Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
1983 Energy Report
ENE 105 Ale shat Power Authe= SHAR ? wee 6 1983 Energy Report \ “ no We : 2, oy Report to Department of Commerce & Economic Development State of Alaska Report to NE Department of Commerce & Economic Development State of Alaska 1983 Energy Report PROPERTY OF: Alaska Power Authority 334 W. 5th Ave. Anchorage, Alaska 99501 ACKNOWLEDGEMENTS The 1983 Energy Report was prepared under the direction of the Division of Energy and Power Devel- opment, Department of Commerce and Economic Development, State of Alaska by Arthur D. Little, Inc., with the assistance of Tryck, Nyman, and Hayes, Inc., Anchorage, the Alaska Pacific University, Anchorage and Mitsubishi Research Institute, Tokyo. TABLE OF CONTENTS List of Figures List of Tables CHAPTER | — OVERVIEW Introduction Strategic Energy Issues Scope and Approach to the 1983 Energy Plan Major Findings CHAPTER II — ENERGY STATUS REPORT Alaska’s Energy Demands and Resources Regional Energy Balances Alaska’s Energy Resources Oil Natural Gas Coal Peat Hydropower Geothermal Wood Resources Wind Energy Resources Tidal Power Resources Solar Energy Conservation Energy Projects and Programs Electricity Generation and Distribution Recent Trends Railbelt Southeast Bush Natural Gas Distribution CHAPTER II! —- ECONOMIC DEVELOPMENT OUTLOOK Economic Development and Energy Demands Economic Constraints Economic Development Scenarios CHAPTER IV — ENERGY OPTIONS Alaska’s Future Energy Demand Modifying Energy Demand Patterns Energy Efficiency Fuel Substitution iii Page vii TABLE OF CONTENTS (Continued) Page CHAPTER IV — ENERGY OPTIONS (Cont’d.) Constraints IV-13 Energy Alternatives IV-14 Electric Supply Options for Bush and Rural Areas IV-15 Railbelt Natural Gas Use Development IV-22 The Susitna Project and Related Issues IV-24 Strategic Energy Options IV-28 For the Bush Regions IV-28 For the North Slope IV-34 For the Southeast Region IV-35 For the Railbelt IV-35 Summary of the Strategic Options IV-37 APPENDIX A — ALASKAN OIL AND GAS DEVELOPMENTS A-1 APPENDIX B— COAL INDUSTRY OUTLOOK AND PEAT POTENTIAL B-1 APPENDIX C — ALAKSAN NORTH SLOPE CRUDE VALUES C-1 APPENDIX D— FINANCIAL ASSUMPTIONS D-1 APPENDIX E — ECONOMIC DEVELOPMENT ALTERNATIVES E-1 APPENDIX F — CONSERVATION F-1 APPENDIX G — BIBLIOGRAPHY G-1 APPENDIX H — DESCRIPTION OF ALASKA ENERGY FORECAST MODELS H-1 APPENDIX |— SUMMARY OF PUBLIC REVIEW COMMENTS 1-1 iv Figure No. 1-1 1-2 1-3 1-4 1-5 1-6 1-1 1-2 1-3 11-4 H-5 11-6 -7 1-8 11-9 11-10 1-11 1-12 1-13 1-14 1-15 11-16 11-17 1-18 11-19 11-20 1-21 11-22 1-23 11-24 IV-1 IV-2 IV-3 IvV-4 LIST OF FIGURES Alaska’s Energy Supply and Demand Typical Ranges of Prices for Energy, 1981 Alaska Energy Forecast System Diagram Strategic Energy Planning Process Energy End-Use Demand Forecast ‘‘Moderate Growth” Scenario Electric Generation Fuel-Use Forecast ‘Moderate Growth” Scenario Alaska 1981 Energy Balance Crude Oil and Natural Gas Flows 1981 Energy Consumption by Fuel 1981 Energy Consumption by Region Per-Capita Consumption of Transportation Fuels, 1981 1981 Utility Primary Fuel Consumption by Region 1981 Utility Primary Fuel Consumption by Fuel Energy Planning Regions 1981 Regional Energy Consumption by End-Use 1981 Basic Energy Sector Consumption by Region 1981 Railbelt Energy Balance 1981 Southeast Energy Balance 1981 North Slope Energy Balance 1981 Bush Energy Balance 1981 Per-Capita Consumption of Residential, Commercial, and Transportation Fuels 1981 Per-Capita Residential Consumption 1981 Comparison of Average Residential Fuel Oil and Electricity Prices State of Alaska Crude Oil and Natural Gas Basins Refinery Product Slates Petroleum Product Distribution Flows Alaskan Coal Reserves by Major Fields Potential Alaskan Fuel Peat Resources Selected Hydroelectric Sites (Railbelt) Selected Geothermal Sites (Railbelt) State of Alaska Forecast of Total Energy Consumption Four Major Scenarios Alaska’s Energy Consumption Moderate Growth Scenario Final Demand by Sector Fuel Oil Consumption by Region Natural Gas Consumption by Region Page 1-3 1-4 1-6 1-8 1-11 1-12 H-2 1-3 H-5 11-6 1-7 11-10 1-11 1-12 11-13 11-14 11-15 11-16 1-17 1-18 1-20 1-21 1-23 1-25 1-27 11-29 11-31 1-32 11-34 11-36 Iv-5 IV-7 IV-8 Iv-9 Figure No. IV-5 IV-6 IV-7 IV-8 LIST OF FIGURES (Continued) Electricity Consumption by Region Strategic Energy Options, Low Growth Energy Plan Strategic Energy Options, Moderate Growth Energy Plan Strategic Energy Options, Accelerated Growth Energy Plan vi Page IV-10 IV-29 IV-31 IV-32 Table No. H-1 W-2 1-3 11-4 1-5 1-6 1-7 \l-7a 11-7b I-7c 11-7d 1-8 I1-8a 1-9 W-1 H-2 I-3 1-4 H-5 IV-1 IV-2 Iv-3 Iv-4 IV-5 IV-6 IV-7 Iv-8 Iv-9 IV-10 IV-11 IV-12 LIST OF TABLES — 1981 — In-state Demand for Petroleum Products, Natural Gas, and Other Energy — 1981 — Transportation Demands Crude Oil and Natural Gas Regional Availability Proposed Hydropower Facilities Electric Capacity and Energy Generation Growth Rates Electric Generating Capacity Railbelt Generation Capacity Anchorage Area, Generation Capacity Anchorage Area, Electric Generation Fairbanks Area, Generation Capacity Fairbanks Area, Electric Generation Southeast Generation Capacity Southeast Electric Generation Bush Regional Centers Generation Capacity Importance of Petroleum and Natural Gas Revenues to Total State Revenues Baseline Annual Growth Rates Baseline Sectoral Annual Employment Growth Rates Economic Development Scenarios Sectoral Annual Growth Rates in Employment for “Accelerated Growth” Scenario Alaskan Energy Forecast Comparison Alaskan Energy/Economic Forecast Comparison Alaska’s Energy Consumption Moderate Growth Scenario Final Demand by Sector Energy Alternatives Large Conventional Electric Generation Systems Small Electric Generation Systems — Comparative Costs Thermal Energy Systems — Comparative Costs Natural Gas Netback Cost Cook Inlet Natural Gas Supply by Pipeline Capacity Additions — Railbelt Cost of Major Capacity Additions, Railbelt Region Average Discounted Value of Electric Rates and Levelized Electricity Cost — Railbelt Region Vii Page 1-4 H-9 11-26 11-35 11-39 11-40 11-40 11-41 1-41 11-42 1-42 11-43 11-44 11-45 H-4 U-7 H-7 1-9 H-12 IV-2 IV-3 IV-6 IV-16 IV-17 IV-18 IV-19 IV-22 IV-23 IV-25 IV-26 IV-27 STATE OF ALASKA 1983 ENERGY REPORT CHAPTER | OVERVIEW 1.1. INTRODUCTION The 1983 Energy Plan is written to comply with Alaska State Law, which provides for a yearly assessment of the State’s energy situation, the supply and demand by end-use. energy conser- vation efforts, projections of future energy needs, and the preparation of a guide to energy development strategies for the Legislature and other agencies of State government with planning responsibilities. An emergency energy plan is being prepared by the Division of Energy and Power Development and will be presented under separate cover. Previous Energy Plans concentrated on data collection. Last year’s Plan, for example, provided a preliminary breakdown of Alaska’s end-uses of energy. It also described some of the energy options available to different regions. Because the database was necessarily limited, however, explicit trade-off analyses and the direct application of findings to Legislative decision making could not be made. The 1982 Plan underscored the necessity of developing a framework for analysis and planning. We have endeavored to build on those past efforts, and to extend them further. The 1983 Plan is based upon a substantially expanded database, and incorporates the results of several computer models (of the Alaskan economy; of energy supply and demand; and of utility and industrial electricity generation) covering 14 energy planning regions and four aggregated planning regions: Railbelt, Bush, North Slope, and Southeast. An investigation of Pacific Rim markets for Alaskan exports also formed part of this study. An extensive program of inter- views with concerned citizens, business leaders, and decision-makers throughout the State supplemented our understanding of the issues involved. Most crucially, however, this year’s Energy Plan presents and embodies an effective strategic energy planning framework. Itself the product of the application of a coherent planning process, this Plan is written to furnish the State with all information needed to continue planning independently in future years. It is designed both to provide an example of the strategic energy planning process and to serve as a handbook for applications by future planners. The 1983 Energy Plan does not present recommendations as such, but rather major findings. The plan analyzes the energy supply alternatives available to the State and the ways in which they can be combined into viable strategic energy options. The critical task now facing the State is a determination of the preferred direction of both economic and energy development. A policy must be forged that represents the interests of all concerned parties. Given such a policy direction, this document provides the necessary material for the design of an appropriate program of action. 1.2 STRATEGIC ENERGY ISSUES Alaska represents an astonishing combination of opportunity and paradox: opportunity in the bounty of its resources and the financial strength of its government, paradox in the conflicting objectives and policy concerns surrounding the energy issue. The mix of economic, environ- mental, cultural, and political concerns arising in any assessment of Alaska’s energy future is uniquely complex. Matching energy resources to energy demand in Alaska is a challenging task. Alaska is rich in energy resources although accessibility is a critical factor in resource development. Fossil fuels such as oil, natural gas, and coal are abundant. Hydroelectric generation is potentially available in many regions of the State. These four resources have served Alaska’s energy demand in the past and currently meet 99 percent of the energy demand. (See Figure I-1.) Wind, geothermal, and solar power technologies also have applications here, although their viability in a given location is governed by a host of site- specific constraints. Yet despite this abundance, all Alaskans do not enjoy access to inexpensive, reliable sources of energy. Energy prices vary nearly tenfold between central and remote regions of the State. (See Figure I-2.) The chief obstacles are geographical and environmental. Alaska extends nearly 2,000 miles east to west and encompasses diverse environments north to south. Extreme climates, tundra and permafrost, as well as topographical barriers make access to these resources difficult, and complicate the implementation of energy programs. These obstacles are the major causes of the uneven distribution of energy supply, demand, and price in the State. Successful energy strategies must be based on evaluations that take full account of these factors when investigating efficiency improvements; centralized versus decentralized energy systems; renewable versus non-renewable energy sources; fuel substitution; single fuel dependence; or conservation. The interior and Arctic coastal areas, for example, cannot obtain fuel supplies in the winter without suffering exorbitant transportation costs. In some cases, fuel oil is delivered by air in barrels. Furthermore, the low population density of scattered Bush villages and the difficulty of construction under Arctic conditions make the development of efficient, centralized elec- tricity systems a costly proposition. Ensuring that the energy solutions developed are both practical and compatible with the lifestyle of the villages they serve is an exacting task, requiring the participation and cooperation of all concerned. Even with the introduction of more efficient generation, the price of electricity will remain high for many Alaskans as long as it is linked to distillate fuels. The installation of small generating capacity based on new technologies like geothermal and wind power may some- times appear technically and economically practical on paper. The successful performance of such projects is dependent, however, on the ability of local personnel to maintain and repair the equipment. Similarly, the price of space heating in many areas is fundamentally tied to the price of fuel oil. Solid fuels (such as wood or peat) may be able to substitute for expensive fuel oil at some sacrifice of operational ease. Conservation programs afford other ways to reduce energy demand and hence costs; their effectiveness depends upon the end-use affected and on the regional environment. 1-2 FIGURE I-1 ALASKA’S ENERGY SUPPLY AND DEMAND (Final Demands to Consumers by Fuel Type) 170,000 160,000 150,000 140,000 130,000 120,000 110,000 100,000 Billions of Btus 90,000 80,000 70,000 60,000 20,000 Coal 10,000 Hydro 0 1960 1965 1970 1975 1980 Source: United States Department of Energy, State Energy Data Report 1-3 Southeast *Prices “Ele Source! FIGURE I-2 TYPICAL RANGES OF PRICES FOR ENERGY,* 1981 $/MMBtus 0 10 20 30 40 50 60 70 80 Electricity Fuel Oil Electricity 80.60** Fuel Oil Electricity \N 72. 15 WN Range of Cost KS are without fuel assistance subsidy effects. e: Arthur D. Little, Inc., estimates. 14 ctricity prices can exceed this range by fifty percent in specific locations. The urban Railbelt and portions of the Southeast do not suffer as much from high energy costs. If anything, the difficulty in the Railbelt is in choosing the best program from among several good options. The rapid growth of these populous areas requires careful planning to meet energy demand in an appropriate manner. The key issue for energy planners is to describe the various alternatives and energy trade-offs in sufficient detail, so that decision-makers can select that combination of alternatives which best fits with the chosen energy policy. 1.8 SCOPE AND APPROACH TO THE 1983 ENERGY PLAN The 1983 Energy Plan presents a range of viable strategic energy options for the State of Alaska. These energy options range from the continuation of energy supply and demand as currently structured to new capital investments which could significantly change sources of energy supply or patterns of energy consumption. These strategic energy options are linked to specific economic development scenarios; each scenario devised was based on public interest and policy issues as well as a realistic assessment of the probability of the development of key projects and industry sectors. The approach to the 1983 Energy Plan was based on modelling relationships between the Alaskan economy and energy demands (Figure I-3). The economic model can be used to examine future economic policy and the impacts of industry projects or infrastructure devel- opment by region or for the State as a whole. The energy models provide a consistent, flexible structure which can be used to examine energy supply and demand options in detail, both independently and in combination with the economic model. The energy forecasts show consumer energy demands responding to economic scenarios and to the pricing and supply assumptions inherent in the analysis. This broad range of energy demands represents several of Alaska’s possible energy futures. The 1983 Energy Plan presents three economic development scenarios for the State to show the range of economic activity and the resultant energy demands. They take into consideration both the future direction of Pacific Rim and world markets, and related economic devel- opments in natural resources, manufacturing, and energy projects within the Alaskan econ- omy. The first two scenarios, “Low Growth” and “Moderate Growth”, represent directions in which the Alaskan economy can develop, given that future world, United States, and Pacific Rim markets maintain a low growth pace. The third scenario, “Accelerated Growth”, depends upon more robust growth in Pacific Rim markets for Alaska’s natural resources, especially the energy markets. These economic development scenarios represent the 1983 Energy Plan’s range of economic growth for the State and, therefore, the range of likely end-use demands by residential, commercial, industrial, and transportation sectors. These economic development scenarios were prepared as examples to aid in the examination of trade-offs in energy planning. They are not intended to serve as definitive predictions emerging from an extensive in-depth economic development analysis. The strategic energy planning framework for the 1983 Plan encompasses both a process and a product, and involves a broad spectrum of participants and a wide variety of data. The process that produces an energy plan is iterative. Assumptions made in early stages are frequently FIGURE I-3 ALASKA ENERGY FORECAST SYSTEM DIAGRAM Economic Database Economic Scenario Specification Population, Development Projects Earnings, Employment Employment Schedule Economic Development Model Projected Economic Activity Population, Households, Earnings, Employment Energy Database Demand Parameters — Elasticities — Conservation Energy Prices by Fuel Type by Region Energy Requirements Demand — Fuel Type — Sector Energy Project Database Capital Operating & Maintenance Discount Rate Project Financial Requirements 1-6 subject to revision as the work progresses (see Figure I-4). In this manner, the plan generated is internally consistent and fully responsive to the State’s policy. Ultimately, the product of the strategic energy plan is, in essence, a blueprint for the effective implementation of the State’s energy policy. The impetus behind strategic energy planning is usually the identification of specific systemic problems, along with the concomitant recognition of the need for planning and coordination at high organizational levels. In Alaska’s case, those needs were identified and expressed in the Legislature, through State Statute HCS CCSB 438 (Finance) and Section 44.56.224. Faced with the paradox of extensive State involvement in energy issues (including substantial revenues from oil development) combined with high energy costs for many consumers, the State sought a constructive way to analyze and manage energy resources and expenditures. The preparation of an Energy Plan was mandated to provide Legislators with the information needed to make informed decisions on behalf of the people they are elected to represent. The first vital step in any strategic plan is a thorough assessment of the current energy situation. In recognition of the importance of this preliminary assessment, the Legislators required that one component of the Energy Plan be “an end-use study examining and report- ing on the nature and amount of energy used and the purposes of such energy use.” This picture of Alaska’s energy demand is, however, only a fragment of the entire energy portrait of the State. Energy supply, in terms of raw resources, production, conversion, and distribution, is another key element. Chapter II of this Plan presents the 198] Energy Status Report on Alaska’s supply and demand balances, as well as the energy resources of the State and its regions. The most critical step in the energy planning process is the determination of policy objectives. Without clear and specific direction, energy programs will be scattered, perhaps even in conflict, and their effects will be difficult or impossible to predict, measure, and control. The situation assessment presented in the Energy Status Report identifies both constraints and areas of potential or particular opportunity; policy must work within that realistically estab- lished framework. The present condition of energy supply and demand is far from static: to capture the true nature of Alaska’s energy balance the State requires a historical description of the ways it has evolved and the likely shape of responses to future policy direction. Hence, a major component of this year’s Energy Plan is the modeling of key factors in the State economy, and of energy supply and demand, that enable users to describe and interpret the effects of future economic and energy developments. Chapter III, “Economic Development Outlook”, presents the three economic development scenarios used for strategic energy planning in the 1983 Energy Plan. Above all, policy objectives serve as the essential focus of a plan, and drive the development of clear and consistent programs. Energy policy derives its fundamental coherence from wider concerns (chief of which is a determination of the overall economic policy direction of the State) and should be supported in three basic ways; by the cooperation of those entities essential to their realization, by a commitment to policy, and by consideration of financial realities. When FIGURE 1-4 STRATEGIC ENERGY PLANNING PROCESS Legal, Regulatory, Institutional Economic Development Policy Energy Policy Energy Objectives Secondary Screening Criteria ee ee [_ Primary Screening Criteria Primary Screening Criteria Menu of Energy Supply Alternatives 1-8 a consensus has been achieved concerning policy direction, decision-makers can begin to formulate the basic elements of energy strategy choice: e@ Specific energy goals: descriptions of the aims of energy policy that the strategic plan is designed to achieve. e Selection criteria: factors according to which the merits of various energy options are assessed to reflect the thrust of energy policy. e Trade-offs: analyses of the limits to planning derived from a careful examination of the situation assessment in the context of energy policy considerations. These elements guide the selection of particular energy options from among the range of energy alternatives. The basic energy alternatives themselves are derived from feasibility studies and analysis of the situation assessment. They are descriptions of the many possible energy programs or projects that can be undertaken; for example, the Susitna hydroelectric project, or a regional conservation program. Energy alternatives provide information about the effects of their implementation on other alternatives, and specify costs, risks, and financ- ing requirements as well. As shown in Chapter IV, “Energy Options”, strategic energy planners can apply selection criteria and use trade-off analyses as guidelines to determine the most effective and desirable combinations of alternatives. Each combination of alternatives represents a viable strategic option to achieve specific energy goals. Once options have been selected, detailed implementa- tion plans can be drafted. Implementation plans describe the specific steps to be taken for the constituent programs/alternatives under each option. Individual programs can be further detailed in work task breakdowns. The final product of this process, the strategic energy plan, is a highly structured description of a practical means to a policy end. The strategic energy options discussed in the 1983 Plan are not the only viable options Alaska can implement. Given the planning framework, other options can certainly be formulated and examined for their economic benefits and costs. Thus, while the options examined are consis- tent with economic and other qualitative criteria, they are not exhaustive. They are presented to assist Legislators and other Alaskan decision-makers to evaluate the energy option trade- offs for the Railbelt, Southeast, Bush, and North Slope regions. The appropriate direction and the level of State involvement will ultimately depend upon the acceptability of economic and financial objectives set for the State’s development, and the public interest and policy issues deemed important by Alaskans in all regions of the State. 1.4 MAJOR FINDINGS The 1983 Energy Plan presents a “Moderate Growth” energy demand forecast as the most likely pattern of energy consumption for Alaska over the next two decades. The most likely forecast for Alaska’s development is associated with a “Moderate Growth” economic devel- opment scenario. This scenario describes a pattern of economic development already familiar to Alaskans. It represents a continuation of major resource project development which com- bines strong elements of a construction-based economy and the intermittent rapid growth 1-9 periods typical of the Pipeline years with steady growth in basic resource industries like fisheries, lumber, and minerals. Growth in the State economy and State revenues is created through the development of Alaska’s natural resources on a project-by-project basis. The following large-scale energy projects are included in this forecast: continuing production of oii and gas from the Cook Inlet; Susitna hydroelectric project starting Watana operation in 1993; Outer Continental Shelf development; tidewater pipeline or ANGTS, started by 1995; National Petroleum Reserve or National Wildlife Reserve resource development, starting by 1990; and liquefied natural gas (LNG) facility, under construction by 1992. Under this “Moderate Growth” scenario, Alaska’s population will reach 701,766 (a 1.9 percent per annum growth) and employment 397,735 (a 2.6 percent per annum growth) by the year 2005. Real income per capita will grow at an annual rate of 2.4 percent, mostly due to jobs associated with oil and gas extraction and project construction. Most important is the continued rapid growth of the Alaskan economy in the 1980's and early 1990’s. For the period 1982 to 1990 Alaska’s population will grow by 2.69 percent per annum and reach 561,418 with employment growing at 4.49 percent per annum and reaching 310,769 in 1990. The energy implications of this “Moderate Growth” scenario are forecast in terms of energy end-use growth and shifts in sources of energy supply. These are shown in Figure I-5. Fuel use for electric generation is shown in Figure I-6. Several significant changes are forecast: A) Residential, commercial, and industrial demand for natural gas from 1982 to 2005 will continue to grow faster (5.2 percent) than all other final demand sectors, primarily as a result of a petroleum and chemical products industry growth in the late 1990’s. Transpor- tation demands for gasoline and distillate fuels for motor vehicles and air transportation will grow rapidly (3.9 percent), but not quite as fast as natural gas. B) Major fuel substitution in the Railbelt may occur as major hydropower projects replace upwards of 43 million cubic feet of natural gas in utility generation in the early 1990’s. C) Residential and commercial demand for energy will become a greater portion of Alaska’s total energy balance as industrial development and population grow at two percent per annum through 2005 and the export of oil, petroleum products, and natural gas holds constant or declines slightly. Several other major findings of the 1983 Energy Report are summarized in the following brief paragraphs: Dependence on Oil: The State of Alaska depends heavily upon petroleum products as its major source of energy. This dependence will continue: the proportion of petroleum products to total primary fuel supply is expected to change little, from 66 percent in 1981 to 64 percent in the year 2005. This figure excludes the amount of jet fuel used for international and domestic flights. Currently, few substitute fuels can provide economically viable options, and conserva- tion is the best way to manage oil use and keep consumer costs down. Strong upward price movements may cause a natural conservation reaction, or specific programs could be imple- mented to improve overall revenue and income for Alaskan residents. 1-10 Economies of Scale: The development of energy export projects can provide real economies for Alaskans. The construction of a pipeline to export North Slope natural gas would permit Fairbanks residents and commercial establishments to switch to natural gas for thermal needs and reduce their heating bills by one half. The construction of an export coal mine in the Cook Inlet area would permit electric utilities to run coal-fired steam-electric generators as an economic alternative to natural gas or large hydropower projects. The lower cost per ton for a large, five million tons per year mine (approximately $1.20 per million Btus versus $1.70 per million Btus for a smaller dedicated utility mine) makes a coal-fueled project very competitive with Susitna and natural gas-fired combined cycle plants. Project Impacts on Energy Demand: The construction and operation activities associated with major projects, such as Susitna or a petrochemical plant, do not boost permanent employment rates significantly. Employment increases in-State during construction and then falls as the project is completed and the smaller operating staff comes into the work force. This creates a ratchet effect on the general upward trend in employment. Thus, major projects do not have as great an impact on energy demands in the State as it might appear. The major growth factor for energy use is a steadily rising population, coupled with increases in energy consumption per household and employee in the Bush, Southeast, and Railbelt regions. Energy Use in the Bush: In many cases it is either technically difficult or uneconomical to change the dependence on oil of Bush communities. Bush villages or households have few good low-cost alternatives which they can implement in confidence that cost savings for energy will materialize. Many of the alternatives, while very attractive on the drawing board, experience operation and maintenance problems which quickly negate any cost savings. Many systems, like wind energy systems, need backup reserves which make them much less cost-effective. Energy conservation offers the most immediate, cost-effective, and practical way to change energy consumption patterns and costs for Bush residents. Effective local programs which inform and facilitate Bush residents to achieve energy cost reductions will be necessary. Energy Use in the Southeast: Energy needs in the Southeast will continue to be met by oil, hydropower, and cogeneration by industry. The growth in electricity demand will necessitate an increase in generation capacity of approximately 65 percent by the year 2005. Fuel oil demands will increase by 54 percent by the year 2005 while the price of fuel oil increases by 36 percent in real terms. Conservation will be almost as important to the Southeast as to the Bush. Energy Use in the Railbelt: Thermal needs in the Anchorage and Kenai portions of the Railbelt are served best by natural gas, provided the Pacific Rim market for natural gas remains highly competitive and natural gas is not in great demand. Utility use of natural gas as a fuel for electric generation does not conserve this fuel for its best uses: space heating and process heat. The Railbelt has several cost-competitive alternatives for electric generation: large hydroelectric projects (Susitna), efficient natural gas-fired combined cycle generators, and mine mouth coal-fired steam-electric generators. The Susitna Project offers the lowest long- term electricity costs, but it has the drawback of high initial capital cost and offers only small increases in long-term direct employment. Natural gas-fired combined cycle generators offer increased efficiency in the utility consumption of natural gas and if natural gas prices remain subject to domestic market demands and not export demands, this option is competitive with the Susitna Project over a twenty year time frame. Coal-fired steam-electric generators can I-13 realize the advantage of economies of scale if developed in conjunction with an export mine and are only marginally less attractive than Susitna and natural gas options. Thus, where economic policy encourages low, long-term costs for Alaskans, the Susitna option affords the most economical choice. If economic policy is implemented that emphasizes employment and the opening of coal export markets, a coal-fired electric generation option offers competitive costs of electricity for the Railbelt. Conservation will continue in the Railbelt, particularly with the price increases in natural gas due to new contracts for supply. Further conservation programs sponsored by the State and utilities can greatly assist all consumers in holding down their real cost increases in energy. Energy Use in Transportation: The transportation sector will continue to be totally dependent on petroleum products. As conservation and greater fuel efficiency in the performance of motor vehicles occurs, the demand for fuels will shift to a greater percentage of diesel fuel. The “Moderate Growth” forecast shows that the demand for motor gasoline will increase only slightly, while the number of vehicle miles increases by at least 200 percent (as fleet mileage efficiency improves and fleet size increases). Diesel fuel consumption will increase by over 300 percent as construction and industrial development take place. Improvements in diesel- powered vehicles will increase their efficiency by nearly 50 percent. 1-14 CHAPTER Il ENERGY STATUS REPORT ll.1 ALASKA’S ENERGY DEMANDS AND RESOURCES Alaska’s current energy situation is complex and changing. The data available is both limited and scattered. Moving up from the detailed information found in some areas, and dis- aggregating information gathered only statewide in others, presents a substantial analytic challenge. This text discusses most topics at a fairly high level of regional aggregation: Railbelt, Southeast, North Slope, and Bush. The Alaskan economy has six basic energy sectors. Five of these, residential, commercial, industrial, transportation, and national defense, represent final demand sectors. The sixth, electric utility generation, functions as a conversion and distribution sector. The major energy sources serving demand are natural gas, oil, coal, and hydropower. In serving these six sectors, energy is lost in three basic categories: refining, processing, and electric generation. During 1981, Alaskans used 543 trillion Btus of primary energy (Figure II-1). Of that total, roughly one-half, or 273 trillion Btus, was consumed in the form of delivered energy to the residential, commercial, industrial, transportation, and national defense demand sectors. In addition, approximately 184 trillion Btus of refined products, ammonia/urea, and liquefied natural gas (LNG) were exported from Alaska (Figure II-2). The remainder was lost in refining (approximately 24 trillion Btus), in electric generation (approximately 30 trillion Btus), and in the processing of natural gas for ammonia/urea and LNG (approximately 32 trillion Btus). In-state demand for petroleum products, natural gas, and other energy is shown on Table II-1. Three main points emerge from an examination of the statewide energy balance. First, energy demand in Alaska is served primarily by four energy resources: oil, natural gas, coal, and hydroelectric power (Figure II-3). Of these resources, oil and natural gas predominate, supply- ing approximately 93 percent of the Btus delivered to the final demand sectors (Figure II-4). These two resources thus represent the major sources of energy for all six energy sectors in Alaska. This dependence on oil and natural gas is of critical significance to strategic energy planning. While it persists, Alaskans’ domestic energy prices will be vulnerable to world market price changes. Furthermore, since the State receives the majority of its revenues from oil, any major shift in world markets to other energy sources will increase its ability to maximize revenues. Second, transportation and feedstocks together account for 58 percent of the total energy demand (Table II-1). Feedstocks, by definition, are fossil fuels. The State’s planning opportu- nities are limited in this sector. The State can restrict the volume exported through its permitting process; it cannot, however, replace the fossil-fuel feedstocks. Changing transpor- tation energy consumption to non-petroleum fuels poses both economic and technical diffi- culties. Alaskans’ dependence on inflexible air and highway transportation options limits the State’s energy planning opportunities in this sector as well. II-1 FIGURE Il-1 ALASKA 1981 ENERGY BALANCE (Billions of Btus) Imports of Petroleum Products 83,162 Exports: A Petroleum 98,973 Natural Gas 84,588 Ammonia/ Crude Oil Input teat Urea Natural Gas to Refineries LNG 199.249 238,586 116.572 Losses: Petroleum 24,091 Natural Gas 31,984 Utility Refineries Primary Fuels Other Energy: Petroleum for Elect Products Generation Sais ee 198,684 : 46,644 Wood 3,100 a Residential 31,035 National Defense 27,537 Commercial/ Public 16,357 Trans- portation 127,444 Industrial 70,839 *Petroleum products exports — excludes North Slope crude. **Primary fuels for industrial and military self-generation are included in industrial and national defense consumption. Source: Arthur D. Little, Inc., estimates. II-2 FIGURE Il-2 CRUDE OIL AND NATURAL GAS FLOWS CRUDE OIL 238,586 BBtus* (100% of Crude Oil Input) EXPORTS 98,973 BBtus (42% of Crude Oil Input) LOSSES Oil Input) IN-STATE CONSUMPTION 115,522 BBtus (48% of Crude Oil Input) *Excludes North Slope crude. Source: Arthur D. Little, Inc., estimates. 24,091 BBtus (10% of Crude II-3 NATURAL GAS 199,249 BBtus (100% of Natural Gas Input) PROCESSING LOSSES 31,984 BBtus (16% of Natural Gas Input) EXPORTS 84,588 BBtus (42% of Natural Gas Input) IN-STATE CONSUMPTION 82,677 BBtus (41% of Natural Gas Input) TABLE Il-1 —1981— IN-STATE DEMAND FOR PETROLEUM PRODUCTS, NATURAL GAS, AND OTHER ENERGY Percent Billions of Btus Transportation 30% 127,444 Electric Utility Generation 11% 30,031 (Losses) Residential, Commercial, and Industrial 25% 118,231 Natural Gas Feedstock 28% 116,572 (Ammonia/Urea and LNG) National Defense 6% 27,537 TOTAL 100% 419,815** **Total energy less refining losses and exports of petroleum products. Source: Figure Il-1. II-4 FIGURE II-3 1981 ENERGY CONSUMPTION BY FUEL Railbelt 69% prong - \ Je 15% North Slope 6% North Slope Southeast 10% 2% Petroleum Products — 198,684 BBtus * 1,469.5 Million Gallons Natural Gas* — 82,677 BBtus 81.0 Billion Cubic Feet Railbelt 47% Southeast 53% Railbelt 78% Bush 10% North Slope 4% Southeast 8% Hydro — 6,196 BBtus 598.5 Gigawatt-hours All Fuels — 303,239 BBtus Railbelt 50% Railbelt Bush 11% 100% Southeast 39% Wood — 3,100 BBtus Coal — 12,582 BBtus 181,300 Cords 765,000 Tons *Includes total electric fuel demand and excludes ammonia/urea plant, LNG facilities demand. Source: Arthur D. Little, Inc., estimates. II-5 FIGURE Il-4 1981 ENERGY CONSUMPTION BY REGION Southeast 23,852 BBtus Petroleum Products 81% Petroleum Products 58% il Petroleum Products 88% Wood 1% Hydro 1% Natural Coal 5% Gas 35% Natural Gas 12% Railbelt 235,929 BBtus North Slope 12,667 BBtus Petroleum Products Petroleum Products 99% Wood 1% Hydro 2% Coal 4% Natural 7 Gas 27% Bush 30,791 BBtus Alaska 303,239 BBtus *Includes total electric fuel demand and excludes ammonia/urea plant, LNG facilities demand. Source: Arthur D. Little, Inc., estimates. II-6 FIGURE II-5 PER-CAPITA CONSUMPTION OF TRANSPORTATION FUELS, 1981 Highway Marine & Aviation - \Y Off-highway . = 400 Railroad o ¢ =~ 900 © S 3 ° a 800 * £ 300 S 5 700 © » z ~ z 2 600 6 § : 200 500 © ° = 3. z 400 © . g = | | 41300 = 5 100 : FA 200 = = 100 0 - 0 Alaska Railbelt Southeast Bush North Slope Highway 113.2 95.9 81.0 204.8 778.2* Marine 26.0 15.3 34.0 81.4 19.2 Aviation 130.0 169.1 18.7 8.2 120.7 Off-highway 31.0 20.5 82.4 39.1 88.4 Railroad 1.6 2.2 0.0 0.0 0.0 Total 301.7 303.0 216.1 333.4 1,006.4 Population Base: 422,187 *High concentration of transportation energy use in construction and oil and gas industry on a per-capita basis. Source: Arthur D. Little, Inc., estimates. II-7 The transportation sector accounts for 30 percent of in-state energy demand (Table II-1) and 64 percent of the demand for petroleum products. By comparison, the residential, commer- cial/public, and industrial sectors combined represent only one-quarter of in-state demand and 26 percent of the consumption of petroleum products. Transportation energy demands for the 1983 Energy Plan are described statewide by fuel type and end-use category (highway, marine, aviation, off-highway, and railroad). The predom- inant category of statewide transportation energy demand is aviation (Table II-2). This is accounted for by approximately 390 million gallons of jet fuel, principally because of the international airports at Anchorage and Fairbanks. The second largest category is fuel for highway use. Thirdly, the losses shown for refining and electrical generation are substantial, about ten percent of primary energy. Some changes to refineries will be made to accommodate increased runs of North Slope crude (due to changing crude oil slates) and to improve the efficiency of the refining process. Major changes in the refining capacity or production slate of Alaskan refineries seem unlikely, particularly in light of the excess refining capacity idle at present around the Pacific Rim. Electric generation, however, represents an area where some loss could be reduced. In 1981, electric utilities consumed 40 trillion Btus of fossil fuel (oil, natural gas, and coal) and six trillion Btus of hydropower equivalent (Figures II-6 and II-7). Inefficiencies arising from overcapacity, old or inadequate technology and plant, and inappropriate load management could be corrected. Currently, the average heat rate statewide (excluding industrial and national defense self-generation) is approximately 13,660 Btus per kilowatt-hour. This num- ber is 30 percent higher than rates of equivalent utilities in the Lower-48 states. In the Bush, energy generating capability is 4.6 times net generation. Furthermore, these generators operate at low rates of utilization, require backup generation for reliability, and cor- respondingly high heat rates, drastically reducing their efficiencies. Il.2 REGIONAL ENERGY BALANCES As shown in Figures II-9 through II-14, energy use varies consideraly from region to region in Alaska. The major factors responsible for these variations are climate, population, type of industry, and distance to market, as well as the efficiency of electrical generation. This uneven distribution of energy consumption and fuel availability is a central planning issue. Figure II- 8 shows the 14 energy planning regions, and the four aggregated regions. This map also shows heating degree days for selected locations. The Railbelt (Anchorage, Fairbanks, Southeast Fairbanks, Matanuska-Susitna, Kenai Penin- sula and Valdez-Cordova) region consumes 78 percent of the total energy delivered to the six basic sectors in Alaska. Of total energy delivered to the Railbelt, 11 percent is national defense (all national defense is allocated to the Railbelt), 41 percent (exclusively petroleum) goes to the transportation sector, and the remaining 48 percent is delivered to the residential, commer- cial, industrial, and electric utility sectors. Natural gas provides most of the energy for space heating and electric generation. Petroleum products are the next largest source, with coal, wood, and hydropower providing no more than seven percent of space heating and electric utility generation. II-8 oll TABLE II-2 —1981— TRANSPORTATION DEMANDS (Millions of Gallons) North Alaska Railbelt Southeast Slope Bush Highway 362.8 231.7 31.7 18.6 80.8 Gasoline 186.6 150.1 15.8 17.0 19.1 Diesel 176.2 81.6 15.9 1.6 61.7 Marine! 79.9 34.8 12.8 0.5 31.7 Aviation? 408.5 394.5 7.4 3.0 3.6 Off-Highway 94.2 46.4 30.7 2.1 15.1 Railroad 4.9 4.9 0.0 0.0 0.0 TOTAL 950.3 712.3 82.6 24.2 131.2 1. Both gasoline and diesel. 2. Jet fuel and aviation gasoline. Source: Department of Revenue and Arthur D. Little, Inc., estimates. FIGURE II-6 1981 UTILITY PRIMARY FUEL CONSUMPTION BY REGION Coal 14% Natural Gas 74% Railbelt 40,115 BBtus 3,343.1 GWH Sales Petroleum Products 11% ; les 4,869.1 GWH Sale Hydro 13% Alaska 46,644 BBtus 4,869.1 Gigawatt-hours Sales *Includes industrial self-generation. Source: Arthur D. Little, Inc., estimates. II-10 Zn Products 5% Zr \vysr0 7% Petroleum Products 21% Hydro 79% Southeast 4,157 BBtus 761.4 GWH Sales Petroleum Products 35% North Slope 473 BBtus 575.7 GWH Sales* Petroleum Products 100% Bush 1,899 BBtus 188.9 GWH Sales FIGURE II-7 1981 UTILITY PRIMARY FUEL CONSUMPTION BY FUEL Railbelt 42% ———_] North Slope 1% Southeast 17% Bush North Slo 38% Natural Gas 3% viel eee Petroleum Products 29.4 Billion Cubic Feet 5,083 BBtus 36.6 Million Gallons Railbelt 100% Railbelt 86% Coal 5,407 BBtus 328,900 Tons Bush 4% North Slope 1% Southeast 9% All Fuels 46,644 BBtus 4,869.1 Gigawatt-hours Sales Southeast 53% Hydro 6,196 BBtus 598.8 Gigawatt-hours Source: Arthur D. Little, Inc., estimates. I-11 FIGURE Il-8 ENERGY PLANNING REGIONS Heating Degree 1981 Square Energy Planning Region Days Population Miles Railbelt 313,863 113,092 1 Anchorage 10,911 185,365 1,732 2 Fairbanks 14,345 59,788 7,404 3 Kenai Peninsula 9,803 27,191 16,056 4 Matanuska-Susitna 10,849 19,607 24,502 5 Valdez/Cordova 10,155 9,070 39,229 6 Southeast Fairbanks 13,698 12,842 24,169 Southeast 51,497 36,044 7 Juneau 9,006 21,613 2,626 8 Other Southeast 8,132 29,884 33,418 9 North Slope 20,265 3,323 90,955 Bush 53,504 330,742 10 Yukon-Koyukuk 15,116 8,255 159,099 11 Kobuk-Nome 15,134 9,980 55,464 12 Wade-Hampton-Bethel 13,203 12,689 53,920 13 Dillingham-Bristo! Bay-Kodiak 8,860 15,619 51,369 14 Aleutian Islands 9,865 6,961 10,890 Alaska 422,187 570,833 II-12 FIGURE II-9 1981 REGIONAL ENERGY CONSUMPTION BY END-USE Commercial/Public 5% Utility Losses 2% Residential Industrial* 20% Industrial* 10% 64% Vehicular and . Aviation Fuels Commercial 24% Public 6% ° Off-Highway 2% Off-Highway 2% North Slope Residential 3% 12,667 BBtus Vehicular and Utility Losses 12% Aviation Fuels 38% Military 12% Railbelt 235,929 BBtus Residential 15% ff-Highwa Industial 29% Commercial/Public c 9) wey ° 18% 5% Commercial ‘ Public Military Vehicular 3% ; 9% and , Industrial Aviation Utility Losses 6% 23% Fuels Southeast 29% 23,852 BBtus Off-Highway 4% Residential 12% Residential Off-Highway 10% Vehicular and 7% Aviation Fuels 38% Industrial 24% Vehicular and Commercial/ Alaska Aviation Fuels Public 2% 303,239 BBtus 51% Utility Losses 4% Bush t “Electricity self-generation losses are not included. 