federally guaranteed finan~ing has recently received a great deal of attention within the State. The Rural Electri- fication Administration {REA) is an agency within the U.S. Department of Agriculture which, under the Rural Electrification Act {7 U.S.C. Section 901), has the authority to loan monies to state agenCies and non-profit cooperatives, for the_purpose of providing electric service to rural areas. The REA has a guaranteed loan program which has been in existence for 10 years that could be a source of funding for. a portion of Susitna. REA can_guarantee loans made by any established lending institutions for generation and transmission projects to service rural areas not receiving central station service. Under the Federal Financing Bank Act of 1973, REA borrowers are entitled to receive their loan through the Federal Financing Bank (FFB), if they choose. FFB is an arm of the U.S. Treasury. Its loans are provided at interest rates of 0.125 percent (1/8th of one percent) above prevailing Treasury bond rates. Because these terms are so favorable, most guaran- w * u c u _j teed loans are made through the FFB. In fiscal year 1984, FFB has avail able $3.3 bill ion for REA's guaranteed loan program. Short-term construction loans, available for a term of three to seven years, can be negotiated based on interest rates for short-term Treasury bills. The REA has guaranteed approximately $30 billion in loans since 1973. Of this amount, only about $800,000 has been lent by institutions other than FFB. 161/169 7-19 c [ 0 [ c [ c 0 D 0 ' D r; u c D 11 u ~~ short-tenn loan may be rolled over to a long-tenn arrangement with a maximum tenn of 35"years. These rates would be based on long-tenn Treasury bond yields. The REA will only finance projects which are designed to serve rural needs and, therefore, Susitna•s total financial needs cannot be met by. REA financing. Where a proposed project is intended to serve both rural and urban areas, as is the case with Susitna, REA will serve only "Act beneficiaries", i.e., customers in areas which the Act defines as rural. The present REA cooperatives of Chugach, Matanuska, Homer and Golden Valley are deemed "Act beneficiaries 11 , since they qualified when first formed. Having once qualified, they may continue to qualify despite population changes. The Power Authority may be an applicant under the REA loan guarantee program. However, it should be noted that the REA guarantee program cannot be utilized in combination with t~x-exempt bonds for the REA guaranteed portion of the project financing. Although REA loans are typically made to generating and transmission cooperatives (G&Ts) or REA * distribution cooperatives, the Alaska Railbelt does not have an estab- lished G&T cooperative. Generally, G&T cooperatives are formed by the initiation and concerted effort of rural cooperatives for the purposes In the past 10 years of the Guaranteed Loan Program, there have · been approximately 923 loans to cooperatives either in their own right, or through a G&T cooperative, 40 to public utility districts, and 4 to investor-owned or municipal utilities for service outside city bound- aries. 161/169 7-20 0 c 0 c [ c c 0 0 0 0 c c [ -[ [ c c [ ~ of financing the construction of needed generation and transmission systems in the REA's service territories. Lacking such a G&T coopera- ·tive, the preferable entity in the Railbelt for receiving an REA loan · for Susitna would be the Power Authority. One key reason for this approach to REA financing is the FERC licensing ·procedure. If the Power Authority were to assist the rural cooperatives in e~tablishing a G&T to act as Applicant for the loan guarantee pro- gram, it·would need to transfer ownership of Susitna to the cooperative. This would necessitate a change in the Power Authority's FERC License Application, with a possible regulatory delay. Financing a portion of the Susitna Project through the REA loan guaran- tee program could provide real benefits to the State as developed in greater detail in the finance plan discussed below. These benefits flow from the relatively low interest rates associated with such ffnancing as compared to other taxable financing options. The interest rate for REA loans in January 1984 was approximately 11.75 percent, as compared to approximately 13.0 percent for taxable bonds and approximately 10.0 percent for tax-exempt bonds. Furthermore, the possible alleviation of the market saturation scenario described above could be very beneficial. A very rea 1 drawback to the use of REA guaranteed 1 oans is the 1 i keli- hood that the REA program will continue to receive decreasing amounts of U.S. Congressional approval. The REA's guarantee program ceiling of $3.3 billion for fiscal year 1984 represents a reduction of $1.3 billion in nominal dollars from fiscal year 1983. The currently proposed 161/169 7-21 l [ [ [ [ [ [ c c E c [ [ [ [ c [ c [ Administration budget for fiscal year 1985 is approximately $1.3 billion, again in nominal dollars. The Susitna Project would· be the REA's largest single commitment if guaranteed to the maximum pos- sible extent. In the current political environment in Washington, the probability of gaining sufficient support for financing all of the participation of cooperatives in Susitna appears to be low. However, participation of the REA tq the extent legally and practically feasible is a financing option which deserves considerable attention. This option has never been ruled out by the Power Authority but has not been pursued actively in recent years because of the size of the Project and the more attrac- tive interest rates available if tax-exemption is achieved. Also, while the REA staff has indicated a willingness to explore more "risk-taking" on their part than would be the case in th·e tax-exempt bond market (such as possibly accepting yearly appropriations of the RSF rather than having dedicated stream of revenue), this would indeed be a departure from their usual policy of having bindin~ commitments on all the ele- ments of a financing package. The likelihood of a variance of basic policy on their largest single project exposure seems somewhat remote. It would seem more probable that the risk of non-appropriation would have to be borne by_ the utilities, and ultimately the consumer, as is the case on present REA loans to cooperatives within the State who now receive power rate assistance funds. 