3:79! BBtus **Excludes ammonia/urea plant and LNG facility. Source: Arthur D. Little, Inc., estimates. II-13 FIGURE II-10 1981 BASIC ENERGY SECTOR CONSUMPTION BY REGION Bush 10% North Slope 14% Southeast 10% Bush 12% Industrial 70,839 BBtus North Slope 1% Railbelt 75% Bush 4% North Slope 4% Southeast 4% Railbelt Southeast 12% Residential 31,035 BBtus Railbelt Commercial Public 100% 16,357 BBtus Natianal Defense 27,537 BBtus Railbelt_ ==} Bush 4% Bush 16% 86% North Slope 5% north Slope 2% Southeast 33% Railbelt 49% Southeast 5% ; Utility Losses Off-Highway 30,031 BBtus 13,069 BBtus Railbelt 77% Sion Slope 3% Southeast 6% Bush 14% Bush 10% S—_]nortn Slope 4% Southeast 8% Railbelt 78% Vehicular and Aviation Fuels 114,375 BBtus All Sectors 303,239 BBtus *Excludes ammonia/urea plant and LNG facility Source: Arthur D. Little, Inc., estimates. Il-14 Transportation Petroleum Residential Petroleum Natural Gas Electricity Other Commercial/Public Petroleum Natural Gas Electricity Other Industrial* Petroleum Natural Gas Electricity Military Petroleum Natural Gas Coal Electricity Total FIGURE I-5 ENERGY END-USE DEMAND FORECAST “MODERATE GROWTH” SCENARIO (Billions of Btus) 1981 1982 1985 1990 1995 2000 2005 127,444 137,459 181,457 237,165 308,889 276,088 330,795 127,444 137,459 181,457 237,165 308,889 276,088 330,795 31,035 32,965 37,728 47,228 58,232 56,797 67,144 15,062 15,330 17,608 22,720 29,408 28,524 34,237 8,261 8,945 9,334 11,409 11,331 11,388 13,821 4,464 4,735 6,320 7,289 10,026 9,714 10,499 3,248 3,955 4,466 5,810 7,467 7,171 8,587 16,357 17,188 20,036 24,041 27,468 26,297 31,771 3,256 3,193 3,793 4,807 6,318 5,841 6,910 7,588 8,056 8,634 10,693 9,647 8,938 10,858 4,444 4,693 6,309 6,861 9,092 8,464 8,874 1,069 1,246 1,300 1,680 2,429 3,054 5,129 70,839 77,120 95,041 124,318 152,176 192,574 249,252 32,543 34,701 40,363 41,159 51,588 71,667 84,490 32,280 35,927 46,219 73,598 89,307 109,169 151,928 6,016 6,492 8,459 9,561 11,281 11,738 12,834 27,537 =27,537 27,537 27,537 27,537 27,537 27,537 15,364 15,364 15,364 15,364 15,364 15,364 15,364 4,590 4,590 4,590 4,590 4,590 4,590 4,590 5,893 5,893 5,893 5,893 5,893 5,893 5,893 1,690 1,690 1,690 1,690 1,690 1,690 1,690 273,212 292,269 361,799 460,289 574,302 579,293 706,499 *Excludes exports and demands for feedstocks since these are forecast exogenously but does account for losses in petroleum refining and natural gas processing. Source: Arthur D. Little, Inc., estimates. I-11 tll FIGURE I-6 ELECTRIC GENERATION FUEL-USE FORECAST “MODERATE GROWTH” SCENARIO (Billions of Btus) 1981 1982 1985 1990 1995 2000 2005 Total Electric Generation* — Fuels Demand 67,626 70,579 93,982 94,722 107,092 103,479 103,563 Petroleum 16,556 17,138 22,909 24,661 20,903 17,616 18,117 Natural Gas 36,687 38,633 54,984 52,176 38,244 36,697 9,435 Coal 8,187 8,269 8,713 8,056 3,995 5,244 0 Hydropower 6,196 6,539 7,376 9,829 43,950 43,922 76,011 Total Electricity Consumed — By Fuel 16,614 17,610 22,778 25,401 32,089 31,606 33,897 Petroleum 4,517 4,793 4,900 6,008 5,305 4,912 5,787 Natural Gas 8,069 8,675 12,958 13,673 10,599 10,200 2,376 Coal 1,986 2,008 2,114 1,952 980 1,289 0 Hydropower 2,042 2,134 2,806 3,768 15,205 15,205 25,734 *Includes industrial and military self-generation. Source: Arthur D. Little, Inc., estimates. FIGURE Il-11 1981 RAILBELT ENERGY BALANCE (Billions of Btus) Natural Gas 81,120 Petroleum Products 137,762 Losses from Industrial Self- Generation and Electric Utilities 28,710 Primary Fuels . for Electric an = 582 Generation 40,115 — Trans- portation 95,145 National Defense 27,537 Commercial/ Public 14,499 Industrial 46,829 Residential 23,209 Source: Arthur D. Little, Inc., estimates. II-15 FIGURE Il-12 1981 SOUTHEAST ENERGY BALANCE (Billions of Btus) Petroleum Products 19,362 Losses from Industrial Self- Generation and Electric Utilities 1,560 Other Energy: Hydro 3,293 Wood 1,197 Primary Fuels for Electric Generation 4,158 National Defense n.a. Commercial/ Public 634 Trans- portation 11,171 Industrial 6,822 Residential 3,665 Source: Arthur D. Little, Inc., estimates. II-16 FIGURE II-13 1981 NORTH SLOPE ENERGY BALANCE (Billions of Btus) Petroleum Products Natural Gas 11,109 1,558 Losses from Industrial Self- Generation and Electric Utilities (1,491) Primary Fuels for Electric Generation 473 Commercial/ Public 573 Trans- portation 3,303 National Defense n.a. Industrial 9,906 Residential 376 Source: Arthur D. Little, Inc., estimates. II-17 FIGURE Il-14 1981 BUSH ENERGY BALANCE (Billions of Btus) Petroleum Products 30,450 Losses from Industrial Self- Generation and Electric Utilities 1,255 Primary Fuels for Electric Other Energy: Generation Wood 342 1,899 National Defense n.a. Commercial/ Public 650 Trans- portation 17,822 Residential 3,784 Industrial 7,281 Source: Arthur D. Little, Inc., estimates. I-18 The Bush has the second greatest demand for energy delivered to the six basic sectors, at ten percent of the State total. The major energy source in this region is petroleum, which supplies 99 percent of energy needs. Wood accounts for the other one percent. Transportation consumes 57 percent of total energy delivered while space heating, electric generation, and industrial cogeneration employ the rest. (Refer to Appendix H for a description of regional industrial energy allocations.) The Southeast region accounts for eight percent of total energy delivered to the six basic sectors in Alaska. The major energy source in this region is, once again, petroleum, at 81 percent; wood (five percent) and hydropower (14 percent) account for the remainder. Transpor- tation consumes 47 percent of total energy delivered; space heating, electric utility generation, and industrial cogeneration account for the other 53 percent. The North Slope, which we consider separately from the rest of the Bush because of oil and gas activities in Barrow and Prudhoe Bay, represents four percent of State demand. Petroleum provides the vast majority (88 percent) of the total energy delivered to the six basic sectors. Natural gas supplies the remaining 12 percent. In contrast to other regions, transportation only consumes 26 percent of total energy delivered. Several observations of critical importance to energy planning can be made about the break- downs of regional energy demand. Clearly, the Bush and North Slope are almost entirely dependent on oil. The Railbelt, on the other hand, is served by a fairly wide variety of additional resources, including natural gas, coal, hydropower, and wood. In the Southeast, energy demands are served almost exclusively by petroleum products, with some supplemen- tal hydropower and wood. Planning for future energy supplies and systems in Alaska must take into account the State’s enormous dependence on oil. The ability to switch away from oil to other fossil fuels or even alternative energy sources will be heavily dependent on future prices of oil in world markets. World oil prices will determine the price changes that Alaskan consumers must absorb. Furthermore, the impact of any shift from one energy resource or delivery system to another will vary considerably, depending on the region in which it takes place. One of the most critical measures of regional energy demand for planning purposes in Alaska is per-capita energy end-use. End-use is composed of the five final demand sectors, and excludes electric utility generation. We also exclude from further consideration national defense, a sector for which the State cannot plan. As shown in Figure II-15, per-capita energy consumption in the North Slope region (for residential, commercial, and transportation end- uses) is three times that found in the Railbelt. Per-capita demand for residential space and water heating energy is 55 percent higher in the North Slope than in the Railbelt, while the Bush and Southeast each consume the equivalent of approximately 96 percent of the Railbelt’s demand (Figure II-16). The Bush, North Slope, and Southeast use proportionately much less electricity per capita, however, than does the Railbelt, at levels of 24 percent, 48 percent, and 89 percent, respectively. II-19 FIGURE Il-15 1981 PER-CAPITA CONSUMPTION OF RESIDENTIAL, COMMERCIAL, AND TRANSPORTATION FUELS Residential 500 AA mmm onan 400 BRT BON POO XOX OY OOO Mirttts BRAT QF OAL ROO OSS Y OO RRR ROOT RRR EXERT RRNA CARRE — RARE OIA BRR OORT RE OSA PA OASIS RRR REX RRR KS ane KR ‘ m7 300 PRR cs Se RO OO wx OOOH PRR RXR] RT BST RXRXRKE BRN XK EXRX RK BY BEXAR BARA RRR x BRAK OORT BARB EAR ROKR RRS OF BRR AAR QO PRR KERR RK SK XRAY RN RNA RXRKKR RC RR SARE LEXAR RE BOA RR BEREAN RRA ON POX RARE BRIAN RO RASA — RRR EN PXXEAXERRYRRT BANA Werrorerets ROI RRR EX RRRRNT— BAXXAXXXX RXR BRNO XRAY BARRO eS 3S ox SoS = roses 3S 3S ret SSSSOSOSOSS PORK RXR PORK RXR ORR R KY PRR RRR PKK RK BKK RK XR] ROARK RRS RXR EK RXR — PRA QO RR RO REX PKK RRR BRR RRS RRR XR ret Ses es Ses xt 2S = 3 2S 3S ree eS 2S S3s Ses 3 SoS 3S 23 SoS ret 333 <r SoS 2 SS aK KR ORRX RR ERY PRR PKR RR KERNEN R RY OOOO KX XX iy 100 PKA POA Bs MMBtus per Capita (Except North Slope) KO RRA KAR RL KEKE RRR XO RRS RK ESSSRXXXYS x XK . DORR POX RXR ERY BORA RRL) OR RRR RX EXX RXR RA KXAN RRR ROX RRX NERS RXR RY RY RXR NY OOOO RY RY KX 1,300 1,200 1,100 1,000 900 800 700 600 500 400 300 200 100 0 Alaska Railbelt Southeast Bush North Slope 114.6 Residential 73.5 74.0 70.9 ae ae Commercial 38.7 46.2 12.3 Ho Mee Transportation 301.9 303.0 216.1 ; F ‘ TOTAL 414.1 423.2 299.3 416.4 1,295. Source: Arthur D. Little, Inc., estimates. I-20 (Ajuo adojg YON) eydeo sed smgw MMBtus per Capita FIGURE II-16 1981 PER-CAPITA RESIDENTIAL CONSUMPTION 120 Thermal (space and water heating) Other 110 100 90 80 70 60 50 40 30 20 10 Alaska Railbelt Southeast Bush North Slope Source: Arthur D. Little, Inc., estimates. II-21 A comparison of energy costs for electricity and fuel oil for the residential sector shows the underlying disparity in energy prices between rural and urban or industrialized regions (Figure II-17). Fuel oil costs approximately $9.68 per MMBtu in the Railbelt. In the Bush, however, the same fuel costs approximately $12.95 per MMBtu, or 34 percent more (on average). However, in certain locations, the prices are substantially greater. The State’s various assistance programs reduce the cost to consumers from these very high price levels. Electricity too is substantially more expensive (by approximately 383 percent) in the Bush than in the Railbelt, since it is almost exclusively derived from inefficient, oil-fired generators. Fuel oil costs in the Southeast are approximately 97 percent of those in the Railbelt, while electricity is 30 percent more expensive. The North Slope pays approximately $12.57 per MMBtu for fuel oil, and $38.69 per MMBtu for electricity (224 percent more than the Railbelt). These electricity prices are average consumer prices which include the benefit of the Alaska Power Assistance Program. Under the Power Cost Assistance Program, payments are made to utilities to lower the cost of power to consumers in areas where costs are high. Local utility customers are billed at the lower power cost. An eligible electric utility is entitled to receive power cost assistance for sales of power to residential and commercial customers and to local community facilities. The assistance is calculated in the aggregate for each community served by the electric utility, based on actual consumption of the first 600 kilowatt-hours per month sold to each customer and not more than 55 kilowatt hours per resident for consumption by local community facilities. The amount of power cost assistance provided per kilowatt-hour may not exceed 95 percent of the power cost, or the average rate per eligible kilowatt-hour sold, whichever is less. The Alaska Public Utilities Commission determines utility eligibility and power costs, and sets rates for State assistance per kilowatt-hour sales for individual utilities. The Alaska Power Authority disburses assistance funds to eligible utilities based upon power cost assistance determined by the Commission and statements of sales to eligible customers submitted by the eligible utilities. The program is funded through fiscal year 1983 with 8 million dollars. Currently, the following utilities are receiving assistance: Akiachak Limited, AVEC, Andreanof Electric Corporation, Bethel Utilities Corporation, Bettles Light & Power, Circle Electric, Cordova Electric Cooperative, Ft. Yukon Utilities, Haines Light and Power, Hughes Power & Electric, Kodiak Electric Association, City of Kotlik, Kotzebue Electric Association, Kwethluk, M&D Enterprises, Manley Utility Company, Manokotak, Matanuska Electric Association (Unalakleet), McGrath Light & Power, Naknek Electric Association, Napakiak Power, Napaskiak, Inc., Nome Joint Utility System, Northern Power & Engineer- ing Corp., Northway Power & Light, Nushagak Electric Cooperative, Ouzinkie Utilities, Pelican Utility Company (Sand Point), the City of Ruby, Takotna Community Association, Tanana Power Co., Tatitlek, Tlingit-Haida Regional Electric Authority, City of Unalaska, and Yakutat Power. In summary, the Railbelt, which accounts for the vast majority of energy demand and boasts the broadest spectrum of end-uses in Alaska, also has access to the widest range of energy sources at the lowest prices in the State. The Southeast region, with a less extensive selection of available energy sources, has the next lowest energy costs. North Slope residents (excluding oil and gas workers) pay high prices for petroleum products, despite the presence of extensive oil fields, because they must import all of their refined fuels. The Bush, utterly dependent on oil that has accumulated costly delivery charges, bears the heaviest price burden. II-22 FIGURE Il-17 1981 COMPARISON OF AVERAGE RESIDENTIAL FUEL OIL AND ELECTRICITY PRICES* United States verage 20.0 = 15.0 = 3 @North Slope 2 S 10.0 3 United States Ww Average 6.2¢ 5.0 1.00 1.25 1.50 1.75 2.00 Fuel Oil ($/gallon) ($/MMBtu) Fuel Electricity Oil Railbelt $ 9.68 $17.24 Southeast 9.43 22.44 Bush 12.95 66.08 North Slope 12.57 38.69 *Subsidies included in price averaging. Source: DEPD Community Survey; Alaska Power Administration, Annual Report; Energy Information Administration, Monthly Energy Review. II-23 ll.8 ALASKA’S ENERGY RESOURCES Alaska is endowed with large oil, natural gas, coal, and renewable energy resources. The magnitude of these resources dwarfs Alaska’s current energy demand and will continue to outstrip it well into the twenty-first century. Not only are the energy resources large, but they are also located for the most part in accessible areas of the Railbelt and North Slope regions. In addition, Alaska’s resources enjoy healthy markets. They are available to most in-state consumers at reasonable prices; some are (and others could be) brought to world markets at competitive prices. Currently, of course, oil is experiencing the greatest market demand, both in-state and for domestic consumption in the Lower-48 states. Natural gas produced in the Cook Inlet is marketed in Alaska, and at present a small amount is exported to Japan in a liquefied form. Natural gas fields off Barrow are used by local consumers and, along with with Prudhoe Bay area reserves, could also be made available for domestic use or for export at present world prices. The coal reserves throughout Alaska, now supplying markets around Fairbanks with fuel for electric and steam generation, have potential for future export to Pacific Rim markets. 11.3.1 Oil Today, oil is Alaska’s most important energy resource. Not only does Alaskan crude oil directly supply 58 percent of Alaska’s refined petroleum products, but it also serves as the State’s main source of revenues. In 1982, these revenues are expected to total more than three billion dollars. The location of identified oil and natural gas basins is shown in Figure II-18 and Table II-3. The largest known proven reserves are located in the North Slope region, with other promis- ing, though undeveloped, basins scattered around the State. Proven reserves of crude oil in the State are estimated at 8.7 billion barrels onshore and 0.2 billion barrels offshore. The aggregate reserve-to-production ratio in Alaska is nearly 14 years at current production levels. For specific fields, the rate can vary from as little as two years for some reservoirs in the Cook Inlet, to as high as 15 years for portions of the North Slope. See Appendix A for a detailed discussion of this subject. A) In-State Refining There are four in-state refineries: Chevron’s Kenai refinery with a capacity of 22,000 barrels per day; Tesoro’s Kenai refinery with a capacity of 48,500 barrels per day; Mapco’s North Pole refinery with a capacity of 46,000 barrels per day (Figure II-19); and ARCO’s topping refinery of 14,000 barrels per day at Prudhoe Bay. Union Oil owns a small asphalt refinery in Anchorage. Both Mapco and Chevron process 100 percent Alaska North Slope (ANS) crude oil. Mapco draws the crude off the Trans-Alaska Pipeline (TAPS) as it passes Fairbanks. Chevron picks up the crude at Valdez (the end of the pipeline) and ships it by tanker to Kenai. Tesoro currently utilizes crude oil from Cook Inlet (90 percent) and the North Slope (10 percent); however, as oil production from Cook Inlet declines, Tesoro will need to use more ANS crude. Mapco and Tesoro both purchase royalty crude oil from the State. (Chevron is negotiating with the State for the purchase of royalty crude.) I-24 FIGURE Il-18 STATE OF ALASKA CRUDE OIL AND NATURAL GAS BASINS Beaufort Sea Chukchi North Slope \ Bering Sea Hope Dnorton Navaring St. Matthew-Hall Cook Inlet “fa Kodiak St. George ¢ North Aleutian Shumagin Aleutian Are LF FD Aleutian Crude Oil (Billions of Barrels) North Bering Gulf of Total Slope Sea Alaska* Alaska Proven Reserves 8.3 _ 0.6 8.9 Undiscovered Reserves: 95% Probability 3.1 — 0.2 wa Mean 14.4 1.8 1.9 19.1 Natural Gas (Trillion Cubic Feet) North Bering Gulf of Total Slope Sea Alaska* Alaska Proven Reserves 29.02 _ 3.0 32.02 Undiscovered Reserves: 95% Probability 16.4 — 1.8 53.1 Mean 73.5 13.2 10.5 101.2 *Includes Cook Inlet; currently the only proven reserves. Source: U.S. Department of the Interior Geological Survey, Estimates of Undiscovered Recoverable Resources of Conventionally Producible Oil and Gas in the United States, Open File Report 81-192, 1981. I-25 NORTH SLOPE BUSH RAILBELT SOUTHEAST TABLE II-3 CRUDE OIL AND NATURAL GAS REGIONAL AVAILABILITY Basins: North Slope, Arctic Foothills, National Petroleum Reserve, National Wildlife Reserve, Beaufort Sea, Chukchi Sea, and Hope Existing infrastructure and distribution channels for crude oil; natural gas is produced, however, no current means to market exist Acquired expertise in Arctic environment can be extended to new developing areas Basins: Norton, Navarin, St. Matthew-Hall, St. George, Aleutian Chain, and Shumagin Limited infrastructure; no distribution channel; Yukon region has Trans-Alaska Pipeline (however, the Yukon has limited hydrocarbon potential) Bering Sea is an area of increased exploration activity Basins: Cook Inlet, Kodiak, and Gulf of Alaska Exiting infrastructure and distribution channels at Cook Inlet for both crude oil and natural gas Location of two refineries, a LNG export facility, an ammonia/urea manufacturing plant, and the terminus of the Trans-Alaska pipeline Basin: Gulf of Alaska Area of limited potential II-26 Percent of Product Slate FIGURE II-19 REFINERY PRODUCT SLATES Jet Fuel Diesel Mogas LPG Product Exported from Alaska 100 90 80 70 60 50 40 30 20 10 Mapco Chevron Tesoro Source: Arthur D. Little, Inc., estimates. I-27 Alaskan refining will not change greatly in the next 20 years with only Tesoro expanding its capacity. Tesoro is the only refiner that will have to change its operations as Cook Inlet crude declines. The option of putting residual fuel oil and light ends back into the pipeline is not available to it, and it will have to deal with the heavier ANS crude oil. In the process of changing the refinery, Tesoro will expand its existing hydrocracker to handle ANS gasoline, but it seems unlikely that Tesoro will complicate its operation to include a coker. Product specifications and coke disposal problems may prove insurmountable. It seems likely that Chevron will continue its present practice, shipping light and heavy products to the West Coast to be processed while producing straight run distillates. In this way Chevron can continue to avoid costly investment alternatives and utilize its West Coast refineries more fully. It may add a small reformer (10,000 to 30,000 barrels per day) in 10 to 15 years, as its West Coast operations become more fully utilized, to produce all grades of gasoline (see Appendix A). Both North Pole Refining and ARCO face similar problems: if they try to use naphtha as a reformer feedstock, they will no longer need pipeline specifications for the rejected materials. Alaska will continue to import aviation gasoline, as no refinery is likely to invest in a gasoline hydrocracker or alkylation unit. Demand for premium motor gasoline may be met by reformer capacity additions. Certainly Alaska will continue to export fuel oil. Refining capacity in Alaska is adequate to support increased transportation and home heating needs, given the problems of bottoms disposal. There may be some scope for increased capacity in existing locations. It seems unlikely, however, that transportation costs would make new locations for refineries economically viable. Adverse climate would hamper the construction of any new refineries. In the short term, refined products in Alaska due to local market strength, will hold their prices in real terms or increase while world crude oil prices hold constant or decline. Figure II-20 shows the distribution flows of petroleum products throughout the State. 11.3.2 Natural Gas Alaska has proven natural gas reserves in the North Slope region and in the Cook Inlet area, estimated at 29 trillion cubic feet and three trillion cubic feet, respectively. Gas from the Cook Inlet fields is used primarily to serve in-state thermal and electric generation demand at the residential, commercial, and industrial levels. Anchorage, Kenai, Prudhoe Bay, and Barrow all use significant quantities of natural gas. Natural gas from North Cook Inlet is reinjected to maintain pressure in the Swanson River oil field. Production of natural gas in 1981 was approximately 2.5 billion cubic feet per day. The State expects to receive 14.6 million dollars in natural gas production taxes and royalties from Cook Inlet and 3.4 million dollars from the North Slope in 1982. These monies are projected by the Department of Revenue to increase substantially, to 90.7 million dollars by 1998. In addition to the gas fields currently in production, another 171.9 billion cubic feet of undiscovered resources (at 5 percent probability) are estimated to remain untapped in Alaska. Current reserves in Cook Inlet are sufficient to meet thermal and electric generation needs for an expanded Anchorage area and the Kenai Peninsula through the year 2000. If liquefied natural II-28 67-11 Barge FIGURE II-20 PETROLEUM PRODUCT DISTRIBUTION FLOWS Refineries Chevron — Kenai — 22 MB/D 8 Tesoro — Kenai — 48.5 MB/D @) North Pole — Fairbanks — 46 MB/D @ Arco — Prudhoe Bay — 14 MB/D Transportation Modes Trans Alaska Pipeline System Siete Tanker —-—-— Barge \aseeeeeeeees Truck Hi4++4 Railroad Pipeline “\. Ex-California ~~~] \ All Products; Re-Supply / Tanker ExNikiski Barge from ae / is to California coe to r etchikan, een ee —«— __ _ Tanker eee! Valdez, Ex-California Anchorage and (All Products) Dutch Harbor gas exports increase, however, the availability of natural gas for local consumption (partic- ularly for electric generation) may become more problematic. Market conditions permitting, the construction of a natural gas pipeline from the North Slope through the south central region to Nikiski could provide enough natural gas to meet Anchorage area demand (as well as opening opportunities for natural gas uses in Fairbanks). A) Natural Gas Processing There are two natural gas processing facilities in Alaska: the Phillips liquefied natural gas (LNG) plant and the Union Chemical ammonia/urea plant, both located in Kenai. LNG has been exported to Japan since 1969 under a 13 year (plus five year renewable) contract. Phillips has recently extended this agreement for five years. The facility processes about 50 billion cubic feet of Cook Inlet natural gas annually. The natural gas is liquefied and shipped to Japan via LNG tanker. Union Chemical manufactures ammonia and urea from Cook Inlet natural gas. Input volumes are 50 to 51 billion cubic feet annually, and over 99 percent of the plant’s output is exported from Alaska. 11.3.3 Coal Although Alaska’s coal resources are thought to at least equal the sum of the rest of the United States’ known deposits, they remain largely unexplored and undeveloped because of their inaccessibility. At present, Usibelli (at Healy near Fairbanks) is Alaska’s only major produc- ing coal mine. In 1981, Usibelli produced more than 800 thousand tons of coal, destined primarily for use in electric generation. The locations of identified coal deposits are exhibited in Figure II-21. Proven reserves amount to approximately 1.3 billion tons. The quality of Alaska’s coal (particularly its heat content) varies widely, from lignite through sub-bituminous to bituminous and anthracite. In the Cook Inlet area, the Beluga field has lower quality coal with a high moisture content and high ash. Higher quality coal is located in the Bering River and Northern Alaska fields. One notable feature of Alaskan coal is its low sulfur content, which makes it less “dirty” than coal of similar Btu content elsewhere. Future development of these resources will depend mostly on economies of scale. While small fields in Bush regions could conceivably supply local utilities, the technology of mining in permafrost and general climatic conditions make the expense daunting, if not prohibitive. Unless more coal-fired electric utilities are built in-state near major population centers, or substantial Pacific Rim markets emerge for the higher-grade coal, Alaskan coal will remain in the ground awaiting future demand and the right price. See Appendix B for further detail on this subject. 11.3.4 Peat Alaska’s permafrost-free peat deposits (Figure II-22), estimated at 27 to 107 million acres, represent more than half of U.S. total peat reserves. Forty-seven million acres are located five feet or less from the surface. Of the 47 million acres, some 30 million acres show promise as an energy resource. A 1980 survey by the Department of Energy investigated peat in the II-30 FIGURE Il-21 ALASKAN COAL RESERVES BY 147 MAJOR FIELDS (Millions of Tons) 70 68 66 64 62 60 OCEAN _ Northern Alaska Fields. : pa Jarvis Creek 37 ~ Field © \ , rn. , ov Matanuska Field Bering| River — 4! oe Broad Pass, IN Field 150 146 142 138 Proven Indicated Hypothetical Reserves Reserves Reserves Northern Fields 235.0 49,000-120,000 330,000 Nenana Field 861.1 6,000 8,700 Jarvis Creek Field 0.3 13-76 0 Susitna (Beluga) 275.0 2,700-10,200 27,000 Matanuska Field 6.6 108-130 149 Bering River Field 0.0 0 36-1,000 Herendeen Bay Field 0.0 10-100 300 Chignik Field 0.0 100 300 TOTAL 1,370 57,900 366,000 Source: Division of Geological and Geophysical Surveys, Department of Natural Resources, Alaska Mineral Resources, 1981-82. II-31 FIGURE Il-22 POTENTIAL ALASKAN FUEL PEAT RESOURCES Copper Center Dillingham Naknek Source: Northern Technical Services and ECONO, Inc., Peat Resource estimation in Alaska, Final Report, Vol. |, August 1980. II-32 Matanuska-Susitna Valley, Fairbanks, Kenai Peninsula, and Bristol Bay areas. The Depart- ment found peat to constitute a potentially valuable source of fuel, particularly for remote communities. At present, however, there is little use of peat for fuel in Alaska. Preliminary studies of contemplated commercial operations in the Railbelt area suggest that an operation producing peat in the range of 300,000 to 500,000 tons per year might be economically viable. With mining costs of approximately $22 to $28 per short ton, peat for use in steam electric generation plants appears economically competitive with bituminous and sub-bituminous coals priced at $2 per million Btu (see Appendix B). Developmental and operational issues associated with prototype plants need to be addressed before large-scale commercial plants can show their practical success. 11.3.5 Hydropower As with many of its other natural resources, Alaska has the nation’s largest potential for hydroelectric development (Figure II-23). At present, however, only a small percentage of that potential is being used. A total of ten hydropower projects, with a combined capacity of 123.56 megawatts, currently provide electricity to the Railbelt and Southeast regions. Approximately 15 new hydroelectric facilities (Table II-4), or an addition of 1,738 to 2,138 megawatts of hydropower capacity, are currently under consideration for development in the State. These proposed developments range in size from 0.2 megawatts at Scammon Bay to the Susitna project at 1,600 megawatts. While by its nature unsuitable for storage or export, hydroelectric power can provide an inexpensive and virtually inexhaustible source of elec- tricity. The price of obtaining that power varies according to the scale of the facility (i.e., construction costs) and the size of the demand it serves. 11.3.6 Geothermal Several areas of Alaska have geothermal potential. Figure II-24 shows areas of geothermal potential for the Railbelt. To date, however, only a fraction of that potential has actually been tapped, in the form of hot springs used for space heating and resort spas. Hot springs are located at Manley Hot Springs, Chena Hot Springs, and Tolovana in the Railbelt. Under the direction of the Alaska Power Authority, a number of geothermal sites are being investigated for their thermal energy and electric generation potential. Areas containing hot igneous systems in the Railbelt include Mt. Sanford, Mt. Drum, Mt. Wrangell, and Double Peak, among others. Other applications could include community heating and agricultural uses. Commercial applications of geothermal technologies are not as yet highly developed. 1.3.7 Wood Resources Wood is available for space heating in residences throughout Alaska, except in the North Slope region. The Southeast and the Railbelt regions of the State have sufficient acreage to allow wood harvesting. In the Bush region, some residents can collect driftwood for use as a substitute for costly home heating oil. The major limitation on harvesting wood for energy is distance from and accessibility to timber lands. Sustainable annual yields of timberlands in II-33 FIGURE II-23 SELECTED HYDROELECTRIC SITES (Railbelt) a& 0-25 Mw STRANDUINE L, 2. LOWER BELUGA 3. LOWER LAKE CR. 4. ALLISON CR, 5. CRESCENT LAKE 2 6. GRANT LAKE 7, MeCLURE BAY 6, UPPER NELLIE JUAN 9. POWER CREEK 10. SILVER LAKE 11, SOLOMON GULCH 12. TUSTUMENA Source: Railbelt Electric 13. 14, 1B, 16. 18. 19. 20. 2. 22. 23. 24, 28. 25-100 Mw WHISKERS. coay CHULITNA oMI0 LOWER CHULITNA CACHE GREENSTONE TALKEETNA 2 GRANITE GORGE KEETNA SHEEP CREEK SKWENTNA TALACHULITNA 26. 2. 28. 29. 32. 3. 35. 36. x7. sNow KENARLOWER GERSTLE TANANA R. BRUSKASNA KANTISHNA R. UPPER BELUGA COFFEE GULKANA R,, KLUTINA BRADLEY LAKE MICK'S SITE Lowe 39. a. a2. 43. 45. ar. ae. “9, ° > 100 mw LANE TOKICHITNA YENTNA CATHEDRAL BLUFFS JOHNSON BROWNE JUNCTION IS VACHON IS TAZILNA KENA! LAKE CHAKACHAMNE SUBITNA Power Alternatives Study — February 1982. II-34 cea TABLE II-4 PROPOSED HYDROPOWER FACILITIES Project Region Area Served Capacity (MW) Scammon Bay Hydro Bush Scammon Bay 0.1 Bradley Lake Railbelt Anchorage, Kenai 135.0 Susitna Railbelt Anchorage, Fairbanks, 1,200 to and Kenai 1,600 Chakachamna Railbelt Anchorage, Matanuska- Susitna 320.0 Grant Lake Railbelt Kenai 6.0 Silver Lake Railbelt Cordova 15.0 West Creek Southeast Skagway, Haines 6.0 Black Bear Lake Southeast Klawock, Craig, and Hydaburg 6.0 Tyee Lake Southeast Petersburg, Wrangle 20.0 King Cove Bush Alaska Peninsula 0.57 Larsen Bay Bush Aleutian Islands 0.27 Crater Lake Southeast Juneau 27.0 Swan Lake Southeast Ketchikan 22.0 Terror Lake Bush Kodiak 20.0 Chester Lake Southeast Metlakatla 3.0 Old Harbor Bush Kodiak 0.24 In addition, smaller hydropower facility sites have been studied in Chickaloon, Kenney Lake, Copper Center, Seldovia, Whittier, Hope, Chignik Lagoon, Chignik, Gustavus, Perryville, Unalaska, Tenakee Springs, Galena and Anaktuvuk Pass. FIGURE II-24 SELECTED GEOTHERMAL SITES (Railbelt) @ Manley © Tolovana On Fairbanks Mt. Sanford Mt. Drum Mt. Wrangell Redoubt : Anchorage , Volcano = g Augustine Volcano B gy ZZ Hot Igneous System @ Hot Springs Source: U.S. Geological Survey, 1975. II-36 Alaska range from two to four acres to support one cord of wood. Annual heating requirements for a typical home amount to 20 to 40 acres of timberland per household. However, recent energy efficient house designs reduce the annual wood consumption to the level of two to three cords instead of ten cords per year. Current prices for wood are in the vicinity of $100 to $120 per cord in the urban areas of Alaska; this compares favorably with fuel oil costs of $1.30 per gallon. In some cases, however, accessibility to woodland and harvesting costs may raise the cost of wood resources beyond levels competitive with oil. The use of wood as solid fuel for electricity generation presents several major problems. A sustainable supply of wood for fueling a steam boiler requires major economies in wood harvesting to keep future price increases down. Operation of wood-fired boilers requires skilled personnel familiar with steam electric generation and the combustion of wood fuels in large boilers. Accordingly, the best opportunities for large-scale wood-fired steam electric plants are in the Southeast, where proximity to the logging, pulp, and paper industry improves the supply of wood resources. The operation of wood or log fuel boilers can be managed in conjunction with logging and pulping operations, assuring the availability of qualified operators. 11.3.8 Wind Energy Resources Wind resources in Alaska are fortuitously located in areas where fuel area prices are high or other indigenous resources are not readily available. Alaska’s coastal regions afford the most attractive opportunities for wind energy systems. The Arctic Slope, the Aleutian Islands, and some of the more remote mountainous regions of Alaska have the greatest potential in wind energy resources. The wind can be an excellent source of electricity supply. Wind energy systems demonstrate economic pay-backs in areas where wind energy levels are in the vicinity of 2,000 watts per square meter. Wind energy systems can be scaled to service a single residence or sized in the 10 to 20 kilowatt range to provide electricity for several households in a community. When wind energy is compared to the electricity provided by diesel electric generators with fuel costs of upwards of two dollars per gallon, it appears to be a very attractive alternative, even at low operating availabilities. However, recent experience with wind turbines has demonstrated the importance of site location and attention to proper operations and maintenance in realizing these economies. 11.3.9 Tidal Power Resources Tidal energy is available in Alaska, primarily in the Cook Inlet area where the height of tidal variation and the volume of tidal flow are sufficient to make tidal power projects practical. Tidal energy can be converted into electricity by capturing both the potential energy associated with the height of tidal fluctuation and the kinetic energy associated with the flow of tidal water volume in and out of an inlet, bay, or contained area. If all the potential and kinetic energy of Cook Inlet were captured and made available to users in the Railbelt area of Alaska, it would provide electric power for the entire region well beyond the year 2050. A recent study prepared by Acres American (“Preliminary Assessment of Cook Inlet Tidal Power”) identified 16 sites in the Cook Inlet area whose total energy capacity exceeded 186,000 gigawatt-hours, with a total potential capacity of 73 gigawatts. II-37 The development of truly commercial tidal power is 15 to 20 years away. Hydrologic, engineer- ing, and environmental studies must be designed and undertaken before tidal power devel- opment can begin. Projects, like those at Eagle Bay or Point McKensey, do, however, warrant further investigation to explore their economic and engineering feasibility. 1.3.10 Solar Energy While Alaska’s solar energy resources are substantial, they are derived primarily from long summer days (at a time of year when energy demands by residential, commercial, and industrial consumers are lower). In comparison, limited solar energy is available in the winter, when the days are cold and short and current solar technologies cannot be particularly effective. Solar energy systems can be designed to work independently or in conjunction with other energy sources. In most instances, solar energy systems working in combination with existing energy sources appear to be the most practical approach, especially in meeting the consumer demand that is out of phase with solar energy potentials. Passive solar energy systems, used to supplement existing energy sources and conservation measures, can often provide an econom- ically attractive means to augment existing home heating systems. Active solar heating systems and electric systems are currently less cost-effective, as has been shown through the introduction of many applications in the Lower-48 states. Only when Federal and State tax incentives are included do these energy systems become economic for consumers. 11.3.11 Conservation Conservation in Alaska stems from two quite different sources. The first, and most important, is the response of consumers faced with rising energy costs. In this case, conservation holds down their expenditures for energy, as they invest in energy conservation measures for their home and, where practical, switch to alternative fuels. The second source of conservation is the energy conservation programs promoted by the State. Home energy audits demonstrate energy inefficiencies to the consumer and provide an incentive grant of 300 dollars for the implementation of recommended improvements. These improvements can include double glazing of windows, upgrading insulation, weather stripping, and so forth. Federal tax advantages for the installation of insulation and other energy conservation measures, as well as tax credits for alternative energy systems such as solar energy, have also provided conser- vation stimuli. In Alaska, both aspects of energy conservation are well under way. In many of the Bush regions, as well as in major cities such as Fairbanks and Juneau, where the costs of home heating and electricity are high, consumers are already responding to price by implementing energy conservation measures and switching to alternative sources of fuel. Many Bush com- munities, for example, have had their homes’ insulation increased through investments by Federal, State, and municipal agencies. In the more urban areas, such as Fairbanks, extensive insulation to improve the integrity of building envelopes can go a long way to help lower home heating bills. Furthermore, many consumers are switching to wood and coal burning stoves as sources of energy for heating. II-38 Conservation actions, however, are only economically attractive in areas where fuel and electricity costs are high. Only in areas where fuel oil and electricity prices are above a specific level do conservation programs represent a reasonable return to the consumer. As fuel and electricity costs rise dramatically, conservation alternatives become attractive. This concept has important implications for energy planning, particularly in the Anchorage area where natural gas and electricity prices are likely to rise faster than in other regions of the State (as natural gas contracts are renegotiated). For further discussion of conservation, refer to Appendix F. \.4 ENERGY PROJECTS AND PROGRAMS Currently, the State of Alaska is engaged in examining a wide variety of alternative energy supply projects. These projects include wind energy systems, geothermal heating systems, peat as fuel for electric generation, ground water heat pumps, and Stirling engine energy systems for total energy supply to Bush village homes. In addition to these energy projects, the State has under way numerous energy programs whereby consumers and industry are assisted in their efforts to develop new supplies and efficient ways to use energy. \.5 ELECTRICITY GENERATION AND DISTRIBUTION* Alaska’s electricity generation and distribution systems consist of two types: the central systems associated with electricity generation in the Railbelt, and the decentralized systems associated with electricity generation in rural regions. Electricity in Alaska is generated by utilities, industry, the military, and independent operators in rural and isolated areas. Gener- ation is fueled primarily by natural gas, diesel, and hydropower, although some electricity is generated by coal. 11.5.1 Recent Trends Between 1970 and 1981, the installed generation capacity of the State grew at a rate of 9.5 percent per year. Growth in capacity was almost twice as high for the period 1970-1977 than over the last four years. The relationship between the growth in actual electricity generation to the growth of capacity is shown in the table below: TABLE II-5 ELECTRIC CAPACITY AND ENERGY GENERATION GROWTH RATES Period Capacity Generation 1970-1977 11.5% 11.9% 1977-1981 6.0% 3.9% 1970-1981 9.5% 8.9% *Alaska Power Administration, Alaska Electric Power Statistics; ACRES. II-39 In Alaska, utilities account for 67 percent of installed capacity (1,374 megawatts), industry is next at 23.5 percent (485 megawatts), and national defense is third at 9.9 percent (205 megawatts). The overall mix of Alaska’s installed generating capacity operated by utilities has changed significantly over the last decade, as shown below: TABLE Il-6 ELECTRIC GENERATING CAPACITY (MW) Type of Generator 1970 1981 Gas Turbine 132 847 Diesel 123 246 Steam-Electric 75 158 Hydro 76 123 Total 406 1,374 Source: Alaska Power Administration, Alaska Electric Power Statistics, 1960-1981. The regional distribution of electric generators by type shows one of the primary reasons why electricity costs are low in the Railbelt and high in the Bush. In the Railbelt, electric generation is by gas turbine, fueled by low-cost natural gas; in the Bush, electricity generation is fueled by expensive diesel oil. 11.5.2 Railbelt In 1981, the Railbelt region had 1,237.5 megawatts of installed capacity (including national defense and industrial generators). TABLE Il-7 RAILBELT GENERATION CAPACITY Capacity Percent (MW) Anchorage, Matanuska-Susitna, and Kenai Peninsula 784.5 63% Fairbanks and Southeast Fairbanks 385.7 31% Valdez-Cordova 67.3 6% 1,237.5 100% Source: Arthur D. Little, Inc., estimates. I-40 A) Anchorage, Matanuska-Susitna, and Kenai Peninsula Generating capacity in this area in 1981 included 49.7 megawatts military, 64.6 megawatts industrial, and 30 megawatts hydropower (controlled by the Alaska Power Administration). Area installed capacity, excluding industrial and military, is shown below: TABLE Il-7a ANCHORAGE AREA GENERATION CAPACITY Capacity Percent (MW) Gas Turbine 582.2 87% Steam Turbine 33.0 5% Hydro 46.0 7% Diesel 9.0 1% 670.2 100% Source: Arthur D. Little, Inc., estimates. The gas turbines are all fired by natural gas; the steam turbine is a waste heat unit; and the diesels are fired by fuel oil. Area generation in 1981 was 2,650 gigawatt-hours, including 335 gigawatt-hours of industrial generation and 130 gigawatt-hours of military generation. Generation, excluding industrial and military, is distributed as follows: TABLE II-7b ANCHORAGE AREA ELECTRIC GENERATION Generation Percent (GWH) Natural Gas 1,900 87.0% Oil 4 0.2% Hydropower 281 13.0% 2,185 100.0% Source: Arthur D. Little, Inc., estimates. The Anchorage, Matanuska-Susitna, and Kenai Peninsula area is served by two municipal utilities and three cooperatives. Anchorage is served by the Municipal Light and Power Department, Chugach Electric Association, and Matanuska Electric Association. Matanuska II-41 Electric also serves the Matanuska-Susitna Borough. The Kenai Peninsula is served by Homer Electric Association and Chugach Electric Association, except for the City of Seward which has a municipal system, Seward Electric System. Anchorage Municipal, Chugach, and Matanuska Electric buy power from the Alaska Power Administration which operates the Eklutna hydroelectric project. Matanuska Electric, Homer, and Seward all buy power from Chugach. B) Fairbanks and Southeast Fairbanks In 1981, the Fairbanks and Southeast Fairbanks area was 385.7 megawatts of installed capacity, including 73.5 megawatts of military capacity. Non-military capacity is shown below: TABLE II-7c FAIRBANKS AREA GENERATION CAPACITY Capacity Percent (MW) Steam Turbine 68.0 22% Gas Turbine 202.9 65% Diesel 41.3 13% 312.2 100% Source: Arthur D. Little, Inc., estimates. All steam turbine capacity is coal-fired. Gas turbines and diesels are oil-fired. Generation was 662 gigawatt-hours in 1981, including 181.5 gigawatt-hours of military generation. Non- military generation is distributed as follows: TABLE Il-7d FAIRBANKS AREA ELECTRIC GENERATION Generation Percent (GWH) Coal 400.7 83% Oil 79.8 17% 480.5 100% Source: Arthur D. Little, Inc., estimates. II-42 Fairbanks is served by Golden Valley Electric Association, a cooperative, and by the Fair- banks Municipal Utilities System, which in addition to self-generation purchases power from national defense facilities. Small communities in Southeast Fairbanks are served by the Alaska Power and Telephone Company, Tanana Power Company, and small village utilities. C) Valdez-Cordova The Valdez-Cordova area had 67.3 megawatts of capacity in 1981; the majority of that, 40 megawatts, is industrial capacity connected with the pipeline terminal in Valdez. Non- industrial capacity is all diesel with the exception of a 2.8 megawatt gas turbine in Valdez. Total generation is 101 gigawatt-hours, all oil-fired, including 38.7 gigawatt-hours of indus- trial generation. This area is served by two cooperatives: Copper Valley Electric Association in Glennallen and Valdez, and Cordova Electric Cooperative. 