161/169 7-22 n u . c i • L_j - _] l J ' _j ' i I ..J _j 7.3.6 Other Sources of Funding In addition to the possible funding sources reviewed above, taxable bonds or private equity financing could also provide financing for the Susitna Project. Generally, however, these sources are not attractive to the State because investors in those markets demand a higher rate of return than can be acconunodated and still achieve a marketable power rate. Although a Rate Stabiliza~ion Fund or State equity could be used in conjunction with some of these markets to reduce the ultimate cost of power in the early years of operation, even that mechanism has limita- tions. In anticipation that other forms of financing may be considered before a final finance plan is decided upon, this section examines taxable bonds and private equity financing as sources of financing for the Project. In addition, G.O. bonds are considered. Taxable bonds may be issued as either fixed-rate or floating interest rate ob 1 i gati ons, as may-tax-exempt bonds. Fixed-rate taxab 1 e bonds which are rated "A" by Moody's or Standard & Poor's are currently carrying an inter-est rate of approximately 13.0 percent or more. At this level, the wholesale cost of energy from Susitna would be quite high. Floating rate bonds carry interest rates generally tied to the· movement of the prime rate or some other index rate. Because the interest rate varies over time, the cost of energy from the Susitna Project would also vary without the establishment of a variable amount RSF. Such fluctuation in the cost of energy without any ceiling would probably be unacceptable to the Railbelt utilities and their customers • A variable amount RSF would probably be unacceptable to the State as well. • 11=\1 /11=\0 _j _] _j l ' _] J l ' _j l ' _j l ' I I _j _j _j l Private equity, if it could be found, would enable parties other than the State of Alaska and its political subdivisions to acquire an own~r­ sh.ip interest in Susitna. There are two major drawbacks to private equity financing for Susitna. First, the rate of return demanded by providers of private equity is quite high, with the probable result of making this the most expensive means of financing the Project. Second, . allowing private equity financi!lg of the Susitna Project would cause the State of Alaska, acting through the Power Authority, to lose consider- able control over the Project, including control over its method of operation, rates and management. This would be inconsistent with the current statutory purposes of the Power Authority. Another alternative source of financing is the use of G.O. bonds. These bonds are issued by a state relying on its general credit rating and do not depend on a dedicated stream of revenue from a project for repay- ment. Payments on the bonds are usually made from the general fund of a state and the bonds can be used for any legal purpose. Because these bonds are the obligations of states they are tax-exempt. The use of G.O. bonds was not considered an attractive source of financing for several reasons. First, through the credit rating process, debt markets limit the amount of G.O. bonds available-to a state. The amount of G.O. bonds needed for Susitna would greatly exceed Alaska's G.O. bond capa- city assuming an investment rating downgrade is unacceptable. Second, the State of Alaska has traditionally followed a prudent policy of repaying its G.O. bonds over a relatively short term while projected oil revenues are reliable, providing excellent coverage. Such financing, repayable over a short-term, would be unacceptable for purposes of 161/169 7-24 n [ l J .., . l l _j ...J ...J ...J Susitna. Accordingly, although G.O. bonds are a possible but limited source of financing, it appears the State would prefer to make other uses of this financing tool; therefore, this option has not been con- sidered in any detail in connection with the Project financing. Another extremely important element of utilizing G.O. debt for Susitna is the probable effect of a potential downgrade in the State's G.O. debt rating resulting from issuing excessive G.O. debt. In the opinion of the financial advisor and investment bankers to the Power Authority, a bond rating of "A" or better on the Susitna revenue bonds is essential to its financing due to the sheer size of the total debt required. A downgrade in the State's G.O. rating could impact the Power Authority's ability to achieve an "A" rating on its bonds. 7.4 IMPACT OF WPPSS DEFAULT ON SUSITNA FINANCING The effects of the recent default by the Washington Public Power Supply System ( "WPPSS") on its debt relating to Units 4 ·and 5 and the resulting possible impact qn the Power Autho·rity, particularly the Susitna Proj- ect, must be reviewed in connection with the Susitna Update. This $2.25 billion WPPSS default is the largest municipal bond failure of record. The implications of the WPPSS experience in the public power finance markets are broad, especially for projects in the Pacific Northwest. Hopefully, the Alaska Railbelt will not automatically be considered part of the Pacific Northwest· Region by investors. In addition, Susitna is 161/169 7-25 n c D 9 ---, J _; not a nuclear project as were WPPSS Units 4 and 5, nor is the Power Authority authorized to pursue nuclear projects. The financing of Susitna will be enhanced by the following facts; that it is a hydro- electric project, it has and will continue to benefit from substantial State investment and it is a project of a State agency. The principal concerns of investors, financial analysts and the rating agencies with large power projects are illustrated perfectly by the WPPSS case. They are as follows: (1) Economic and financial viability of the project, (a) Need for power (accurate load forecasts), (b) Acceptable power rates (competitive with alternatives), (c)_ Public support for project (environmental concerns and willingness to pay), (d) Executive and Legislative commitment, (e) Consistency in dealing with energy policy; (2) Risks associated with the project, (a) Risk of completion, (b) Risk of cost overruns, (c) Risk of construction delays; (3) Market access for subsequent series of bond issues (market saturation); (4) Validity of power sales contracts relating to the provision of necessary revenues to service the debt. n I L u 1 _j __j As a case in point, Standard & Poor•s, one of the two principal bond rating agencies, has written many, if not all, public power entities with rated debt outstanding and requested them to obtain new 1 ega 1 opinions from bond counsel to the effect that, even in 1 ight of the WPPSS deci~ions by the Supreme Courts of Washington and Idaho, the existing power sales agreements applicable to their project are legal, binding and enforceable in accordance with their terms. Presumably, the inability to produce such opinions could result in the reduction, if not withdrawal, of the bond rating. Another case in point is that some large institutional investors have now .established policies of not buying electric revenue bonds where power sales agreements have not been validated by litigation (test case or otherwise). And, to the extreme, some investors are shying away from all power bonds, at least for the present. It seems that load forecasts are the subject of far more review than ~ver before and that the invest- ment community is striving to be certain, to the degree possible, that a given project makes economic sense, regardless of the existence of power sales agreements or the validity thereof. Nevertheless, the existence of legal.ly binding power sales agreements will be essential and a test case may be necessary or advisable before marketing any long-tenn Power Authority bonds for Susitna. The financial advisor and investment bankers of the Power Authority have in the past and continue to advise that State contributions of equity to the Project should be made. in the early years and in substantial amounts with bonds issued at a later date. The WPPSS lessons learned from the 161/169 7-27 _ _; _j _j l _j ., -j j _j default make it clear that this earlier recommendation is appropriate. It is important not only to reduce the ri~k of completion but also to make the cost of energy economically feasible. It also demonstrates the State's commitment to the Project, which was missing in the WPPSS situation. Despite the favorable differences between the Power Author- ity and WPPSS, the sheer size of the Susitna financing, even with large State equity contributions, will cause Susitna financing to be carefully scrutinized by the investment community. 7.5 FINANCING OPTIONS SELECTED FOR ANALYSIS Based upon a review of the relative advantages and disadvantages of the various fundin_g sources discussed in Section 7 .3, two specific financing options have been identified for further analysis and discussion herein: Option A: Tax-Exempt Revenue Bonds combined with State Equity and Rate Stabilization Fund Option B: REA Gua.ranteed Loan and Tax-Exempt Revenue Bonds (50/50) combined with State Equity and Rate Stabilization Fund In Section 7.6, Options A and B will be analyzed assuming that the Devil Canyon Phase in each instance will be financed from proceeds of revenue bonds or other debt instruments bearing the same interest rate as was assumed for Watana tax-exempt revenue bonds. Relatively small amounts .of RSF funds will also be required in the first few years of operation of Devil Canyon. The exact means of financing Devil Canyon is not 161/169 7-28 r critical to the financing of the Watana Phase which must stand on its L. r L r own in the financial market. In Option B, a 50/50 split of the debt portion between REA guaranteed u loans and tax-exempt revenue ·bonds is assumed because: {1) the avail- 1 ~· - ability of a share larger than 50 percent from the REA program is highly improbable; {2) the interest rate benefit of tax-exempt financing of approximately 1.75 percent per annum is clearly the least expensive form of long-term debt presently available, regardless of debt service coverage considerations; and {3) .the 50/50 split may have a beneficial effect on the potential market saturation problem relating to the tax-exempt bond market; howev~r, it should be noted that the Federal ~ government could also experience market saturation problems if present '"l ---; J j -, _j levels of budget deficits continue. The actual split of the debt portion of the financing between REA guaranteed loans and tax-exempt revenue bonds would be determined based upon market conditions and availability of REA guaranteed loans at the time debt is marketed. Both financing options employ a combination of funding sources