11.5.3 Southeast Generation in the Southeast is primarily hydropower and oil-fired diesel. Total capacity in the Southeast was 249 megawatts in 1981, of which 68.3 megawatts was industrial capacity used to power the pulp mills. Forty-seven megawatts of hydro capacity is controlled by the Alaska Power Administration. Non-industrial capacity in the Southeast is installed as follows: TABLE II-8 SOUTHEAST GENERATION CAPACITY Capacity Percent (MW) Hydro 81.4 45% Diesel 81.8 45% Gas Turbine 17.5 10% 180.7 100% Source: Arthur D. Little, Inc., estimates. Generation in the Southeast was 705.2 gigawatt-hours in 1981, including 310.6 gigawatt- hours of industrial generation. Non-industrial generation is distributed as shown below: I-43 TABLE Il-8a SOUTHEAST ELECTRIC GENERATION Generation Percent (GWH) Hydro 318.0 81% Oil 76.6 19% 394.6 100% Source: Arthur D. Little, Inc., estimates. The Southeast is served by four private utilities: Alaska Electric Light and Power Company in Juneau; Alaska Power and Telephone Company in Skagway and several surrounding commu- nities; Haines Light and Power Company; and Yakutat Power, Inc. The Alaska Power Administration controls 47 megawatts of hydro capacity. The communities of Sitka, Ketchi- kan, Wrangell, Petersburg, Metlakatla, and Klukwan are served by municipal utility systems. There are also two cooperatives in the Southeast. The Tlingit-Haida Regional Electric Authority serves five small communities. The Glacier Highway Electric Association also runs a small diesel in Juneau. 11.5.4 Bush The Bush region is almost exclusively dependent on oil-fired diesel generation, with the exception of gas-fired generation in Barrow. Regional centers are served by municipal utilities (Nome), private utilities (Bethel, Fort Yukon), or cooperatives (Kotzebue, Barrow, Dilling- ham). Villages are served through the Alaska Village Electric Cooperative (which serves 48 communities), other central village generators, school generators, or small private generators at individual residences. A) Alaska Village Electric Cooperative The Alaska Village Electric Cooperative (AVEC) serves 48 communities with generators in 44 communities and tie lines to the remaining four. In 1981, AVEC had 17,778 kilowatts of installed capacity and generated 21,909 megawatt-hours. I-44 B) Regional Centers Capacity and generation data for regional centers is more reliable than data for villages in the Bush region. The more important centers in the Bush are listed below: TABLE II-9 BUSH REGIONAL CENTERS GENERATION CAPACITY Capacity Generation (KW) (MWh) Barrow 7,200 17,476 Bethel 8,400 21,649 Dillingham 3,850 9,044 Fort Yukon 1,050 2,013 Kotzebue 4,825 22,531 Nome 6,968 15,935 Unalakleet 1,150 2,166 Source: Arthur D. Little, Inc., estimates. Il.6 NATURAL GAS DISTRIBUTION Natural gas transmission lines bring natural gas from the gathering site for Cook Inlet gas on the Kenai Peninsula to markets in Kenai, Soldotna, and Anchorage. There the natural gas is distributed by distribution companies to residential, commercial, and industrial customers. A separate natural gas transmission line runs from Tyonek to the Chugach gas-electric gener- ation station at Beluga. II-45 CHAPTER Il ECONOMIC DEVELOPMENT OUTLOOK IIl.1 ECONOMIC DEVELOPMENT AND ENERGY DEMANDS Energy policy must be considered as a subset of economic development policy. The linkages between the pattern of growth in an economy and the pattern of energy demand are not always direct, but the relationship is nonetheless critical. Historically, Alaska’s economy has been driven almost exclusively by a series of fortuitous discoveries and major project investments, starting as far back as the purchase of the territory from Russia, through the Gold Rush and construction of the railroad, to the exploration and development of Prudhoe Bay oil fields and the construction of the Trans-Alaska Pipeline. The future direction of Alaska’s economic development will have important effects upon energy policy; to a certain extent, Alaskans can choose that direction, and be prepared to implement energy policies most appropriate to that pace of development. The ties between economic development and energy policy stem from some key economic indicators and activities. Perhaps the most basic of these is population growth: population has a direct effect on household size, automobile ownership and usage, and the consumption of commercial goods and services in general. Virtually every sector of the economy experiences an increased energy demand when population size increases. Expanded commercial and industrial activity, which is reflected in increased employment in specific sectors, also has a substantial effect on energy demand. Increased employment is, of course, linked to population growth and to the size of disposable incomes that may be returned into the economy to stimulate additional energy demand. Furthermore, the energy required for operating facilities and processing materials is a constant proportion of sectoral growth. The magnitude of increased demand will vary depending upon the industries in which growth occurs. The opportunities for directing economic development are, however, limited by certain con- straints. In the Alaskan economy, for example, world energy markets are an external factor of extraordinary importance. Other constraints (including wages, climatic conditions, and loca- tion) govern the cost of doing business in the State. It would be unrealistic, therefore, to strive for the development of a broad-based manufacturing sector to compete with, say, the Japanese. On the other hand, Alaska’s economy is, and will continue to be, supported by revenues from oil and gas development. It is highly unlikely, therefore, that economic conditions will ever again return to the low levels of 20 or 40 years ago. A discussion of the economic constraints to development follows later in this chapter. IIl-1 Furthermore, the nature of the linkage between economic development and energy demand is not stable over time. As the Alaskan economy matures and energy prices rise in real terms, the rate at which energy demands keep pace with growth in employment will decline. Conservation, energy efficiency improvements, and cost cutting measures will play an increas- ingly important part in the size of residential, commercial, industrial, and transportation demands for energy. For planning purposes, a vital consideration is the nature and extent of the State’s participation in the direction of economic development. The State, whether it functions as investor, manager, or facilitator, will play a key role. There are unavoidable consequences to any State action. By supporting industrial infrastructure, for example, the State may also affect the competitive structure of the economy. By choosing to create incentives in certain sectors, or by financing and managing development projects, the State itself enters the market dynamic. The effects of State expenditure on energy demand will vary from sector to sector. Each sector is governed by different “multiplier effects” (for example, the relationship of investment to levels of employment, or of employment to energy demand). As an investor on behalf of its citizens, the State can generate high dividends if it chooses its investments wisely. These dividends can be returned directly (as the Permanent Fund does at present) or in the form of increased net worth (through state-owned assets) or greater personal income (derived from less expensive eleciricity or other state-provided services). However, State investments in assets should be reviewed with due consideration for inherent uncertainties. Any increased risks should be incorporated into the required return on financial investments. Finally, because it “owns” vast areas of resource-rich land and collects “rents” in the form of severance taxes, lease rentals, and royalty payments, the State’s economic clout is directly linked to energy policy. Future revenue streams from economic development are very unlikely to equal in scope the income derived from the Prudhoe Bay development. If, for example, the coal industry were to develop a five million ton annual export business, revenues to the State (based on a five percent severance tax) over a 30-year period would amount to less than one- tenth of those received from the Prudhoe Bay fields in one year. The State can plan and implement programs that will affect the overall shape of the Alaskan economy. Specifically, it can formulate objectives for the magnitude and sources of its own revenues, establish policy objectives concerning the promotion of domestic and export industries, and attempt to guide economic development in a direction representative of and compatible with its citizens’ lifestyle preferences. Any economic development policy (and hence the energy policy associated with it) must be carefully conceived and thoroughly investigated to ensure that its objectives are both desirable and achievable. The three general economic scenarios described later in this chapter represent directions that we believe are both feasible and representative of different citizens’ interests. IIl.2 ECONOMIC CONSTRAINTS In Alaska, energy and economic development have most recently been linked through the exploration of oil and gas, both in Cook Inlet and in the North Slope region. Oil industry development has, directly and indirectly, brought with it a rapid growth in State population and employment. State employment associated with the extractive and related industries (oil and gas, petroleum and chemicals, and pipeline transportation) grew from 3,140 in 1970 to IiI-2 7,606 in 1978 at the peak of the Trans-Alaska Pipeline construction, and totaled 10,099 in 1982, a growth of 222 percent from 1970. As a result of the development of services to the oil industry and its employees (multiplier effects), as well as greatly increased State expenditure made possible by oil revenues, population mushroomed from 304,000 in 1970 to 460,000 in 1982; employment grew 64 percent to about 222,000 over the same period. This startling growth has vital implications for the State’s economic development. (See Appendices A, B, and E for documentation of the subjects covered below.) First, it is important to recognize that while the oil and gas industry is responsible for a large percentage of Alaska’s phenomenal growth, other industries have grown as well. Food products (including fisheries) employment grew from 3,744 in 1970 to 7,164 in 1981 at 6.1 percent annually. Lumber employment grew from 1,766 in 1970 to 1,949 in 1981 at 0.9 percent annually. These industries contribute basic growth to the Alaskan economy, providing a crucial element of diversification. Second, Alaska’s economy is fundamentally governed by world market prices for its natural resources. The Lower-48 states are at present, and by law, the only purchaser of Alaska’s chief export product: oil. The Pacific Rim markets, however, could represent a valuable opportunity for Alaskan natural resources exports. East Asian countries are expected to develop their consumer markets, thus creating further demand for energy products. Certainly Japan, Korea, and Taiwan are experiencing strong growth, and the People’s Republic of China is likely to follow. As part of the United States, Alaska has an important geopolitical role to play in the Pacific Rim. Its strategic location and vast resource potential place the State in a position to function as a key supplier to the area. The fluctuating price for North Slope crude oil over the early months of 1982 increased the uncertainty about oil price movements, and their likely impact on future State revenues. The market conditions that have created this uncertainty in world crude oil markets continue to persist. The State’s June 1982 petroleum production revenue forecast suggests that this situation will continue, and that prices will remain soft through fiscal year 1983. Real crude oil prices should decline through 1985 as OPEC struggles to hold the current price of $34 per barrel in nominal terms in the face of continuing weak demand for crude oil. The importance of oil and gas revenues to total State revenues must be underscored. As shown in Table III-1 below, petroleum revenues are expected to constitute 70 percent of total State revenues in 1983 and 1984. The remaining 30 percent comes from other economic activity within the State, some of which is directly linked to oil and gas industry multiplier effects or to State expenditures. The majority of the petroleum and gas revenues, almost 95 percent, come from the North Slope. Currently, crude oil prices have been running between $30 per barrel for contract and $31 to $32 per barrel for spot. In June 1982, Tesoro announced a price increase to $30.75 for Alaskan North Slope crude oil delivered to the Gulf Coast. Spot prices which had dropped to $26 per barrel in March firmed to $32 and $33 per barrel through May and June. 11-3 TABLE Iil-1 IMPORTANCE OF PETROLEUM AND NATURAL GAS REVENUES TO TOTAL STATE REVENUES (Million 1982 Dollars) Petroleum and Total Year Gas Revenues Revenues Percent 1982 $3,141 $5,591 56.2% 1983 $2,587 $3,685 70.2% 1984 $2,619 $3,764 69.6% Source: Department of Revenue, Revenue Forecast, June 1982 North Slope oil production is estimated at 1.57 million barrels per day in fiscal year 1982. Production is expected to rise gradually as oil from the Kuporuk field and other North Slope developments are added to the Sadlerochit volumes, ultimately reaching a peak of 1.85 million barrels per day in fiscal year 1989. Thereafter, total production will decline, dropping to 755,000 barrels per day in fiscal year 1998. Cook Inlet oil production is expected to decline over the 17-year period from a high of 79,500 barrels per day in fiscal year 1982 to a low of about 14,000 barrels per day in 1998. An independent forecast of crude oil prices was prepared by Arthur D. Little, Inc., for the 1983 Energy Plan. This crude oil price outlook is based on a Delphi survey completed in July of 1982 which forecasts the price of Saudi Light crude in real terms through the year 2000. This price forecast places Alaskan North Slope crude at 36 to 40 percent higher in 1990 than the State’s in current dollar terms, and 20 to 26 percent higher in 1998, the last year of comparison. Based on these higher prices for Alaskan North Slope crude, a new petroleum production revenue forecast for Alaska was projected. It maintains the same relative weight of production taxes, royalties, conservation taxes, and Pump Station #1 prices as the June 1982 production forecast. Oil is the most marketable of Alaska’s resources. The continued uncertainty of oil supplies from the politically volatile Middle East increases the value of sources in stable and secure regions of the world. Under current Federal law, however, North Slope crude cannot be exported from the United States, thus effectively shutting off promising markets in the Pacific Rim. If and when this restriction is lifted, Alaska’s oil could be sold to Japan, for example, at very attractive prices. Another valuable export product is Alaska’s natural gas. The market for natural gas in the Pacific Rim, and indeed worldwide, is currently quite soft. Indonesia and Australia have large volumes of natural gas available to market and are aggressively pur- suing long-term contracts in East Asia. Canada and the Lower-48 states have also developed new gas reserves at a time when the demand for natural gas has begun to decline, a result of IlI-4 the global recession and the effects of conservation. The demand for natural gas may soften further as prices rise with deregulation and interfuel competition becomes more severe. Alaska can expect to face major market challenges in the export of LNG. Despite these caveats, the price of natural gas is expected to increase at one percent above inflation through the year 2000 as the world economy recovers. A review of specific Pacific Rim markets and netback costs for transportation to market, plus shipping, handling, and taxes, established estimated export prices for natural gas. Natural gas shipped from the Cook Inlet would have a netback price FOB the Cook Inlet of $5.20 per million Btus for Japan and $4.70 per million Btus for the United States West Coast in 1982 dollars. This assumes a cost of $0.70 per million Btus for LNG transport. Natural gas from tidewater in South Central Alaska would be worth from $3.70 to $4.20 per million Btus if the cost for liquefaction of $1.00 per million Btus in 1982 dollars were netted out. Gas production in the Cook Inlet could increase, over a 17-year forecast period, from the current level of 507 million cubic feet per day to a 1998 level of 722 million cubic feet per day (given the construction of an LNG facility using 200 million cubic feet per day).* Cook Inlet gas, however, would not have to cover the cost of a pipeline system to reach market, as would North Slope natural gas. To cover the cost of the construction and operation of a tidewater gas pipeline, the netback price of North Slope natural gas would be closer to $1.50 to $2.00 per million Btus. Finally, the market for coal in the Pacific Rim has seen a modest surge of enthusiasm. Japan, Korea, and Taiwan are converting from oil- to coal-fired electric generators. Despite slow economies, these countries have signed new contracts for long-term supplies of coal from Australia, Canada, and the United States. All three Asian nations have also, until recently, been moving swiftly in the development of nuclear power plants. These programs are starting to come under scrutiny, and may be subject to change. If nuclear power developments are scaled back, and these East Asian economies continue to grow, the demand for coal (and/or natural gas) may increase significantly. The world market price for coal will, however, remain very competitive. Australia, Canada, and the Lower-48 states can offer contracts to Pacific Rim countries at very attractive prices. Alaskan coal, at least that which is most easily accessible to mining, suffers from low Btu content, high moisture, and high ash. Overall, the price of coal is not expect to grow faster than the rate of inflation. Export coal prices FOB Beluga or Nenana might run from $17 to $32 per ton (in 1982 dollars) for a full-scale effort producing approximately five million tons of coal per year which repre- sents a competitive price range of between $1.00 and $1.95 per million Btus. The delivered price of coal to Japan would be around $48 to $52 per ton or $2.82 to $3.06 per million Btus. Netting back the transportation costs and subtracting allowances for quality differentials, the tidewater FOB price of coal at Cook Inlet, Seward, or Cordova would be $2.01 to $2.80 per *Source: Alaska Natural Gas Development, |CF, Inc., September 1982. Ill-S million Btus. Given these differentials between coal FOB the mine and coal FOB the tide- water, this only allows $4 to $15 per ton for transportation to Pacific Rim markets. At current Pacific Rim coal market prices, Alaskan coal as a potential export is just marginal. (See Appendix B for further discussion.) The State has other export products; lumber, pulp, and fisheries also form part of the Alaskan economy, and depend to a certain extent on Pacific Rim markets. Significant growth in these sectors will depend heavily upon State promotion. Third, the State does not have unlimited economic and financial resources upon which to base its growth. The rate of future economic growth in Alaska will, to a large extent, be dominated by developments in oil and natural gas. Past discoveries and development have occurred primarily on State-owned lands. Future development is more likely to take place on Federal lands, both offshore and onshore. The State of Alaska receives no lease fees or royalty payments from activities beyond the three-mile offshore limit; Alaska cannot expect to con- tinue to receive oil revenues at recent rates. (See Appendix A for a discussion of likely oil and gas developments.) Despite its large revenues, projected at a total of more than $5.5 billion for 1982, the State can only participate in a limited number of economic development projects. Furthermore, a measure passed on the State ballot in November of 1982 puts a 2.5 billion dollar per annum budget spending limit (escalated by population and inflation) on the Legislature. Economic development cannot exceed the practical constraints of export markets and existing infrastructure without requiring undue investment risks, either on the part of private industry or by the State. A careful assessment of the State of Alaska’s role in economic development is a prerequisite to the development of strategic energy plans. II.3 ECONOMIC DEVELOPMENT SCENARIOS The 1983 Energy Plan investigates three alternative economic development scenarios to demonstrate the relationships and trade-offs inherent in the planning process. These scenarios represent specific (although not comprehensive) examples of the directions future State policy can take, and the effects of certain economic developments upon the growth and balance of the Alaskan economy. Each scenario has different implications for energy planning. The scenarios were formulated from interviews and discussions with representative members of the Alaskan community: individual citizens, business leaders, State officials, and academicians. The 1983 Energy Plan economic development scenarios were developed with the aid of a model of the Alaskan economy designed specifically for this Plan. While the model does not provide an exhaustive description of the intricacies of the Alaskan economy, it does describe and project the growth of major elements and sectors. (See Appendix H for a description of the computer model.) This pattern of growth (documented and discussed in Appendix E) was taken as an economic “Baseline” (the fundamental direction of the Alaskan economy as determined by historical trends and the inherent development associated with continued growth of the basic economic sectors). This Baseline simulation incorporates the opinions and professional judgments of individuals versed in Alaska’s economic structure. Ill-6 In terms of total employment, the economic Baseline for the 1983 Energy Plan shows the State’s economy growing at approximately 4.7 percent annually, from 1981 to 1990, and at 1.4 percent from 1990 to 2000. These growth rates compare to historical growth rates of 8.2 percent annually from 1970 to 1975, and 0.2 percent annually for the period from 1976 to 1980. (The slowing of growth in the latter period was due to a decline in employment associated with the construction of the Trans-Alaska Pipeline.) Annual rates of growth associated with the Baseline simulation are shown in Table III-2. TABLE Ill-2 BASELINE ANNUAL GROWTH RATES 1970-1980 1980-1990 1990-2000 2000-2005 Population 2.8% 3.0% 2.2% 2.3% Employment 4.1% 4.0% 2.3% 2.5% Earnings 5.9% 6.2% 4.0% 4.2% Source: Arthur D. Little, Inc., estimates Personal income per capita (expressed in constant 1972 dollars) grew from $5,110 in 1970 to $7,050 in 1980, and is projected to reach $9,299 in 1990 and $11,281 in the year 2000. Table III-3 shows annual rates of employment growth for the major sectors of the economy in the Baseline simulation. TABLE Ill-3 BASELINE SECTORAL ANNUAL EMPLOYMENT GROWTH RATES Sector 1970-1980 1980-1990 1990-2000 2000-2005 Agriculture 2.4% 4.0% 2.3% - 1.3% Oil and Gas Extraction 8.3% 6.0% 2.4% 2.1% Mining (excluding Coal) 1.8% 1.4% 1.3% 1.5% Coal Mining 2.8% 6.7% 1.38% 0.8% Food Processing 7.8% I atide 0.4% 0.4% Lumber 4.3% 0.8% 2.6% 2.5% Pulp 0.4% 2.1% 1.6% 1.5% Refineries 8.5% 9.9% 5.6% 5.9% Construction 2.6% 12.1% 2.0% 1.8% Other Manufacturing 6.7% 5.5% 3.1% 3.2% Pipeline Transportation 61.6% 4.3% 1.6% 1.6% Source: Arthur D. Little, Inc., estimates III-7 Three distinct economic development scenarios were constructed as variations on this Base- line. Since the Alaskan economy is primarily export driven, these scenarios carefully delineate development in key export sectors. New natural resource and energy projects also have a significant impact on Alaska’s economy; they are built in response to export market opportu- nities or internal State needs. Thus, each scenario assumes specific rates of development in various sectors of the economy: differing coefficients and relationships are employed to gener- ate population, employment, and wages under each scenario. Rates of growth in export sectors and the mix of large-scale projects moving from construction through to commercial operation are the two major factors used to differentiate and drive these scenarios. The most critical economic sectors driving the scenarios are: Natural Resources: Logs and Lumber, Pulp, Fish and Shellfish (Food Processing), Petroleum and Natural Gas, and Minerals Construction Manufacturing: Chemicals (Ammonia/Urea) and Other Manufacturing. Over 14 major projects were reviewed to determine the likelihood of their implementation. Of these, eight were identified as probable elements of future economic development. They were: e@ Tidewater Natural Gas Pipeline or ANGTS @ Cook Inlet Oil and Gas Development e National Petroleum Reserve or National Wildlife Reserve Oil and Gas Development @ Outer Continental Shelf Oil and Gas Development e@ Liquefied Natural Gas (LNG) Export Facility e@ Petrochemical Facility e Export Coal Mine e Susitna Hydroelectric Power Project. The three scenarios are: “Low Growth,” in which the focus of economic development policy is on maintaining and enhancing the values unique to the State on behalf of its current residents; “Moderate Growth,” in which economic development continues in its historical pattern, project by project; and “Accelerated Growth,” in which the State and industry coordi- nate efforts and share the responsibility for bringing Alaska’s resources to market. Table III-4 shows the allocation of projects to these scenarios. A more detailed description of the elements comprising the three basic economic development scenarios (and their two variations) can be found in Appendix E. III-8 TABLE Ill-4 ECONOMIC DEVELOPMENT SCENARIOS (Year of Initial or Continuing Activity) Low Scenarios Most Likely High Scenarios “Low Growth” Scenario #1: With Susitna 1982 Upper Cook Inlet, Low Production 1983 Outer Continental Shelf Development 1983 Susitna Hydroelectric Project 1985 Fisheries Growth Scenario #1a: All the Above Except Susitna, and Adding: 1987 Fossil-Fueled Electric Generation “Moderate Growth” Scenario #2: 1982 Upper Cook Inlet, Mid-range Production 1990 National Petroleum Reserve or National Wildlife Reserve Exploration 1983 Outer Continental Shelf Development 1990 Tidewater Pipeline or ANGTS 1992 LNG Facility 1983 Susitna Hydroelectric Project III-9 “Accelerated Growth” Scenario #3: With Susitna 1982 Upper Cook Inlet, High Production 1987 National Petroleum Reserve or National Wildlife Reserve Exploration 1983 Outer Continental Shelf Development 1987 Tidewater Pipeline or ANGTS 1988 LNG Facility 1988 Petrochemicals 1990 Beluga Coal 1983 Susitna Hydroelectric Project 1985 Fisheries Growth 1985 Lumber and Pulp Growth Scenario #3a: All the Above Except Susitna, and Adding: 1987 Fossil-Fueled Electric Generation A) Scenario 1: “Low Growth” “Low Growth” characterizes an economic development policy in which a strong commitment to the Alaskan way of life prevails: “Let’s keep the resources and beauty of Alaska for residents, and sell only what we must to maintain our good lifestyle.” State economic policy objectives will limit the exports of natural resources to those with the highest economic rent (oil) and will direct investment in development or infrastructure only when the return on investment is substantial. Economic development will not follow a high growth path, but rather build State and industry assets slowly, increasing the net worth of all Alaskans. This policy stresses financial security, low risk, and the preservation of current State residents’ way of life. This scenario shows the implementation of an economic policy designed to fulfill two objec- tives: first, to maximize the individual net worth of all current Alaska residents (allowing for natural growth in population), through investment in State-provided services which, in effect, increase disposable income; and second, to preserve and enhance the values embodied in Alaskan lifestyles (independence, self-sufficiency, and interaction with a pristine environ- ment). Essentially, the “Low Growth” scenario focuses economic development on sectors that are not labor-intensive, thus minimizing the importation of additional population from outside the State. To generate this scenario, the Baseline model is modified only slightly. Oil and gas development in the Cook Inlet follows a low production profile (i.e., no new discoveries are added). Thus, oil production declines from a present level of 79,000 barrels per day in 1982 toa low of 13,000 barrels per day in 2000. In the North Slope region, oil production is expected to rise from 1.6 million barrels per day in 1982 to a high of 1.85 million barrels per day in 1989, and then to fall off to 0.5 million barrels per day in 2000. Increased employment associated with the Outer Continental Shelf development is included (see Appendix A). Under this scenario, the only economic sector that experiences significant growth is the fishing industry. Exports are increased, and the industry grows at nearly three percent per annum. The construction of the Susitna hydroelectric power project is assumed to begin in 1983 with a road constructed to the site. Commercial operations at Watana and Devil’s Canyon are scheduled for 1993 and 2003, respectively. To ensure that energy planning was appropriate, an alternative version of this scenario was also devised to project economic developments if Susitna is not built. In this second case, smaller natural gas combined cycle power plants were modelled instead. Under the basic “Low Growth” scenario, State population will grow at approximately 2.1 percent annually from 1981. Total population in the year 2000 will reach about 616,000 with employment at 345,000 (a growth of 2.7 percent annually). Real income per capita will grow at an annual rate of 2.6 percent (excluding any transfer payments from the State), with earnings increasing predominantly in the oil and gas extraction industries, and in the fisheries sector. These direct benefits will be felt most strongly in the southern coastal areas of the Bush, the Railbelt, and, to a lesser degree, in the Southeast. Indirect benefits of the State’s revenue policy will, however, be shared equally among all Alaskans. The State’s role, under this scenario, is to promote and participate only in those activities which will maximize returns to its citizens. The State will be actively planning, managing, IHl-10 and investing its resources in the economy. A careful balance between investment in infrastructure and in public projects will be reached, governed by the criteria of maximum return to residents and the maintenance of traditional lifestyles, as well as preservation of the environment and individual freedoms. Prudent sale of State resources (primarily oil-based) to export markets at favorable prices, combined with a fiscal policy of investment in industry development or financial instruments with high returns, will allow the State to distribute its revenue wealth equitably among citizens in all the regions of Alaska. Environmental impacts will be minimal; resource developments in many of the Bush regions of Alaska would occur only if the projects promise returns near the high side of private industry developments (at or above industry discount rates of 12 percent each). B) Scenario 2: “Moderate Growth” This scenario describes a pattern of economic development already familiar to Alaskans. The main policy thrust is to identify and develop a series of large-scale industrial or infrastructure projects. The focus of State policy is to implement the next best project once the most recent one has been completed. The projects will be chosen by a combination of State incentives and industry initiatives; the objective is to develop the political consensus and economic climate necessary to their implementation. The values of entrepreneurship, both in the private sector and for the State, and the pride in accomplishing major undertakings are emphasized in this scenario. Fundamentally, this economic development scenario is less “planned” than the other two and therefore comes closer to representing free market development. The intent is to create growth in the State economy and State revenues through the development of Alaska’s natural resources on a project-by-project basis. The scenario assumes that the projects are sufficiently attractive to be undertaken by either private industry or the State. To generate this scenario, the following large-scale projects are scheduled into the Baseline model: mid-range production of oil and gas in the Cook Inlet, Susitna hydroelectric project, Outer Continental Shelf development, tidewater pipeline or ANGTS, National Petroleum Reserve or National Wildlife Reserve resource development, and the liquefied natural gas (LNG) facility. Given this scenario, the economy will reach plateaus as construction labor stabilizes or declines, and operating employment, usually at substantially lower levels, takes over. Under this scenario, population grows more rapidly than that in “Low Growth,” as the multiplier effects of additional jobs bring more people into the State. By the year 2000, population will reach about 627,000 with employment at 350,000, or 2.8 percent annual growth from 1981. Real income per capita will grow at an annual rate of 2.6 percent, mostly due to jobs associated with oil and gas extraction and project construction. Employment rises rapidly in the early years as construction begins, reaching 311,000 in 1990. After 1995, the employment in the State stabilizes; annual growth in employment drops to 1.4 percent from the 4.7 percent experienced in the late 1980s and early 1990s. I-11 The State’s role in this scenario is focused on the provision of financing funds and infrastructure to encourage these developments. An integral part of this scenario is the assumption that Pacific Rim markets are at present attractive enough to warrant the devel- opment of these major projects. Almost all of the economic benefits of this scenario flow through the major population center of the State: the Railbelt. Advantages to the Bush and the Southeast will be indirect; and, as these projects come to fruition, the State must wrestle with internal policy questions involving whether, when, and how their benefits are to be distributed. The lifestyles of most Alaskans will not change drastically as the result of this economic development policy. The majority of the population lives in the Railbelt, and residents’ incomes will increase as these resources are developed and exported through Alaska’s central region. Bush residents will directly benefit from the economic growth when the project development draws upon their communities’ resources. Native Alaskans may indirectly bene- fit from this scenario as their Regional Corporations invest and participate in projects. C) Scenario 3: “Accelerated Growth” The third economic development scenario, “Accelerated Growth,” describes activities which can take place only if world markets return to higher levels of activity, and the prices for raw materials and natural resources worldwide become firmer. Under this scenario, the State adopts a strong resource export policy, with a focus on big business and large-scale projects. Resource development is planned and exports managed so as to maintain high levels of economic growth within the State. This pattern of development could be described as the “boom-but-no-bust” approach. Under this scenario, the objective of economic policy is to maximize gross State product and employment through the aggressive development and export of Alaska’s natural resources. To achieve this objective, the economies of all the countries of the Pacific Rim must become stronger than is currently anticipated for the remainder of the 1980s. To generate this scenario, the Baseline model is modified to show high annual growth rates in the major export sectors of the Alaskan economy: TABLE Ill-5 SECTORAL ANNUAL GROWTH RATES IN EMPLOYMENT FOR “ACCELERATED GROWTH” SCENARIO Sector 1980-2005 Lumber and Products 2.1% Pulp 2.3% Food Products (Fisheries) 0.2% Minerals/Coal Mining 4.2% Oil and Gas Extraction 4.4% Source: Arthur D. Little, Inc., estimates IH-12 In addition to the projects included under “Moderate Growth” (Scenario 2), “Accelerated Growth,” also assumes the development of a five million ton per year coal export mine at Beluga, a petrochemical facility at a tidewater location in Kenai, and increased Cook Inlet natural gas production for export. As with “Low Growth” (Scenario 1), an alternative version of this scenario was modelled that does not include Susitna. The development of a world-scale coal mine makes the prospect of coal-fired utilities quite attractive as a supply of electricity to meet growing demand. Projections for this scenario show a population of 673,000 by the year 2000. Employment will reach a level of 377,000 persons, at an annual growth of 3.2 percent from 1981. Real income per capita will grow at a rate of 2.6 percent annually. The sectors showing the largest real earnings increases will be those directly associated with substantial export markets: oil and gas (7.1 percent), coal mining (13.2 percent), petroleum and chemical products (13.8 percent), and pipeline transportation (5.9 percent). Total construction employment in this scenario reaches 30,000 in 1990, but declines again by 2000 to 17,000. The State’s role under this scenario will be two-fold: first, to work in coordination with industry to bring Alaska’s resources to market as economically as possible; and second, to create employment. The projects envisioned under this scenario are far too numerous for the State to participate in each of them financially. A combination of financing, infrastructure support, and favorable taxation or other business incentives will make this level of economic development possible. Given this high level of economic development, some Bush communities will secure the economic prosperity and the jobs they seek. Other groups, through investments and ownership of land where natural resources are located, will be financially secure and able to control the effects upon their ways of life. Some people and communities throughout the State, however, may find themselves outside the centers of development, and their desire to move to areas of employment and opportunity could create major population shifts. Traditional values of Native Alaskans will be subject to greater pressure for change, and the scope of major project developments could include greater environmental sacrifices. III-13 CHAPTER IV ENERGY OPTIONS IV.1. ALASKA’S FUTURE ENERGY DEMAND Economic development policy prefaces energy policy and project development. The three economic development scenarios presented in Chapter III have an energy demand forecast associated with them. Energy consumption is forecast by fuel type, by end-use, and by region based on the final demand energy forecast model described in Appendix H. Tables IV-1 and IV- 2 and Figure IV-1 show energy consumption, in billions of Btus, for the year 2000 under “Low Growth,” “Moderate Growth,” “Accelerated Growth,” and an additional modified scenario that indicates the effects of State conservation programs on “Moderate Growth,” Scenario 2. The benchmark year energy demands for 1981 are provided for reference purposes. Energy use under the “Moderate Growth” scenario has total 1981 in-state final energy demand of 241 trillion Btus increasing to 542 trillion Btus by the year 2000, an increase of 4.3 percent per annum (see Table IV-3 and Figures IV-2 through IV-5). Total transportation demand grows 4.1 per annum and decreases its share of the State’s final energy demand from 52.8 percent to 51.0 percent. Stationary energy use in the residential, commercial, and industrial sectors increases from 114 trillion Btus in 1981 to 265 trillion Btus in 2000, an increase of 4.5 percent per year. Thus, transportation demands (even with the input of vehicle efficiency standards) increase only 90 percent as fast as stationary energy use. Under the “Moderate Growth” scenario, Bush energy demand grows faster than either the Railbelt or Southeast. In 1981, 71.7 percent of the residential, commercial, and industrial energy use was in the Railbelt; this will decrease slightly to 69.4 percent by the year 2000. At the same time, the Bush and North Slope regions will increase their share of total energy use from 19.5 percent to 25.3 percent, with the Southeast’s proportion declining from 8.7 percent to 5.3 percent. These shifts and the increase in energy use in the Bush and North Slope regions stem primarily from increased project employment for construction and production operations of energy-related developments. The growth in use of the major energy sources is also shown in Table IV-2. Natural gas use grows the fastest, driven primarily by the natural gas pipeline and liquefaction facilities on tidewater. Under the “Moderate Growth” scenario, natural gas increases 5.4 percent, fuel oil 3.9 percent, and electricity 3.7 percent, due to a large increase in industrial use of lower-priced fossil fuels. Electricity reduces its share of the stationary energy use market from 13.1 percent to 11.3 percent, while the natural gas share increases to 48.8 percent from 42.2 percent. The transportation sector’s growth of 4.1 percent is driven by the use of jet fuel (4.8 percent) for both international and domestic travel. The use of motor gasoline and diesel fuel for highway travel grows 3.7 percent per annum with the demand for motor gasoline rising slowly as vehicle efficiency improvements impact the motor fleet. Thus, future energy demands in Alaska are likely to shift usage to greater demand for natural gas and a shift in transportation usage to more diesel fuels. These changes reflect shifts in greater industrial use of natural gas, greater industrial activity with an increased use of IV-1 TABLE IV-1 ALASKAN ENERGY FORECAST COMPARISON* — Consumption in the Year 2000 — (Billions of Btus) “Moderate 1981 “Low “Moderate “Accelerated Growth With Level Growth” Growth” Growth” Conservation” Stationary Uses Alaska 113,916 252,810.3 265,443.2 365,173.2 231,604.6 Railbelt 81,761 175,695.9 184,341.3 282,281.1 166,068.9 Southeast 9,924 14,106.8 14,058.1 15,444.8 12,003.5 Bush & North Slope 22,231 63,007.8 67,044.0 67,447.5 53,532.4 Electricity Alaska 14,924 28,908.6 29,916.0 34,564.3 23,558.4 Railbelt 9,717 19,989.5 20,900.7 24,885.0 16,551.6 Southeast 2,598 3,949.4 3,952.1 4,369.6 3,421.6 Bush & North Slope 2,609 4,969.7 5,063.2 5,309.7 3,585.2 Fuel Oil** Alaska 50,863 101,759.1 106,031.6 109,358.7 89,719.4 Railbelt 25,167 40,922.4 41,939.6 44,237.5 33,642.0 Southeast 7,326 10,157.4 10,106.0 11,075.2 8,581.9 Bush & North Slope 18,370 50,679.5 53,986.2 54,046.2 47,495.7 Natural Gas** Alaska 48,129 122,142.6 129,495.6 221,250.2 118,326.8 Railbelt 46,877 114,784.0 121,501.0 213,158.6 115,875.3 Southeast 0 0 0 0 0 Bush & North Slope 1,252 7,358.6 7,994.6 8,091.6 2,451.5 Transportation Uses 127,444 269,950.0 276,088.0 306,593.0 276,088.0 *Excludes National Defense **Excludes Fossil Fuels for Electricity Generation IV-2 £-Al ALASKAN ENERGY/ECONOMIC FORECAST COMPARISON — 1981 Base — Population 422,187 Employment 208,840 Stationary Uses Total Railbelt Southeast Bush & North Slope Electricity Total Railbelt Southeast Bush & North Slope TABLE IV-2 — Compound Annual Growth Rates 1981 to 2000 — ““Moderate “Moderate” ‘Accelerated’ Growth With “Low” Growth Growth Growth Conservation” 2.01% 2.09% 2.49% 2.09% 2.68% 2.76% 3.16% 2.76% 4.28% 4.55% 6.32% 3.81% 4.11% 4.37% 6.74% 3.80% 1.87% 1.85% 2.36% 1.01% 5.64% 5.98% 6.02% 4.73% 3.54% 3.73% 4.52% 2.43% 3.87% 4.11% 5.07% 2.84% 2.23% 2.23% 2.77% 1.46% 3.45% 3.55% 3.81% 1.69% v-Al TABLE IV-2 (Continued) ALASKAN ENERGY/ECONOMIC FORECAST COMPARISON — Compound Annual Growth Rates 1981 to 2000 — “‘Moderate “Moderate” ‘Accelerated’ Growth With — 1981 Base — “Low” Growth Growth Growth Conservation” Population 422,187 2.01% 2.09% 2.49% 2.09% Employment 208,840 2.68% 2.76% 3.16% 2.76% Fuel Oil Total 3.72% 3.94% 4.11% 3.03% Railbelt 2.59% 2.72% 3.01% 1.54% Southeast 1.73% 1.71% 2.20% 0.84% Bush & North Slope 5.49% 5.84% 5.84% 5.13% Natural Gas Total 5.02% 5.35% 8.36% 4.85% Railbelt 4.83% 5.14% 8.30% 4.88% Southeast 0.00% 0.00% 0.00% 0.00% Bush & North Slope 9.77% 10.25% 10.32% 3.60% Transportation Uses 4.03% 4.15% 4.73% 4.15% S-AI FIGURE IV-1 STATE OF ALASKA FORECAST OF TOTAL ENERGY CONSUMPTION* FOUR MAJOR SCENARIOS Accelerated Growth 850 (5.5 percent P/A) 750 Moderate Growth 3 percent P/A) /’ / Low Growth “ 7 (4.1 percent P/A) me 650 a a 3 —_—— a a om vA =o oy TT —— — Moderate Growth with = oan Conservation E (3.9 percent P/A) 450 350 250 1980 1985 1990 1995 2000 2005 “Includes National Defense but excludes Utility Conversion Losses. Source: Arthur D. Little, Inc., forecasts. 9-Al TABLE IV-3 ALASKA’S ENERGY CONSUMPTION MODERATE GROWTH SCENARIO FINAL DEMAND BY SECTOR Billions of Btus 1981 1982 1985 1990 1995 2000 2005 Transportation 127,444 137,459 181,457 237,165 308,889 276,088 330,795 Residential 31,035 32,965 37,728 47,228 58,232 56,797 67,144 Commercial 16,357 17,188 20,036 24,041 27,468 26,297 31,771 Industrial* 70,839 74,099 91,071 119,208 145,233 183,562 236,333 Electric Generation Fuel Demand 67,622 70,579 93,982 94,722 107,092 103,479 103,563 *Excludes demands for feedstocks but does account for losses in petroleum refining and natural gas processing. Source: Arthur D. Little, Inc., forecasts. L-AI FIGURE IV-2 ALASKA’S ENERGY CONSUMPTION MODERATE GROWTH SCENARIO FINAL DEMAND BY SECTOR 350,000 1 Transportation” 300,000 w» 250,000 3 . ee 2 ie ‘7 6 7 7 200,000 7 c a s | © 450,000 eT eon Pe : —_— Commercial” 100,000 Pail en eee |) "en Industrial* pe cae a To der etter ll 50,000 0 1981 1982 1985 1990 1995 2000 2005 *Exludes demands for feedstocks but does account for losses in petroleum refining and natural gas processing. Source: Arthur D. Little, Inc., forecasts. 8-Al FIGURE IV-3 FUEL OIL CONSUMPTION BY REGION (Non-Cumulative) 1,000 900 Alaska 800 700) o c = 600 © es 00 . 5 ° Bush 2 5 400 = Railbelt = 300 _—— Bush w/o North Slope 200 = oo Oil & Gas Industry Consumption 100 es SOUtHEast 0 1985 1990 1995 2000 2005 Source: Arthur D. Little, Inc., forecasts. Bcf FIGURE IV-4 NATURAL GAS CONSUMPTION BY REGION* (Non-Cumulative) 1985 1990 1995 2000 2005 “Excludes natural gas for electricity generation, feedstocks, and national defense demands. Source: Arthur D. Little, Inc., forecasts. Iv-9 FIGURE IV-5 ELECTRICITY CONSUMPTION BY REGION (Non-Cumulative) Alaska 8,000 7,000 Railbelt 6,000 5,000 2 Ss o a = 4,000 = © Ly So 3,000 2,000 Southeast Bush 1985 1990 1995 2000 2005 Source: Arthur D. Little, Inc., forecasts. IV-10 electric:cy, greater demands for jet fuel by domestic and international flights, and strong price- induced conservation for natural gas, fuel oil, and electricity for residential and commercial uses. IV.2 MODIFYING ENERGY DEMAND PATTERNS There are three ways to adjust energy consumption patterns and thus change demand to suit energy policy and available fuels. The first is to use energy sources more efficiently. This can be accomplished either through the introduction of new, more efficient technologies or through the improvement of existing energy systems. The replacement of a higher heat-rate electric utility generator by one with a lower heat rate or the installation of a more efficient home water heater are both examples of energy efficiency improvements. The second approach is fuel substitution. Cost savings can be realized. Economic factors adjusted by freeing energy products for export and independence from a single fuel supply can frequently offer lower cost alternatives. New technologies offer opportunities for fuel sub- stitutions. Using wind power instead of fuel oil for electric generation is an example of fuel substitution moving to a renewable from a non-renewable resource. However, backup gener- ation capability is frequently required. Fuel substitution may occur spontaneously in response to scarcity or relative fuel prices. It can also be encouraged as part of energy policy, through grants or other incentives. The third and often most economical approach to modify energy demand is conservation. During the “energy crisis” of 1973, many people drastically reduced their consumption of petroleum products; clearly, high energy prices are one of the most effective inducements to conservation. Energy policy programs designed to communicate the benefits of conservation, and implementation programs designed to support conservation efforts, can also substantially reduce consumption. Table IV-1 indicates that total State energy demand under the “Moderate Growth” scenario with a “Most Likely Conservation Program” results in nearly three percent less final energy demand than that under the “Low Growth” scenario. (See Appendix F for further discussion of conservation.) IV.2.1 Energy Efficiency A) Electricity: Electricity generation efficiency can be improved in both the urban Railbelt and the Bush by upgrading existing generators to more efficient energy conversion sys- tems and by introducing larger-sized power plants (hence, greater economies of scale). In the Bush and North Slope regions, integration of end-users through regional electricity distribution systems might permit large diesel generators to operate as central sources of supply at increased efficiencies, replacing less economical, smaller-sized household or village diesel generators serving smaller, less economically viable energy demands. For the Railbelt and other urban areas, the upgrading of existing combustion turbines and diesel generators to larger steam electric generators, or combustion turbine combined- cycle power plants (with or without waste heat utilization), can improve operating effi- ciencies and secure the economies of scale inherent in a larger system operation of major electric utility systems. B) Space heating: For thermal energy needs, energy conservation applied directly at the end- use level is the most effective alternative currently available to improve energy use patterns. Energy conservation programs and options available to consumers that reduce IV-11 heat loss from residences, commercial establishments, and industrial facilities can greatly lower energy consumption and reduce energy costs for consumers. Currently, the economic incentives for conservation in the Anchorage area are minimal, since the average price of natural gas for space heating is relatively low (approximately $1.70 per million Btus) compared with those of electricity and fuel oil at nearly $15.00 and $10.00 per million Btus, respectively. For Bush communities, however, where average fuel oil costs (including fuel assistance programs) are upwards of $14.00 per million Btus, conservation is a very attractive energy alternative, especially if information and technical services are available to implement conservation measures. In addition to increased thermal envelope improve- ments, changes in thermal energy technologies (such as upgrading home heat furnaces and boilers to more efficient systems and the introduction of more efficient commercial space heating systems) can help consumers make better use of the thermal energy supply. |V.2.2 Fuel Substitution The reduction of Alaska’s dependence on oil through fuel substitution, whether for economic, environmental, or sociopolitical reasons, remains a key strategic issue. If the State desires to maximize revenues and return to citizens, substitution for petroleum can improve the revenue and return picture. It is not, however, possible to eliminate the heavy use of petroleum products in the transportation sector and the Bush and North Slope regions. A) Transportation: Transportation energy demands, for example, are and will continue to be served almost exclusively by oil. Any major improvements in transportation efficiency will be introduced, not at the State level, but industry-wide or at the national level. Miles per gallon and environmental control regulations, as established by the Federal government, are directing the automotive industry to new efficiency levels in the future. State man- dates concerning operating efficiency have only minor influences on future trends. Energy efficiency improvements offers the economic option for Alaska in the usage of fuels for Alaska’s transportation. Fuel substitution in the transportation sector, while theo- retically possible, is not yet an economical or practical way to lower the cost of transporta- tion fuels or make the State more reliant on non-petroleum indigenous resources. Currently, compressed natural gas is used as a transportation fuel by gas company fleet vehicles in Anchorage. Compressed natural gas, liquefied petroleum gases, and methanol fuels are more practical for areas such as Anchorage and Juneau, where the climate is reasonably temperate in the winter. In Fairbanks and the colder regions of Alaska, however, technical considerations are likely to hinder the efficient use of these alternative transportation fuels. Furthermore, to achieve fuel substitution on a significant scale would require a sizable investment in infrastructure to service such vehicles. The size of Alaska’s motor vehicle fleet and the needs for widely distributed demands restrict fuel substitution. There are some other possible alternatives for fuel substitution in the transportation sector. A railroad electrification program would permit the substitution of diesel fuel for electricity generated from natural gas or hydropower. In addition, the distribution modes that are used to transport energy throughout Alaska could be modified. The transportation energy consumed to distribute petroleum products for electric generation and thermal use (e.g., marine fuels in barges, aviation gasoline for planes) could be reduced, if more IV-12 efficient modes of transportation were used. Electric transmission lines, as well as oil and gas pipelines, could minimize the use of various transportation fuels for distribution of other fuels into the less accessible regions of Alaska. B) Space Heating: Similarly, fuel substitutes for thermal needs are few and difficult to implement. In some areas of the Bush, coal and wood are available and can be used as supplements or substitutes; however, their direct substitution for a liquid fuel like oil requires a sizeable capital investment. The operation of solid fuel systems is not as convenient as petroleum-based systems. Practical alternatives to small decentralized oil or gas thermal systems are limited in the Bush; only solid fuel stoves and (in the future) Stirling engine systems are potential alternatives. Even for urban areas in the Railbelt and the Southeast, there are few thermal fuel substitutes which compare economically to oil or natural gas. Solid fuels can be used as in the Bush, in stoves or perhaps ultimately in Stirling engines. Hydropower can generate electricity for space heating, and waste heat systems can capture some heat lost in energy conversion and distribute it to nearby buildings. Solid fuel boilers can also produce steam or hot water to meet thermal demands. These alternatives, however, require sizeable investments of capital for the energy systems and need to prove their operating flexibility. C) Electricity: In contrast, fuel substitution for electricity generation in Alaska is quite practical. Hydropower, coal, peat, and biomass (when proven practical) can all be used to replace petroleum and natural gas in the electricity generation sector. These fuel sub- stitutions can be both for the large scale associated with electric generation in the Railbelt and for the operation of regional electric systems in the Bush. Most of these alternative energy sources, however, must prove practical for applications to small decentralized electric systems that serve one or several households before wholesale introduction can occur. Besides hydropower, electric generations systems can be developed to run on other renewable resources: geothermal, solar photovoltaic and solar thermal, wind, and tidal power. The application of many of these systems is possible today with currently available technologies, but the economics of long-standing operations must be proven. Of the many alternatives, only two are considered technically difficult today. One is the use of fuel cells to convert hydrogen fuels to electricity and heat. The other is the Stirling engine. Both of these alternatives should demonstrate their practicality in the 1980s and become commer- cially available in the 1990s. 1V.2.3 Constraints Fuel substitution is limited by two fundamental constraints which, although distinct, are nevertheless linked. The first constraint is price: fuel substitution from a less expensive to a more expensive alternative is unlikely. The second is availability: an energy source that is inaccessible or scarce is not an attractive alternative. It is also likely to be more expensive. As discussed in Chapter II, oil and petroleum products are delivered and are available to all regions of Alaska. Through a widespread (although often expensive) distribution network, petroleum products for electricity generation, thermal use, transportation, and national defense are transported throughout the State. Natural gas, on the other hand, is currently available only in the proximity of the gas fields at Cook Inlet and portions of the North Slope. IV-13 Coal is mined in the Nenana field at Usibelli and near Greeley south of Fairbanks. Small amounts of coal are mined elsewhere in the Railbelt region and in the Bush for space heating. In general, however, coal is not readily available in the Southeast nor on the North Slope. Good coal resources are to be found in northwestern Alaska and at numerous locations in the Bush, but the likelihood of development will vary and availability will depend on the scale of operations, the economics, and the regional demand. Wood resources can also be found in many interior Bush regions and in the southwest. In the northwest and Arctic Slope areas of Alaska, wood resources are scarce; even driftwood is hard to obtain. Hydropower is by nature site-specific, and every region of Alaska has some potential for hydropower. Similarly, wind energy is a potential source of electric powér in all regions of Alaska. Its potential is very site-specific. The best locations for wind energy appear to be the coastal regions on the North Slope, the sub-Arctic Coast, Aleutian Islands, Alaska Peninsula, Prince William Sound, and the Southeast. Geothermal power is available at specific locations throughout Alaska although its potential has yet to be tapped commercially. The greatest number of potential sites are in the Aleutian Islands and Alaskan Peninsula, with others on the southwest coast, around the Prince William Sound area, in the Fairbanks region, and in the Southeast. Finally, tidal power is only readily available in the Cook Inlet area where tidal range is in excess of 30 feet. Thus, fuel constraints direct the selection of energy sources and fuels for the various regions of Alaska to focus on fossil fuels and hydroelectric power for the Railbelt; petroleum and site- specific alternatives for the Bush; petroleum, hydropower, wood, and perhaps wind energy systems for the Southeast; and primarily oil and natural gas in the North Slope region. IV.3 ENERGY ALTERNATIVES As described in Chapter I, strategic energy planning requires the formulation of a menu of alternatives for energy supply. The preliminary menu of alternative technologies and energy systems encompasses items which are: e@ available either immediately or within the next ten years; and e technically feasible under Alaskan climatic conditions. This menu was then further screened to determine the more limited list of technologies that represent truly practical alternatives in Alaska. The criteria used for this sorting include: @ cost of energy: based on a realistic assessment of operating performance characteristics in meeting typical Alaskan energy demand; © cost of investment: a measure of the level of capital intensiveness, and hence risk, associated with each alternative; IV-14 @ operation maintenance cost: the level of labor and variable operating costs needed to achieve consistent energy output over the life of the equipment, another measure of risk; @ fuel requirements: the availability of fuel supply and the degree to which it will be subject to scarcity or price pressures; and @ system compatibility: the ease with which an alternative can be integrated into existing energy supply systems for immediate economic benefits. The results of this primary screening effort produced the list of practical alternatives shown as Table IV-4. These are the technology alternatives which can contribute to changing Alaskan energy demand patterns: by allowing fuel substitution, by introducing cost savings, and by increasing efficiency. The menu of alternatives can be arrayed in four groups to allow for meaningful comparisons. Table IV-5 shows levelized electricity cost in 1982 ¢/kWh conventional electric generation plants over their economic life. Small electric generation system costs are shown in Table IV-6. Although small systems generate electricity that is significantly more expensive, they also represent alternatives that can be applied in remote regions of the Bush, North Slope, Southeast, and even the Railbelt, where large systems or electric distribution are impractical and even inefficient. Of the large systems, hydropower projects are clearly the most cost- effective, but they also carry high capital costs. Bottoming cycles for diesel electric generators show very attractive marginal costs at moderate capital costs. Table IV-7 compares the costs for various thermal supply technologies. Of those shown, the Stirling engine energy systems and air recuperators promise the most cost-effective source of thermal energy. Conservation is listed in this table as an energy source to show the cost advantages achievable through investment in insulation, thermopane windows, and other conservation measures. In areas where it is practical, a passive solar system can afford reasonably priced thermal energy with an acceptable payback period. e Four energy project categories were chosen for more detailed analysis. These are: rural electrification, both from the Railbelt and regionally; natural gas pipelines, including a gas distribution pipeline from Cook Inlet and an offshoot at Fairbanks of the anticipated North Slope pipeline; railroad electrification; and the Susitna hydroelectric project. IV.3.1 Electric Supply Options for Bush and Rural Areas One of the major energy cost differences in Alaska is the cost of electricity. Today, consumers in Anchorage pay 5¢ to 6¢ per kilowatt-hour whereas electricity customers in the Bush and rural areas (if they are generating their own electricity using fuel oil at $2.00 a gallon) pay an average of 27¢ per kilowatt-hour, of which 22¢ per kilowatt-hour covers the cost of the fuel. Similar energy costs are experienced in the Yukon region, Bethel, and the North Slope. Energy prices of approximately 15¢ per kilowatt-hour are the norm in the Dillingham and Aleutian Islands areas. (These prices do not include the effect of the Power Cost Assistance Program.) IV-15 TABLE IV-4 ENERGY ALTERNATIVES Practical Availability Railbelt Southeast Bush Basic Electrical Generation: 1. Steam — Electric (Oil, Gas, Coal, Municipal Refuse) 1982 x x 2. Combustion Turbine 1982 x x 3. Hydropower (Large Scale) 1982 x xX 4. Diesel — Electric 1982 x x x 5. Combined Cycle (Combustion Turbine — Steam Electric) 1982 x x 6. Tidal 1982 x Other Technologies: 1. Single-Wire Ground Return Transmission Line 1982 x x x 2. 69 KV Transmission Line 1982 x x xX 3. 115 KV Transmission Line 1982 x x 4. 240 KV Transmission Line 1982 x x 5. Gas Pipeline 1982 xX 6. Oil Pipeline 1982 x 7. Railroad Electrification 1982 x 8. Fuel Cells 1990 xX x x 9. Total Energy Systems Heat Distribution 1982 x x x 10. Heat Pumps 1982 x x x 11. Air/Water Recuperators 1982 x x x 12. Bottoming Cycle on Heat Recovery Systems 1985-88 x x x 13. Electricity Storage 1982 xX x x 14. Stirling Engines 1990-95 x x 15. Wind Systems 1982 x x x 16. Geothermal 1982 x x 17. Solar Passive 1982 Xx x x 18. Low Head Hydro 1982 x x x Source: Arthur D. Little, Inc. IV-16 Nortn Slope << x < «KKK OX TABLE IV-5 LARGE CONVENTIONAL ELECTRIC GENERATION SYSTEMS Levelized Real NPV Electricity Economic System Type Elect. Cost Cost* Capital Cost O&M Cost Fuel Cost Life (1982¢/kWh) (1982¢/kWh) (1982$/kW) (1982¢/kWh) (1982¢/kWh) (Years) Hydropower: 50-100 Chakachamna 0.808 3.957 3,860 0.0215 0.000 Susitna 0.797 3.904 3,159 0.0254 0.000 Other 50MW 1.114 5.441 6,000 0.1260 0.000 Steam Electric (200MW): 30-35 Natural Gas 1.631 5.763 1,800 0.2950 2.067 Coal 1.756 6.205 2,100 0.3375 1.759 Combined Cycle (75MW): 20-25 Natural Gas 1.732 4.661 1,050 0.3030 2.078 Oil 4.376 11.775 1,050 0.3030 8.336 Combustion Turbine (24MW): 15-20 Natural Gas 3.563 8.199 400 1.2970 3.544 Oil 9.049 20.824 400 1.297 11.715 Diesel (large) Oil (10MW): 7.779 17.902 850 1.344 9.205 10-20 Steam Electric (5OMW): 20-30 Municipal Waste 2.667 9.423 3,320 3.557 0.000 Municipal Waste 3.124 11.038 3,230 3.557 1.407 *Levelized over the economic life of the system. Assumptions: Fuel costs per million Btus in 1982$: Natural Gas $2.32; Diesel $8.00; Coal $1.75; Combined Cycle Oil $9.50. Natural gas and diesel prices escalate at 1 percent above inflation; coal prices at inflation. Fixed O&M costs escalate at 0.5 percent above inflation; variable O&M costs escalate at inflation. For comparative purposes the following discount and fixed charge rates were assumed. Discount rates (real): 9.7% (15.7%, nominal). Fixed charge rates (real): Susitna and Chakachamna 4%, all others 9%. Capital cost escalates at 1 percent above inflation. Source: Arthur D. Little, Inc., estimates. IV-17 SI-AI TABLE IV-6 SMALL ELECTRIC GENERATION SYSTEMS — COMPARATIVE COSTS First Year Capital 1982 Cost Cost O&M Electricity System* per kWh** per kW per kWh Fuel Source Diesel Electric 27.0¢-31.0¢ $275-$500 2¢-5¢ Oil Bottoming Cycles for Diesel Electric 6.0¢-7.5¢ $1,400 1¢-2¢ Waste Heat Wind Energy Systems 10.8¢-14.8¢ $3,000 1¢-5¢ Wind Low Head Hydro 18.7¢-73.0¢ $5,000-$75,000 2.4¢-24.0¢ Hydro Stirling Engines 10.8¢-21.3¢ $2,500-$3,500 2.0¢-4.0¢ Wood, Coal Fuel Cells 9.2¢-22.8¢ $1,000-$5,000 1¢ Natural Gas or Propane Electricity Storage 8.07¢ $1,480 0.41¢ Electricity *All small electric generation system alternatives, except diesel electric generators, have to prove practical performance in the Alaskan environment before wide-scale development can occur. **Based on supply energy at a 0.35 load factor with the fixed carrying charges based on a 10 percent fixed charge rate. Fuel oil costs are at $2.00 per gallon, with coal or wood at $4.00 per million Btus. For example, for wind energy, capital costs are $150,000 giving fixed costs of (.10 x 150,000) or $15,000. Capacity is 50 kW and annual production at a 0.35 load factor is 153,300 kWh (50 x 8760 x .35). Total O&M costs range from $1,533 to $7,665 (1¢ to 5¢ per kWh). Adding fixed and O&M costs together gives total costs of $16,533 to $22,665. Dividing by 153,300 kWh gives 10.8¢ to 14.8¢ per kWh. Source: Arthur D. Little, Inc., estimates. TABLE IV-7 THERMAL ENERGY SYSTEMS — COMPARATIVE COSTS Thermal System First Year* 1982 Cost MMBtu Capital Cost* First Year* Other Cost** Fuel Source Stirling Engine Solar Passive Solar Active Earth-Source Air Recuperators Geothermal with District Heat Conservation Wood Coal Stoves Waste Heat Recovery-District Heating $6-$8 MMBtu $12.50 MMBtu $26 MMBtu $10-$12 MMBtu $8-$12 MMBtu $7.5-$55 MMBtu $10 MMBtu $15 MMBtu $20-40 MMBtu (Typically 1,000-ft System for 10 Homes) “Represent typical installation costs. $2,500-$3,500 kW Shared Energy System with Electricity = $1,000 $1,200 for Wasteheat $1,500 Investment Saves 12 MMBtu per Year in Heat $3,000 Installation Saves 11.6 MMBtu per Year in Water Heating $5,000-$6,500 per $1,200-$1,500 Residence Saving 20-30 MMBtu Year $100.000-$500,000 Btu $200.000-$5,000.000 for District Heating System for 20-50 Homes $5.000 Bidg for 50 MMBtu Saving in Space Heat Year $2,700 Installation for 50 MMBtu per Year $77,000 for Module Plus $200 ft for Piping O&M Included in Stirling Engine Elect. Power Cost Cost of Electricity Electricity: Install. Cost Na $500 Year $13,850 Year Wood Coal Oil Waste Heat from Electricity Generation 5,000 Btus Hour Solar Solar Electricity Waste Heat in Air and Water Discharge Geothermal Energy Space Heat Loss Wood Coal Waste Heat “*Based on capital costs with 10 percent cost for fixed charges. Wood and coal prices are $4.00 per million Btus and fuel oil costs are $2.00 per gallon. Source: Arthur D. Little. Inc., estimates. IV-19 A) Regional Electrification Regional electrification for rural areas is one alternative for reducing Bush region electricity costs. The 1983 Long Term Energy Plan made two assessments of electrification schemes. These are: e Supplying electricity from the Railbelt to the Bush region (for the villages of the Kuskok- wim region surrounding Bethel or the region surrounding Nome and Kotzebue); and e The electrification of the villages of the Kuskokwim region by electricity distributed from Bethel, or electrification of villages surrounding Nome and Kotzebue from those regional centers. The electrification of the Bush from the Railbelt would require the installation of a high voltage electric transmission line from Beluga to a location such as Aniak in the Kuskokwim region. Similarly, for the villages around Nome and Kotzebue, high voltage transmission lines would have to run from the vicinity of Fairbanks to a location such as Koyuk or Candle on the Seward Peninsula. The transmission lines would run approximately 320 and 400 miles, respectively. A line to the Bethel region would have to cross the very difficult terrain of the Alaska Range; in the case of the Seward Peninsula area, the line would have to make difficult river crossings at several locations. Electrification from the Railbelt via high frequency transmission lines pose significant diffi- culties. One difficulty is the selection of a transmission line voltage level sufficient to hold electric power transmission losses to acceptable levels for the distances traversed and the power transmitted. The energy losses on a 69 kilovolt line are approximately ten percent for 50 miles. Over the distance of 320 to 400 miles, the losses would be in the vicinity of 25 to 30 percent of the total power transmitted. If higher transmission line voltages are used, losses can be reduced substantially. For a 230 kilovolt transmission line, power transmission losses would be approximately 7 to 9 percent of the total power transmitted over the 320 to 400 mile distance. However, the 230 kilovolt transmission line would be at least 50 percent more expensive. Typical costs for 69 and 230 kilovolt transmission lines are approximately $250,000 and $375,000 per mile, respectively (for construction over easy terrain). If, however, construc- tion requires the use of helicopters in areas where there is no road access, construction costs will be at least 60 percent greater. The cost of construction of a 69 kilovolt line over difficult terrain by helicopter would be approximately $400,000 per mile, and the 230 kilovolt trans- mission line would cost in the vicinity of $600,000 per mile. On the basis of these costs and power losses, the economics of transmitting electricity from the Railbelt to the Bush regions do not appear to be favorable. With construction costs averaging $325,000 per mile (assuming 50 percent of the line is difficult to construct and 50 percent could be constructed over easy terrain), total capital cost is likely to be slightly more than 100 million dollars to reach the Bethel region and $130 million dollars to reach the Seward Peninsula. These capital costs do not include interest during construction or the additional cost of regional distribution. If these transmission lines were financed by tax-exempt revenue bonds at a 10 percent interest rate, the annual principal and interest payment to retire the debt over the 50-year life of the transmission line would be 10.1 million dollars per year for the line to the Kuskokwim area or 13.1 million dollars for the Seward Peninsula region. Iv-20 This finance charge would result in a cost to the customer of 32¢ per kilowatt-hour for the Bethel region and approximately 42¢ per kilowatt-hour for the Seward Peninsula. Thus, regional electrification from the Railbelt to the Bush region does not show any economic advantage, nor does it appear to be competitive with oil generation. B) Distribution from Regional Centers The electrification of communities in the Kuskokwim area or on the Seward Peninsula in the vicinity of Nome and Kotzebue can be effectively achieved by the construction of single-wire ground return distribution lines which are probably the lowest-cost regional distribution system practical in the Bush region. Based on the costs of two recently installed systems, the 1982 cost for single-wire ground return 7.5 kilovolt distribution lines is approximately $44,000 per mile, to which costs of river crossings ($27,000) and system interfacing ($25,000) must be added. More extensive engineering and system costs to account for power transients and safety code requirements for operations may add to these costs. If regional distribution of electricity for the Kuskokwim included the 54 villages discussed in an earlier Alaskan Power Administration study,* the cost of the regional electrification would amount to approximately $68 million dollars. This regional electrification network would permit large-scale central generation in Bethel to operate at higher levels of capacity utiliza- tion and therefore higher efficiencies. As was indicated in the 1982 Long Term Energy Plan, the efficiency of many Bush electric systems is about 16 to 24 percent, compared to rates of efficiency in other electric systems of 24 to 33 percent. The introduction of regional elec- trification could improve this operating performance, provided it can be accomplished at a reasonable cost per customer. Based on the 68 million dollars to regionalize the electricity system in the Kuskokwim river basin, finance charges at a utility fixed charge rate of 15.7 percent would amount to approximately 9.9 million dollars per year. Based on the 31 million kilowatt-hours of elec- tricity sold in the Bethel region in 1981, such a regional single-wire ground return distribution system would cost approximately 32¢ per kilowatt-hour. Even if the transmission line were financed with tax-exempt revenue bonds at 10 percent interest, the cost would be approximately 20¢ per kilowatt-hour. If the cost of regional distribution is added to the cost of electric generation (by a Bethel utility at 27¢ per kilowatt-hour), the total cost to village consumers reaches 47¢ to 59¢ per kilowatt-hour. Regional electricity distribution thus results in electricity cost to customers, in many villages, greater than those incurred by individual households or villages using decentralized diesel electric generation even without fuel assistance. Individual regional electricity distribution projects may be practical where improved diesel electric generation efficiency results in cost savings greater than the added cost of the electric distribution system. Electricity use must increase over today’s levels in most villages before it is economical to transmit electricity even six to ten miles from a regional center or other centralized electric generation system. *“A Regional Electric Power System for the Lower Kuskokwim Vicinity” Iv-21 1V.3.2 Railbelt Natural Gas Use Development A) North Slope Natural Gas for the Railbelt One major energy project which offers economies of scale to Alaskans is a natural gas pipeline from the North Slope. This transmission line could be routed near Fairbanks for both the tidewater or ANGTS alternatives. With the tidewater alternative, the existing gas distribu- tion system with additional branch lines could expand the residential, commercial, and industrial use of natural gas in the Railbelt and insure a supply of gas well out into the twenty-first century. In either case, a simple feeder could provide natural gas to Fairbanks for space and water heating. The netback cost for North Slope natural gas based on Japan or United States West Coast prices is shown in Table IV-8 are: TABLE IV-8 NATURAL GAS NETBACK COST ($/MCF) Range Japan/United States West Coast Prices $6.20-$5.70 Regasification 0.30- 0.30 LNG Transport 0.60- 0.60 Liquefaction 0.90- 0.90 Transmission 0.90- 0.90 Total Netback Cost $3.50-$3.00 Source: Arthur D. Little, Inc., estimates. Thus, the city gate price for natural gas at Fairbanks would be approximately $3.00 to $3.50 per thousand cubic feet. An additional cost of distribution would be $4,350 per customer, or $2.00 to $2.50 per thousand cubic feet. Based on this cost analysis, the price of energy to the residential customer would be $5.00 to $5.50 per thousand cubic feet in 1982 dollars. Cur- rently, the average Fairbanks customer using fuel oil pays $2,460 per year for space heating; this is equivalent to $10.00 per thousand cubic feet. Thus, the typical residential customer would save approximately $1,000 per year if natural gas were available from a North Slope gas transmission line. B) Cook Inlet Natural Gas Pipeline The distribution of natural gas from the Cook Inlet to various areas in the Railbelt represents one practical alternative for using local energy resources for space and water heating in place IV-22 of more expensive distillates. The extension of existing natural gas transmission lines will depend upon the volumes of gas to be piped. The cost to the consumer for delivered natural gas depends on the fixed costs (the capital investment plus overhead) as well as the cost of the gas. To keep fixed costs down, the ratio of capital cost to demand for gas must be low. Either the capital cost is small (i.e., a short pipeline) or the volume of gas throughput is high. For the Cook Inlet gas fields, service would be limited to areas around Anchorage, north to the Matanuska Valley, and parts of the Kenai Peninsula. Table IV-9 shows 1990 and 2000 gas demands and the cost of reaching these areas by pipeline. TABLE IV-9 COOK INLET NATURAL GAS SUPPLY BY PIPELINE Potential Potential Construction 1990 Demand 2000 Demand Cost ($/mile) (MMCF) (MMCF) Matanuska Valley 1.7 2.1 $300,000- $450,000 Kenai Peninsula* (Homer, Seward) 3.5 4.7 $450,000- $700,000 “The construction of the tidewater natural gas pipeline and a liquefaction facility greatly increase demand. Source: Arthur D. Little, Inc., estimates Based on these pipeline costs, the cost of gas transmission ranges from $1.76 to $3.42 per thousand cubic feet, in addition to the cost of gas and the cost for local distribution. If gas costs $2.32 plus $1.80 per thousand cubic feet, the range of gas prices would be $5.88 to $7.54 per thousand cubic feet. While these gas prices are higher than those paid by current gas customers, they are still lower than equivalent prices of fuel oil for home heating. One alternative that does not appear economical at present is the installation of a gas pipeline from Cook Inlet to Fairbanks. The cost of the pipeline would be approximately 280 million to 300 million dollars, with a total potential residential demand of 7.93 million cubic feet in 1990 and 8.64 million cubic feet in 2000. For this gas line, the cost of gas transmission would range from $5.29 to $7.56 per thousand cubic feet. This would result in a price for gas piped and distributed in Fairbanks of $10.21 to $12.48 per thousand cubic feet in 1982 dollars. Natural gas could not compete in Fairbanks against fuel oil at $10.00 per million Btu. IV-23 IV.3.3 The Susitna Project and Related Issues The Susitna hydroelectric project can provide the Railbelt region of Alaska with the majority of its electric power needs for the next 50 years. As with all hydroelectric projects, its capital cost determines the future cost of the electricity resulting from the available hydropower. For Susitna, the capital cost of the Watana (1,020 megawatts) and Devil’s Canyon (600 mega- watts) facilities (including all powerhouses, plant, and equipment) is 5.1 billion 1982 dollars. By comparison, a coal-fired steam electric power plant of equal size would cost 3.4 billion 1982 dollars and a natural gas-fired combined cycle plant would cost 1.7 billion 1982 dollars. However, fuel costs in 1982 dollars for coal and natural gas under new contracts are likely to cost $1.70 and $2.40 per million Btus, while hydropower “fuel” is free. Thus, Susitna trades off a high capital cost for zero fuel cost, whereas the coal and natural gas options trade off lower capital costs for higher and potentially escalatory fuel costs. Three electric power options for the Railbelt appear to be excellent. Hydropower from the Susitna project; the Beluga, Kenai, or Matanuska coal fields, and Cook Inlet natural gas are available fuel sources for electric generation. The costs of electricity generation of these three alternatives as components of the Railbelt electric system determine the relative economics. Accordingly, for the 1983 Long Term Energy Plan, an interconnected Railbelt electric system was modeled, including all current and planned electric generation, with industrial and military capacity. Then, using electric demand growth rates from the energy forecast models, the production cost of future electricity generation was calculated. Capacity was added to maintain a 20 percent reserve margin, except in the case of Susitna, where reserves are allowed to drop to the minimum spinning reserve margin of the largest unit on the system. The installed generation capacity of industry was assessed to maintain at least a 60 percent capacity utilization, and the military will replace only one fourth of its installed capacity with new base installations for minimum levels of emergency standby and peak operations. Tables IV-10 and IV-11 show major capacity additions and costs. Appendix H describes the utility model framework and the underlying assumptions. These modeled forecasts were extended out to the year 2050 so that the 50-year economic life cycle of Susitna could be accurately compared with other alternatives. It is anticipated that the Susitna project’s operations would extend beyond 50 years, and span at least two replace- ment cycles for fossil fuel-fired generators. For each alternative, the financial and overhead costs of the Railbelt electric systems were estimated and also forecast to the year 2050. From the combined fixed and variable cost forecasts, the annual revenue requirement as well as the average annual cost of electricity in current dollars were determined. The forecast electric rates for the Railbelt are shown in Appendix H. The annual rates discounted to 1981. Then the average discounted price or rate and the levelized cost of electricity were calculated as measures of economic preference. These average discounted values and levelized costs of electricity are shown in Table IV-12. The Susitna Plan is shown to have a lower average discounted value and levelized cost than the alternative of using natural gas-fired generation in Anchorage and coal-fired generation in Fairbanks. The Susitna advantage changes little over a range of discount rates (10.5 percent to 15.7 percent) and lower versus higher growth rates for coal prices (— 1 percent to + 1 percent) and natural gas prices (0 percent to 2 percent). While growth rates for electricity demands in the Railbelt were forecast to range from 3.9 percent to 5.1 percent for the three basic economic development scenarios, and at 2.9 percent IV-24 S7-AI TABLE IV-10 CAPACITY ADDITIONS — RAILBELT (Megawatts) With Susitna Without Susitna Anchorage Valdez- Anchorage Valdez- Area Fairbanks Cordova Total Area Fairbanks Cordova Total 1982 158.4 0.0 12.0 170.4 158.4 0.0 12.0 170.4 1988 97.0 0.0 0.0 97.0 97.0 0.0 0.0 97.0 1990 200.0 0.0 0.0 200.0 200.0 0.0 0.0 200.0 1993 787.5 212.1 20.4 1,020.0 200.0 0.0 10.0 210.0 1995 0.0 0.0 0.0 0.0 200.0 0.0 0.0 200.0 1997 0.0 0.0 0.0 0.0 0.0 150.0 10.0 160.0 2002 493.1 94.0 12.0 600.0 0.0 50.0 0.0 50.0 2003 0.0 0.0 0.0 0.0 200.0 0.0 0.0 200.0 2005 0.0 25.0 0.0 25.0 400.0 25.0 0.0 425.0 TOTAL 1,736.0 332.0 44.4 2,112.4 1,455.4 225.0 32.0 » 1,712.4 9C-AI TABLE IV-11 COST OF MAJOR CAPACITY ADDITIONS, RAILBELT REGION (1982 dollars) Susitna Natural Gas-Fired! Coal-Fired Combined Cycle Steam Electric Capital Cost ($/kW) 3159 1050 2100 Capacity (mW) 1620 75 50 Fixed Charge Rate (%) 10.5 15 15 Discount Rate (%) 15.7 15.7 15.7 Fuel Cost ($/MMBtu)? 1.0 1.24 Fixed O&M ($/kW) 19 7.5 17 Variable O&M ($/mWh) 1.8 0.6 1. Natural gas-fired combined cycle capacity is added in the Anchorage area while coal-fired steam electric capacity is added in Fairbanks in the non-Susitna scenario. 