and both utilize the Rate Stabilization Fund concept for reasons stated in Section 7 .3.3, principally to lower State equity requirements {on a present worth basis) and to spread the State assistance payments over a 1 onger period of years. The base case {or recommended approach) for each option assumes the State equity and RSF wiii be paid in as needed by means of a revenue source such as the proposed Major Project Fund which further assists in spreading the State's assistance over a greater period of time. In Option B,' to the extent tax-exempt financing is 161/169 7-29 c [ [ c n u "l J l J assumed for more than the presently available 25 percent (estimated) of the Project to be utilized by 11 exemp:t persons 11 , the base case assumes the tax-exempt question will be resolved in favor of the State. Sensitiv~ty analyses have been performed on: (1) the ~ffect of the RSF being required 11 Up-front 11 at the time of debt financings in the event a dedicated· revenue stream has not been approved by the electorate; (2) the effect of no tax-exemption for Project financing in excess of the 25 percent estimated to be utilized by 11 exempt persons 11 ; and (3) the effect on the financing and equity requirements if a 120 percent 11 Willingness to pay 11 exists during the first years of operation. 7.6 ANALYSIS OF FINANCING OPTIONS The two financing options presented in Section 7.5 were analyzed using a financial model. The model computes the annual disbursements required during the construction and operation periods of the Susitna Project. The basic assumptions used in the· analysis.are presented in Exhibit 7.1. 7.6.1 Comparison of Options The amounts required from each funding source under the base case of each option are shown on Exhibit 7.2. Amounts are given on Exhibit 7.2 for both Watana and Devil Canyon; however as stated earlier, Devil Canyon is financed by revenue bonds and RSF, if necessary, under each option. For that reason the discussion that follows applies only to the Watana Development • . 161/169 7-30 n u The annual disbursements required during the constructfon and operation periods for Options A and B are shown on Exhibits 7.3 and 7.4, respec- u tively. These Exhibits also present the wholesale cost of energy for n each option. Exhibit 7.5 shows the wholesale cost of energy of the two options compared to that of the least-cost thermal alternative. A comparison of the State funds required for equity ~contributions and ~ RSF under each option is shown on Table 7.1. The total equity plus RSF required in each of t~e options, expressed in 1983 dollars, is $1,915 million in Option A and $2,054 million in Option B, a difference • of about 7 percent • ...J J 'l ! _j l _, l _j In Nominal Dollars Equity RSF TOTAL In 1983 Dollars Equity RSF TOTAL Table 7.1 COMPARISON OF STATE EQUITY AND RSF CONTRIBUTIONS * (In Million Dollars) Option A {Bonds, Eguit~, RSF} Option B (Bonds, REA, Eguity, 2,400 2,700 1,013 888 3,413 3,588 1,519 1,707 396 347 1,915 2,054 RSF} * Assumes reinvestment earnings on a 11 State equity including rate ·~ stabilization accumulated for the benefit of the Project. 161/169 7-31 0 U Table 7.2 shows the ·annual disbursement of equitY: and RSF contributions required for each option. _Exhibit 7.6 shows the nominal disbursements c c D c D D n '-J LJ ' D l .J _j j J l l .. in each year compared to 10 percent of forecast oil and gas revenues in each year. As can be seen from Exhibit 7.6, Watana's requirements are well below the 10 percent limit under both options, allowing funds to be used for other capital projects. Year 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 TOTALS 161/169 Table 7.2 DISBURSEMENT OF STATE EQUITY AND RSF CONTRIBUTIONS (In Million Dollars) Option A Option B {Bonds, Eguitl, RSF} Nomina 1 983 {Bonds, REA, Eguit~, Nominal 19 3 Dollars Dollars Dollars Dollars 177 151 199 170 196 157 220 176 210 159 236 178 227 161 254 180 247 164 276 183 246 153 276 172 238 140 266 156 237 130 265 146 239 123 268. 138 233 113 261 126 150 68 179 82 256 109 200 86 277 111 253 102 247 93 228 86 214 76 198 70 19 7 9 3 3,413 1,915 3,588 2,054 7-32 RSF} n l j _j 1 _j l 1 _j j J 7.6.2 Sensitivity Analyses 7.6.2.1 Revenue Bonds Two key assumptions regarding the revenue bonds used in the options are: (1) that the bonds are tax-exempt status and (2) the passage of a constitutional amendment establishing a fairly unifonn dedicated stream of revenues for Watana before and during its construction and during its initial years of operation. It is assumed that taxable revenue bond~ bearing an interest rate of 13 percent could be used to finance the Project if exemption is not obtained. If a dedi- cated stream of revenues is not allocated to Watana, bond underwriters and prospective investors will probably require that all equity and RSF funds are allocated 11 Up front 11 before the revenue bonds are iss~Jed. Sensitivity analyses for these two assumptions were performed. The amounts required from each financing source are given on Table 7.3 for each option. . 