2. Natural gas prices are escalated taking into account future contract renegotiations. All other costs are escalated by the rates listed in Appendix D. TABLE IV-12 AVERAGE DISCOUNTED VALUE OF ELECTRIC RATES AND LEVELIZED ELECTRICITY COST RAILBELT REGION* (¢/KWH) With Without** Average Discounted Rates Susitna Susitna Anchorage — Kenai — Matanuska — Susitna 0.8803 0.9035 Fairbanks 1.4371 1.4837 Valdez-Cordova 3.0181 3.2814 Average*** 1.0400 1.0729 With Without** Levelized Electricity Cost Susitna Susitna Anchorage — Kenai — Matanuska — Susitna 9.67 9.93 Fairbanks 15.79 16.31 Valdez-Cordova 33.17 36.06 Average*** 11.43 11.79 *The values on this table represent the average cost of electricity, from all generating sources, for the region under alternative scenarios. Electricity from hydro, baseload thermal and peaking thermal generation is included in each simulation of the scenarios. This is in contrast to Table IV-5 where the cost of electricity from a single generating source is given. **The scenario without Susitna assumes natural gas-fired capacity additions in Anchorage, coal-fired additions in Fairbanks and oil-fired additions in Valdez-Cordova. ***Weighted on the basis of electric consumption in three subregions of the Railbelt. IV-27 with a continued effective conservation program, the analysis of Susitna holds up even substantially lower growth rates. The growth rates for electricity demand were dropped to 2.5 percent per annum. At that lower growth rate for electricity demand, the Susitna project still remains marginally better than the thermal generation alternatives. The Susitna project was analyzed under two financing alternatives. The first was as a traditional public project financing with a fixed charge rate of 10 percent. This traditional financing causes a substantial price shock in electricity demand: the 1993 price increase from 13.12¢ to 28.03¢ per kilowatt-hour causes a dramatic drop in electricity demand. This price shock is severe and can be reduced by alternative financing. With alternative financing, all principal and some interest costs are deferred, starting with only 6.5 percent interest repay- ment (0.5% real) in 1993, rising to the full 8.5% (2.99 % real) interest payment in 2003, when the Devil’s Canyon portion starts commercial operation. This financing alternative replaces the price shock to approximately 2¢/kWh. After 2003, principal plus rolled over interest payments are paid off over the remaining economic life of the project. Under the “Low Growth” scenario, the lower growth of electricity demand, even with conser- vation, can be served at a low, long-term cost by Susitna. If a lower capital cost option is preferred, natural gas combined cycle power plants can meet demand at nearly comparable rates Under “Accelerated Growth”, both Susitna or a coal-fired generation (drawing on the economics of an export coal mine) can provide economical attractive options. IV.4 STRATEGIC ENERGY OPTIONS The energy alternatives identified above can be combined subject to secondary screening criteria. These secondary screening criteria match energy options to energy policy and introduce the public interest and policy issues. Energy policy objectives and the interest of Alaskans synthesize alternatives into strategic energy options. The strategic energy options which best meet the energy policy objectives and the public interest and policy issues are summarized in Figures IV-6 through IV-8 and described below. IV.4.1 For the Bush Regions Under “Low Growth”, the minimization of long-term energy costs and a moderate pace of growth can be achieved through the continued use of fuel oil for decentralized electric gener- ation in small villages and the use of community diesel-generators in larger villages and regional centers. The household use of oil for space heating plus the encouragement of conservation will provide the end-use path to low, long-term energy costs. Solid fuel stoves can provide economical heat. If the village or community is not far from a regional center or larger electric generator, the distribution of electricity by single-wire ground return system may be attractive if demand is high. In the future, Stirling engine energy systems may offer attractive economies as decentralized sources of electricity and heat. Under the “Moderate Growth” scenario, the energy options for the Bush would change little. Oil use will continue in current patterns and larger scale regional projects may be introduced where economical. Community-sized diesel generators could also be possible. Decentralized use of Stirling engine total energy systems may prove practical. IV-28 67-Al Region FIGURE IV-6 STRATEGIC ENERGY OPTIONS LOW GROWTH ENERGY PLAN Current Efficiency Practice Improvements Fuel Substitution Bush and Rural North Slope: — Electricity — Thermal Railbelt: — Electricity — Thermal *An attractive future alternative; excellent if shown flexible in various solid fuels use (coal, wood). Diesel Generators Oil Furnaces and Heaters Natural Gas, Coal, Hydro and Diesel Electric Generators Natural Gas and Oil Furnaces, Small Amount of Electric Heat ® Bottoming Cycle on Existing Diesel Generators @ Single-Wire Ground Return Distribution © Conservation @ Natural Gas Combined Cycle Power Plants © Bottoming Cycles on Existing Diesel Generators © Electric Transmission Lines Conservation Air Recuperators Electric Heat to Natural Gas e@ Wind Energy Systems *Stirling Engine Electric System @ Wood/Coal Stoves *Stirling Engine Energy System @ Hydropower e@ Wind Energy Systems *Stirling Engine Electric System — Rural Areas @ Solar Passive e Natural Gas Transmission *Stirling Engine Electric System — Rural Areas O€-Al FIGURE IV-6 STRATEGIC ENERGY OPTIONS LOW GROWTH ENERGY PLAN (Continued) Current Efficiency Fuel Region Practice Improvements Substitution Southeast: — Electricity Hydropower, Diesel @ Bottoming Cycles on e@ Wind Energy Systems Generators and Gas Diesel Generators @ Hydropower Turbines @ Conservation *Stirling Engine Electric System — Rural Areas — Thermal Oil Furnaces and @ Conservation e Solar Passive Electric Heat Barrow & Prudhoe Bay: — Electricity — Thermal Transportation *An attractive future alternative; excellent if shown flexible in various solid fuels use (coal, wood). Natural Gas Turbines and Diesel Generators Natural Gas and Oil Furnaces Petroleum Products Source: Arthur D. Little, Inc. e Air Recuperators ®@ Bottoming Cycles on Diesel Generators @ Waste Heat Recovery Generators Conservation Waste Heat Recovery Systems e Air Recuperators *Stirling Engine Energy System — Rural Areas @ Wind Energy Systems Region FIGURE IV-7 STRATEGIC ENERGY OPTIONS MODERATE GROWTH ENERGY PLAN Current Practice Bush and Rural North Slope: — Electricity — Thermal Railbelt: — Electricity — Thermal Southeast: — Electricity — Thermal Diesel Generators Oil Furnaces and Heaters Natural Gas, Coal, Hydro, Diesel Electric Generators Natural Gas and Oil Furnaces, Small Amount of Electric Heat Hydropower, Diesel Generators, Gas Turbines Oil Furnaces and Heat Barrow & Prudhoe Bay: — Electricity — Thermal Transportation Natural Gas Turbines and Diesel Generators Natural Gas and Oil Furnaces Petroleum Products Source: Arthur D. Little, Inc. Efficiency Improvements Single-Wire Ground Return Distribution Bottoming Cycle on Existing Diesel Generators Conservation Natural Gas Combined Cycle Power Plants Bottoming Cycles on Gas Turbines and Diesel Generators Conservation Switch to Natural Gas from Electricity Conservation Electric Transmission Lines Conservation Conservation Conservation IV-31 Fuel Substitution Wood Coal Stoves Hydropower Electric Transmission and Distribution for Rural Areas Natural Gas Distribution Electric Transmission Lines Hydropower €-Al c FIGURE IV-8 STRATEGIC ENERGY OPTIONS ACCELERATED GROWTH ENERGY PLAN Current Efficiency Fuel Region Practice Improvements Substitution Bush and Rural North Slope: — Electricity Diesel Generators e@ Commercial/Industrial e@ Wind Energy Systems Generation Systems with *Stirling Engine Heat Recovery Electric System — Thermal Oil Furnaces and @ Conservation @ Wood/Coal Stoves — Heaters © Commercial/industrial Rural Areas - Cogeneration *Stirling Engine Energy System Railbelt: — Electricity Natural Gas, Coal, © Bottoming Cycles on © Coal-Fired Electric Hydro and Diesel Diesel Generators in Generators Electric Generators Rural Areas e Hydropower @ Commercial/Industrial e@ Wind Energy Systems Cogeneration — Thermal Natural Gas and Oil @ Conservation e Natural Gas Furnaces, Small @ Commercial/Industrial Distribution Amount of Electric Cogeneration @ Wood/Coal Stoves — Heat Natural Gas Rural Areas *An attractive future alternative; excellent if shown flexible in various solid fuels use (coal, wood). €e-Al FIGURE IV-8 STRATEGIC ENERGY OPTIONS ACCELERATED GROWTH ENERGY PLAN (Continued) Current Efficiency Fuel Region Practice Improvements Substitution Southeast: — Electricity Hydropower, Diesel @ Commercial/industrial e Hydropower Generators and Gas Cogeneration e Electric Transmission Turbines Lines *Stirling Engine Electric System — Thermal Oil Furnaces and © Commercial/industrial e Electric Heat Pumps Electric Heat Conservation *Stirling Engine Barrow and Prudhoe Bay: — Electricity Natural Gas Turbines @ Commercial/industrial and Diesel Generators Cogeneration — Thermal Natural Gas and Oil Furnaces Transportation Petroleum Products *An attractive future alternative; excellent if shown flexible in various solid fuels use (coal, wood). Source: Arthur D. Little, Inc. Energy System Under the “Accelerated Growth” scenario, the State seeks to maximize the use of renewable energy in the Bush to conserve oil and hold down the cost of energy, which may increase slightly faster than in other scenarios. Conservation will play a very important role in this case, as will energy systems than can provide both heat and electricity economically. Here, the application of a Stirling engine energy system for solid fuels is likely to prove attractive. Wind energy systems can eliminate some of the cost of electricity generation, but care must be used that the savings of fuel are not negated by decreases in the efficiency of diesel generators that operate when the wind systems cannot. For the Bush, the options across this broad range of energy policies start with conservation and improvements in efficiency in the use of fuel oil for thermal needs and electricity. Investments in heat recovery systems or alternative energy systems appear attractive; they can provide savings of fuel oil amounting to 2,000 to 3,000 dollars per year. This would permit a household to recover a capital investment of 5,000 to 7,000 dollars over the course of a few years, and realize a reduction in their annual energy bill of 1,000 to 1,600 dollars. This would reduce the average household energy bill in 1982 for Nome by 20 to 32 percent, for Bethel by 25 to 35 percent, and for other areas in the interior by 33 to 54 percent. |V.4.2 For the North Slope The alternatives for the North Slope do not differ greatly from those of the Bush. The continuing use of natural gas and fuel oil at Barrow and Prudhoe Bay is clearly the most economical alternative, given the investment already made in central energy systems and the reasonable prices of natural gas and fuel oil. A greater application of conservation in Barrow could improve annual energy cost and extend the availability of natural gas. For the other North Slope communities, as in the Bush, the alternatives are to conserve or to improve energy efficiency where possible. Thus, the use of heat recovery systems and existing diesel generators for thermal energy, or bottoming cycles for electricity generation, can increase efficiency. Similarly, the use of a Stirling engine energy system for thermal and electricity needs of a household could be attractive, even if powered by fuel oil. It is not clear whether the use of renewable energy sources like wind is economical for the North Slope; good wind energy densities exist but operation and maintenance costs under very severe climatic conditions are likely to be prohibitive. If a “Low Growth” economic development policy is chosen, the continued use of fuel oil and natural gas should be promoted. Investments in heat recovery or bottoming cycles should only be made when there is an excellent payback. This will be difficult to achieve at current energy prices for Barrow and Prudhoe Bay, but would be practical for remote villages where the cost of fuel oil reaches $2.00 per gallon or more. If a “Moderate Growth” or “Accelerated Growth” policy is adopted, greater conservation and energy efficiency improvements are the best way to hold the impact of price increases down for residents and businesses in the near term. Currently, the average annual cost of energy per household in the North Slope region is 2,200 dollars. However, this includes those households in Barrow and Prudhoe Bay that profit from the use of natural gas at $2.00 per million Btus. For remote villages, the annual energy bill can be three to ten times as high as in Barrow or Prudhoe Bay. Here the upgrading of homes and the retrofitting of diesel generators with heat recovery or bottoming cycles is desirable. IV-34 |V.4.3 For the Southeast Region Given a “Low Growth” economic policy, the energy focus in the rural areas of the Southeast should be on low capital cost approaches. Oil for electricity and space heat must continue in use where electric transmission lines and renewable resources cannot economically provide long-term, low-cost electricity to households and businesses. Decentralized alternatives of solid fuel stoves, Stirling engine energy systems, and heat recovery systems should be exam- ined in depth, and introduced where economical for thermal needs. Many of these options face difficult economic tests. The average annual energy bill for a household in the Southeast (excluding Juneau) is 2,350 dollars. A 20 percent saving in energy use represents a 470 dollar per annum cost savings or, at a 15 percent interest rate, a 3,000 dollar investment which can be financed. Typical investments which could pay off at this level of savings are wind energy systems, solid fuel stoves (wood), conservation, and solar hot water systems. However, higher-cost investment options are precluded. Under a “Moderate Growth” economic policy, the emphasis will be on regional electric distri- bution, and greater use of oil for central electricity generation where hydropower is not available or economically attractive. The use of heat pumps, with earth-sourcing as primary heating and fuel oil or electric heat as supplements, can be attractive, given greater availability of electric generation capacity. While the use of fuel oil and electricity is the focus of the energy plan, a strong measure of conservation will reduce total energy demand per customer. The typical household in the Southeast uses approximately 220 million Btus for space and water heating. A 20 percent saving would cut 470 dollars off the household energy budget and could finance ceiling insulation, weatherstripping, and caulking with a one- or two-year payback. However, the use of earth-source heat pumps with hydropower delivered at 6¢ to 7¢ per kilowatt-hour can promote the utilization of the Southeast hydropower resources and result in competitive house heating costs. For hydroelectric costs above the 6¢ to 7¢ per kilowatt-hour delivered, the saving in fuel oil achieved by switching to a heat pump will be insufficient to warrant the investment. Under an “Accelerated Growth” policy, the energy plan should focus on the maximum use of renewables for electricity and space heating, with a heavy emphasis on conservation to reduce the demand for oil. This program would also help consumers hold their energy costs down as the price of fuel oil rises. The investment in renewable sources may not yield the lowest short- term energy cost, but it should help stabilize prices to consumers as Alaska enters more Pacific Rim markets. The use of wood-fueled steam electric generators will provide substitutes for oil where hydropower is not available. Similarly, the use of cogeneration by industry and the sale of cogenerated power by industry to the local electric utility is appropriate in this scenario. |V.4.4 For the Railbelt The Railbelt offers many alternatives which can be synthesized into coherent energy options. Under a “Low Growth” policy, the Railbelt has readily available hydropower, natural gas, and IV-35 fuel oil. The challenge is to select the alternatives, both for thermal and electricity needs, that will provide the lowest long-term energy cost for the minimum investment. Certainly, for thermal needs, the use of natural gas, even at new production prices recently contracted at $2.32 per thousand cubic feet, is significantly cheaper than oil at $1.30 per gallon or electricity delivered at 5¢ to 6¢ per kilowatt-hour. This price of natural gas should remain competitive with other fuels for in-state use even with the promotion of natural gas heating in the Railbelt as the lowest-cost alternative. While the cost of constructing a natural gas pipeline from the Cook Inlet to Fairbanks is too high to be attractive, a pipeline serving communities in the Kenai Peninsula and to the north of Anchorage in the Matanuska-Susitna Borough appears economically feasible. Where natural gas cannot be supplied, the alternatives of fuel oil and a heavy emphasis on conservation is appropriate.For electricity needs, the two lowest-cost alternatives for further generation additions are hydropower and natural gas-fired combined cycle power plants. Considering the alternatives evaluated earlier, the choice is among Susitna, Chakachamna with future gas-fired combined cycle units, or natural gas-fired com- bined cycle units alone. With electricity growth at 4.2 percent per annum for the Railbelt to 2000 (without a major emphasis on conservation by the State) or at a 2.9 percent growth rate per annum with reductions due to State conservation programs, Susitna, Chakachamna with future gas-fired combined cycle units, and natural gas combined cycle units alone are all acceptable. Susitna marginally shows the lowest long-term cost of electricity. Where the sensitivity to discount rates and possible fossil fuel price increase are considered, the Susitna project affords greater stability. From a capital cost standpoint, however, Susitna at 5.1 billion 1982 dollars is more than twice as expensive as the combined cycle alternative at nearly two billion dollars. Under a “Moderate Growth” economic policy, the options for the Railbelt are virtually the same as with “Low Growth”. The continued use of natural gas for electric generation rather than space heating fuel is inefficient. The Susitna project is to be compared with natural gas- fueled combined cycle plants and coal-fired steam electric power plants, and once again the comparative costs make Susitna the most attractive. The only major alternative in this scenario for the Railbelt is the introduction of natural gas heating in Fairbanks as an offshoot of the construction of natural gas pipeline to bring North Slope gas to market. In this case, the price to residential customers would be $5.00 to $5.50 per thousand cubic feet (in 1982 dollars). This would save the Fairbanks customers approximately 1,000 dollars per year on space heating alone. The construction of a North Slope natural gas pipeline provides two major benefits: the North Slope gas is brought to market, and the city of Fairbanks can have natural gas for space heating at an annual cost savings of 15 million dollars if all 15,000 centrally located residences in Fairbanks are connected. Given an “Accelerated Growth” policy, further opportunities for energy supply are available. In this case, the development of an export coal mine in the Cook Inlet area would provide the opportunity to use coal to generate electricity. The price differential between a dedicated coal mine for electric generation only at 400,000 to 600,000 tons per year and a five million ton per year mine would be approximately 50¢ per million Btus less at $1.20 per million Btus. This reduced price for coal would make a mine mouth plant associated with an export mine competitive with the Susitna option for this scenario. Thus, electricity generation in the Railbelt could be provided by the Susitna hydropower project or by coal-fired plants in the Cook Inlet area and near Fairbanks. This coal option would cost slightly less than 4.0 billion dollars, as compared to Susitna’s 5.1 billion dollars. Additional generation capacity would have be to be planned for the middle of the next century. IV-36 The natural gas option for Fairbanks would be available from a North Slope pipeline, and the distribution of natural gas to the Kenai Peninsula and north of Anchorage could also occur. Thus, the majority of the energy use in the Railbelt could be supplied by coal, natural gas, or hydropower. IV.6 SUMMARY OF STRATEGIC OPTIONS The key features of the strategic energy plans for Alaska under the three economic devel- opment scenarios are: A) “Low Growth” Emphasis on minimizing environmental impacts; Natural gas for space and water heat in the Railbelt and, where available, on the North Slope; Susitna for long-term, low-cost electricity or natural gas combined cycle power plants as lower capital cost alternatives for the Railbelt; Conservation in Bush and Southeast regions to hold down annual costs of space and water heating; Energy alternatives for electricity in the Bush, and small electric distribution sys- tems where practical; Hydropower for electricity in the Southeast. B) “Moderate Growth” Emphasis on development of major energy projects, one at a time; Natural gas for space and water heat in the Railbelt and the North Slope (where available); Susitna for long-term, low-cost electricity; Conservation in the Bush, Railbelt, Southeast, and North Slope regions to hold down space and water heating costs; Electric transmission and distribution in the Bush and the Southeast regions to improve efficiency and hold down electricity costs; Hydropower for electricity in the Southeast. IV-37 C) “Accelerated Growth” e Emphasis on selling Alaska’s energy resources; e@ Natural gas for space and water heating in the Railbelt and the North Slope (where available); @ Coal-fired steam electric power plants with coal export mine or Susitna hydropower project; @ Commercial/industrial cogeneration projects by industry where practical; e@ Hydropower and electric transmission projects in the Southeast; e Conservation and bottoming cycles for electricity in the Bush. IV-38 1983 Energy Report Appendix APPENDIX A ALASKAN OIL AND GAS DEVELOPMENTS ALASKAN OIL AND GAS DEVELOPMENTS Introduction Based on a review of available project sponsors' reports, publicly available information, and Arthur D. Little's assessment of United States and Pacific Rim energy markets over the next twenty years, the following assessment has been made of major oil- and gas-based "projects" likely to be undertaken by the year 2000. The definition of "projects" is a broad one, encompassing major stand-alone ventures (e.g., Alaska Natural Gas Transportation System (ANGTS) or a tidewater gas pipeline, or the Dow-Shell petrochemical complex), as well as aggregations of individual activities, such as exploration and new field development. Three development scenarios were adopted. The "Low Growth" scenario accepted Department of Natural Resources' forecast of oil and gas developments. Under "Moderate Growth", we included only those projects which are expected to come onstream by the year 2000 taking into account projected world economic and energy market conditions and assuming no financial subsidies or other forms of intervention by the State of Alaska which might otherwise accelerate their development. For example, a major natural gas export pipeline is not expected to be onstream by 2000 under "Moderate Growth", although it is quite probable that construction activity may have started prior to that date. Projects which overlap the year 2000, in the sense that they provide construction employment but not operating employment nor tax or royalty revenues for the State, are excluded from project lists and from the estimates of capital investment costs (Table A-l) and will be addressed later in this Appendix when the issue of project timing is discussed. Under "Accelerated Growth", we assumed a more favorable environment for new energy developments in Alaska, including higher energy prices, Federal and State government policies to accelerate Alaskan energy developments, and increased availability/lower cost of both public and private sector finance. The activities addressed here do not encompass the full range of Alaskan oil and gas activities, or funds flows through this period. Excluded are: e Physical activities and cash flows resulting from existing oil and gas operations; e New oil and gas investments which are too small, both individually and collectively, to identify (for example, new residential furnaces) ; e Activities or revenues arising from the implementation of these major new projects. For example, we have not estimated the cash flows, manpower requirements, or other aspects of new projects once they are onstream; and TABLE A-1 SUMMARY OF CAPITAL EXPENDITURES BY INDUSTRY FOR OIL AND GAS DEVELOPMENTS IN ALASKA TO 2000 (Billion 1982 Dollars) "Moderate "Accelerated "Low Growth" Growth" Growth" Oil and Gas Exploration! $ 8.80 $ 8.80 $16.35 Oil and Gas Development” 14.00 18.85 47.42 Prudhoe Bay $9.60 $9.60 $9.60 Kuparuk 3.50 3.50 8.50 Other Existing Discoveries 0.90 0.90 8.75 New Discoveries 0.00 4.85 20.57 Oil and Gas Transportation Syspeme 0.10 0.10 21.60 TAPS 0.10 0.10 0.10 Gas Pipeline-Gas Conditioning Plant? 0.00 0.00 17.00 NGL Pipeline-Extraction Plant 0.00 0.00 4.00 Aleutian Island Crude Oil Terminal 0.00 0.00 0.50 Oil- and Gas-Based Industrial Projects~ 0.15 0.15 7.05 Tesoro Hydrocracker Expansion 0.10 0.10 0.20 Chevron Catalytic Reformer Addition 0.05 0.05 0.10 LNG Export Facility 0.00 0.00 i,73 Dow-Shell Petrochemical Complex 0.00 0.00 5.00 Oil- and Gas-Based Marketing and Distribution” 0.17 0.17 0.48 Petroleum Distribution-Marketing 0.15 0.15 0.40 Fairbanks Gas Distribution 0.00 0.00 0.02 Anchorage Gas Distribution 0.02 0.02 0.06 Source: Arthur D. Little, Inc. estimates. 1. Excludes operating costs. 2. Excludes lease bonuses. 3. Alaska portion only. e Lease bonuses paid by energy companies for the rights to explore on State and Federal lands. In a few cases there were several alternative means by which projects could move ahead. The case of Prudhoe Bay gas is a good example where several alternative, or overlapping, options exist: e Alaska Natural Gas Transportation System; e The Hickel/Egan proposal to pipe gas to southern tidewater; e Methanol production on the North Slope; e Electricity generation on the North Slope; and e Extension of the Trans-Alaska Pipeline System (TAPS) natural gas fuel line to Fairbanks. Another good example would be the plethora of proposals received by the State to construct new local or export-oriented refineries based on Alaskan royalty crude. We reviewed each competing proposal, to the extent permitted by data availability and time, to separate out those that are mutually exclusive (and those that are not) and evaluated each project qualitatively in terms of its intrinsic technological, economical, and financial viability. Thus many proposals which have been made to the State, or discussed in the press, have been excluded based on our judgment that they are intrinsically less attractive than other project alternatives, or are economically infeasible on a stand-alone basis. Alaska is a resource-rich state in a relatively early stage of resource development. It is quite likely that major, new oil discoveries could be made in the next twenty years which fall well beyond the probabilistic assessments made here. In this case a higher level of investment activity would result. From the standpoint of energy policy assessment, we believe a conservative approach is preferable since developments based on undiscovered resources are more risk-prone. Finally, it should be noted that not all existing and expected oil and gas finds will be fully developed during this time frame. As a general rule, almost all oil, except for small offshore Arctic finds or heavy oil deposits (such as Ugnu), will be developed as quickly as technically, environmentally, and economically feasible. For natural gas, however, the economics of development and the lack of markets dictate against early development (viz. Prudhoe Bay). Discovery of natural gas, therefore, is much less likely to produce immediate investment and employment spin-offs. Overview of World Energy Environment The next twenty years will be characterized by continuing uncertainty in the price and availability of energy resources. Energy-importing A-3 nations will continue to exert efforts to reduce hydrocarbon consumption per GNP dollar through conservation and fuel-switching, using both market and regulatory mechanisms. Oil demand is likely to remain stable, or fall, in the developed countries but increase in the developing countries. Oil supplies will tend to exceed demand until declining real oil prices stimulate new consumption or until political events act to withdraw supplies from the market. The "Moderate Growth" scenario is for world oil prices to decline in real terms through the mid-1980s. The 1985-1990 time frame should see, however, a quantum increase in oil prices brought about by political or market events that will raise the real price of crude oil above its current level. Thereafter we expect another period of adjustment, lasting for perhaps five to ten years, characterized by falling oil prices in real terms (but not in money terms), followed by perhaps another upward surge around the mid-1990s. The trend line of oil price increases is expected to average about 1.4 percent per year in real terms through 2000 (see Appendix D). A small to moderate increase in real oil prices by 2000 will entail no significant change in market incentives to develop major export-oriented Alaskan gas projects. Oil exploration and development should thus continue to be attractive but will, as before, concentrate primarily on exports to the Lower-48 states. Outside the State, major markets for Alaskan oil and gas are the Lower-48 states and the Pacific Rim (notably Japan and Taiwan). Competition for oil markets will be intense. OPEC is the major crude supplier to the Pacific Rim and Alaskan crude cannot, currently, be exported. For petroleum products, surplus refining capacity in the Lower-48 states, Japan, and Singapore will make it very difficult for a new Alaskan export refinery to compete economically. Natural gas import markets exist in the Lower-48 states, Japan, and Korea; others may develop. Here Alaska must compete not only with low-cost suppliers (e.g., Canada, Indonesia, Malaysia, Australia, and some Middle East OPEC producers), but also against Lower-48 states supply, boosted by the progressively increasing price incentives for natural gas production put into effect by the Natural Gas Policy Act of 1978. The supply of natural gas from current or probable sources is expected to be more than adequate for world markets in the 1980s. After 1990, the depletion of current reserves will require the development of new sources, of which Alaska may be one. The level of United States Government support for Alaskan gas developments will be important. Without subsidies, major Alaskan gas developments before 2000 will be much more difficult, considering the high cost of development, financing difficulties, and problems in marketing. Chemical derivatives based on Alaskan gas (methanol, ammonia/urea) or natural gas liquids (NGL) (olefinic petrochemicals) face similar threats of over-capacity and competition from cheaper sources of production, such as the Middle East. A-4 Alaska suffers certain basic disadvantages in meeting the competition for United States and Pacific Rim energy markets. These include: e Distance from markets, particularly important in natural gas markets where transportation costs are much higher than for petroleum; e Climate and environment, resulting in higher capital and operating costs; e Technological challenges, arising out of exploration and commercialization of resources in frontier areas; and e Legislative restrictions on the export of primary hydrocarbons, and regulatory controls affecting shipping costs (i.e., the Jones Act). In a free market these disadvantages act to postpone the timing of energy developments until lower-cost resources are depleted and the scale economies of Alaskan resource developments offset the locational penalties. Furthermore, in static or declining energy markets, the very size of major new Alaskan projects poses problems of absorption and over-dependency. While these are not insurmountable obstacles, they tend to add to the number of project participants, blur the market focus, and add to the overall cost. If this analysis sounds excessively pessimistic, it should be noted that these comments apply to the timing, rather than the ultimate viability of Alaskan oil and gas projects. The world will continue to need energy, and resource depletion will inevitably make the development of currently sub-commercial Alaskan oil and gas economically attractive. In the long run, Alaskan policy-makers may be assured that their resources will find markets. Overview of Alaskan Oil and Gas Developments As Table A-1l shows, capital expenditures on major oil and gas development projects under the "Moderate Growth" scenario are estimated to amount to approximately 19 billion 1982 dollars through the year 2000. (It is assumed that under the "Low Growth" scenario that only additional capital investment to support OCS development will be needed in the next 25 years.) Under this scenario, very heavy emphasis is placed on oil exploration and development, with less than one billion dollars of investment going into transportation systems, industrial projects, and marketing of oil and gas in Alaska. This scenario reflects an environment under which energy prices do not increase significantly in real terms and markets for gas-based products suffer from intensifying competition from more proximate and less costly sources. Under the "Accelerated Growth" scenario, where economic and policy conditions are more favorable to accelerated development of Alaskan oil and gas resources, nearly 100 billion 1982 dollars could be spent on projects through the year 2000. Aside from the higher level of oil and A-5 gas exploration and development, major gas-based projects are forecast to come onstream in this scenario. Of particular importance are projects surrounding the commercialization of Prudhoe Bay natural gas, including a natural gas pipeline system and an NGL pipeline system linked to a petrochemical complex in southern Alaska. Thus a more rapid rate of oil development, better utilization of natural gas resources, and greater diversification of the industrial base in Alaska occurs in "Accelerated Growth." This results from higher expectations with respect to world energy prices, as well as policy, legislative, regulatory, and financial measures taken to stimulate the Alaskan economy. Unless these actions are taken, however, it can be seen that the economy of Alaska, at least in energy terms, will continue to be substantially dependent upon oil, the great majority of which is exported outside the State for further processing and use. Oil and Gas Exploration The identification and eventual production of oil and gas from unexplored areas relies on two basic parameters. These are: first, the existence and distribution of undiscovered resources; and _ second, Federal and State leasing programs which dictate the extent and timing of new exploration efforts. In its most recent survey of potential undiscovered resources, the United States Geological Survey (USGS) (Circular 860-1982) estimated an undiscovered crude oil resource in Alaska of 7.1 billion barrels (at a 95 percent probability leve1)!, somewhat less than the _ proven 2 reserves contained within the Prudhoe Bay. reservoir. The mean estimate of undiscovered crude oil reserves (Table A-2) is 19.1 billion barrels. Undiscovered natural gas resources are estimated at 53 trillion cubic feet at a 95 percent probability level, and the mean estimate is over 100 trillion cubic feet. While these numbers may appear large, they are lower than previous USGS estimates and cannot provide a substantive basis for State policy-making until the resource estimates are converted into reserves through the exploration process. Undiscovered resource estimates favor natural gas, rather than crude oil resources, and favor offshore rather than onshore discoveries. As already discussed, this distribution is likely to result in a slower rate of development of these resources (when and if they are discovered) than if they were predominantly onshore crude oil. Nevertheless, Alaska still represents, to a very large extent, the last frontier of oil and gas exploration in the United States. We may expect continued high levels of exploration activity in Alaska, consistent with the pace of leasing programs, industry cash flow availability, and the technology to deal with exploration in increasingly severe and environmentally difficult locations. 1. The probability of more than the amount of the resource is 95 percent. pa A "most likely" estimate of the quantity of resource associated with the greatest likelihood of occurrence. A-6 TABLE A-2 STATE OF ALASKA OIL AND GAS RESOURCE ESTIMATES Onshore Cumulative Production Reserves: - Measured (Proven) - Indicated - Inferred Undiscovered Resources: - 95% Probability - Mean - 5% Probability Offshore Cumulative Production Reserves: - Measured (Proven) - Indicated - Inferred Undiscovered Resources - 95% Probability - Mean - 5% Probability Total Cumulative Production Reserves: - Measured (Proven) - Indicated - Inferred Undiscovered Resources: - 95% Probability - Mean - 5% Probability (As of December 31, 1979) Natural Gas Crude Oil Liquids Natural Gas (10°Bb1s) (10°Bb1s) (TCF) 1.2 Small 1.2 aie 0.4 30.0 0.0 n/a n/a 5.0 n/a 4.4 Zuo) ; 19.8 6.9 1.3 36.6 14.6 62.3 0.7 Small 0.6 0.2 0.4 2.0 0.0 n/a n/a 0.1 n/a i.e 4.6 33.3 22 2.1 64.6 24.2 109.6 1.9 Small 1.8 8.9 0.8 32.0 0.0 n/a n/a oy k n/a 5.6 Fel f 53.1 19.1 3.4 101.2 38.8 l 171.9 Source: United States Geological Survey, Circular 860 (1982). A-7 In Table A-3 we have summarized the proposed leasing schedules for the Alaskan offshore and onshore basins. Dates for Federal and State lease sales have now been established for all the prospective basins, even those which have yet to be explored (e.g., Bering Sea). Table A-3 shows the planned dates for first lease sales in each of the basins that will eventually be opened up for oil and gas exploration, as well as the distribution of proven reserves and undiscovered resources as estimated by the USGS. (Table A-3 does not represent the entire Alaska oil and gas resource base as presented in Table A-2). Table A-4 shows an estimated schedule for exploration and production activity to follow the leasing schedules shown in Table A-3. In addition, the volume of reserves likely to be discovered and the resulting levels of oil and gas production by the year 2000 are also shown. Both the 95 percent case and the mean estimate assume that one half of the USGS reserve estimates shown in Table A-3 will be discovered by the year 2000. For oil, the reserve estimates were converted into production rates by applying reserve-to-production ratios varying from fifteen to twenty- five years (depending upon the lead time and technological complexity required to initiate production for a particular reserve). In the case of natural gas, market limitations were assumed to dictate the early development of new natural gas reserves found outside the Cook Inlet. It was assumed that additional gas in the Cook Inlet could be brought onstream to support the growth in domestic natural gas consumption in the Anchorage area or even, in an optimistic scenario, to provide sufficient incremental production to support an liquefied natural gas (LNG) project, such as Pac-Alaska, at a level of up to 400 million cubic feet per day. A continuing use of natural gas for electric generation will considerably shorten the time horizon over which the Cook Inlet fields will support an export project and the increasing consumer demand of the greater Anchorage area. Table A-4 shows that exploration outside traditional producing areas in Alaska is likely to produce at least 200 thousand barrels per day of oil production by the year 2000, and possibly as much as 890 thousand barrels per day under the mean estimate case. Based on the oil and gas exploration program discussed above and presented in Table A-4, we have estimated the cumulative capital expenditure on oil and gas exploration through 2000 under both the "Moderate Growth" and "Accelerated Growth" scenarios. These costs are subject to considerable uncertainty since many of the Arctic regions, such as the Beaufort and Bering Seas, remain virgin provinces. Until better experience of these frontier areas can be obtained, any estimate of exploration expenditures must remain speculative. The estimates included in Table A-5 are conservative and may understate actual exploration expenditures in 1982 dollars by as much as 50 or 100 percent. It should be noted that these figures exclude any payments by exploration companies to the United States Government or the State of Alaska in the form of lease bonuses. TABLE A-3 PROSPECTIVE ALASKAN OIL AND GAS BASINS UNDER PROPOSED LEASING SCHEDULES Subregion Area Exploration Activity Planned Proven Reserves Undiscovered Resources Date Date Date 95% Probability Mean of of First of First Date of Lease Exploration Commercial First Sale Activity Discovery Production Crude Oil Gas Crude Oil Gas Crude Oil Gas (10°Bb1) (TCF) ~—-(10°Bb1) (TCF) ~(10°Bb1) _(TCF) Arctic Onshore North Slope 1964 1967 1968 1977 8.3 29.00 (NPR-A) 1981 1948 1949 1950 0.0 0.02 0.9 3.8 4.4 18.1 (ANWR) ? ? ? ? 0.0 0.00 Arctic Foothills ? 2? ? ? 0.0 0.00 0.3 3.2 1.6 13.7 Arctic Sea Beaufort Sea/Diapir 1980 1981 ? ? 0.0 0.00 1.9 9.4 7.0 35.0 Chukchi Sea/ Barrow Arch 1985 ? ? ? 0.0 0.00 0.0 0.0 1.4 6.4 Hope Basin 1985 ? 2 2? 0.0 0.00 0.0 0.0 0.0 0.3 Bering Sea Norton Basin 1982 0.0 0.00 0.0 0.0 0.2 1.2 St. Matthew-Hall ? 0.0 0.00 0.0 0.0 0.0 0.0 Navarin Basin 1984 0.0 0.00 0.0 0.0 0.9 5.6 North Aleutian Basin 1985 0.0 0.00 0.0 0.0 0.3 1.5 St. George Basin 1984 7 ? ? 0.0 0.00 0.0 0.0 0.4 2.3 Aleutian Basin 2 0.0 0.00 0.0 0.0 0.0 0.0 Bowers Basin ? 0.0 0.00 0.0 0.0 0.0 0.0 Aleutian Arc ? 0.0 0.00 0.0 0.0 0.0 0.0 Shumagin 1985 0.0 0.00 0.0 0.0 0.0 0.6 Gulf of Alaska Cook Inlet Onshore 1950 1956 1957 1961 0.4 1.00 0.1 1.1 0.6 3.3 Cook Inlet Offshore 1960 1962 1962 1966 0.2 2.00 Mad: Cad 0.4 tak Gulf of Alaska Onshore ? ? ? ? 0.0 0.00 0.0 0.0 0.2 0.3 Offshore 1976 1976 ? ? 0.0 0.00 0.0 0.0 0.4 2ad Kodiak 1985 ? ? ? 0.0 0.00 0.0 0.0 0.4 2.0 Source: United States Geological Survey, Circular 860 (1982) OT-V TABLE A-4 DEVELOPMENT SCHEDULE FOR NEW ALASKAN OIL AND GAS DISCOVERIES 95% PROBABILITY MEAN Commercial Commercial Reserves Potential Reserves Potential Discovered by Production on Discovered by Production on Date Date 01/01/2000 01/01/2000 01/01/2000 01/01/2000 of First of First Date Exploration Commercial of First Oil Gas Oil Gas Oil Gas Oil Gas — Activity Discovery Production (19sb1s) (TCF) (MB/D) (MMCF/D) (10°Bb1s) (TCF) (MB/D) (MMCF/D) North Slope 1967 1984 1989 0.1 0.3 15 0 ou 1.0 30 0 NPR-A 1982 1984 1992 0.2 1.0 30 0 1.0 4.5 140 0 ANWR 1990 1993 2000+ 0.2 0.6 0 0 1.0 3.5 0 0 Arctic Foothills 1987 1990 2000+ 0.2 1.6 0 0 0.8 6.8 0 0 Beaufort Sea/ Diapir 1981 1984 1992 1.0 4.7 135 0 aus 17.5 480 0 Other Arctic 1987 1990 2000+ 0.0 0.0 0 - 0.7 au3 0 0 Bering Sea 1984 1986 1994 0.0 0.0 0 0 0.9 5.6 100 0 Cook Inlet” 1956 1984 1987 - 0.1 0.9 20 90 os 3.0 90 300 Gulf of Alaska 1976 1987 1993 0.0 0.0 0 0 0.4 2.2 50 0 TOTAL 1.8 9.1 200 90 9.0 38.4 890 300 1. Excluding existing discoveries (Prudhoe Bay, Kuparuk, Flaxman Island/Pt. Thompson, Milne Point/Gwdyr Bay, Sag Delta and Duck Island). 2. Excluding existing onshore and offshore discoveries in the Upper Cook Inlet. Source: Arthur D. Little, Inc. estimates based on USGS resource evaluation. TI-V TABLE A-5 ESTIMATED ALASKAN OIL AND GAS EXPLORATION EXPENDITURES TO 2000 Cumulative Exploration Number of Exploration Expenditures 1982-2000 Wells 1982-2000 Cost per (Billion 1982 Dollars) "Moderate "Accelerated Exploration Well "Moderate "Accelerated Growth" Growth" ($ Million) Growth" Growth" North Slope! 150 200 $10 $1.50 $2.00 Beaufort Sea 150 250 35 5.25 8.75 Bering Sea 50 150 30 1.50 4.50 South Alaska, Onshore 20 40 5 0.10 0.20 Cook Inlet/ Gulf of Alaska 30 60 15 0.45 0.90 TOTAL WELLS 400 700 TOTAL EXPENDITURES $8.80 $16.35 1. Including NPR-A, ANWR and Arctic Foothills. Source: Arthur D. Little, Inc. estimates. Oil and Gas Development and Production Two cases for Alaskan crude oil production were forecast through the year 2000. The "Moderate Growth" scenario relies upon the Alaska Petroleum Revenue Division's June 1982 forecast of production from existing discoveries, to which are added estimated production (at the 95 percent probability level) for new fields discovered prior to 2000. Under the "Moderate Growth" scenario (Table A-6), the forecast portrays a steadily declining level of Alaskan crude oil production after 1989, when the Prudhoe Bay field production begins to drop off. In this case, TAPS throughput by the year 2000 falls to approximately half of its current level. Table A-7 shows our forecast of Alaskan crude oil production under the "Accelerated Growth" scenario, in which Alaskan crude oil production is expected to remain in the range of 1.6 to 1.9 million barrels per day over the next eighteen years. This incremental production is derived from several sources: o More extensive development of existing North Slope/shallow Beaufort Sea discoveries, including Milne Point, Sag Delta, Duck Island, and the cretaceous heavy oil Ugnu deposits overlying the Kuparuk reservoir. This last source is of particular interest to longer-term Alaskan energy developments, since up to 40 billion barrels of heavy oil-in-place have been estimated for this resource. | Major problems of recovery and on-site upgrading need to be addressed before Ugnu can contribute significantly to longer-term Alaskan oil production, but eventually this deposit may become the largest single source of Alaskan oil production in the 2lst century.. o A more accelerated and successful program of exploration in the deep Beaufort Sea (such as the Diapir field) resulting in an incremental 350 thousand barrels per day of oil production’ by 2000. o Successful exploration in the Bering Sea resulting in commercial oil discoveries brought into production by the year 2000 at a level of around 100 thousand barrels per day. While several basins hold promise, the Navarin basin is perhaps the most attractive in terms of underlying resource potential. The technology for successful production in the Bering Sea is still uncertain and production mechanisms could involve the combined use of gathering pipelines to St. Matthew Island and shuttle tankers to a very large crude carrier (VLCC) terminal in the Aleutian Islands, or by the construction of a direct pipeline from the producing areas to the Aleutians. 1. Based on proprietary oil industry communication and articles in the Oil and Gas Journal. A-12 €I-V ALASKAN CRUDE OIL PRODUCTION FORECAST, "MODERATE GROWTH" North Slope: l Prudhoe Bay Crude/Condensate Kuparuk/Milne Point Flaxman Island/Pt. 1 Thompson/Canning Island Sub-Total Existing Discoveries New Discoverjes on North Slope/NPR-A, Beaufort Sea Total TAPS Throughput Cook Inlet: 1 Existing Fields, New Discoveries Total Cook Inlet TOTAL ALASKA TABLE A-6 (Millions of Barrels per Day) 1983 1984 1985 1986 1987 1988 1989 1990 1995 2000 1.52 1.53 1.53 1.54 1.53 Lipa — tanto 1.31 0.61 0.28 0.09 0.14 0.20 0.28 0.31 0.31 —0.31_— 0.31 70.24 0.20 0.00 0.00 0.00 0.00 0.00 0.00 0.02 0.02 0.05 0.06 1.61 1.67 1.73 1.82 1.84 1.84 1.85 1.64 0.90 0.54 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.01 0.04 0.05 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.06 0.14 1.61 1.67 1.73 1.82 1.84 1.84 1.85 1.65 1.00 0.73 0.07 0.06 0.06 0.05 0.05 0.04 0.04 0.03 0.02 0.01 0.00 0.00 0.00 0.00 0.01 0.01 0.01 0.01 0.02 0.02 0.07 0.06 0.06 0.05 0.06 0.05 0.05 0.04 0.04 0.03 1.68 1.73 1.79 1.87 1.90 1.89 1.90 1.69 1.04 0.76 2. Arthur D. Little, Inc. estimates. 1. Alaska Petroleum Revenue Division Quarterly Report, June 1982. vI-V TABLE A-7 ALASKA CRUDE OIL PRODUCTION FORECAST, "ACCELERATED GROWTH" North Slope: Prudhoe Bay Crude/Cgndensate’ Kuparuk/Milne Point Flaxman Island/P5. Thompson /Canning Island 1 Sag Delta/Duck, Island Ugnu Heavy Oil Sub-Total Existing Discoveries New Discoveries on North Slope sNPR-A Beaufort Sea Total TAPS Throughput 2 Bering Sea * Cook Inlet: Existing Fields, New Discoveries Total Cook Inlet Gulf of Biases” TOTAL ALASKA (Millions of Barrels per Day) 1983 1984 1985 1986 1987 1988 1989 1990 1995 2000 1.52 1,53 ivao 1.54 1,53 1,53 inane 1.34 0.64 0.31 0.09 0.14 0.20 0.28 0.31 0°31 — 0.31— —0.31—7 0.30. —0.30 0.00 0.00 0.00 0.00 0.00 0.00 0.04 0.06 0.10 0.10 0.00 0.00 0.00 0.00 0.00 0.00 0.02 0.04 0.15 0.15 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.05 0.10 1.61 1.67 laa? 1.82 1.84 1.84 1.89 17 o— 1:28 0,06 0.00 0.00 0.00 0.00 0.00 0.00 0.01 0.02 0.08 0.17 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.15 0.48 1.61 1.67 1.73 1,82 1.84 1.84 1.90 1.77 1.47 1.61 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.02 0.10 0.07 0.06 0.06 0.05 0.05 0.04 0.04 0.03 0.02 0.01 0.00 0.00 0.00 0.00 0.01 0.02 0.02 0.03 0.06 0.09 0.07 0.06 0.06 0.05 0.06 0.06 0.06 0.06 0.08 0.10 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.01 0.05 1.68 1.73 1.79 1.87 1.90 1.90 1.96 1.83 1.58 1.86 2. Arthur D. Little, Inc. estimates. 1. Alaska Petroleum Revenue Division Quarterly Report, June 1982. e A greater level of success in southern Alaska, both onshore and offshore, including the Copper River basin, Upper and Lower Cook Inlets, and the Gulf of Alaska. Based on these two production forecasts, we have estimated the development costs for both existing and new crude oil reservoirs to meet the volume projections in Tables A-6 and A-7. Table A-8 summarizes the capital expenditures projected for the 1982-2000 period for the Prudhoe Bay field as well as other fields on the North Slope/shallow Beaufort Sea. Capital cost estimates were obtained from the press and checked with the Prudhoe Bay partners where possible. These figures, which are presented in constant 1982 dollars, discount construction already completed before January 1, 1982. Particular uncertainty is attached to the costs for developing new fields on the North Slope (e.g., Flaxman Island, Point Thompson, etc.) and, in particular, for the development costs of the Ugnu heavy oil deposit. While development costs for Ugnu could conceivably exceed the $50,000 per barrel per day estimated in Table A-8, any significant increase above that level will render Ugnu field development uneconomic for the foreseeable future. Estimates of the costs to develop oil production from new Alaskan discoveries are listed in Table A-9. Once again it should be stressed that the level of uncertainty surrounding these cost estimates is very high. For example, various press reports have suggested a range of between $15,000 and $50,000 per barrel per day to develop deep Beaufort Sea oil. Until these uncertainties are resolved through experience, the capital costs, timing, and ultimate production levels associated with these new oil discoveries must perforce remain speculative. Oil and Gas Transportation Systems ‘ Under the "Moderate Growth" scenario, we foresee very little added activity downstream of the oil and gas exploration and development, since crude oil will continue to use existing transportation systems and no major new uses for natural gas are expected. In this case, the only significant developments which we expect to arise are: e The addition of Pump Station #11 on the Trans-Alaska Pipeline to permit throughput of up to two million barrels per day; e The addition of a catalytic reformer at Chevron's Nikiski refinery, as well as an expansion of the hydrocracker at the Tesoro refinery; e The replacement of petroleum distribution logistics facilities (e.g., trucks), and addition of petroleum storage in the Bush; and e Expansion of the Anchorage residential gas distribution system by Enstar. A-15 9T-V TABLE A-8 ESTIMATED DEVELOPMENT COSTS FOR EXISTING ALASKAN OIL AND GAS FIELDS TO 2000 (Billion 1982 Dollars) Cumulative Expenditure Estimated 1982-2000 Start Projegt "Moderate "Accelerated Field Project Duration Date Cost Growth" Growth" (Years) Prudhoe Bay Infill Drilling 5 1979 $2.0 - 3.0 $2.50 Produced Water Injection 3 1981 1.0 1.00 Seawater Injection 4 1982 1.5 - 2.0 1.80 Gas Lift 3 1983 1.5 - 2.0 1.70 Low Pressure Separators 4 1981 1.5 - 2.0 1.70 Well-Pad Manifolding 4 1981 0.7 0.70 Operations Center 2 1981 0.2 0.20 Kuparuk/ Field Development / Milne Point Waterflood 8 1979 5.07 3.50 3.50 Miscible Gas Recovery . 5 1987 5.0 0.00 5.00 Other Fields Flaxman Island/Pt. Thompson/ Canning Island, etc. 3 1984 $15,000 per B/D? 0.90 3.75_ Ugnu Cretaceous Heavy Oil 10 1987 $50,000 per B/D> 0.00 5.00 1. Oil and Gas Journal, July 12, 1982. 2. Adjusted to 1982 dollars. 3. Arthur D. Little, Inc. estimate. LI-V TABLE A-9 ESTIMATED NEW ALASKAN OILFIELD DEVELOPMENT EXPENDITURES TO 2000 Cumulative Development Peak Oil Production by 2000 Expenditures 1982-2000 "Moderate "Accelerated Cost of Oil "Moderate "Accelerated Growth" Growth" Development Growth" Growth" (MB/D) ($000/Bb1/Day) (Billion 1982 $) Crude Oil by Region North Slope: 45 170 15 $0.68 $2.55 Beaufort Sea 135 480 30 4.05 14.40 Bering Sea 0 100 Fe 0.00 2.50 South Alaska, Onshore 10 45 5 0.05 0.23 Cook Inlet/Gulf of Alaska _10 _95 12 0.12 1.14 Total Crude Oil 200 890 4.67 19,97 Natural Gas by Region (MMCF/D) ($/MMCF/D) Cook Inlet 90 300 2 0.18 0.60 1. Including National Petroleum Reserve-A. Source: Arthur D. Little, Inc. estimates "Accelerated Growth" boasts a greatly expanded level of activity and capital expenditure on oil and gas transportation systems, as well as downstream activities, largely centered on the accelerated commercialization of Prudhoe Bay natural gas, and, to a lesser extent, natural gas from Cook Inlet. Given the temporary shelving of the ANGTS project, and the subsequent emergence of other proposals to market Prudhoe Bay natural gas, substantial uncertainty surrounds the timing and precise nature of Prudhoe Bay gas utilization. Figure A-1 summarizes the key generic alternatives which have been proposed at various times. In addition to these specific projects, various studies have evaluated the relative attractiveness of different systems for commercializing North Slope natural gas in generic terms: for example, the recent study performed by ICF, Inc. for MARAD (United States Maritime Administration) (September 1982, Alaska Natural Gas Development, An Economic Assessment of Marine Systems). This study examined various means for disposing of North Slope gas outside Alaska, including a pipeline to the Lower-48 states, LNG exports to the United States West Coast or Japan, as well as natural gas conversion to methanol and ammonia/urea. The study concluded, in general terms, that LNG exports to Japan were most preferable from an economic standpoint. Other studies currently under way (e.g., the Hickel/Egan proposal) are apparently based on a similar concept of exporting North Slope gas to Japan via the LNG process. As this study has not yet been made available, an economic comparison of the alternatives is not possible at this time. Although economic comparisons appear to favor the Hickel/Egan tidewater pipeline proposal, the ANGTS project cannot be excluded at this time due to the political support it has garnered. Since the ANGTS proposal has been costed in extensive detail, cost estimates for the Alaskan portion of the ANGTS system appear in Table A-1l. Based on public filings and recent press reports, the estimated capital cost for the Prudhoe Bay gas conditioning plant and the Alaskan leg of the ANGTS pipeline amounts to 17 billion 1982 dollars (Table A-10). Initial indications are that the Hickel/Egan proposal for a gas pipeline to tidewater, NGL extraction, and LNG exports would cost an approximately equivalent amount. Estimates for the cost of developing an NGL/petrochemical complex based on Prudhoe Bay natural gas liquids were derived from the Dow-Shell feasibility study presented to the State of Alaska in 1981. This project requires the separation of up to 230 thousand barrels per day of natural gas liquids downstream of the Prudhoe Bay gas conditioning plant, construction of a dedicated NGL pipeline to the southern tidewater (implementation of the Hickel/Egan proposal may eliminate the need for a separate NGL pipeline), and construction of a fractionation plant, gas liquids storage, and export terminal. Estimated costs are: ESTIMATES FOR THE COST OF AN NGL/PETROCHEMICAL COMPLEX (Billion 1982 Dollars) Separation Plant Stel Pipeline to Kenai Peninsula or Valdez 2.6 Fractionation, Storage, and Terminal 0.3) TOTAL 4.0 A-18 61-Vv Tidewater Condition: Plant Condit toning, ANTS Plant Dry NGL Extraction Plant New NGL Pipeline NGL Fraction. _Export LNG Plant NGLs Frac- ? = Elosatiton!) U.S. Project Description ing Hickel or Egan Crude/NGL Separation NCL Methanol Fracttonatior Plants Power Generation Transmission Line Figure A-l: Project Alternatives Lower 48 ames gtuane/Propane or rochemicals Dow/ShelL at ion: a pacific} | Rim 2 Doyon Crude Ot1/ Alaska Methanol interior Mixture Resources Z Based on Prudhoe Bay Gas and NGLs Status Under Review Deferred Shelved Cancelled ~ TABLE A-10 ESTIMATED CAPITAL COSTS OF THE ALASKAN NATURAL GAS TRANSPORTATION SYSTEM (Billion Dollars Including Contingency)! 1980 1982 Dollars Dollars Prudhoe Bay Gas Conditioning Plant $ 3.6 $ 4.3 Alaska Pipeline (Northwest Alaska) 10.8 WAST) Canadian Pipeline eraneit tia) Sots) 6.8 United States East and West Lege” 2.8 303 TOTAL ESTIMATED CAPITAL COSTS $23.0 $27.1 Source: Arthur D. Little, Inc. estimates, based on published data. 1. Excluding inflation and interest during construction. 2. Of which Pre-Build: ($1.7) ($2.0) A-20 The final oil and gas transportation investment required in "Accelerated Growth" is the construction of a crude oil transshipment terminal in the Aleutian Islands to receive Bering Sea crude oil by pipeline or shuttle tanker from such areas as the Navarin basin, the Norton basin, the St. George basin, and the North Aleutian Shelf. This transshipment terminal, on deep water, would receive VLCCs for shipment of crude oil to the Lower-48 states. Based on terminal costs developed by ICF in their re- cent study for MARAD, we have allocated 500 million dollars for this terminal. Oil and Gas-Based Industrial Projects Aside from the local refinery modifications suggested in "Moderate Growth," high levels of industrialization in Alaska, based on domestic oil and gas resources, are unlikely. Even in "Accelerated Growth," expenditures for exploration, development, and transportation of Alaskan oil and gas substantially exceed processing costs. In this scenario, we have assumed that two major processing projects are constructed on the southern tidewater of Alaska prior to the year 2000. These are: A worldscale petrochemical complex, such as that proposed by Dow- Shell, based on ethane extracted from North Slope natural gas liquids, to produce a wide range of chemical products including polyethylene, ethylbenzene, ethylene glycol, ethylene dichloride, alfa-olefins, ammonia, urea, and methanol. The total cost of the primary cracking and fractionation plants to produce olefins and the down- stream derivative plants is estimated at approximately 5 billion 1982 dollars. A 1.3 billion dollar natural gas liquefaction plant and terminal at Nikiski to export up to 400 million cubic feet per day of Upper Cook Inlet gas as LNG to California. This project may be viable if additional gas reserves are discovered in the Upper Cook Inlet, and Lower-48 states natural gas markets become more receptive to incremental sources of natural gas supply. Final approvals for the Point Conception LNG import terminal were recently obtained and no major problems in the construction of this terminal should arise if the Pac-Alaska project is revived. In addition to these processing projects, implementation of the Hickel/ Egan proposal for moving North Slope natural gas to market, via a pipe- line to the southern tidewater and subsequent LNG liquefaction, is a viable alternative to the ANGTS system. We expect that the capital cost expended in Alaska for an equivalent volume would be roughly similar to that for the ANGTS system. These estimates, which are based on ICF's recent report to MARAD, break down as follows: CAPITAL COSTS ASSOCIATED WITH THE HICKEL/EGAN PROPOSAL (Billion 1982 Dollars) Gas Conditioning Plant $ 3.4 Pipeline to Kenai I S7/ LNG Liquefaction Plant 2)5.0) TOTAL $17.1 A-21 Thus, even if the ANGTS proposal is eventually replaced by a project along the lines of the Hickel/Egan proposal, no major change in capital expenditures in Alaska will take place, unless the project is downscaled. Moreover, the distribution of expenditures between transportation and processing facilities does not change significantly. Petroleum Marketing and Distribution Petroleum marketing and distribution in Alaska has evolved to serve consumers under the constraints of population distribution, a harsh, rugged environment, and limited infrastructure capabilities. itis unlikely that any radically different system could serve users in the State as well. Therefore, major future capital expenditures are likely to be directed towards maintaining, upgrading, and expanding the existing marketing and distribution network rather than instituting significantly different mechanisms. Under the "Moderate Growth" scenario, no major expansion of the system is expected to occur. The emphasis in marketing operations is expected to be: e the introduction of electronic, labor-saving equipment at service stations; e maintaining and upgrading service station islands, storage tanks, and buildings; e maintaining the delivery fleet in areas using Arctic distillate for residential/commercial use; and e maintaining and upgrading aviation fuels marketing operations. Further, a small number of new marketing facilities are likely to be built in and around major existing demand centers. Distribution expenditures in this scenario are likely to be directed almost exclusively towards maintaining Alaska's existing capabilities (e.g., tankage, docks, and transport fleet). Total marketing and distribution capital requirements are expected to be no more than 150 million 1982 dollars through the end of the century (Table A-11). Under "Accelerated Growth," the extent of marketing upgrading, conversion, and construction is likely to expand while the pace of maintenance and replacement activities accelerates. Similarly, distribution expenditures are expected to cover a greater number and broader range of maintenance investments. Moreover, this scenario affords the opportunity to undertake minor new product handling and distribution projects. Examples of these include loading/unloading capabilities and small diameter product pipelines. The total marketing and distribution capital cost under this scenario is calculated at 400 million dollars by the year 2000 (Table A-11). A-22 TABLE A-11 PETROLEUM MARKETING AND DISTRIBUTION EXPENDITURES TO 2000 (Billion 1982 Dollars) "Moderate "Accelerated Growth" Growth" Marketing $0.04 $0.11 Distribution 0.11 0.29 TOTAL EXPENDITURES $0.15 $0.40 Source: Arthur D. Little, Inc. estimates. A-23 APPENDIX B COAL INDUSTRY OUTLOOK AND PEAT POTENTIAL COAL INDUSTRY OUTLOOK AND PEAT DEVELOPMENT General Overview The current Alaskan coal industry is primarily located to the southwest of Fairbanks in the Nenana Coal field. There is one active surface mine which supplies the local steam coal market with slightly over 800,000 short tons of annual production. The Alaskan industry represents less than one tenth of one percent of total United States coal output. While the industry is at present relatively small, the potential for future development is quite good: e The reserve base in Alaska is quite large (Table B-1); e The stripping ratio of overburden to seam thickness is low, which suggests favorable mining costs; e Large reserve beds are close to tidewater, suggesting favorable transportation costs for exporting coal by sea routes; e Alaska is closer to the Japanese, Korean, and Taiwanese markets where coal demand is growing, when compared to other competing coal regions such as Western Canada, Western United States, and Australia; and e The reserve base contains much low sulfur coal; it is, however, lower in Btu content per pound (7,500 to 12,000 Btus per pound). The lower heating content offsets some of the attractiveness of the Alaskan coal in the export market. Domestic Market Any development of the coal industry for domestic consumption will be driven by the electricity generating industry. The Usibelli mine near Fairbanks reportedly can expand production without any significant capital investment to over two million tons per year. This expansion would essentially triple the output and provide enough coal for one additional 400 megawatt electric generating station. If the region does not need an additional 400 megawatts of plant capacity, there would seem to be little potential for coal development for domestic consumption. In the Anchorage area, there are three coal fields which could supply the region with coal for steam generation: Beluga, Matanuska, and Kenai fields. Of the three, Beluga has been explored the most and is best understood. Thus, although we restrict ourselves to a discussion of the Beluga field, the general overview applies to all three coal fields and to other coal fields in Alaska (Tables B-2 and B-3). Currently, there are no coal-fired generating plants in the Anchorage area. Any plants built in the area could be located near Anchorage or at a newly constructed mine. The economic trade-off is between the cost of transporting coal to Anchorage or transporting electricity by B-1 e-d Northern Fields Nenana Field Jarvis Creek Field Susitna (Beluga) Field Matanuska Field Bering River Field Herendeen Bay Field Chignik Field TOTAL ALASKA Source: Alaska Mineral TABLE B-1 ALASKAN COAL RESERVES AND RESOURCES FROM MAJOR FIELDS (Millions of Tons) Proven Reserves Indicated Reserves Hypothetical Reserves 235.0 49,000 - 120,000 330,000 861.6 6,000 8,700 0.3 13 - 76 0 275.0 2,700 - 10,200 27,000 6.6 108 - 130 149 0 0 36 - 1,000 0 10 - 100 300 0 100 300 1,370 57,900 366,000 Resources, Department of Natural Resources. ena Field Beluga Kenai! Nenana Nenana Kuparuk NOTE: Source: Production Level (MMT) 5.0 5.0 2.1 ite 5.0 TABLE B-2 PRICE ESTIMATES FOR MINE MOUTH POWER PLANTS (Dollars per Short Ton) FOB Mine Price 17.50 - 26.20 18.50 18.60 - 20.90 30.25 - 32.60 27.00 - 29.80 Arthur D. Little, Inc. estimates. Handling Costs 2.00 2.00 2.00 2.00 2.00 1. Interview with Kenai River Coal Company (11,000 Btus per pound). 2. Requires opening of additional coal fields with substantial capital investment. Thus, 3.00 3.00 3.00 3.00 3.00 The netback from Japan for Alaska coal is approximately $15 to $18 per ton. is based on a market coal of Australian bituminous coal. costs are considered. heat Total Price 19.50 20.50 20.60 32.25 29.00 29.20 21.50 23.90 35.60 32.80 This netback value content and utilization TABLE B-3 PRODUCTION OF COAL NECESSARY TO SUPPORT VARIOUS ELECTRIC PLANT SIZES* Tonnage per Year (Thousands of Short Tons) Plant Size (MW) Beluga Nenana Kuparuk 150 655 614 409 200 873 818 546 300 1,310 1,849 819 400 1,750 1,641 1,094 600 2,620 2,456 1,638 *Based on capacity factors of 65 percent and heat rate of 11,500 Btus per kilowatt-hour. Source: Arthur D, Little, Inc., estimates, B-4 electric transmission power lines. The Beluga field is some 70 miles from the city. Generally, transmission cost favors locating the plant near the mine. Based on the Beluga coal's average heating value of 7,500 Btus per pound, a utilization factor for the plant of 65 percent, and a heat rate of 11,500 Btus per kilowatt-hour, the following table shows the coal production needed to support various plant sizes. (Most mining studies show that to achieve favorable costs, a single mine should be designed to produce a minimum of five million short tons per year.) ESTIMATED PRODUCTION OF BELUGA COAL NECESSARY TO SUPPORT VARIOUS ELECTRIC PLANT SIZES Electric Plant Size Yearly Tonnage (MW) (000 Short Tons) 150 655 200 873 300 1,310 400 1,750 600 2,620 1,200 5,240 Depending upon the future demand of electricity, one economically-sized strip mine could adequately support a plant of 1,200 megawatts. Export Market Alaska's greatest potential for developing its coal reserves lies in the export market (Tables B-4 and B-5). As mentioned before, one of the Beluga field's best attributes is that it is located close to tidewater. This means that overland transportation costs will be minimized. In addition, Alaska is relatively close to Pacific Rim markets which again suggests lower costs for transportation relative to other competing coal regions. Over the long term, the Beluga field could support large-scale production. Certainly, there are opportunities for competitive, low- cost production as economies of scale are realized. Even though the Beluga field is very attractive for the export market, the Suneel Shipping Co. is negotiating a 10-year contract with the Usibelli Coal Company for coal from the Nenana Basin for shipment to the Korea Electric Power Company through Seward. The proposed delivery schedule is reported to be: Year Tonnage per Year 1982 200,000 1983 500,000 1984-1991 800,000 B-5 9-4 Source: Field Beluga Nenana Nenana Kuparuk TABLE B-4 ESTIMATES OF EXPORT PRICES (1982 Dollars per Short Ton) Production Cost of Level Mine Mouth Price Transportation (MMT) 5.0 17.50 - 26.20 6.40 - 7.00 Qo 18.60 - 20.90 13.10 - 14.25 4.1 30.25 - 32.60 13.10 - 14.25 5.0 27.00 - 29.80 23.60 - 25.90 Arthur D. Little, Inc. estimates. 23.90 31.70 43.35 50.60 Price FOB Port 33.20 35.15 46.85 55.70 L-a TABLE B-5 PROJECTION FOR COAL PRODUCTION ABOVE THE EXISTING 800,000 TONS "Alaska for the Alaskans" Nenana "Business as Usual" Nenana "Opening the Cache" Nenana Beluga 1983 (Million Tons per Year) 1984 1985 1986 0.8 1987 No Growth No Growth No Growth 1.6 1988 2.4 1989 3.2 1990 4.0 1995 5.0 This contract agreement indicates that foreign buyers have judged inland Alaskan coal to represent a desirable commodity. As experience is gained in exporting Nenana coal, certainly there will be influences on the development of the Beluga, Matanuska, and Kenai fields. Peat Alaska has the greatest percentage of peat reserves in the United States. Alaska's deposits, excluding those in permafrost areas, represent about 51 percent of total United States acreage. On average, the moisture content of peat when utilized is approximately 35 percent, resulting in a heating value of 6,000 Btus per pound. On a dry basis, fuel peats range between 8,300 and 10,5000 Btus per pound. This is a poor fuel when compared to high-quality bituminous coal or petroleum, but its attractiveness lies in its accessibility, with the average depth of United States peat deposits only seven feet. Detailed information on Alaska's peat reserves is scarce, but estimates range from 27 million to 107 million acres. Of the above estimate, 47 million acres are only five feet deep, and 30 million acres of this are believed to be potential fuel. In 1980, a Department of Energy survey investigated the Matanuska-Susitna Valley, Fairbanks, Kenai Peninsula, and Bristol Bay areas of Alaska. The general conclusion was that peat in Alaska had the potential of being a good fuel source, especially for remote communities. The survey, however, did not develop any cost estimates. To establish reliable cost data will require an investigation of developers' plans to extract the peat. B-8 TABLE B-6 ALASKA FUEL PEAT RESOURCES ESTIMATION (Millions of Acres) Permafrost Zone Seasonal Thick Thick Frost Discontinuous Discontinuous Continuous Deep 5) 25 17 1 Shallow 17 6 33 3 Source: "Peat Resource Estimation in Alaska," Northern Technical Services and Ekono, Inc. APPENDIX C ALASKAN NORTH SLOPE CRUDE VALUES ALASKAN NORTH SLOPE CRUDE VALUES A review was made by Arthur D. Little, Inc., of mid-year projections (June 1982) prepared by the Alaska Department of Revenue (DOR) (Table C-1). Several key elements contributed to the DOR projection: o International crude oil price levels; o The marketing pattern of Alaskan North Slope crude (ANS) as it affects the price of ANS crude FOB Valdez; o Pipeline tariffs to Valdez; and o Total production volumes of oil, and possible changes in the quality of oil production as new fields come on stream. This review focuses on the first two of these elements, and accepts the DOR assumptions regarding production and the Trans Alaska Pipeline System (TAPS) tariff. Projected International Crude Oil Price Levels Arthur D, Little's current crude oil price outlook is based on a Delphi Survey conducted in July of 1982. The forecast considers the contract price of Saudi Light crude in real terms through the year 2000. The forecast, summarized in Table C-2, anticipates declining real crude prices through 1985 as OPEC struggles to hold the current marker price of $34 per barrel in the face of continued weak demand for crude oil. After 1985, with stronger economic conditions and some stimulus to oil demand as a consequence of declining real prices, the forecast anticipates that OPEC will once again be able to achieve real price growth, averaging 1.4 percent per year through 2000. It should be noted that the apparent smoothness of the price progression is more a function of the survey averaging process than a genuine reflection of how prices are expected to move. In fact, price increases are expected to result from one or more periodic supply crises occurring after 1985. Similarly, while the forecast represents the best estimate of future prices, there is a high degree of uncertainty associated with it. There is a significant possibility that OPEC will be unable to maintain production discipline, leading to a significant decline in prices in the near and intermediate terms. The DOR crude price forecast is in current dollars, and looks at spot versus contract prices. Moreover, Saudi Medium (30° API) rather than Saudi Light (34° API) is used as the basis for projecting ANS crude. Accordingly, a direct comparison of forecasts is not possible. However, it does appear that in broad outlines the two forecasts are similar: both anticipate no rupture in prices and the resumption of real price growth after 1985 at about 1.5 percent. The DOR does anticipate lower prices through 1985 than the Arthur D. Little Delphi forecast, with the result that the DOR's long-term price progress is lower. This is illustrated in Table C-2. C-1 c-9 ALASKAN DEPARTMENT OF REVENUE PETROLEUM PRODUCTION REVENUE FORECAST, JUNE 1982 Table C-1 (Values in Millions of Dollars) North Slope Cook Inlet STATEWIDE Year OPT GPT O ROY G ROY ocT TOTAL OPT GPT O ROY G ROY ocT TOTAL TOTAL 1982 1,565.20 1.36 1,421.48 2.06 0.63 2,990.72 28.14 7.39 108.22 7.22 0.03 151.00 3,141.72 1983 1,277.46 1.55 1,187.72 2.39 0.61 2,469.73 20.28 7.62 83.47 6.81 0.03 118.21 2,587.95 1984 1,295.61 1.65 1,208.42 2.58 0.64 2,508.89 17.15 8.48 75.77 8.69 0.02 110.12 2,619.01 1985 1,341.16 1.75 1,294.97 2.76 0.66 2,641.29 10.03 9.13 63.47 9.50 0.02 92.16 2,733.45 1986 1,600.36 1.87 1,570.62 2.95 0.70 3,176.49 8.30 9.84 60.44 10.17 0.02 88.76 3,265.25 1987 1,878.35 2.09 1,866.72 3.33 0.70 3,751.18 5.85 18.71 60.46 22.84 0.02 107.87 3,859.05 1988 1,769.90 2.22 2,956.09 3.54 0.70 3,832.44 4.53 20.09 57.64 24.60 0.02 106.87 3,939.31 1989 «1,977.33 2.36 8 2,302.25 3.76 0.70 4,286.41 1.85 21.48 54.89 26.36 0.01 104.59 4,391.00 1990 1,762.07 2.50 2,217.57 3.99 0.57 3,986.70 0.13 22.99 51.85 28.29 0.01 103.26 4,089.95 1991 1,540.00 2.56 1,997.81 4.23 0.44 3,545.03 0.00 24.54 49.35 30.28 0.01 104.18 3,649.21 1992, 1,468.92 2.65 1,936.69 4.48 0.42 3,413.15 0.00 26.21 46.51 32.44 0.01 105.18 3,518.33 1993 1,287.79 2.62 1,835.84 4.75 0.37 3,131.37 0.00 27.97 43.96 34.73 0.01 106.66 3,238.04 1994 1,197.02 2.64 1,775.67 50.03 0.33 2,980.69 0.00 29.80 41.66 37.15 0.01 108.61 3,089.30 1995 1,060.76 2.69 1,598.80 5.34 0.30 2,667.88 0.00 31.78 43.35 39.78 0.01 114.92 2,782.81 1996 944.53 2.50 1,567.92 5.66 0.22 2,520.82 0.00 33.92 45.43 42.65 0.01 122.01 2,642.84 1997 986.57 2.62 1,628.07 6.00 0.21 2,623.47 0.00 36.17 48.00 45.63 0.01 129.81 2,753.28 1998 1,015.48 2.58 1,694.38 6.36 0.21 2,719.01 0.00 36.17 52.38 45.63 0.01 134.19 1,853.20 OPT = Oil Production Taxes O ROY = Oil Royalties OCT = Oil Conservative Taxes GPT = Gas Production Taxes G ROY = Gas Royalties TABLE C-2 COMPARATIVE CRUDE OIL PRICES FORECASTS 1 Arthur D. Little Delphi Alaska DOR Saudi Light Saudi Light Saudi Medium Saudi Medium FOB United States United States United States Ras Tanura Gulf Coast Gulf Coast Gulf Coast ($1982 per Bbl) ($1982 per Bbl) ($ Current?) ($Current) 1985 $30.67 $32.42 $38.70 $ 35.00 1990 34.00 35.82 61.80 52.00 1995 35.67 38.45 95537 85.00 1998 37.64 39.76 122.55 107.00 I. From June 1982 revenue forecast, Figure P.6. Due to Monte Carlo analysis employed by DOR, there is no specific price forecast which can be used for comparative purposes. 2% Based on DOR inflation assumptions and $1.60 quality differential between Saudi Light and Medium. Source: Arthur D,. Little, Inc. estimates; Alaska Department of Revenue. Alaskan North Slope Crude Values Apart from world crude oil price levels, prices for ANS crude will depend on where it is sold and the freight costs to those markets. The DOR methodology assumes that delivered ANS crude competes directly with Saudi Medium in major United States markets (West, Gulf, and East Coasts). For each location, individual netbacks are calculated and weighted by volume percentage. The proportion of ANS crude sold by major market is summarized in Table C-3. In theory, ANS should be valued according to its marginal price-setting market (United States East Coast) with prices netted back to Valdez to determine future FOB prices. Prices in other markets (e.g., West Coast) can be equated to this FOB price plus freight. SOHIO and other producers have, however, been successful in selling crude on a cost-in- freight (CIF) basis, so that prices on the West Coast have not fallen to Gulf Coast (USGC) parity. As shown in Table C-4, contract price differentials have ranged from $0.25 to $1.25 per barrel versus freight differentials of $2.00 to $5.00 per barrel. Nevertheless, it seems that the ANS producers will be unable to maintain a two-tier price structure, particularly in a weak crude oil market. Further, in the interests of conservatism, Gulf Coast parity appears to be an appropriate price for revenue projections, since it results in lower prices and netbacks for volumes sold on the West Coast. Forecast ANS FOB crude prices on the basis of Gulf Coast parity with Saudi Light are shown in Table C-5. This includes an ANS quality premium over Saudi Light in Gulf Coast conversion refineries (as opposed to the quality discount assumed by the DOR on a gravity basis from their assumed benchmark of Saudi Medium). Also shown is the expected delivered price in Los Angeles, which will effect product prices in California and Alaska. These prices are approximately 25 percent higher than those anticipated in the DOR revenue forecast (Table C-6). The potential effect of these price differences on State revenues is considerable. At a combined royalty and production tax rate of 25 percent, State revenues in 1990 would be about $3 billion higher in 1990 at Arthur D. Little's projected prices than the $4.1 billion projected by the DOR. It appears that the DOR September revenue forecast will reflect higher prices than the June report. Sensitivities Two major factors could affect the Alaskan revenue forecast. First is the likelihood that the average quality of Alaskan crude production will decline (particularly after 1990) as new fields come on stream and existing Prudhoe production declines. Arthur D. Little projections of production suggest that this decline might be 3° to 5° API by 2000. At current approximate gravity differentials of $0.25 to $0.30 per °API, average prices could be $1.00 to $1.50 lower (in 1982 dollars). This would tend to lower netback prices for Alaskan crude. TABLE C-3 DESTINATIONS OF SHIPMENTS OF NORTH SLOPE CRUDE FROM VALDEZ (Thousand Barrels per Day) 1979 1980 1981 West Coast 901 795 743 Los Angeles 427 368 355 San Francisco 265 243 180 Puget Sound 209 184 208 Panama Transit” 459 528 759 United States Gulf 324 397 505 East Coast 86 71 134 Puerto Rico 50 43 76 Virgin Islands 14 3 0 Direct Elsewhere 174 194 155 Virgin Islands 106 127 96 Hawaii 44 33 43 United States Gulf Coast 13 13 0 Alaska ll 21 16 TOTAL SHIPMENTS FROM VALDEZ 1,534 1,501 1,657 * Figures in this category do not add since the total is based on date of loading, and sub-total figures are based on date of arrival. C-5 TABLE C-4 ALASKA NORTH SLOPE CRUDE PRICES (Dollars per Barrel) Gulf Coast West West Coast/ Contract Coast Gulf Coast SOHIO Spot SOHIO Contract Contract Spot Differential Contract Differential 1981 February $35.02 $37.00 $ + 1.98 $34.77 $0.25 March 35.02 35.75 * 0,73 34.77 0.25 April 35.02 34.90 - 0.12 34.77 0.25 May 33.02 32.90 - 0.12 32.77 0.25 June 33.02 32.50 - 0.52 32.77 0.25 July 33.02 32.50 - 0.52 32.77 0.25 August 33.02 32.90 - 1.12 32.77 0.25 September 32.02 32.00 - 0.02 30.77 1.25 October 32.02 32.70 + 0.68 30.77 1.25 November 32.02 34.00 + 1.98 30.77 Luteo December 32.02 32.90 + 0.88 30.77 1,25 1982 January 32.02 33.20 + 1.18 30.77 Lied February 29.75 30.70 * 0.95 29.50 0.25 March 27.75 26.70 - 1.05 27.50 0.25 April 27.75 29.20 + 1.45 27.50 Cues May 27.75 33.20 + 5.45 27.50 0.25 June 30.75 33.30 + 2.55 29.50 1.25 July 30.75 32.60 + 1.85 29.50 1.25 August 30.75 31.50 + 0.75 29.50 Lage September 30.75 32.50 + 1.75 29.50 1.25 Source: Platts. TABLE C-5 COST OF ALASKAN NORTH SLOPE CRUDE CIF LOS ANGELES-USGC NETBACK (1982 Dollars per Barrel) 1985 1990 1995 2000 Arabian Light Fos! $30.70 $34.00 $35.70 $37.50 Plus Freight 1.18 To27) Dre lad: ZS) Plus Lightening 0.25 0.25 0525 0525) Plus Insurance and Loss 0.19 0.21 0523) 0.24 Plus Duty 0.10 0.10 0.10 0.10 Arabian Light CIF USGC $32.42 $35.82 $38.45 $40.64 Quality Differential 0.61 Ces OU. 0.62 ANS CIF USGC $33.03 $36.49 $39.02 $41.26 Less Insurance and Loss 0.10 0.11 0.12 0.13 Less Freight from Valdes” 3.85 3.94 3.96 3.99 ANS FOB Valdez $29.08 $32.44 $34.94 $37.14 Plus Freight 1.06 1.10 1.10 1.12 Plus Insurance and Loss 0.09 0.11 0.12 0.13 ANS CIF Los Angeles $30.23 $33.65 $36.16 $38.39 1. Based on July 1982 Delphi, high self raters, 1990 adjusted. 2. Based on fully built up costs of US flag tankers and $1 per barrel Trans-Panama pipeline tariff. Source: Arthur D. Little, Inc. estimates. TABLE C-6 COMPARATIVE ANS CRUDE PRICES (Current Dollars per Barrel) Gulf Coast West Coast ADL DOR ADL DOR 1985 $ 41.48 $ 33.00 $ 37.96 $ 30.00 1990 65.90 47.00 60.78 44.00 1995 100.99 83.00 93.59 80.00 1998 129.63 102.00 120.43 99.00 Source: Arthur D. Little, Inc. estimates; Alaska Department of Revneue. A second major factor is the price-setting basis for ANS crude. Rather than the Gulf Coast parity basis used above, it is possible that exports will be permitted to Japan. This eventuality would raise netback value for ANS crude and produce higher State revenues. APPENDIX D FINANCIAL ASSUMPTIONS FINANCIAL ASSUMPTIONS The economic analysis of energy supply and demand alternatives requires the specification of economic and financial parameters. Table D-1 shows the assumptions made with respect to inflation rates, interest rates, and fixed charge rates. The escalation rates for equipment, labor, and fuel costs are real rates (net of inflation). A nominal rate of inflation can be calculated as the sum of the real rates of escalation and the general rate of inflation. The escalation rates for equipment, labor, and fuel costs incorporate the future market potential of Alaskan resources. The escalation rate for electricity is based on an analysis of utilities in each region. Similarly, the imbedded fixed cost and administration costs of serving gas utility customers are added to the city gate cost of natural gas in determining the escalation rate of natural gas. Table D-1 also lists real interest rates for debt financing and rates for equity financing for industry and for electric utilities. Discount rates, by which the present value of future operating costs may be determined, are presented for private industry and public projects. The discount rate is established for industry on the basis of a 50-50 debt-to-equity ratio. The discount rate for public projects represents the real return investors would anticipate earning in tax-exempt investments for public financing of state-sponsored projects. The fixed-charge rates shown in Table D-1 are used to convert capital costs into annual fixed costs. Fixed costs include depreciation, taxes, insurance, and administrative expenses. Explanation of Assumptions The accuracy and reasonableness of the representative quantities in Table D-1 are best tested by adding back the "inflation premium," i.e., the rate of inflation, to each estimated value in the Table. Thus, one can see that, given a 6-7% inflation environment, one is now dealing with expected nominal private utility returns on equity, after taxes, in the neighborhood of 13%, with the cost of long term taxable bonds at around 11%. The fixed charge rate (FCR) is correspondingly in the neighborhood of 16% per annum. This assumes typical utility plant investment with 30-year life and typical tax deductions. A _ good illustration of the components of the FCR and also the weighted average cost of capital calculations in current usage is presented in the EPRI Technical Assessment Guide (EPRI/PS-1201-SR, July 1979), an excerpt from which is attached for your information. To illustrate public financing, we assumed tax exempt bonds, keyed to rates now prevalent, adjusted for inflation effects. Thus, the assumption of a real cost of about 3% of tax-exempt money, together with the longer book life typical of public works projects, yields a fixed charge rate of about 5% in constant dollar terms as shown in the table. D-1 TABLE D-1 PARAMETERS FOR FINANCIAL ANALYSIS 1982-1985 1985-1990 1990-2000 Inflation Rate 6.5% 7.0% 6.0% GNP Growth Rate (Real)! Lower-48 States 2.3 Fea Ql, Debt Financing (Real) Taxable Industrial, Long-Term 5.0 mal 4.5 Taxable Industrial, Short-Term 5.0 Dyi0) 4.0 Tax-Exempt Public 3.0 S55) aos Equity Financing (Real After-Tax ROE) Private Utilities 6.5 750 6.0 Private Industries 9.0 9.5 8.5 Fixed Charge Rate (Real)? Industry (Utilities) 9.5 10.5 9.0 Public Projects (Tax exempt) 5.0 Sait 4.5 Discount Rate (Real Pre-Tax) Industry (50-50 Debt-to-Equity) LSS, 12.5 10.5 Public Projects (Hypothetical) dS 7.8 6.8 Escalation Rates (Real) Equipment 1.0 1.0 1.0 Labor 0.0 0.0 0.0 Fuel: Oil (#2 and #6) 0,5 Dae, eS) Coal 0.0 0.0 0.0 Natural Gas 1.0 1.0 1.0 Electricity At production cost + embedded fixed cost 1S The economy will be recovering from the recession during the 1982-1985 period and will experience productivity improvement; the economy during the period 1985-1990 will return to normalcy, while the economy during the period 1990-2000 will be a mature one. a The fixed charge rate includes cost of capital plus depreciation, taxes (Federal, State and local), insurance, and administration. 3. The discount rate for private industry is based on the industrial average cost of capital while the discount rate for a hypothetical public project estimated arbitrarily is based on the average of the industrial and tax-exempt rates. 