161/169 7-33 __j __j _] 1 J J _j -, I _j ...J -, .J j Table 7.3 SENSITIVITY OF ANALYSIS TO EXEMPTION AND DEDICATED REVENUES (In Million Nominal Dollars) O~tion A Base Case Sensitivity Tax-Exem~tion Exem~t Non-Exem~t Revenue Bonds 6,0 5 3,324 Equity 2,400 3,800 RSF 1,013 145 TOTAL 9,488 7,269 Base Case Sensitivity Dedicated Revenues Dedicated U~ Front Revenue Bonds 6,075 11,181 Equity 2,400 RSF 1,013 1,910* TOTAL 9,488 13,091 O~tion B Base Case Sensitivity Tax-Exem~tion Revenue Bonds Exem~t 2,736 Non-Exem~t 2,337 REA Loan 2,332 1,884 Equity 2,700 3,200 RSF 888 607 TOTAL 8,656 8,028 Base Case Sensitivity Dedicated Revenues Dedicated U~ Front Revenue Bonds ·2,736 5,606 REA Loan 2,332 4,964 Equity 2,700 RSF. 888 2,280** TOTAL 8,656 12,850 * Amount set aside during 1985-88 equals $4,314 million in 1996 with interest accruals. ** Amount set aside during 1985-88 equals $5,152 million in 1996 with interest accruals • 161/169 7-34 ,. "l j _j ,., j ' j ! J _j _j _; .J ' i The annual disbursements required for the "up front" equity and RSF contributions are given on Table 7.4. Table 7.4 SENSITIVITY ANALYSIS DISBURSEMENT OF EQUITY AND RSF CONTRIBUTIONS -(In Million Dollars) · Option A Option B (Bonds, Equity, RSF) (Bonds, REA, Equity, RSF) Nominal 1983 Nominal 1983 Year Dollars Dollars Dollars Dollars 1985 419 357 501 428 1986 463 371 555 445 1987 497 374 595 448 1988 531 375 629 445 TOTALS 1,910 1,477 2,280 1,766 7. 6. 2. 2 Wi 11 i ngness to Pay The concept of "wi 11 i ngness to pay" was discussed in Section 7.2. If a 120 percent wi1ljngness to pay is ·assumed for the options, the amount of financing required from each source for each option would be as indicated on Table 7.5. The annual disbursements of State funds to the sensitivity cases are shown on Exhibits 7.7 and 7.8, respectively, for Options A and B. 161/169 7-35 n ' ' __ j _j _j l 1 j j l 1 _j _, _j Option A Tax-Exempt Bonds Equity RSF TOTAL Option B . Tax-Exempt Bonds REA Loans Equity RSF TOTAL 7.7 CONCLUSIONS Table 7.5 SENSITIVITY OF ANALYSIS TO 120 PERCENT WILLINGNESS TO PAY (In Million Nominal Dollars) Base Case 100% 6,075 2,400 1,013 9~488 2,736 2,332 2,700 888 8,656 The conclusions which can be drawn from the analysis are: Sensitivity 120% 8,090 1,500 1,373 10,963 3,608 3,088 1,900 1,177 9,773 0 There is a relatively minor difference (about 7 percent) in the amount of State contributions required under either financing option base case, as shown on Table 7.1. Approximately $2 billion in 1983 dollars is required in each instance;· 161/169 7-36 l _j ' l l .J .J l ~ l ~ J l j ~. l l _j ; J j 0 0 The cost of energy is approximately the same under each financing option base case as refl€cted on Exhibit 7.5; and Both proposed financing options have potential for financing the Project and should be pursued iri tandem. The sensitivity analyses demonstrate that the assumptions regarding tax-exemption, the constitutional amendment establishing the dedicated stream of revenues for the Susitna Project, and willingness to pay each have a significant effect on the financing options. If tax-exemption is not obtained, the State's contribution will have to be substantially increased. Requiring State equity and RSf funds up-front will increase the debt associated with the Project and the required annual State contribution, a 1 though the State • s tota 1 contribution wi 11 decrease. The State's contribution will be substantially decreased if·a portion of the financia 1 burden of the Project is passed on to consumers in the form of a willingness to pay premium. Five issues need to be reso 1 ved before any p 1 an of finance for the _Susitna Project can be finalized. The Power Authority will pursue each of these issues with appropriate entities, keeping· the Legislatur.e and Administration apprised of progress. The five issue~ are: 0 Tax-exempt status of the Susitna revenue bonds; Ability and willingness of the REA to guarantee debt in meaningful amounts; 0 Establishment of a dedicated stream of revenues; 161/169 7-37 l .J ' ] J '! r J ,._, J l _j ! _j l 0 0 Willingness of utilities to contract for the purchase of Susitna power; and Willingness of the State to allow the use of its 11 mora1 obligation 11 to support Project funding. 161/169 7-38 l _j ' _j l j -, ~.., EXHIBIT 7.1 ASSUMP.TIONS USED IN FINANCIAL ANALYSIS Financing Terms: Source. Revenue Bonds,Tax Exempt Revenue Bonds, Taxable REA Loans Interest Rate, Percent 10.00 13.00 11.75 Repayment Period, Years 35 35 35 Interest Rates on Invested Funds: Equity and Short Term *: Long Term: ·Rate Stabilization Fund: Inflation and Deflation Rate: 6.5%/yr Page 1 of 2 9%/yr 11%/yr 5%/yr Willingness to Pay: 20% above thermal cost of energy when applicable. ~P~ro~j~e~ct~C~o~ns~t~ru~ct~i~o~n_C~o~s~t_(~1~9~83~).: (License Application) 1983 Dollars Nominal Dollars Watana $3,750 million $7,200 million Devil Canyon 1,620 million 4,638 million TOTAL $5,370 million · $11,838 million First Year of Construction: Watana 1989 Devil Canyon 1995 First Year of Operation: Watana 1996 Devil Canyon 2002 Eduit~ Contribution Limit: 1 % o Oil and Gas Revenues Oil and Gas Revenue-Forecast * Ca en ar Year 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 Less than one year. 161/169 Revenues in M1 1on (Nominal Dollars) 3,053.5 3,381.5 3,629.5 3,910.5 4,252.5 4,242.0 4,097.5 4,083:5 4,124.5 . 4,015.5 3,798.5 3,818.5 1 _j _j .J EXHIBIT 7.1 ASSUMPTIONS USED IN FINANCIAL ANALYSIS Power Market Forecast (SHCA-NSD): Rail belt Net Energy Year Generation Requirements, GWh 1995 4,450 2000 4,846 2020 8,063 Thermal System Energy Costs in Nominal Dollars: 1996 Target Cost: 11.2¢/kWh . 