4. Electricity price is forecast in the utility supply models. See Appendix H. D-2 This is compatible with an assumption of sinking fund depreciation spread over a period of about 50 years, and no taxes. When converting to nominal terms, the 11.5% FCR is still a representative number; however, the exact breakdown will depend on the assumptions about depreciation, taxes, etc. A discount rate of 15.7 percent was used in the utility supply model analysis based on an average of the industry and public projects rates weighted equally over the time periods covered. To illustrate: Average discount rate = 3 x (Industry Rate + Public Rate, 1982-85) + 18 2 Years in the period 5 x (Industry Rate + Public Rate, 1985-90) + Total Years 18 2 10 x (Industry Rate + Public Rate, 1990-2000) = 18 2 (.167 * (18 + 13.8)) + (.278 x (19.5 + 14.8)) + (.556 x (17.0 + 12.8))= 2 2 2 2.655 + 4.768 + 8.284 = 15.707 To illustrate how the numbers shown under Discount Rate (real, pre tax) were derived, the 1982-1985 column of figures will be developed. "Industry" = 11.5% = 5 (from taxable industrial long-term debt financing) X 50% debt + 9.0 (from real after-tax cost of equity, private industry) divided by 0.5 effective tax rate X 50% equity financing. = real weighted average cost of capital pre-tax This is not the cost of capital figure used in the utility FCR; the latter should assume effectively about 70% debt, 30% common stock financing since utilities are typically highly leveraged. Moreover, the utility cost of capital is usually computed on a full after tax basis, or else as per the EPRI method embodied in the FCR calculation. Thus, the real after-tax weighted cost of capital for a utility with a 70/30 capital structure would be, using the numbers in Table D-1: (5%) X (.7) X (.5) + (6.5%) (.3) = 3.72 (debt cost) (wt.) (income tax effect) (ROE) (wt.) In current dollar terms with 6.5% inflation, this would equate to cost of capital in the neighborhood of 10% (or, if the tax deductibility of interest is not factored in, a cost of about 12%). D-3 The Public Projects (hypothetical) discount rate (Real, Pre-Tax) was illustrated arbitrarily as mid-way between the private industrial cost of capital (11.5%) illustrated above, and the 3% tax exempt rate: [NOES Ws) 7.3% 2 The rationale was that a public development could utilize both private and tax-exempt financing (e.g., industrial revenue bond and pollution control projects), or that the arrangements legislated/authorized could be approximated to effectively result in this magnitude of cost. Typical values for the components of a levelized fixed charge rate composite are shown below based on a 30-year book life, a 20-year tax life, and using normalized accounting; this accounting method is described under the topic "Tax Preference Allowances:" Components for Levelized Fixed Charge Rates Total return (weighted cost of capital)” 10.00% Depreciation (sinking fund)” 0.61 Allowance for retirement dispersion 0.56 Levelized annual income tax 4.70 Levelized annual accelerated depreciation factor (1.98) Levelized annual investment tax credit at 10% (1.68) Property taxes, insurance, etc. 2.00 With tax preference allowances, total 14.21% Without tax preference allowances, total 17.87% Source: Epri Technical Assessment, Guide EPRI/PS-1201-SR, July '79. * The total return plus sinking fund depreciation equals capital recovery factor for a life of 30 years and 10% interest = 10.61%. D-4 Assumed Values for Weighted Cost of Capital. The following values are assumed for the base parameters used in financial calculations (implying a 6%/year rate of inflation): Assumptions for Weighted Cost of Capital Debt ratio 50% Debt cost 8%/yr Preferred stock ratio 15% Preferred stock cost 8.5%/yr Common stock ratio 35% Common stock cost 13.5%/yr Weighted cost of capital 10%/yr Federal and state income tax rate 50% Property taxes and insurance 2% Investment tax credit” 10% While the cost of capital to a utility may be currently greater than that given, the values in this Guide are considered to represent expected long-term trends. The cost of all forms of capital depends strongly on the rate of inflation expected by investors, and the 10% weighted cost of capital implies an expected inflation rate on the order of 6%. The "discount rate" is equal to the weighted cost of capital. If_a_ study is being performed without inflation for fuel and 08M costs, the cost of capital and other components of the fixed charge rate must also be reduced by the inflation component in order to have all costs on a consistent. Source: Epri Technical Assessment, Guide EPRI/PS-1201-SR, July '79. *although income tax preference allowances (accelerated depreciation and investment tax credit) are included in the current income tax laws, these are often neglected in an analysis of investments to be made very far in the future because of their history of frequent changes. For EPRI purposes, it is recommended that income tax preference allowances be excluded from long-term analyses, but may be appropriately included in near-term studies. This is discussed in more detail later. D-5 APPENDIX E ECONOMIC DEVELOPMENT ALTERNATIVES ECONOMIC DEVELOPMENT SCENARIOS Economic trends in Alaska have an important effect on the demand for energy. For example, population growth, as reflected in households and automobile ownership, creates demand for home heating, lighting, and transportation. Service activities, such as commerce, offices, and government, are usually closely linked to concentrations of population; these also have significant energy demands for heating and lighting. Basic industries, such as petroleum refinery, transportation, fishery, food processing, mining, and pulp and paper mills, all have substantial energy demands generated where the activity is located, which is not necessarily near concentration of population. Several forecasts of economic growth in Alaska have been made during the past six years. These include the "Railbelt Study" by Battelle Pacific Northwest Laboratory ("Alaska Economic Projections for Estimating Requirements for the Railbelt" by Battelle Pacific Northwest Laboratory and Institute for Social and Economic Research, Anchorage), the 1976 Man in the Arctic Forecasts ("MAP"), and those of the United States Office of Business and Economic Research and Bureau of Economic Analysis (BEA). For the year 2000, projections of statewide employment vary widely, from a low of 275,000 for the low-growth scenario in the study by Battelle to a high of 535,000 for the highest-growth scenario in the same study (beginning from a base of about 212,000). The wide range of these forecasts is mainly due to differing assumptions about the rate of development of major projects (e.g, coal and metals mining and oil development and production), as well as the emergence of new industries, such as_ petrochemicals. A second important difference among the forecasts is the inclusion of specific employment sectors. For example, the BEA forecast includes military personnel, agricultural, fisheries, forestry, and some additional rural self-employed workers. On the other hand, the Department of Labor and Division of the Budget's estimates exclude some or all of these workers, causing a substantial difference in the employment base, as much as 47,000 (out of roughly 200,000) in 1978. Methodology The focus of the regional analysis was to develop a range of economic development scenarios that would encompass the likely growth in the State's economy. An exhaustive model of the Alaska economy was not developed; rather, emphasis was placed on determining the implications for energy demand of modelled economic alternative development scenarios. Two critical factors in the scenarios are: first, the employment base (the categories of employment included); and second, the scheduling of new projects development and the expansion of existing projects or particular economic activities. E-1 For the Baseline projection of the Alaskan economy, the BEA regional data were used. There were several reasons: first, the categories of employment are the most comprehensive; second, the series is consistent with projections for the rest of the United States (with which the Alaskan State economy is closely linked); third, data were available in a form which could be aggregated to the 14 energy regions (see Table H-10 in Appendix H); fourth, forecasts are available for population, employment, and personal income, which are important variables used in the energy model; and fifth, the sectors of the model are balanced (the service sector is related in size to the basic sectors). Arthur D. Little obtained the latest available employment, population, and income data from BEA, thus updating the data to 1981. Future projections were adjusted to create a revised Baseline and interpolate it out to the year 2005. BEA projections were revised primarily to include different assumptions of projects that are likely to materialize. Data for the 27 regions used by BEA were aggregated to the 14 regions used in the energy model. In a few instances it was also necessary to interpolate data because of changes in regional definitions. This was accomplished through the use of detailed 1980 United States Census data. Forecasted employment in 2000 under the most likely scenario is 350,324. This is lower than the BEA projection of 374,693 and close to the Battelle study most likely projection of 351,656. Complete employment forecasts under different scenarios are found in Appendix Q. Alternative Economic Development Scenarios The major differences in the growth rates of the Alaskan economy projected by various studies are closely related to the mix and scheduling of large projects. Numerous interviews in Alaska indicated concern that, in light of the current world economic situation, it is unlikely that the moderate (most likely) level of development forecast in the Railbelt/Battelle study will be realized. Therefore, a careful review was made of the 14 large projects considered in the Railbelt/ Battelle study. Each of these was reviewed by Arthur D. Little, Inc., staff and discussed with knowledgeable persons in Alaska. Based on these discussions, the likelihood of a project, its size, start-up, timing, and the employment associated with it were estimated, under likely, low-growth, and high-growth conditions. The results were then incorporated into five alternative scenarios. We have developed three principal economic development scenarios, derived from the addition of specific projects and sectoral growth rates to the BEA-adapted Baseline model of employment, labor, and income by industry sector. In several key sectors (oil and gas extraction, coal extraction, petrochemicals, and electric utilities), the various scenarios imply a varying mix of major industrial projects, which we have made specific because of their significant impact on overall State employment levels. These projects include a tidewater terminal natural gas pipeline or the Alaska Natural Gas Transportation System (ANGTS), Upper Cook Inlet petroleum development, National Petroleum Reserve or National Wildlife Reserve Development, Outer Continental Shelf (OCS) development, a liquefied natural gas (LNG) project, a major petrochemical project, Beluga coal field development, and the Susitna hydroelectric project. Two additional scenarios are added to the basic three by consideration of an electric utility alternative to Susitna, probably fossil-fuel based. Table E-1 indicates which projects are included in the various scenarios, and shows the starting dates for construction, exploration activities, or export growth. ECONOMIC DEVELOPMENT SCENARIOS TABLE E-1 (Year of Initial or Continuing Activity) LOW SCENARIOS “Low Growth" Scenario #1: WITH SUSITNA 1982 Upper Cook Inlet, Low Production 1983 Outer Continental Shelf Development 1983 Susitna Hydroelectric Project 1985 Fisheries Growth Scenario #la: ALL THE ABOVE EXCEPT SUSITNA, and ADDING: 1987 Fossil-Fueled Electric Generation MOST LIKELY "Moderate Growth" Scenario #2 1982 Upper Cook Inlet, Mid-range Production 1990 National Petroleum Reserve or National Wildlife Reserve Exploration 1983 Outer Continental Shelf Development 1990 Tidewater Pipeline or ANGTS 1992 LNG Facility 1983 Susitna Hydroelectric Project HIGH SCENARIOS "Accelerated Growth" Scenario #3: WITH SUSITNA 1982 Upper Cook Inlet, High Production 1987 National Petroleum Reserve or National Wildlife Reserve Exploration 1983 Outer Continental Shelf Development 1987 Tidewater Pipeline or ANGTS 1988 LNG Facility 1988 Petrochemicals 1990 Beluga Coal 1983 Susitna Hydroelectric Project 1985 Fisheries Growth 1985 Lumber and Pulp Growth Scenario #3a: ALL THE ABOVE EXCEPT SUSITNA, and ADDING: 1987 Fossil-Fueled Electric Generation The following descriptions provide details about the projects and the projected levels of employment associated with them. Their status and scheduling is also included. oO Tidewater Natural Gas Pipeline or Alaska Natural Gas Transportation System This project involves either the development by the Northwest Alaskan Pipeline Company of a 4,800-mile pipeline to transport natural gas from Prudhoe Bay to the United States West Coast, or a tidewater natural gas pipeline to the Southcentral area of Alaska at Nikiski in the Kenai Peninsula region. The Alaskan portion of the construction in either case would be about 750 to 800 miles long and would include a gas conditioning plant on the North Slope. The Alaska Natural Gas Transportation Sytems (ANGTS) was originally scheduled for construction beginning in 1981; however, the project was indefinitely postponed due to insufficient private financing. For the purpose of our analysis, we have assumed that the Tidewater pipeline project will be chosen. The likely estimate for construction of a pipeline to get under way is 1990, in response to renewed upward pressure on world oil prices during the latter part of the decade. Construction of the pipeline would require approximately eight years, with the pipeline starting operations five years after construction begins. Under the "Moderate Growth" scenario (Table E-2), construction employment begins in 1990 and occurs in the North Slope, Bush (Yukon-Koyukuk), and Railbelt (Fairbanks, Matanuska-Susitna, Kenai Peninsula, and Anchorage) regions. Construction employment starts at 217, peaks in 1995 at 10,749 employees, and ends in 1997 at 312 employees. Oil and gas extraction employment starts in 1993 in the North Slope region at 160 and rises to 200 the following year where it remains constant for the life of the project. Pipeline transportation employment commences in 1994 at 137 and occurs in all regions. This employment drops to 101 in 1996 and remains constant to the year 2005. Under the "Accelated Growth" scenario, construction on a pipeline system will begin in 1987 and the system would be in operation by 1993. Under the conservative estimate, construction of a pipeline is postponed beyond 2005. 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 TABLE E-2 EMPLOYMENT IMPACTS Tidewater Natural Gas Pipeline "Moderate Growth" Construction 217 217 546 1,923 5,094 10,749 4,055 32 0 oo ooooeo Oil & Gas Extraction 160 200 200 200 200 200 200 200 200 200 200 200 200 Pipeline Transportation ooo oo 137 137 101 101 101 101 101 101 101 101 101 101 ° ° Upper Cook Inlet This project involves continued oil and natural gas exploration and production activities in the Kenai-Cook Inlet area. Currently, the Upper Cook Inlet region is producing oil at the rate of 120 thousand barrels per day. While there has been concern that production might decline dramatically over the next 18 years, we expect that the current production level may decline by only about 25 percent through the year 2000, with the application of enhanced recovery techniques and _ further exploration activity. Employment under the "Moderate Growth" scenario will remain level at 778 employees through the year 2000, in spite of production declines. Under the "Low Growth" scenario, steeper production declines reduce employment from 778 to 389 by the year 2000. The "High Growth" scenario shows expanded activity in the Upper Cook Inlet, leading to an additional 484 oil and gas extraction employees by the year 2005. National Petroleum Reserve or National Wildlife Reserve Development This project involves oil and natural gas exploration and production activities on Federal lands in the North Slope region, to commence in the late 1980s or early 1990s. Under the "Moderate Growth" scenario (Table E-3), construction activity in the North Slope region gets under way in 1990 with 38 employees. The level of construction employment peaks twice, in 1994 at 550, and in 2000 at 294. Oil and gas extraction employment starts two years after construction commences in 1992, The level of employment grows from 44 in 1992 to 267 in 2000 and declines to 222 in 2001. Employment remains at this level through 2005. Under the "Accelerated Growth" scenario, construction activity begins in 1987 with operating employment starting in 1989. Under the "Low Growth" scenario, activity associated with this project is postponed beyond the year 2005. Outer Continental Shelf Development Oil and natural gas exploration and production activities on offshore lands will continue to _ grow. The United States Geological Survey has estimated that there are between 7 billion and 32 billion barrels of recoverable oil and between 30 trillion and 97 trillion cubic feet of recoverable natural gas waiting to be discovered in the Outer Continental Shelf. Construction activity associated with Outer Continental Shelf development will get under way in 1983 under all scenarios (Table E-4). Construction employment begins at in the Railbelt E-7 TABLE E-3 EMPLOYMENT IMPACTS National Petroleum Reserve or National Wildlife Reserve Development Moderate Growth" Oil & Gas Construction Extraction 1990 38 1991 38 1992 132 44 1993 494 88 1994 550 115 1995 383 222 1996 132 117 [997 206 187 1998 195 177 i999 224 204 2000 294 267 2001 244 222 2002 122 222 2003 122 222 2004 122 222 2005 122 222 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 TABLE E-4 EMPLOYMENT IMPACTS Outer Continental Shelf Development Construction 30 51 30 143 302 823 1,333 1,963 1,933 1,729 1,729 1,729 1,729 720 100 100 100 100 50 50 50 50 50 All Scenarios Oil & Gas Extraction 309 458 596 675 736 700 699 830 1,486 1,486 1,486 1,486 1,486 3,630 3,630 3,630 3,630 3,630 4,621 4,621 4,621 4,621 4,621 Other Operations 100 142 207 448 394 386 316 554 879 1,035 1,020 1,020 1,020 955 955 955 955 955 994 994 994 994 994 ° (Anchorage), North Slope, and Southeast regions in 1983, with added activity in the Bush (Aleutian Islands, Kobuk-Nome, Dillingham, and Wade-Hampton) region in 1984 and 1986. Construction employment, the majority of which occurs in the North Slope region, peaks in 1990 with 1,963 employees. Starting in 1997, construction activity occurs only in the Bush (Wade-Hampton) region. Oil and gas extraction employment starts in 1983 with 309 employees in the Railbelt (Anchorage and Kenai) Southeast, and North Slope regions. Additional mining activity in the Bush (Kobuk-Nome, Wade-Hampton, Dillingham, and Aleutian Islands) starts in 1984 and 1986. The level of employment increases steadily, at 1,486, 3,630, and 4,621 in 1991, 1996, and 2001, respectively. Other operations employment starts in 1983 in the Railbelt (Anchorage and Kenai), Southeast, and the North Slope regions with 100 employees. Bush (Aleutian Islands, Kobuk-Nome, Wade-Hampton, and Dillingham) areas are added in 1984, 1985, and 1986. The level of employment peaks in 1992 at 1,035, declines to 1,020 in 1993, and then flattens out at 955 to the year 2000. Employment rises in 2001 to 994 where it remains through 2005. Liquefied Natural Gas Facility This project involves construction of a liquefied natural gas (LNG) facility on the Kenai Peninsula at Nikiski. The project will include a pipeline gathering system, a liquification plant, and a loading dock. Under the "Moderate Growth" scenario (Table E-5), construction of a LNG project will begin in 1992 with 146 construction employees in the Railbelt (Kenai Peninsula) region, peaking in 1993 with 1,323 employees, and dropping to 420 in 1994, the last year of the project. The plant would begin operation in 1994, with total operating employment of 100. Under the "Accelerated Growth" scenario, construction activity on the LNG project would get under way in 1988, and the plant would be operational in 1990. Under the "Low Growth" scenario, the development of the project is postponed until after the year 2005. Petrochemicals Several companies have considered establishing a petrochemical plant in Alaska. One group, headed by Dow Chemical Company and Shell Chemical Company, would build a facility to produce polyethylene, ethylene glycol, styrene, propylene, and other products from the 230,000-barrel per day of natural gas liquids (NGL) flowing from a natural gas pipeline. The proposed Dow-Shell facility would be located at a tidewater site in Southeast Alaska, and would require a liquids pipeline to run in tandem with the natural gas pipeline. E-10 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 TABLE E-5 EMPLOYMENT IMPACTS Liquefied Natural Gas Facility "Moderate Growth" 142 1,323 420 ooooococmcmcUucm OCC COCUCOCUCcOCUlUlcSD Construction E-11 Oil & Gas Extraction 40 40 40 40 40 40 40 40 40 40 40 40 Other Operations 60 60 60 60 60 60 60 60 60 60 60 60 fe} Under both the "Moderate" and "Low Growth" scenarios, the development of any petrochemical project is delayed beyond the year 2005, largely because the world market price of oil will not rise to a level which would make such a project feasible. Under the "Accelerated Growth" scenario, real world oil prices escalate to about $40 a barrel, making the project economically feasible by 1987. Construction of a petrochemical plant would begin in 1988 with 409 employees in the Railbelt (Kenai Peninsula) region. Construction employment peaks in 1990 with 5,284 employees, and ends in 1993 with 1,746 employees. Operat- ing employment begins in 1995 with 2,300 and remains constant at that level throughout the life of the project. Beluga Coal This projects involves the development of a large number of beds of subituminous coal on the west side of Cook Inlet. This coal might be exported to Japan or other Pacific Rim locations. Studies are under way to determine the feasibility of using this coal in the production of synthetic fuels. Under the "Moderate Growth" scenario, coal production is limited to the existing Usibelli mine in the Nenana field. Production is expected to increase from an estimated 0.8 million tons in 1982 to 4.8 million tons by 1990, and thereafter remains constant. Employment at the Usibelli mine under this scenario grows from approximately 100 to 160 by 1990 where it levels off through the year 2000. Under the "Accelerated Growth" scenario, an export mine is developed in the Beluga coal field. Construction employment begins in 1990 at 150, peaks in 1992 at 400, and ends in 1994 at 200. Mining operations employment starts in 1995 with 524, then decreases to 519 in 2000, where it remains constant through the year 2005. All activity occurs in the Railbelt (Kenai Peninsula) region. Susitna This project entails the development of a large hydroelectric generating facility at two locations, Watana and Devil's Canyon, and the construction of high voltage transmission lines. Under the "Moderate Growth" scenario (Table E-6), construction of the Susitna hydroelectric plant begins in 1983 in the Railbelt (Matanuska-Susitna) region with 200 employees. Construction employment is in two cycles, peaking at 3,500 in 1990, declining to 300 by 1995, and then rising once again to 1,800 in 1998 and ending at 500 in the year 2000. Operating employment begins in 1995 with 200 employees and remains at this level throughout the life of the project. E-12 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 TABLE E-6 EMPLOYMENT IMPACTS Susitna Hydroelectric Project "Moderate Growth" Construction 200 1,000 1,600 2,300 2,800 3,200 3,400 3,500 3,300 2,700 2,000 900 300 500 1,200 1,800 1,200 500 oooelclcUclcfm E-13 Operating Employment ooooooeoeoeogoo.,e 200 200 200 200 200 200 200 200 200 200 200 oO oO Extra Electric Generator Projects In the variations of the "Low" and "Accelerated Growth" scenarios that assume the Susitna hydroelectric plant is not built, extra generators are constructed in the Railbelt region to meet the growth in demand for electricity. Both scenarios assume a need for extra capacity by the year 1987, which continues to grow through the year 2005. Under the "Low Growth" scenario, construction of the electric generators begins in the Anchorage and Fairbanks regions in 1987 with 55 employees. The level of construction employment remains approximately constant until the year 2000, when employment rises to 625. By 2002 it has dropped to 60 again. The operating employment related to these utilities starts in 1990 at 120, doubles by 1995, increases to 420 in the year 2000, and levels at 500 in the year 2005. Under the "Accelerated Growth" scenario, construction begins in 1987 with 400 construction employees, peaking once in 1988 and again in 1998 with 600 employees. The operating employment starts in 1990 with 120 employees, increasing to 320 by year 2000, and then dropping to 80 by year 2005. Forestry, Logs, and Lumber The forestry, logs, and lumber sector is almost entirely export- based. There are virtually no regional exports of logs and lumber to the Lower-48 states because of the Jones Act, which makes it unprofitable to ship domestically. Over 90 percent of logs and lumber from Alaska are destined for Japan. The industry has suffered from depressed conditions over the past few years, largely due to a slump in Japanese construction activity. Federal laws prevent the foreign export of unprocessed timber from national forest lands, thus much of the timber exported from the Tongass and Chugach forests is rough cut into "squares" before shipment to Japan. The 1981 timber harvest in Alaska totaled 522.5 million board feet, down from 584.7 million board feet in 1980. An estimated 347 million board feet valued at $132 million left the Alaskan region in the form of logs and lumber in 1981. Growth in exports of logs and lumber between 1976 and 1981 averaged 1.9 percent per year. Future growth in regional exports will be a function of at least three factors: first, the Forest Service allowable annual cut; second, the rate of development and harvest determined by the Native Corporations; and third, market conditions in Japan. Under the "Moderate" and "Low Growth" scenarios, regional exports of logs and lumber are expected to grow by an average 2.5 percent over the 1981-2000 period, from 347 million board feet to 554.7 million board feet, valued at 182.8 million 1981 E-14 dollars. This implies an overall timber harvest of about 835 million board feet in the year 2000 (assuming the 1981 ratio of exports to total timber harvest holds). Under these scenarios, we are assuming slow or flat growth in Japanese construction activity, a long-term decline in imports of logs and lumber as a percentage of Japanese consumption, and an increase in Alaska's share of Japanese imports. Growth in Alaska's timber capacity has been estimated based on current national forest contracts plus estimated potential output from Native lands at sustainable yield levels. Under the "Accelerated Growth" scenario, an increase in demand for logs and lumber is projected, resulting in an additional 75 persons employed in 1985, 100 new employees in 1990, and growing by 50 employees every five years thereafter. Pulp In 1981, Alaskan pulp exports totaled an estimated 314,840 short tons, valued at $151.3 million. Between 1976 and 1981, pulp exports increased in volume an average 9.4 percent per year, and grew in value at about 16 percent a year. Alaska's pulp exports are produced at two plants, the Sitka mill of the Alaska Lumber and Pulp Company and the Ketchikan mill of the Ketchikan Pulp Company, Inc. The industry has been producing primarily chemical-grade pulp for shipment to Japan, as well as a small quantity of paper-grade pulp. The bulk of Alaska's pulp production is exported to Japan. While some exports find their way to the People's Republic of China, Canada, India, and the Lower-48 states, Japanese future demand remains the dominant influence on future production increases. Japanese pulp imports are expected to grow at a rate slightly less than one percent per year during the forecast period. Thus, in spite of the fairly rapid increase in Alaska's export volume during the 1976-1981 period, a long-term trend of only one percent per year is forecast. This is slightly higher than the anticipated growth trend in overall Japanese imports. It reflects the likelihood of a marginal increase in Alaska's share of total Japanese pulp imports. The bulk of the growth in Alaska's pulp exports will be in paper grades. Under the "Low" and "Moderate Growth" scenarios, Alaska's pulp exports are expected to increase from an estimated $151.3 million in 1981 to $182.8 million in 2000. Under these scenarios, BEA projected growth of the sector is considered to hold. Under the "Accelerated Growth" scenario, the export growth is expected to be two percent, reflecting slightly faster growth in Japanese demand and a larger share of the Japanese market held by Alaskan exports. Growth in the pulp sector results in an additional 75 persons employed in 1985, 100 new employees in 1990, and increased by 50 every five years thereafter. E-15 o Fish and Shellfish In 1981, the Alaskan fisheries harvest totaled 983.7 million pounds. Production of processed fish and shellfish has grown enormously during the 1976-1981 period, from 253.9 million pounds to 816.1 million pounds. Most of this increase, however, was due to the extension of United States territorial waters to the 200-mile limit. This substantially expanded the catch available to domestic fishermen. Traditionally-popular species of fish (e.g., salmon) and shellfish are currently being harvested at or near maximum sustainable yield levels. Significant future growth in the Alaskan fisheries industry will require development of the bottomfish industry, including such species as pollock. While some industry observers are quite optimistic about this sector, the slow, long-term growth in per-capita consumption of fish and shellfish in both the United States and Japan suggests slow development of the bottomfish industry. Under the "Moderate Growth" scenario, BEA projected growth in this sector is assumed. In the "Low" and "Accelerated Growth" scenarios, a higher growth in the sector is projected, resulting in 275 additional employees in 1985 and subsequently growing by 100 employees every five years to the year 2000. An additional 175 employees are added from 2000 to 2005. Table E-7 summarizes direct employment impacts for the "Moderate Growth" scenario. The complete employment impacts for all regions and industry sectors affected by each project under the various economic development scenarios have been provided to the Division of Energy and Power Development. Readers wishing access to these files should contact the Division. E-16 Lt-a TABLE E-7 EMPLOYMENT IMPACTS FOR ALL PROJECTS "Moderate Growth" Susitma Upper Cook National Outer Hydroelectric Inlet Mid- , Petroleum Continental Tidewater LNG Project Range Production Reserve Shelf Pipeline Facility Total 1983 200 0 439 639 1984 1000 0 651 1651 1985 1600 0 833 2433 1986 2300 0 1266 3566 1987 2800 0 1432 4232 1988 3200 0 1909 5109 1989 3400 0 2348 5748 1990 3500 0 38 3347 217 7102 1991 3300 0 38 4298 217 7853 1992 2700 0 176 4250 546 142 7814 1993 2000 0 582 4235 2083 1323 10,223 1994 900 0 665 4235 5431 520 11,751 1995 500 0 605 4235 11,086 100 16,526 1996 700 0 249 5305 4356 100 10,710 1997 1400 0 393 4685 613 100 7191 1998 2000 0 372 4685 301 100 7458 1999 1400 0 428 4685 301 100 6914 2000 700 0 561 4685 301 100 6347 2001 200 0 466 5665 301 100 6732 2002 200 0 344 5665 301 100 6610 2003 200 0 344 5665 301 100 6610 2004 200 0 344 5665 301 100 6610 2005 200 0 344 5665 301 100 6610 Under the "Moderate Growth" scenario, employment remains constant, therefore there are no impacts in the forecast period. APPENDIX F CONSERVATION ESTIMATING CONSERVATION FOR ALASKA The science of estimating potential conservation that theoretically could be achieved, as well as actual conservation savings likely to be achieved in practice, is a rapidly developing field. A myriad of conservation studies, demonstration programs, measurement attempts, load curtailment programs, and the like have been initiated within the past few years. Based upon the results of such conservation programs, estimation methodologies that predict the success of future efforts are being developed. Utility conservation programs instituted in the early to mid-1970s were established primarily in response to regulatory agency pressures. During the past few years, however, there has been a dramatic change in utility management attitudes toward energy conservation. Many programs have been initiated by utilities themselves, in recognition of the fact that conservation can legitimately be viewed as a supply option. It is primarily in that light, as a supply option, that the amount of conservation that can be achieved concerns energy planners. General Concept of Conservation Energy conservation is a diversely interpreted concept. Consumers, suppliers, and energy planners all mean something slightly different when they say "conservation." Many consumers associate conservation with the short-term curtailment activities associated with the Arab oil embargo in 1973. Energy suppliers, in analyzing the relationships between conservation programs, demand, and energy supply needs, include not only the short-term consumption damping actions that result from public awareness or weatherization programs, for example, but also longer-term conservation effects. Such effects can result from the replacement of older less energy-efficient building stock with newer and more efficient stock, as well as the replacement of energy consuming appliances by more efficient ones. Energy strategists and planners often employ an even broader notion of conservation, equating conservation with "wise use." Three major strategies can be defined with regard to the "wise use" of energy: o Obtaining higher efficiency in energy production and utilization; o Accommodating behavior to maximize personal welfare and response to changing prices of competing goods and services; and o Shifting from scarce to more plentiful energy resources. All three strategies imply technological changes that reduce the energy requirements for a given level of amenity. Thus, conservation can be defined as the sum of all those measures which simultaneously save energy and are economically justifiable. The main principal guiding the determination of a desirable level of energy conservation is therefore the comparison of the real price of energy with that of alternative goods and services. In estimating the amount of conservation that could theoretically be achieved in Alaska and the amount most likely to be achieved in practice, it is important to distinguish between: o A damping in demand for the use of energy that results from regular price increases, and o The type of energy conservation that results from organized efforts or programs for conservation. This distinction is essential to the demand forecasting methodology used by the energy planner. The planner's forecasting models incorporate the demand damping effects that result both from price increases (a curtailment that would take place in the absence of any organized "conservation" effort) and then show the additional reduction in demand or conservation that results from organized conservation efforts. In sections below, we restrict our discussion to the conservation effect of organized conservation programs. Different Types and Sources of Conservation Organized conservation programs are generally designed to attain conservation through some combination of four basic approaches. Elimination of Waste To the energy planner, waste is definitely an economic term. Failure to make changes in consumption that do not affect lifestyles (i.e., the level of amenities derived from energy consuming devices), and which could be achieved with an acceptable rate of return on investment, is a wasteful practice. Conservation programs aimed at eliminating waste of this kind are qualitatively different than those which attempt to change lifestyles. Lifestyle or Behavior Change Programs in this category are those that are designed to achieve conservation by reducing the consumer rate of energy utilization through behavioral changes. Such programs may aim to encourage the lowering of lenergy: The Conservation Revolution, John H. Gibbons and William U. Chandler, Plenum Press, New York, 1981. F-2 thermostats in residential or commercial buildings in the winter and their raising in the summer. Other programs might be those aimed at persuading persons who prefer individual transportation to use public transportation or to carpool. Fuel Switching Programs for conservation in this category include those that are aimed at conserving non-renewable energy resources through the use of alterna- tive renewable energy sources such as biomass, wind, and solar power. In addition, programs designed to switch consumption from less economic to more economic fuel sources can be included in this category, although many are closely linked to the following category. Technology Technological advances can offer a significant potential for energy conservation. Programs in this category include those that are designed to create conservation through the more complete application of existing technology (to improve the thermal integrity of homes and buildings), as well as the development and application of new, more energy-efficient technology. Combined Programs The categories or sources of conservation defined above should not be conceived of as mutually exclusive. Programs aimed at the wise use, and thus conservation, of energy typically include a number of features designed to help raise the public's awareness of all sources of conservation and of the need for practices that truly achieve the wise use of energy. However, for most regions of Alaska, particularly the Bush, conservation programs should be directed: first to the elimination of waste, and second to fuel switching away from petroleum products. The major impacts of conservation programs are formed in improving the efficiency of energy use through the elimination of waste. Estimating and Measuring Conservation Two distinct methods are employed to estimate the effect of conservation programs and actions. These are briefly outlined below, as they apply directly to the development of such estimates for conservation in Alaska. Use of Engineering Estimates The use of engineering estimates to quantify the results of conservation programs is the primary theoretical method of estimating conservation. This is in contrast to direct measurement methods discussed below. Engineering estimates are not strictly theoretical; for example, the estimations of conservation attained from various improvements in technology or weatherization actions are soundly based in the physical sciences and may be the result of extensive testing of appliances or technologies. The use of such estimates for quantifying conservation program results is fairly widespread. Strictly speaking, however, these estimates are based upon the assumption that the customer continues to exhibit or institute behavior appropriate to the particular technology or program design, and that conservation actions are taken in accordance with the engineer's assumptions. It is in this sense that the use of engineering estimates provides a theoretical measure of the amount of conservation that could be achieved. Direct Measurement In addition to the use of engineering estimates, programs are being implemented throughout the nation in an attempt to obtain direct measurement of conservation achieved. The most straightforward approach to direct measurement is a program which, for example, monitors gas or electric consumption at the meter, both before and after the implementation of some conservation action. Naturally, a variety of approaches can be designed for obtaining direct measurement data for various types and groups of consumers and for subsequent analysis of conservation program effectiveness. Programs for Measuring Conservation While there are a great number of conservation programs under way across the country, there is no generally recognized body of information on the results achieved from these programs. Illustrating the extent of such activity, the Electric Power Research Institute (EPRI) published in January 1982 the results of its 1980 survey and evaluation of utility conservation, load management, and solar energy end-use projects. Of the utilities responding to the survey, EPRI reports that 66 are conducting 130 conservation projects, and 119 utilities are actively involved in 283 solar end-use projects. The conservation projects cited included incentive programs, advertising and promotion, evaluation of energy-efficient products and _ systems, development of efficiency standards, public information programs, and heat recovery programs. A further complicating factor for the energy planner and _ the conservation strategist is that data resulting from the evaluation of conservation programs are not readily comparable. Many different methodologies are used for the evaluation and quantification of conservation results, and it is often difficult or impossible to compare the specific provision of conservation programs implemented in different areas or by different utilities or other organizations. The science of estimating the conservation results that can be achieved through different program design features is thus in its infancy, although it is receiving more and more attention. Alaskan Work to Date in Measuring and Estimating Conservation As has been noted elsewhere in this report, some of the characteristics and conditions of Alaskan energy consumption and thus the potential for conservation are atypical with regard to the rest of the country. To improve the confidence that one can place in estimates of past conservation or future conservation to be attained in the State, Alaska-specific data concerning conservation program results must be obtained. Given such information, and a better developed data base on the extent and condition of the residential housing and commercial building stock, and of the appliance stock by type of energy used, a sound basis can be established for estimating the potential in Alaska for cost-effective conservation. There are several efforts, both public and private, under way throughout the State that could contribute data on conservation program results. We briefly review three such programs below. State Residential Energy Conservation Program Two sections within the Division of Energy and Power Development, Department of Commerce and Economic Development, are responsible for implementing the State's residential energy conservation program. The Conservation Section of the Division has primary responsibility for the State's energy conservation programs. It is responsible for administration of the United States Department of Energy's (DOE) low-income weatherization program, carried out on a contractual basis by local and regional municipal or non-profit organizations. In addition, the Section has primary responsibility for administering the State's residential energy conservation program. The Division trains and certifies residential energy auditors across the State to perform home energy audits. The Division also provides financial subsidies to homeowners who have requested an audit. The Division reports that over 35,000 audits have taken place since December 1980. Once an audit has been completed, the Division also administers refunds or grants for energy-saving improvements made as recommended through the energy audit. This refund or grant is for an amount up to $300 for a single family residence, or $200 for each unit within multi-family buildings. The Division reports that it processes an average of 1,000 to 2,000 grant or refund applications per month. Through the energy audit program, a considerable amount of useful information for evaluating attained conservation has been compiled. The Division currently has a contract with a private firm for computeriza- tion of the audit results. Once other factors are known to better characterize the State's housing and commercial building stock, this will allow a better estimation of conservation results achievable within the State. F-5 It is important to note that achieved conservation results will be based upon engineering estimates of attainable conservation calculated from the major energy-saving improvements made as a result of the audit. Municipality of Anchorage Low-Income Weatherization Program The Municipality of Anchorage, under contract to the Division of Energy and Power Development, has evaluated conservation results achieved through its implementation of the Department of Energy's low-income weatherization program. Approximately 1,000 such weatherization efforts had been completed, as of late 1982. The Municipality reports that it has completed approximately 325 such weatherization projects annually since the program's implementation, and expects to complete approximately this number on an annual basis in the near future, assuming continued DOE funding at current levels. In an evaluation analysis reported in November 1981, the Municipality concluded that the program had reduced the thermal energy needed in mobile homes an average of 7.82 percent for those weatherized and had reduced thermal energy consumption in wood-frame homes an average of 16.31 percent. Additional data are available from the Municipality regarding other evaluation results. This program also bases its estimates of program results primarily upon engineering estimates. Rural Alaska Community Action Program (RurAL CAP) RurAL CAP is currently undertaking a direct measure evaluation of weatherization results in Bush communities. According to representatives of the program, at least two case studies are being conducted. Energy consumption in residences was monitored before weatherization and is being monitored for a one-year period following the weatherization actions taken. The evaluators feel that the one-year monitoring period is necessary to provide accurate data on conservation attained over the entire one-year weather cycle in the State at the two locations. This information should provide useful indications of attainable conservation from residential weatherization in such rural locations. Using Conservation Estimates and Measurements in Energy Planning Earlier, the distinction was made between conservation actions taken by the consumer as a result of sensitivity to regular price increases and those that are induced from organized conservation programs. This distinction should be kept in mind when considering the use of data on conservation program results being produced under the three conservation evaluation efforts noted immediately above. Engineering estimates provide an indication of attainable conservation from organized programs; before and after metering projects also require that the evaluator take account of conservation actions that may have been the consumer's response to changes in rates. Effect on Demand Forecasts Data on conservation attainable are generally utilized to revise demand forecasts downward. Typically, a forecast of demand will be prepared using a forecasting methodology that assumes "no conservation" or "business as usual." Remember that "no conservation" here means no conservation attained from organized programs, and does not imply that the forecast excludes a certain measure of conservation induced by energy prices. The first type of '"no-conservation" demand forecast can then be contrasted with a maximum conservation forecast. For policy purposes, the energy planner must be able to forecast alternative levels of energy demand under differing assumptions regarding levels of conservation investment. One approach to estimating conservation potential in a particular service sector is by identifying the technological possibilities for reducing energy consumption. This results in estimates of possible decline in unit energy requirements on an end-use basis over time given the adoption of more efficient technologies. Given these technological assessments, a maximum conservation forecast can be produced incorporating both the replacement of appliances as they physically decay, or the earlier replacement of appliances as new technical options provide lower lifecycle costs to consumers. The total maximum conservation potential for the service sector can then be determined by aggregating results for all end-uses. According to this procedure, then, the "no-conservation" demand forecasts for future years are revised downward by the amount of conservation potentially attainable in each future year as programs are implemented. It should be noted, however, that this maximum conservation forecast is made on the basis of 100 percent consumer acceptance of the conservation programs to be implemented. From the planner's perspective, such a 100 percent acceptance is unrealistic. Therefore, a forecast of conservation "most likely" to be attained can be estimated on the basis of assumptions about the likely extent of consumer acceptance and implementation of conservation programs. Thus, information on conservation program results provides the energy planner with the practical basis for two revisions to the "no-conservation" forecast -- a maximum conservation potential revision of demand and a most likely forecast of demand. Methods of Forecasting Demand The recent history of energy demand models has seen an evolution from aggregate, static, equilibrium specifications to dynamic, multiequation specifications disaggregated by end-use. F-7 The aggregate static models generally relate energy demand to trends in energy prices and changes in the activity of energy-consuming sectors of the economy, such as commercial activity and residential income. Thus, the demand for a fuel in a certain period of time is estimated as a function of the price of that fuel and competing fuels, the income level or production level of the user, weather and climatic conditions, and any other relevant socioeconomic factors considered. While these aggregate static models have proved to be useful tools in recent years for energy demand analysis, their limitations have become more apparent. These aggregate static models ignore’ specific technological characterizations of the fuel-burning capital and appliance stock, and they fail to treat differences between long- and short-run energy demand explicitly. Nor do they capture’ the relationship of energy demand to the demand for the capital and appliance stock required to burn that energy. Furthermore, aggregate static models cannot be used to assess the potential penetration of new energy technologies, consumer responses to mandated conversion and appliance efficiency regulations, changes in patterns of appliance utilization, and/or changes in patterns of appliance and capital stock purchase and _ retirement. These limitations in modeling consumer behavior and the change in appliance and capital stock confound the energy planner's attempts to estimate and plan for conservation effects. To overcome these limitations, multi-equation dynamic end-use models have been developed. These models explicitly recognize the different behavioral characteristics of short- and long-run energy demand, and incorporate, to varying degrees, the technological characteristics of the energy-burning appliance and capital stock. To accomplish this, the models use separate equations for short- and the long-run energy demand. In the short run, the energy-using appliance stock is fixed in size and