0.3% Revenue Bond Characteristics: Maximum Bond Size: No limit, determined by annual requirements. Interest During Construction: Page 2 of 2 Each-succeeding bond funds prior year(s) bond(s) interest Debt Service: Debt service begins in first year of operation Debt Service Coverage: 10% Financing Expense: Equal to 3 percent of principal amount Debt Service Reserve: One year 1 s levelized debt service based on 35-year repayment pe.riod Reserve and Contingency Fund (hydro): One year 1 s capital renewals plus one year's operation and main- tenance cost (established at start of bond issue) Working Capital Fund: Fifteen percent of first year's operation and maintenance cost plus 10 percent of-first year's total am1ual system cost 161/169 l l I j _j l _j . .J _j _j _j EXHIBIT 7.2 FUNDING REQUIREMENTS -BASE CASE (In Million Nominal Dollars) Watana Devil Canlon O~tion A Tax-exempt Bonds 6,075 7,049 Equity 2,400 RSF 1,013 463 TOTAL 9,488 7,512 O~tion B Tax-exempt Bonds 2,736 7,049 REA Loans 2,332 Equity 2,700 RSF 888 463 TOTAL 8,656 7,512 161/169 Total 13,124 2,400 1,476 17,000 9,785 2,332 2,700 1,351 16,168 L. .J L J L J L." . .J L .. , .J L ' L .J l~~·-J L ... ~ .. J L ... -.JJ l. ... LJ l ...... J l ... J L .. J l .. .J :J C.. J C---:J c=:J .) EXHIBIT 7.3 FINANCING OPTION A -ANNUAL DISBURSEMENTS (REVENUE BONDS PLUS EQUITY PLUS RSF) (in million nominal dollars) Disbursements during Construction Reserve & Watana Interest Revenue Debt Contingency Net Construction Equity on Bond Service & w. Capital Interest Bond Bond Year Cost Contribution Equity Funding Reserve Fund Dur. Const Fees Issues 1985 0 177 16 0 0 0 0 0 0 1986 0 196 35 0 0 0 0 0 0 1987 0 211 57 0 0 0 0 0 0 1988 0 227 83 0 0 0 0 0 0 1989 566 246 87 0 0 0 0 0 0 1990 529 246 68 0 0 0 0 0 0 1991 634 238 43 0 0 0 0 0 0 1992 734 237 19 287 40 32 17 11 387 1993 1,373 239 10 1,123 147 0 106 43 1,419 1994 1,485 233 10 1' 243 180 0 263 52 1,738 1995 1,343 150 6 1,186 196 3 444 57 1,886 1996 527 0 0 527 67 0 32 19 645 7,200 2,400 434 4,366 630 35 862 182 6,075 Disbursements during Operation Energy Thermal Debt Less Thermal Oper. & Total Genera-Energy Least- Bond Service Interest Investment Capital Fuel Maint. System tion Cost Cost RSF Year Debt Service Plus Cover Earnings Cost Renewals Costs Cost Costs GWh ¢/kWh ¢/kWh Fund 1996 563 619 72 50 36 94 39 766 4,530 16.9 11.2 256 1997 630 693 86 50 38 107 41 843 4,608 18.3 12.3 277 1998 630 693 93 50 40 122 44 856 4,688 18.3 13.0 247 1999 630 693 100 50 43 137 47 870 4,767 18.2 13.8 214 2000 630 693 107 50 46 159 54 895 4,846 18.5 18.0 20 ·2001 630 693 114 50 49 183 58 919 4,963 18.5 18.8 0 L~ .. _J ~"··· Jl l ... I l I l. I l. I Lc. .J L J L .. ,. .. ~ .. J L.u.JJ L. ..... J l.~. J l .J r J l. .. J [ .. ·-:J ~ c-J c-:::J ·-~-j •••• <J ·-l EXHIBIT 7.4 FINANCING OPTION B -ANNUAL DISBURSEMENTS (REVENUE BONDS PLUS REA LOAN PLUS EQUITY PLUS RSF) (in million nominal dollars) Disbursements during Construction Reserve & Watana Interest Revenue Debt Contingency Net REA Net Construction Equity on Bond Service & W. Capital Interest Bond Bond Loan Interest REA Year Cost Contribution Equity Funding Reserve Fund Dur. Const Fees Issue Funding Dur.Const Loan 1985 0 198 18 0 0 0 0 0 0 0 0 0 1986 0 220 39 0 0 0 0 0 0 0 0 0 1987 0 236 64 0 0 0 0 0 0 0 0 0 1988 0 254 93 0 0 0 0 0 0 0 0 0 1989 566 276 101 0 0 0 0 0 0 0 0 0 1990 529 276 85 0 0 0 0 0 0 0 0 0 1991 634 266 65 0 0 0 0 0 0 0 0 0 1992 743 266 32 0 0 0 0 0 0 0 0 0 1993 1,373 268 12 538 72 34 32 21 697 538 39 577 1994 1,485 261 11 607 85 0 107 25 824 607 112 719 1995 1 '343 179 8 578 93 3 193 26 893 578 194 772 1996 527 0 0 263 33 0 16 10 322 264 0 264 7,200 2,700 528 1,986 283 37 348 82 2,736 1,987 345 2,332 Disbursements during Operation Energy Thermal Bond REA Total Debt Less Thermal Oper. & Total Genera-Energy Least- Debt Debt Service Interest Investment Capital Fuel Maint. ~ystem tion Cost Cost RSF Year Service Service Plus Cover Earnings Cost Renewals Costs Cost Costs GWh ¢/kWh ¢/kWh Fund 1996 250 251 527 34 50 36 94 39 712 4,530 15.7 11.2 201 1997 284 312 625 41 50 38 107 41 820 4,608 17.8 12.3 254 1998 284 312 625 44 50 40 122 44 837 4,688 17.8 13.0 228 1999 284 312 625 47 50 43 137 47 855 4, 746 17.9 13.8 198 2000 284 312 625 50 50 46 159 54 884 4,846 18.2 18.0 9 2001 284 312 625 54 50 49 183 58 911 4,963 18.4 18.8 0 c [ [ [ [ [ [ [ c D c [ [ [ [ [ [ [ [ · EXHIBIT 7.5 45 ,---------------------------------------~ LEAST -COST THERMAL 40 35 FULL FUNDING WITH TAX-EXEMPT ~ REVENUE BONDS ~ ..J 30 4( z ~ 0 z ~ 25 > CJ cr w z w u. 20 0 ... U) 0 0 ~ 15 < U) w ·5 J: ~ 10 5 RATE ST ABIUZA TION FUND 04-----------~ • .------------.------~----~ 1996 2000 2005 2010 YEAR ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE ENERGY COST COMPARISON' FEBRUARY 1984 0 c c c c [ c D C/J a: < ~ ~ D 0 c ~ < z 0 ~ 0 z z 0 0 ~ ~ ~ c c c c c c [ c EXHIBIT 7.6 450------------------------------------------~ 400 350 300 250 200 150 100 50 10" OF OIL AND GAS REVENUES STATE CONTRIBUTION REQUIRED FOR WATANA OPTION B r---, I L ,--..J I r-----~-"'L-- 1 ~-J -----r-r I I I r-~ I _.J 1985 1990 YEAR 1995 I I I I _J ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE ANNUAL STATE CONTRIBUTIONS FOR FINANCING OPTIONS A AND B FEBRUARY 1984 2000 c c [ 550 c 500 c 450 [ 400 [ CJ) 350 0 a: < ...J ...J 0 D c 300 ...J < z 3 D 0 250 z z 0 D :::::i ...J 3 200 [ 150 [ 100 [ [ 50 [ [ [ [ ---., FUNDS REQUIRED UP FRONT FOR RATE STABILIZATION 10% OF OIL AND GAS REVENUES ,...-------- L----..r-L -, r-'1 !. L i I I L I r-, Ll -J. -1 I -It-L....., ~ 0 OP:::-.Jl, .II' L -_f (BASE) ' r 1 I . --'---~-.. -.L~ I _rs-.r 0 ui ~ \._120% WILLINGNESS TO PAY ! I I I . , I I 75% OF REVENUE ~ 1 BONDS TAX ABLE _,r :_J 1985 1990 1995 2000 YEAR ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDA.TE ANNUAL STATE CONTRIBUTIONS FOR OPTION A SENSITIVITY CASES FEBRUARY 1984 EXHIBIT 7. 7 n LJ c [ [ c [ [ D 0 0 c c c [ [ c [ c [ UJ a: < 650 ~---------------t 600 550 500 450 400 FUNDS REQUIRED UP FRONT FOR RATE STABILIZATION 10% OF OIL AND GAS REVENUES :::f 350 0 a ..J < z 300 ::E 0 z ~ 250 :J ..J ::E 200 150 100 50 qO% OF REVENUE , BONDS TAX ABLE . . 99 YEAR ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE ANNUAL STATE CONTRIBUTIONS FOR OPTION B SENSITIVITY CASES FEBRUARY 1984 EXHIBIT 7.8 n LJ c c c c c c c 0 D 0 c c c [ c c c c 8.0 FUTURE ACTIONS 8.1 INTRODUCTION Chapters 1 through 7 of this Report have provided an Update of the economic and financial feasibility of the Susitna Hydroelectric Project. The purpose of this Chapter is to outline the major future actions to be accomplished prior to construction of the Project. The Power Authority has identified 9 such major actions and these are reviewed below. 8.2 POWER SALES AGREEMENTS Power sales agreements need to be signed and in place before the start of engineering design for the Project. The Railbelt utilities have been contacted to provide letters of support for the Project. To date, three utilities have provided such letters and others are expected. Although these letters do not obligate the utilities to enter into power sales agreements, they will be used in support of the FERC License Applica- tion. The preparation of utility profiles has been initiated. These profiles, to be developed in cooperation with the utilities, will serve as a basis for cost of energy and Project feasibility analyses. These analyses will provide the analytical tool for the Railbelt utilities and the Power Authority to evaluate the merits of the Project as a basis for signing Letters of Intent. Continued update of these profiles and economic and financial assumptions based on the current estimated cost 219/169 8-1 n u c [ c D c c D 0 0 D c c [ [ D c c c of the Project will enable the utilities and the Power Authority to enter into power sales agreements. 8.3 FINAL FINANCE PLAN Before a final finance plan for Susitna can be devised, a number of issues need to be resolved. First, the tax-exempt status of Susitna revenue bonds must be determined. As noted in Chapter 7, if Susitna is financed using revenue bonds on which interest is taxable, the higher interest rate of those bonds will require the State•s equity and RSF contribution in the Project to increase. Determining the tax-exempt status will depend upon possible changes to existing law (either Federal or State) or possible restructuring of the Railbelt electric system. As discussed in Chapter 7, all possible changes ·contain considerable uncer- tainty. It is also possiQle that only a request for a Revenue Ruling from the Internal Revenue Service will resolve the question; however, such a request can only be made when the final form of the power sales contracts has been determined and the relative participation of Railbelt utilities is known. A second issue to be resolved is the ability and willingness of REA to guarantee debt in meaningful amounts. Specific matters to be pursued with REA include the availability of REA funds for Susitna, the quan- tities expected to be available in the key financing years, and the decision of REA to make necessary commitments. If REA is unwilling to make commitments for funds or if tax-exempt interest rates continue to 219/169 8-2 0 c D D c [ c D D D D c c [ E u [ c c be more favorable than REA interest rates, Option B would have to be revised. The third finance issue which needs to be resolved is the willingness of the State to establish a dedicated revenue source to support the Proj- ect's financing. As noted in Chapter 7, one means of providing the necessary equity contributions and RSF payments would be the proposed Major Projects Fund. A measure now pending before the Alaska Legisla- ture would place a proposed constitutional amendment creating such a fund on the ballot in November 1984. Careful attention to the funding mechanism provided for in such legislation is necessary to assure that such mechanism is consistent with assumptions made herein. Fourth, the willingness of Railbelt utilities (and ultimately Railbelt consumers) to pay a premium price for Susitna energy needs to be ex- plored and validated. As noted in Chapter 7, if there was a willingness to pay 20 percent more for wholesale Susitna energy, it would reduce the State's necessary equity and RSF contribution in the Project. However, there is no assurance that such willingness to pay exists. Finally, the willingness of the State to allow the use of its "moral obligation" to support Project funding needs to be assessed. The completion of Four Dam Pool power sales agreement negotiations embodying moral obligation features will be an indication of the State's willing- ness to consider such an arrangement for its projects. 219/169 8-3 c c [ c c [ c 0 c D 0 c c [ [ c c [ [ 8.4 LEGISLATIVE AUTHORIZATION As with all new projects of the Power Authority, the Legislature must approve the Susitna Project by enacting law that authorizes the Project at an approved construction cost. Prior to such Legislative approval, ALASKA STAT. § 44.83.183 requires that the Power Authority submit a feasibi 1 ity study and plan of finance to the Office of Management and Budget (OMS) for review. OMB must then submit a report of their find- ings along with a recommendation of approval or disapproval to the Governor and Legislature within 60 days. Existing law ALASKA STAT. § 44.83.185 further requires that the feasibility study, plan of finance, an independent cost estimate, and the report from OMB be submitted to the Legislature for consideration. 8.5 FERC LICENSE AND OTHER MAJOR PERMITS A number of regulatory approvals must be obtained before construction of the Susitna Project ·can commence. Although the most important of these is issuance of a 1 icense to construct and operate the Project by the FERC, a number of permits from other Feder a 1 and State agencies must also be obtained. 8.5.1 FERC License The FERC licensing process is currently underway and proceeding toward the target license issuance date of March 18~ 1987. The Susitna License Application was accepted for processing by the FERC on July 29, 1983. 219/169 8-4 [ c [ [ c [ [ c 0 0 D c [ [ [ [ c [ [ Since that time the Power Authority has responded to numerous FERC Staff requests for additional information and has begun preparation for the two-phase hearings tentatively planned for the case. The current schedule calls for 11 Need for Power .. hearings to be held in the Summer of 1984 and for hearings on environmental and dam safety issues to begin in the Spring of 1985. The second phase hearings may be shortened through settlements; if so, it is possible that a FERC License could be issued earlier than the March 1987 target date. As with most regulatory actions, however, there is the possibility of future legal challenges which could delay the effective date of the FERC License. 8.5.2 Other Major Permits In addition to the FERC License, several Federal, State and local permits will be required to construct the Project. A 1 i sting of the major permits, and the agencies involved, follows: • Federal Permits 1. U.S. Army Corps of Engineers, Obstructions of Navigable Waterway Permit 2. U.S. Army Corps of Engineers, Wetlands Fill Permit 3. Bureau of Land Management, Right-of-Way Grant, Land and Gravel Permits 4. Environmental Protection Agency, National Pollution Discharge Elimination System Permit 5. En vi ronmenta 1 Protection Agency, New Source Performance Statements 219/169 8-5 0 c c c c [ [ D D 0 D D [ I' u c c I' I 'u State Permits 1. Department of Environmental Conservation, Water Quality Certificate of Reasonable Assurance, Air Quality Permits to Operate 2. Office of Management and Budget, Coastal Zone Consistency Determination 3. Department of Fish and Game, Fisheries Protection Permits 4. Department of Natural Resources, Water Right, Permit to Construct a Dam, Material Sales, Right-of-Way Local 1. Matanuska-Susitna Borough, Talkeetna Mountains Special Use District Variance The Power Authority has been coordinating with permitting agencies for the past two years to insure that timely acquisition of permits will be achieved. Applications have already been submitted for several permits. It is anticipated that, in most instances, the information and analyses being prepared to support the FERC licensing process will also support the processing of necessary Federal, State and local permits. 8.6 DESIGN COMPLETION FOR INITIAL CONTRACTS Before award of initial construction contracts the Power Authority will require completion of deta i 1 ed design. This po 1 icy wi 11 reduce the tendency for construction cost over-runs that has been experienced as a 219/169 8-6 c c c c c c c 0 0 0 0 0 c c c c c c c result of the common industry practice of inviting bids on preliminary design documents and then completing design during construction. 8.7 EXTERNAL REVIEW BOARD CONCURRENCE As will be required by the FERC, the Power Authority has retained a board of qualified, independent engineering consultants to review the design, specifications and construction of the Susitna Project for safety and adequacy. The consultants on this External Review Board have been involved in reviewing the Project•s design for the past several years, and will be required to submit a final statement to the FERC indicating their satisfaction with the construction, safety and adequacy of the Project•s structures when built. In addition, the Power Authori- ty will require the External Review Board•s concurrence on final Project design before proceeding with construction. These measures provide an extra layer of review which ensures that the Project will be built to the highest engineering standards. 8.8 ACCEPTABLE LABOR AGREEMENT A Project Labor Agreement will be necessary to provide uniformity, stabi 1 ity and continuity during construction and to avoid potentially costly labor disputes. The labor agreement will include standardized working hours, strong work stoppage-no strike clauses, progressive grievance and arbitration procedures, jurisdictional delineation of crafts, and training programs and employment opportunities for Native Alaskans and other minorities. 219/169 8-7 0 c c c c c c D D 0 0 D c c c c c c L Since it would not be practical to negotiate wage rates for the length of the job, provisions will be negotiated providing that in the event of a strike by a local bargaining unit, work would continue on the Susitna Project and the wage scale eventually agreed upon would be paid retroac- tively to those Susitna craftsmen represented by the local unit. 8.9 ACQUISITION OF PROJECT LANDS Approximately 71,000 acres of land are required for the Susitna Project. The current ownerships of that acreage is distributed as follows: 1. 6,944 acres, State of Alaska 2. 33,350 acres, Native {CIRI and CIRI Villages) 3. 31,105 acres Federal {29,600 of these are State and Native Selected) 4. 270 acres Municipal Lands {Mat-Su Borough and Municipality of Anchorage) The following methods will be used to obtain the use or title to each land ownership category: 1. State of Alaska lands, easements, classifications 2. Native Land, purchase or land trade, use provisions of Sec- tion 24 of Federal Power Act 3. Federal Land, State selection under Statehood Entitlement, Land Use Permits, and Grants of Right-of-Way 4. Municipal, purchase or gr·ant of Right-of-Way 219/169 8-8 n c c c 8 c 0 u u 0 0 0 c 0 0 c c 0 u Although land acquisition planning is underway, no land will be acquired until the construction of the Project has been legislatively approved. 8.10 POWER AUTHORITY DECISION TO CONSTRUCT Before construction of the Susitna Project commences a final decision will be required by the Board of Directors of the Power Authority. The Board will not authorize construction unless it has been shown that the Project is economically and financially feasible and all actions dis- cussed in this Chapter have been completed to the extent necessary. 219/169 8-9