technological characteristics (efficiency), and equations analyze demand as a function of the utilization of fixed capital/ appliance stock. In the long run, however, the size and technological characteristics of the capital/appliance stock are allowed to change as a result of behavioral decisions and/or mandated appliance standards, and these effects are explicitly incorporated into long-run equations. Conceptually, only practicality and data availability limit the end-uses a forecaster may specify. In the residential sector, end-uses typically include space heating, water heating, air conditioning, clothes drying, cooking, and other uses. In the commercial sector, fewer end-uses are generally specified and total square footage of floor space is the driving variable. Methods of Forecasting Conservation Energy planners are still developing methods for forecasting conservation. In general, neither utilities nor energy planners in regulatory or other governmental agencies yet have either a data base or specific tools to measure the impact of existing and _ planned conservation programs upon load growth or upon the financial position of energy suppliers. Because of the lack of data and tools to measure the impact of conservation programs in general, there is an inordinate amount of uncertainty and, consequently, risk surrounding any potential expansion of conservation programs and the substitution of conserved energy for increased capacity on the supply side. In the forecasting field, improved demand estimating models are beginning to take account of conservation effects that stem from consumer choices concerning appliance utilization, primarily in the residential sector. Some utilities and regulatory agencies are currently incorporating these improved demand models into their forecasting efforts. These models take explicit account of the fact that residential energy use and conservation decisions are the result of choices regarding the use of services provided by various energy using appliances. An individual's demand for energy can thus be viewed as being contingent upon the following three general decisions: o The decision to purchase a specific type of energy using appliance; o Decisions concerning specific characteristics of the appliance that is purchased; and o Utilization decisions regarding the frequency and intensity of its use by the consumer. There is a great deal of effort under way in adapting residential demand models currently used and/or under development as vehicles for estimat- ing the saturation and savings of energy conservation programs. In the absence of a general methodological body of knowledge available for forecasting conservation effects, the energy planner must adopt estimation procedures in the interim. Estimating Conservation Impacts for Alaska The general approach used to estimate conservation impacts obtainable in the future in the State of Alaska is the application of a "conservation factor" to the "no-conservation" demand forecast prepared. As the "no-conservation" demand forecast has been prepared on the basis of several major end-uses in the residential and commercial sectors, (both for metropolitan and other non-metropolitan areas), conservation factors have been estimated for these same end-uses from expert judgment. The demand forecasting models for the residential sector have been based on the specification of three end-uses: space heating, water heating, and all other uses. The methodology for forecasting demand in the commercial sector has been based on two end-use categories, space heating and all other commercial uses. Two sets of conservation factors for these specific end-uses in the residential and commercial sectors have been prepared. The first set of conservation factors was prepared for the maximum conservation potential alternative, and the second set has been prepared for a most likely conservation achieved alternative. The conservation factors should be interpreted as representing the proportion or fraction of energy that would be used under the maximum potential and most likely conservation alternatives, as compared with the "no-conservation" alternative. Residential Conservation Impacts Table F-1 presents the conservation factors for the end-uses in the residential sector for the maximum conservation potential alternative, while Table F-2 presents these factors for the most likely alternative. As can be seen, the conservation factors for the most likely alternatives are considerably less optimistic than conservation that could be achieved given the theoretical technological potential and full consumer acceptance of conservation actions and programs. Commercial Conservation Impacts Table F-3 presents the conservation factors estimated for commercial space heating and all other commercial end-uses under the maximum conservation potential alternative. Table F-4 presents these same factors under the most likely conservation alternative. Discussion of the Conservation Factors We are assuming "business as usual" in the demand for electricity and natural gas. The only impacts that can be assumed to occur within the spirit of conservation will be those associated with higher energy prices and the relevant price elasticities included in the forecasting model. For the maximum conservation case, we assume that all reasonably achievable conservation actions are immediately taken within the residential and commercial sectors, without consideration to the economics or the means by which the actions are financed or instituted. While this case may seem somewhat unrealistic, we believe that it is necessary to describe a "so-called" upper bound on conservation potential. Since it is virtually impossible to determine the existing composition of the residential and commercial sectors, we have assumed for this study that the typical residential structure has R-19 insulation in F-10 Year 1981 1982 1983 1985 1990 1995 2000 2005 TABLE F-1 ALASKA ENERGY PLAN - RESIDENTIAL CONSERVATION IMPACT MAXIMUM POTENTIAL Metropolitan Space Heat 1.00 0.65 0.60 0.50 0.42 0.40 0.40 0.40 Water Heat 1.00 0.75 0.71 0.60 0.48 0.45 0.45 0.45 Space Other Heat 1.00 1.00 0.80 0.60 0.76 0.54 0.70 0.45 0.65 0.40 0.60 0.35 0.60 0.35 0.60 0.35 F-11 Other Areas Water Heat 1.00 0.75 0.71 0.60 0.48 0.45 0.45 0.45 Other 0.75 0.70 0.65 0.60 TABLE F-2 ALASKA ENERGY PLAN - RESIDENTIAL CONSERVATION IMPACT MOST LIKELY Metropolitan Other Areas Space Water Space Water Year Heat Heat Other Heat Heat Other 1981 1.00 1.00 1.00 1.00 1.00 1.00 1982 0.97 0.95 0.99 0.90 0.97 0.99 1983 0.95 0.93 0.97 0.87 0.95 0.97 1985 0.93 0.90 0.95 0.85 0.93 0.95 1990 0.87 0.87 0.93 0.80 0.90 0.93 1995 0.83 0.85 0.91 0.75 0.85 0.91 2000 0.80 0.82 0.89 0.72 0.80 0.89 2005 0.77 0.80 0.87 0.70 0.77 0.87 F-12 TABLE F-3 ALASKA ENERGY PLAN — COMMERCIAL CONSERVATION IMPACT MAXIMUM POTENTIAL Metropolitan Other Areas Space Space Year Heat Other Heat Other 1981 1.00 1.00 1.00 1.00 1982 0.80 0.80 0.70 0.80 1983 0.67 0.76 0.67 0.76 1985 0.65 0.70 0.65 0.70 1990 0.60 0.65 0.60 0.65 1995 0.55 0.60 0.55 0.60 2000 0.55 0.60 0.55 0.60 2005 0.55 0.60 0.55 0.60 F-13 Year 1981 1982 1983 1985 1990 1995 2000 2005 TABLE F-4 ALASKA ENERGY PLAN - COMMERCIAL CONSERVATION IMPACT Metropolitan Space Heat 1.00 0.99 0.95 0.93 0.87 0.83 0.80 0.77 MOST LIKELY Other 1. 0 0. F-14 00 99 97 95 93 91 -89 87 Space Heat 1.00 0.90 0.87 0.85 0.80 0.75 0.72 0.70 Other Areas Other 1.00 0.99 0.97 0.95 0.93 0.91 0.89 0.87 the ceiling and R-11 in the walls with double-paned glass and a minimum amount of weatherstripping or caulking. Furthermore, the water heater does not have a water heater blanket and is gas-fueled with a pilot light; the space heater has a pilot light without any efficiency improvements. For the commercial sector, it is assumed that there is R-19 insulation in the ceilings, and R-ll in the walls, and water heating and space heating equipment do not have any efficiency options attached to them. Using these assumptions about the housing shell and energy-using devices existing in residential and commercial buildings within the State of Alaska, we produced the factors for maximum conservation case (Tables F-1 and F-3). In the first year, there is a substantial drop in the level of projected consumption; in following years, the factor continues to decline until by the year 2005 it reaches approximately 50 percent of the base year value (1981). The factor drops in 1982, to reflect that without economic considerations, many people could pursue various ways to increase the efficiency of their housing shell and energy-utilizing equipment. The factor continues to decline as a greater proportion of existing stock is turned over and replaced with more energy efficient shells, water heating, and space heating equipment. We considered that the devices to be installed would have the following characteristics: increased insulation in the ceilings from R-19 to at least R-38; complete caulking and weatherstripping of all doors and windows; triple-paned glazed windows; storm windows; water heater blankets and hot water pipe wraps; and a more efficient space heating combustion system. Preliminary information suggests that installation of these improved energy conservation efficiency options within existing homes would cost in the neighborhood of $2,500 to $3,000 per household. This estimate will of course change depending on the existing state of the energy-utilizing equipment as well as the accessibility to the various crawl areas necessary for the installation of insulation, etc. Only in the regions of Alaska where heating degree days and energy cost would permit these conservation costs to be recouped in three to four years, would this maximum conservation scenario be appropriate. Regions in which energy budgets meet this criteria are: Bethel, Nome, Yukon, North Slope (ex Barrow and Prudhoe Bay), and Southeast Fairbanks. In the most likely conservation scenario (Tables F-2 and F-4), we considered the economics of installing various conservation devices, given existing prices within Alaskan energy markets. As provided by the financial assumption table in Appendix F, natural gas prices are expected to increase substantially in real terms, due to new supply contracts, while fuel oil and electricity prices will remain nearly flat. Based on these assumptions, we tempered our expectations of the most likely projections. This most likely estimate of conservation does, however, reflect an assumption that the State of Alaska further expands its conservation programs, not only in the form of residential audits and low interest loans and grants, but also in the introduction of grants, loans, and audit programs for the commercial sector. The level of conservation anticipated in the most likely case is predicated on the continuing introduction of conservation programs sponsored by the State of Alaska. To achieve the level of conservation shown in the most F-15 likely case, we expect that the cost of the conservation actions would be approximately $700 to $1,000 per typical household. Conservation devices installed in the most likely case would be storm windows, additional ceiling insulation, and weatherstripping and caulking, water heater blankets, and hot water pipe wraps. We do not anticipate further glazing of windows, extensive insulation, or retrofitting of appliances. The general trend in the most likely forecast is a function of two factors: first, the retrofitting of existing structures over the short-term, and the continual replacement of existing stock with more efficient appliances and structures; and second, the anticipated economic growth in the State of Alaska. Conservation programs which introduce this level of energy saving are applicable in all areas of Alaska, even the central Railbelt. Savings of 10 to 20 percent of the household energy budget by this level of conservation would realize a payback of nearly 1 to 2 years in Bush regions such as the North Slope, Nome, and Bethel and a 4- to 6-year payback in rural areas of the Railbelt and the Southeast. Further Recommendations Previous sections have alluded to the need for the development of Alaska-specific data regarding the residential and commercial building stock, end-use appliance saturations by fuel type, and energy savings from ongoing conservation programs, among other information. Without these types of data, best estimates of the conservation potential can only be prepared on the basis of judgments made by experts with experience in such programs in other locales. It is for this reason that the further development of empirical data to characterize the Alaskan situation is critical to responsible energy planning. F-16 APPENDIX G BIBLIOGRAPHY A CITIZEN'S GUIDE TO THE CONSTITUTION OF THE STATE OF ALASKA, by Gordon S. Harrison, Institute of Social and Economic Research, University of Alaska, ISER Series #55, 1982. A CRITICAL REVIEW OF SINGLE-FUEL AND INTERFUEL SUBSTITUTION RESIDENTIAL ENERGY DEMAND MODELS, by Raymond S. Hartman, MIT Energy Laboratory, August 1979, A DISCUSSION OF CONSIDERATIONS PERTAINING TO RURAL ENERGY POLICY OPTIONS, Alaska Department of Commerce and Economic Development, Division of Energy and Power Development. AGENDA 80s: 1980 PROCEEDINGS, 3lst Alaska Science Conference, American Association for the Advancement of Science, Alaska Division, September 17, 18 and 19, Anchorage, Alaska. ALASKA, A HISTORY OF THE 49TH STATE, by Claus-M. Naske and Herman E. Slotnick, the William B. Eerdmans Publishing Company, Grand Rapids, Michigan, 1979. ALASKA COAL MARKETING CONFERENCE, The Resource Development Council for Alaska, Inc., February 18-19, 1982. ALASKA ELECTRIC POWER STATISTICS 1960-1981, Seventh Edition, United States Department of Energy, Alaska Power Administration, August 1982. ALASKA ENERGY PLANNING STUDIES: SUBSTANTIVE ISSUES AND THE EFFECTS OF RECENT EVENTS, Part I prepared for Division of Policy Development and Planning, Office of the Governor, State of Alaska, by Institute of Social and Economic Research, University of Alaska, August 17, 1982. ALASKA ENERGY PLANNING STUDIES: SUBSTANTIVE ISSUES AND THE EFFECTS OF RECENT EVENTS: A review of four consultant studies submitted to Alaska state agencies in fiscal-year 1982, Part I, for the Division of Policy Development & Planning by Institute of Social and Economic Research, University of Alaska, August 1982. ALASKA FACTS: OIL AND GAS INDUSTRY, Alaskan Oil & Gas Association, Anchorage, Alaska, 1982. ALASKA MINERAL RESOURCES 1981-1982, Division of Geological and Geophysical Surveys, Department of Natural Resources. ALASKA MINERAL TAXATION, Summary Report, Whitney & Whitney, January 1982. ALASKA MINES & GEOLOGY, State of Alaska, Department of Natural Resources, Division of Geological & Geophysical Surveys, April 1982. ALASKA MINES & GEOLOGY, State of Alaska, Department of Natural Resources, Division of Geological & Geophysical Surveys, July 1982. ALASKA NATURAL GAS DEVELOPMENT, An Economic Assessment of Marine Systems, by the United States Department of Transportation Maritime Administration, Final Report September 1982. G-1 ALASKA OCS SOCIOECONOMIC STUDIES PROGRAM: ST. GEORGE BASIN, PETROLEUM TECHNOLOGY ASSESSMENT, FINAL REPORT, prepared for Bureau of Land Management Alaska Outer Continental Shelf Office, by Peter T. Hanley, William W. Wade and Marvin F. Feldman of Dames & Moore, August 1980. Alaska Oil & Gas News, March 1981. Alaska Oil & Gas News, September 1978. ALASKA POPULATION OVERVIEW, 1981, State of Alaska, Department of Labor, 1982. ALASKA SOLAR RADIATION ANALYSIS, by James L. Wise, State Climatologist, February 1979, Arctic Environmental Information and Data Center. ALASKA STATUTES, Title 38, Public Lands, September 1977. ALASKA STATUTES, Title 38 to 44, 1981 Cumulative Supplement, October 1981. AN ALASKA CENSUS OF TRANSPORTATION, by John T. Gray and J. Phillip Rowe, Institute of Social and Economic Research, University of Alaska, ISER Report Series #54, 1982. AN ALASKA CENSUS OF TRANSPORTATION, by John. T. Gray and J. Phillip Rowe, University of Alaska, Institute of Social and Economic Research, March 1982. ANALYZING ECONOMIC IMPACT IN ALASKA, prepared by Scott Goldsmith, Institute of Social and Economic Research, University of Alaska, ISER Report Series #52, 1981. AN ENERGY PROGRAM FOR RURAL ALASKA: THE RURAL ENERGY CRISIS, Ruralcap, 1982. ANNUAL ALASKA PLANNING INFORMATION, State of Alaska Department of Labor, Research and Analysis Section, January 1982. 1979 ANNUAL REPORT TO CONGRESS, Vol. 3, Projections, United States Department of Energy, Energy Information Administration, 1980. ANNUAL REPORT, Ahtna, Inc., 1981 ANNUAL REPORT, Arctic Slope Regional Corporation, 1981 ANNUAL REPORT, Bering Straits Native Corporation, 1980 ANNUAL REPORT, Bristol Bay Native Corporation, 1981 ANNUAL REPORT, Calista Corporation, 1981 ANNUAL REPORT, Chugach Natives, Inc., 1981 ANNUAL REPORT, Cook Inlet Region, Inc., 1981 G-2 ANNUAL REPORT, Doyon, Limited, 1981 ANNUAL REPORT, Koniag, Inc., 1981 ANNUAL REPORT, NANA Regional Corporation, 1981 ANNUAL REPORT, Rural Alaska Community Action Program, 1981 ANNUAL REPORT, Sealaska Corporation, 1981 ANNUAL REPORT, The Aluet Corporation, 1981 Arctic Offshore, June 1980. Arctic Offshore, December 1980. BEAUFORT SEA STATEWIDE AND REGIONAL DEMOGRAPHIC AND ECONOMIC SYSTEMS IMPACTS ANALYSIS, Report No. TR-62, Alaska OCS Socioeconomic Studies Program, United States Department of the Interior, Bureau of Land Management, Alaskan Outer Continental Shelf Office, August 1981. BENZENE, Vol. 3 of 10, report to the State of Alaska, Feasibility of a Petrochemical Industry, by Alaska Interior Resources Company. BILL HISTORY & JOURNAL INDEX, HOUSE OF REPRESENTATIVES, 12th Legislature, prepared by Legislative Affairs Agency, July 1982. BILL HISTORY & JOURNAL INDEX, SENATE, 12th Legislature, prepared by Legislative Affairs Agency, July 1982. CENSUS OF CONSTRUCTION INDUSTRIES, INDUSTRY AND AREA STATISTICS, 1977, United States Bureau of the Census, July 1981. CENSUS OF HOUSING, GENERAL HOUSING CHARACTERISTICS (1980), ALASKA, United States Bureau of the Census, July 1982. CENSUS OF MANUFACTURERS, GEOGRAPHIC AREA SERIES, ALASKA (1977), United States Bureau of the Census, November 1980. CENSUS OF MINERAL INDUSTRIES, SUBJECT INDUSTRY AND AREA STATISTICS (1977), United States Bureau of the Census, Area Statistics Tables, August 1981. CENSUS OF MANUFACTURERS, SUBJECT STATISTICS, VOL. I, FUELS AND ELECTRIC ENERGY CONSUMED (1977), United States Bureau of the Census, States by Industry Group Tables, September 1981. CENSUS OF POPULATION, GENERAL POPULATION CHARACTERISTICS, ALASKA (1980), United States Bureau of the Census, August 1982. CENSUS OF POPULATION, NUMBER OF INHABITANTS, ALASKA (1980), United States Bureau of the Census, July 1982. CHAKACHAMNA HYDROELECTRIC ALTERNATIVE FOR THE RAILBELT REGION OF ALASKA, Comment Draft Working Paper No. 3.7, Ebasco Services, Inc., March 1982, prepared for the Office of the Governor, Division of Policy Development and Planning, by Battelle. COAL-GASIFICATION COMBINED CYCLE POWER PLANT ALTERNATIVE FOR’ THE RAILBELT REGION OF ALASKA, Comment Draft Working Paper No. 3.10, Ebasco Services, Inc., June 1982, prepared for the Division of Policy Development and Planning by Battelle. COMMUNICATION from Battelle Pacific Northwest Laboratories, April 20, 1982. COMMUNICATION, from Cross, Alaska Power Administration, September 8, 1982. COMMUNITY PROFILES, University of Alaska, Arctic Environmental Information and Data Center for the United States Department of the Interior, July 1978. COMPARISON OF SOLAR RADIATION MEASUREMENTS ON A HORIZONTAL, INCLINED, AND VERTICAL SURFACE IN ANCHORAGE, ALASKA, by Richard Becker, Jr., August 1981, Arctic Environmental Information and Data Center. COORDINATION AND ANALYSIS IN THE EXECUTIVE MANAGEMENT SYSTEM, prepared by Jay Moor for the Division of Policy Development and Planning, December 16, 1980. CORDOVA POWER SUPPLY: INTERIM FEASIBILITY ASSESSMENT, Vols. I and II, Stone & Webster, June 1982. COST OF EXPLORATION FOR METALLIC MINERALS IN ALASKA, 1982, Paul A. Metz and Bruce W. Campbell, Mineral Industry Research Laboratory. COUNTY BUSINESS PATTERNS 1980, ALASKA, United States Bureau of the Census, July 1980. DIRECTORY OF RURAL ALASKAN ORGANIZATIONS, 1982, Rural Alaska Community Action Program. DIRECTORY OF STATE OFFICIALS, prepared by Legislative Affairs Agency, August 1982. ECONOMIC ANALYSIS OF CONCURRENT DEVELOPMENT OF OUTER CONTINENTAL SHELF OIL AND GAS LEASES IN THE BERING SEA, Report No. 80, Alaska OCS Socioeconomic Studies Program, United States Department of the Interior, Bureau of Land Management, Alaska Outer Continental Shelf Office, August 1982. ECONOMIC AND DEMOGRAPHIC STRUCTURAL CHANGE IN ALASKA, Report No. TR-73, Alaska OCS Socioeconomic Studies Program, United States Department of the Interior, Bureau of Land Management, Alaska Outer Continental Shelf Office. C-4 ECONOMIC & DEMOGRAPHIC STRUCTURAL CHANGE IN ALASKA, Report No. TR-73, Alaska OCS Socioeconomic Studies Program, United States Department of the Interior, Bureau of Land Management, Alaskan Outer Continental Shelf Office, June 1982. ECONOMIC FEASIBILITY, Report to the State of Alaska, Feasibility of a Petrochemical Industry, by the Dow-Shell Group, Volume 2 of 10, 1981. ECONOMIC IMPACTS OF STATE EXPENDITURES - A _ PRELIMINARY ANALYSIS, prepared by Dona Lehr, ISER for the Division of Policy Development and Planning, April 6, 1982. ECONOMETRIC STUDIES IN ENERGY DEMAND AND SUPPLY, by G. S. Maddala, W. S. Chern and G. S. Gill, Praeger Publishers, New York, 1978. ECONOMETRIC STUDIES OF UNITED STATES ENERGY POLICY, Ed. by Dale W. Jorgenson, North-Holland Publishing Co., Amsterdam, and American Elsevier Publishing Co., New York, 1976. ELECTRIC POWER CONSUMPTION FOR THE RAILBELT: A PROJECTION OF REQUIREMENTS, TECHNICAL APPENDICES, by Scott Goldsmith and Lee Huskey, University of Alaska, Institute of Social and Economic Research, May 23, 1980. ELECTRICITY REQUIREMENTS FOR THE RAILBELT: DETAILED WORK PLAN, S. Goldsmith, November 14, 1979. ENERGY AND TRANSPORTATION, A STAFF REPORT ON THE ALASKA TRANSPORTATION ENERGY CONSERVATION PROGRAM, prepared by the Systems Evaluation Section Southeast Region, Planning & Programming, Alaska Department of Transportation and Public Facilities. ENERGY CONSERVATION OPTIONS FOR ALASKA MOBILE HOMES, Technical Assistance Report, Division of Energy and Power Development 82-087-B14. ENERGY DEMAND AND INTERFUEL SUBSTITUTION IN THE COMBINED RESIDENTIAL AND COMMERCIAL SECTOR, by Wen S. Chern, Oak Ridge National Laboratory, September 1976. ENERGY DEVELOPMENT AND THE NORTH SLOPE INUPIAT: Quantitative Analysis of Social and Economic Change, ISER, Man in the Arctic Program, 1981. ENERGY DEVELOPMENT AND THE NORTH SLOPE INUPIAT: Quantitative Analysis of Social and Economic Change, Man in the Arctic Program, Institute of Social and Economic Research, University of Alaska. ENERGY FOR ALASKANS, A Resource Handbook, State of Alaska, Division of Energy and Power Development, DERP-82-089-B-10, August 1982. ENERGY IN AMERICA: PROGRESS AND POTENTIAL, American Petroleum Institute, 1981, ENERGY USE IN’ FREIGHT TRANSPORTATION, United States Congress, Congressional Budget Office, February 1982. ENERGY USE IN’ FREIGHT TRANSPORTATION, United States Congress, Congressional Budget Office, February 1982. ENGINEERING ECONOMICS FOR UTILITIES, VOL. I. ESTIMATES OF UNDISCOVERED RECOVERABLE RESOURCES OF CONVENTIONALLY PRODUCIBLE OIL AND GAS IN THE UNITED STATES, United States Department of the Interior Geological Survey, Open-File Report 81-192, 1981. ESTIMATES OF UNDISCOVERED RECOVERABLE CONVENTIONAL RESOURCES OF OIL AND GAS IN THE UNITED STATES, Geological Survey Circular 860, 1981. EXECUTIVE SUMMARY; 1982-1986 OVERVIEW AND STRATEGY, EPRI, July 1982. EXPENDITURE LIMITATIONS, prepared by Dona Lehr, ISER, for the Division of Policy Development and Planning, August 1, 1980. FEASIBILITY STUDY FOR KING COVER HYDROELECTRIC PROJECT, Vol. B, Draft Report, Alaska Power Authority, February 1982. FEDERAL REVENUES AND SPENDING IN ALASKA: A FISCAL YEAR 1981 UPDATE, Institute of Social and Economic Research, University of Alaska. FEDERAL REVENUES AND SPENDING IN ALASKA: THE FLOW OF FUNDS BETWEEN ALASKA AND THE FEDERAL GOVERNMENT, Institute of Social and Economic Research, University of Alaska. FERC FORM NO. 1: ANNUAL REPORT OF ELECTRIC UTILITIES, LICENSEES AND OTHER [Class A and Class B], revised December 81. FINAL REPORT - CITY OF SITKA - ALTERNATE ENERGY STUDY, prepared for APA by Ott Water Engineers, Inc., and Black and Veatch Consulting Engineers, February 1982. FINAL REPORT: RECONNAISSANCE STUDY OF ENERGY REQUIREMENTS AND ALTERNATIVES FOR CORDOVA, prepared for the City of Cordova and State of Alaska, Alaska Power Authority by International Engineering Company, Inc., June 1981. FINAL STATUS OF BILLS AND RESOLUTIONS, 12th Legislature, prepared by Legislative Affairs Agency, July 1982. FIVE-YEAR OIL AND GAS LEASING PROGRAM MID-YEAR EDITION, State of Alaska Department of Natural Resources, Division of Minerals and Energy Management, July 1982. FRONTIERS IN ENERGY DEMAND MODELING, by Raymond S. Hartman, Annual Review of Energy, Vol. 4, 1979. GAS FACTS, American Gas Association, 1970-1980. GENERAL OBLIGATION BONDING POLICY AND DEBT DEFEASANCE, prepared by Dona Lehr, ISER, for the Division of Policy Development and Planning, February 23, 1981. G-6 GLOSSARY OF LEGISLATIVE TERMS, prepared by Legislative Information Office, December 1980. HANDBOOK ON ALASKA STATE GOVERNMENT, prepared by Legislative Affairs Agency, January 1981. HISTORIC AND PROJECTED OIL AND GAS CONSUMPTION, State of Alaska Department of Natural Resources, Division of Minerals and Energy Management, January 1982 and January 1980. IMPROVING INTERAGENCY COORDINATION THROUGH A_ RESOURCE PLANNING SUBCABINET, prepared by Sally Rue for the Division of Policy Development and Planning, December 19, 1980. INDUSTRIAL DEMAND FOR ENERGY, prepared for the National Science Foundation by Robert Halvorsen and the National Bureau of Economic Research, Inc., May 1977. INFRASTRUCTURE AND SOCIOECONOMIC IMPACTS, Vol. 7 of 10, report to the State of Alaska, Feasibility of a Petrochemical Industry by Alaska Interior Resources Company. ISSUES IN ALASKA DEVELOPMENT, prepared by David T. Kresge, Thomas A. Morehouse and George W. Rogers. LEGISLATIVE PROCESS IN ALASKA, prepared by Legislative Affairs Agency, December 1980. LIME VILLAGE PROJECT, PHASE II, Equipment Demonstration Plans prepared by Alaska Energy Research Group, February 1982. MANAGEMENT OF ALASKA STATE GOVERNMENT - THE GOVERNOR'S POLICY THEMES, prepared by Jay Moor for the Division of Policy Development and Planning, September 26, 1980. MEMORANDUM, Engineering Issues of the 1980s, Department of Revenue, J. Love, August 24, 1982. MEMORANDUM, G. Matz, Division of Budget and Management, Office of the Governor of Alaska, August 6, 1982. MEMORANDUM, Myers, Environmental Group, September 14, 1982. MEMORANDUM, State of Alaska Legislature Budget and Audit Committee, August 27, 1982. METHANOL, Vol. 4 of 10, report to the State of Alaska, Feasibility of a Petrochemical Industry by Alaska Interior Resources Company, Inc. METHODOLOGY FOR ESTIMATING THE FISCAL IMPACT OF PETROCHEMICAL DEVELOPMENT, prepared by Dona Lehr, ISER, for the Division of Policy Development and Planning, September 9, 1981. MINING SEES STEADY INCREASE, by C. N. Conwell and G. R. Eakins in Alaska Construction & Coil, January 1982. MORE PERFECT UNION, a preliminary report of the Alaska Statehood Commission, January 19, 1982. MOVING NORTH SLOPE NATURAL GAS TO MARKET: A POSITIVE ALTERNATIVE FOR THE NATION, November 1981. NAVARIN BASIN SOCIOCULTURAL SYSTEMS BASELINE ANALYSIS, Report No. TR-70, Alaska OCS Socioeconomic Studies Program, United States Department of the Interior, Bureau of Land Management, Alaskan Outer Continental Shelf Office, January 1982. NAVARIN BASIN SOCIOCULTURAL SYSTEMS BASELINE ANALYSIS, Report No. TR-70, Alaska OCS Socioeconomic Studies Program, United States Department of the Interior, Bureau of Land Management, Alaska Outer Continental Shelf Office. NEWSLETTER, Alaska Federation of Natives, Inc., Vol. I, No. 2, August, September 1982. NEWSLETTER ON THE SUSITNA HYDRO STUDIES, Alaska Power Authority Public Participation Office, January 1982. NEWSLETTER ON THE SUSITNA HYDRO STUDIES, Alaska Power Authority Public Participation Office, April 1982. NEWSLETTER ON THE SUSITNA HYDRO STUDIES, Alaska Power Authority Public Participation Office, June 1982. NORTH SLOPE BOROUGH ENERGY AWARENESS PROGRAM, February 1981. NORTH SLOPE BOROUGH ENERGY AWARENESS PROGRAM, September 1981. NORTH SLOPE BOROUGH ENERGY AWARENESS PROGRAM, February 1982. NORTH SLOPE NATURAL GAS: TRANSPORTATION ALTERNATIVES AND THE PROMISE OF A WORLD-SCALE PETROCHEMICAL INDUSTRY, March 1980. NORTH SLOPES'S KUPARUK FIELD PRODUCING 80,000 BARRELS PER DAY, in Alaska Oil & Gas News, December 1981. OMB CIRCULAR A95 AND ADMINISTRATIVE ORDER 62 - WHAT THEY ARE, HOW THEY WORK, prepared by Mike Whitehead/Dave Haas for the Division of Policy Development and Planning, April 15, 1981. OPTIONS FOR REORGANIZING ALASKA'S ENERGY PLANNING AND DEVELOPMENT PROCESS by Steven Greene. PAD V PETROLEUM SUPPLY/DEMAND FORECAST WITH REFERENCE TO ALASKA NORTH SLOPE CRUDE, Dames & Moore, March 5, 1982. G-8 PEAT RESOURCE ESTIMATION IN ALASKA, Final Report, Vol. I, Northern Technical Services and ECONO, Inc., August 1980. PETROLEUM PRODUCTION REVENUE FORECAST, Quarterly Report, Alaska Department of Revenue Petroleum Revenue Division, June 1982. PETROLEUM REFINING AND CONSUMPTION IN’ ALASKA: IMPLICATIONS FOR MANAGEMENT OF ROYALTY OIL, House Research Agency Report 81-1, Alaska State Legislature, May 1981. POLICY ANALYSIS PAPER NO. 82-10: THE PROBABLE EFFECT OF LOWER STATE REVENUE FORECASTS ON THE PROJECTION OF ELECTRICITY DEMAND IN THE RAILBELT, Office of the Governor, Division of Policy Development and Planning, September 21, 1982. POTENTIAL FOR INDUSTRIAL DEVELOPMENT IN THE RAILBELT REGION OF ALASKA BASED ON THE AVAILABILITY AND COST OF ELECTRIC POWER, prepared by SRI, International, Menlo Park, California, October 1982. POWER PRODUCTION ASSISTANCE PROGRAM, Policy Analysis Paper No. 80-19, State of Alaska, Office of the Governor, Division of Policy Development and Planning, December 11, 1980. PRELIMINARY ASSESSMENT OF COOK INLET TIDAL POWER, PHASE II REPORT, Vol. II Acres American Incorporated, September 1982. PRELIMINARY ALTERNATE ENERGY PROFILES for Grayling, Scammon Bay, Goodnews Bay, and Togiak, November 1980, by Northern Technical Services and Van Golik Associates, Inc. PRELIMINARY FEASIBILITY STUDY, COAL EXPORT PROGRAM, Chuitna River Field, Alaska, Bechtel, April 1980. PRELIMINARY REPORT, FEB. 1980, SHUNGNAK, KIANA AND AMBLER, Reconnaissance Study of Energy Alternatives, Vol. I, Text prepared by Wind Systems PROBLEMS AND POSSIBILITIES FOR SERVICE DELIVERY AND GOVERNMENT IN THE ALASKA UNORGANIZED BOROUGH, Alaska Department of Community and Regional Affairs, Division of Community Planning, Pouch "B", Juneau, Alaska 99811, September 1981. PROCEEDINGS From The Energy Bureau, Inc., Alaskan Mining, September 29 and 30, 1982. PROJECT INDEPENDENCE REPORT: AN APPRAISAL OF UNITED STATES ENERGY NEEDS UP TO 1985, by J. E. Hausman, The Bell Journal of Economics, Vol. 6, No. 2, Autumn 1975. PROJECT LIST, Alaska Power Authority, May 1, 1982. RAILBELT ELECTRIC POWER ALTERNATIVES STUDY: EVALUATION OF RAILBELT ELECTRIC ENERGY PLANS prepared for the Office of the Governor, State of Alaska, Division of Policy Development and Planning and the Governor's Policy Review Committee by Battelle, February 1982. G-9 RECONNAISSANCE ASSESSMENT OF ENERGY ALTERNATIVES - CHILKAT RIVER BASIN REGION, prepared for the State of Alaska APA, by CH2M-Hill, February 1980. RECONNAISSANCE STUDY OF ENERGY REQUIREMENTS AND ALTERNATIVES for Akhiok, King Cove, Larsen Bay, Old Harbor, Ouzinkie, Sand. Point Prepared for APA by CH2M-Hill, June 1981. RAILBELT ELECTRIC POWER ALTERNATIVES STUDY: TECHNOLOGY ASSESSMENT PROFILE REPORT, AN OVERVIEW, prepared by Ebasco Services, Inc., May 1981. RECONNAISSANCE STUDY OF ENERGY REQUIREMENTS AND ALTERNATIVES for Buckland, Chuathbaluk, Crooked Creek, Hughes, Koyukuk, Nikolai, Red Devil, Russian Mission, Sheldon Point, Sleetmute, Stony River, Takotna and Telida prepared for APA by International Engineering Company, Inc., May 1981. RECONNAISSANCE STUDY OF ENERGY REQUIREMENTS AND ALTERNATIVES for Kaltag, Savoonga, White Mountain, Elim by Holden & Associates, June 1981. RECONNAISSANCE STUDY OF ENERGY REQUIREMENTS AND ALTERNATIVES for Tanana Report Summary by Marks Engineering/Brown & Root, Inc., July 1981. RECONNAISSANCE STUDY OF ENERGY REQUIREMENTS AND ALTERNATIVES Main Report, Prepared by Northern Technical Services & Van Gulik & Assoc. RECONNAISSANCE STUDY OF ENERGY REQUIREMENTS AND ALTERNATIVES: MAIN REPORT, May 1982 for APA. RED: The Railbelt Electificity Demand Model Specification Report, Volume VIII, July 1982, prepared for the Division of Policy Development and Planning and the Governor's Policy Review Committee by Battelle, Pacific Northwest Laboratories. REGIONAL ANALYSES OF HIGHWAY ENERGY USE, by G. Kulp, D. L. Greene, G. H. Walton, M. J. Collins, D. B. Shonka and J. L. Blue, Oak Ridge National Laboratory, April 1980. REGIONAL ECONOMETRIC MODEL FOR FORECATING ELECTRICITY DEMAND BY SECTOR AND BY STATE, by W. S. Chern, R. E. Just, B. D. Holcomb, and H. D. Nguyen, Oak Ridge National Laboratory, October 1978. REGIONAL PLANNING COORDINATION, prepared by Sally Rue for the Division of Policy Development and Planning, October 13, 1980. REMARKS, W. J. Hickel, World Arctic Study, George Washington University, September 9, 1982. REPORT TO THE STATE OF ALASKA: FEASIBILITY OF A PETROCHEMICAL INDUSTRY, Vol. I, The Dow-Shell Group, 1981. RESIDENTIAL DEMAND FOR ELECTRICITY AND GAS IN THE SHORT RUN: AN ECONOMETRIC ANALYSIS, by A. Werth, MIT Energy Laboratory, June 1978. G-10 RESOURCE REVENUES AND STATE SPENDING: ALASKA'S GOLDEN OPPORTUNITY, December 1980. REVENUE SOURCES FISCAL YERS 1982-1984, Quarterly Update, Alaska Department of Revenue, June 1982. REVIEW OF ALASKA MINERAL RESOURCES, 1981, Division of Geological and Geophysical Surveys, Department of Natural Resources. REVIEW OF ALASKA ROYALTY OIL POLICY AND FINDINGS FOR PROPOSED DISPOSITION OF ROYALTY OIL, Alaska Department of Natural Resources Pouch "mM", February 26, 1982. REVIEW OF CORDOVA POWER STUDY, Stone & Webster, 1982. REVISED COUNTY AND METROPOLITAN AREA PERSONAL INCOME, SURVEY OF CURRENT BUSINESS, Vol. 62, No. 4, United States Department of Commerce, Bureau of Economic Analysis, Regional Economic Meaurement Division, April 1982. SCE PROJECTIONS OF CONSERVATION GOALS, 1982-1986, Southern California Edison Company, Report before the Public Utilities Commission for the State of California, October 1981. ST. GEORGE BASIN PETROLEUM TECHNOLOGY ASSESSMENT, Technical Report No. 56, Alaska OCS Socioeconomic Studies Program, by P. T. Hanley, W. W. Wade, and M. F. Feldman, August 1980. SELECTED TOPICS ON ASSOCIATION, memoranda prepared for the Alaska Statehood Commission by Richard Haggart, 1981. SHUGNAK, KIANA AND AMBLER, Reconnaissance Study of Energy Alternatives, Vol. I - Text, prepared for the Alaska Power Authority, by Wind Systems Engineering, Inc., February 1982. SHORT-RUN RESIDENTIAL DEMAND FOR FOEUS: A DISAGGREGATED APPROACH, by Raymon D, Hartman and A. Werth, Land Economics, Vol. 57, No. 2, May 1981. SITE SELECTION, DESIGN: ANIAK AND RUBY, for the Division of Energy and Power Development, RURAL WASTE HEAT CAPTURE FOR ALASKAN AGRICULTURE, November 1981. SOCIOECONOMIC IMPACT STUDY OF RESOURCE DEVELOPMENT IN THE TYONEK/BELUGA COAL AREA. STATE ENERGY DATA REPORT, 1960 THROUGH 1980, July 1982. STATE ENERGY ORGANIZATION, prepared by T. Dwight Connor, National Conference of State Legislatures for the House of Representatives, Alaska Legislature, March 20, 1981. STATEWIDE NATURAL RESOURCES PLAN FISCAL YEAR 1981: APPENDIX I, Land and Resource Planning, Division of Research and Development, Alaska Department of Natural Resources. G-1l1 STATE OF ALASKA INTERNAL AUDIT/REVIEW FUNCTION, prepared by Jay Moor for the Division of Policy Development and Planning, March 1, 1980. STATE OF ALASKA LEGISLATION - CSSSSB 684 (Fin) am - HCS CSSB 842 (Fin) am H - FCCSSB 25 - FCCSSB 26 - CCSHB 9 - SB 559 am STATE OF ALASKA LONG-TERM ENERGY PLAN EXECUTIVE SUMMARY, prepared by Applied Economics Associates, Inc., and Energy Analysis & Planning, Inc., Kirk Hall and Associates and Information Services of Alaska for the State of Alaska, Department of Commerce & Economic Development, Division of Energy & Power Development, August 1981. STATE OF ALASKA, LONG-TERM ENERGY PLAN, 1982 Report, Appendix, Department of Commerce & Economic Development, Division of Energy and Power Development. STATE OF ALASKA MEMORANDUM, prepared by Kyle Weaver, Administrator, Energy Education and Outreach Division of Energy and Power Development, for R. C. Howes, Energy Assessment and Planning Division of Energy and Power Development, October 8, 1982. STATE PLANNING AND DPDP, prepared by Jay Moor for the Division of Policy Development and Planning, June 25, 1980. STATUTORY OPTIONS TO IMPROVE THE ENERGY PROGRAM FOR ALASKA, ANALYSIS AND RECOMMENDATION, Policy Analysis Paper No. 81-25, State of Alaska, Office of the Governor, Division of Policy Development and Planning, November 16, 1982. SUBSISTENCE AND THE NORTH SLOPE INUPIAT: The Effects of Energy Development, ISER, Man in the Arctic Program, July 1982. SUMMARY OF ALASKA LEGISLATION, 12th Legislature, Second Session, prepared by Legislative Affairs Agency, July 1982. SUSITNA HYDROELECTRIC PROJECT: SUMMARY REPORT, Alaska Power Authority, March, 1982. THE ALASKA ALMANAC, facts about Alaska, Alaska Northwest Publishing Company, 1982 Edition, 1981. THE ALASKA ECONOMIC INFORMATION AND REPORTING SYSTEM, Quarterly Report, August 1982. THE ALASKA ECONOMETRIC MODEL, POLICY ANALYSIS PAPERS, prepared by the Department of Policy Planning, Dir. Papers #82-1, 81-25, 81-23 I, II, 81-18, 81-9, 81-3, 80,24, 80-19, 80-16, 80-11, 82-4, 81-21, 81-5, 81-10, March 1981. G-12 THE ALASKA OIL & GAS STORY, Alaskan Oil & Gas Association, Anchorage, Alaska, 1981. THE CONSTITUTION OF THE STATE OF ALASKA, February 5, 1956. THE DEMAND FOR ELECTRICITY: A SURVEY, by Lester D. Taylor, The Bell Journal, Vol. 6, No. 1, Spring 1975. THE IMPACT OF RISING ENERGY COSTS IN RURAL ALASKA, Policy Analysis Paper No. 80-24, State of Alaska, Office of the Governor, Division of Policy Development and Planning, November 11, 1980. THE IMPACT OF RISING ENERGY PRICES ON RURAL ALASKA, Research Summary prepared by the Institute of Social and Economic Research, University of Alaska, No. 9, March 1981. THE INTEGRATION MODEL OF THE PROJECT INDEPENDENCE EVALUATION SYSTEM, Vols. I through VI, United States Department of Energy, Energy Information Administration, February 1979. THE JONES ACT AND ITS IMPACT ON THE STATE OF ALASKA, Vol. I: Executive Summary, and Vol. II: Final Report, prepared for the Alaska Statehood Commission, July 1982, by Simat, Helliesen & Eichner, Inc. THE MONTANA RENEWABLE ENERGY HANDBOOK, Montana Department of Natural Resources and Conservation, May 1981. THE OUTLOOK FOR ALASKA NORTH SLOPE CRUDE OIL PRODUCTION: 1981-200, Research Summary prepared by the Institute of Social and Economic Research, University of Alaska, No. 8, January 1981. THE PROMISE AND THE PITFALLS OF ALASKA'S STATE LOAN PROGRAMS, May 1981. THE SEARCH FOR OFFSHORE OIL AND GAS: A NATIONAL IMPERATIVE, American Petroleum Institute, 1981. TOGIAK, GOODNEWS BAY, SCAMMON BAY AND GRAYLING, RECONNAISSANCE STUDY OF ENERGY REQUIREMENTS AND ALTERNATIVES. A report by Northern Technical Services and Van Gulik & Associates, Anchorage, Alaska, February 1981. TRANSPORTATION AND MARKET ANALYSIS OF ALASKA COAL, DOE, November 1980. TRANSPORTATION ENERGY CONSERVATION DATABOOK: EDITION 3, by D. B. Shonka, Oak Ridge National Laboratory, February 1979. UNITED STATES ENERGY OUTLOOK: A DEMAND PERSPECTIVE FOR THE EIGHTIES, United States Congress, Congressional Research Service, US Government Printing Office, July 1981. UNITED STATES RESERVES: OIL FALLS, GAS INCREASES, in Oil & Gas Journal, September 6, 1982. G-13 WESTERN ALASKA LOCAL SOCIOECONOMIC SYSTEMS ANALYSIS, Report No. TR-69, Alaska OCS Socioeconomic Studies Program, United States Department of the Interior, Bureau of Land Management, Alaskan Outer Continental Shelf Office, January 1982. WESTERN ALASKA TRANSPORTATION SYSTEMS ANALYSIS, Report No. TR-66, Alaska OCS Socioeconomic Studies Program, United States Department of the Interior, Bureau of Land Management, Alaskan Outer Continental Shelf Office, February 1982. WIND ENERGY ALTERNATIVE FOR THE RAILBELT REGION OF ALASKA, Comment Draft Working Paper No. 3.9, Ebasco Services, Inc., prepared for the Division of Policy Development and Planning by Battelle, March 1982. STATISTICAL YEAR BOOK, Edison Electric Institute, 1960-1980 (Annuals) POWER PRODUCTION, FUEL CONSUMPTION, AND INSTALLED CAPACITY DATA, United States Department of Energy, 1963-1980 (Annuals) NATURAL GAS ANNUAL, United States Department of Energy, 1960-1980 (Annuals) DELIVERIES OF FUEL OIL AND KEROSENE, United States Department of Energy, 1960-1981 (Annuals) HIGHWAY STATISTICS, Federal Highway Administration, 1959-1981 (Annuals) G-14 APPENDIX H DESCRIPTION OF ALASKA ENERGY FORECAST MODELS DESCRIPTION OF ALASKA ENERGY FORECAST MODELS The 1983 Long Term Energy Plan forecast of future energy demands is based on modelling relationships between the Alaskan economy and energy demands as shown in (Figure H-1). The economic model was used to examine future economic policy and impacts of industry projects or infrastructure development on regions or the State as a whole. The energy models, both demand and supply, provide a consistent, flexible structure which can be used to examine energy demand and supply options in detail, both independently and in combination with the economic model. The energy forecasts show consumer energy demands responding to economic scenarios and to the pricing and supply assumptions inherent in the analysis. This broad range of demand represents several of Alaska's possible energy futures. The economic and energy models are described in this appendix. Detailed output from these models is available from the Division of Energy and Power Development. FIGURE H-1 Economic Database Economic Scenario Specification Population, Development Projects Earnings, Employment Employment Schedule Economic Development Model Projected Economic Activity Population, Households, Earnings, Employment Energy Prices Energy Database by Fuel Type Demand Parameters by Region - Elasticities - Conservation Energy Requirements Demand - Fuel Type - Sector Energy Project Database Capital Operating & Maintenance Discount Rate Project Financial Requirements H-1 DESCRIPTION OF ECONOMIC DEVELOPMENT MODEL The economic development model divides economic activity into two distinct categories: that serving markets outside the State, and that serving internal markets. Sectors serving external markets are driven by two factors: the demand for products in external markets; and the way in which the markets are served. In Alaska, the second factor is governed predominately by large-scale projects oriented toward development of natural resources. These large-scale projects result in stepped rather that smooth growth from year to year. These projects also involve substantial cyclicality in construction employment, which forms another discontinuity in economic growth. Activity in externally oriented (export or base) sectors places requirements for goods and services on the local economy. The goods and services demanded may be either produced locally or imported. Local economic activity satisfying primary demand in turn creates further demand for goods and services. This feedback constitutes the familiar multiplier process, in which an addition of employment in one sector generates even more employment in the total economy. The magnitude of the multiplier between export sector jobs and total jobs is directly related to the proportion of total demand for additional goods and services provided locally rather than through import. The economic model developed for Alaska defines the following sectors as export or "external market-oriented" activities: Oil and Gas Mining Coal Mining Metal Mining Food Processing Lumber Paper Heavy Construction Pipeline Transport oooooo0o0oo0o These sectors are not, unfortunately, exclusively oriented toward external markets. For example, oil and gas are consumed locally, and coal mining is presently oriented to local demand. The major force behind the future growth of these sectors, however, will be the sale of their products in external markets. Other sectors not classified as externally oriented activities also derive a component of their demand from external markets. For example, many service activities are oriented toward tourism. Nevertheless, the future growth of these activities will not be dominated to the same extent by external factors. We should note, as a final caveat, that the classification of export and local activities is a matter of degree, not an absolute distinction. The Economic Development Model Structure The economic model is structured in two parts: a projection of the relationships between the various specific sectors of the economy, and the projection of employment and earnings levels associated with each of the development scenarios. The model is implemented through a series of computer programs which read the economic database and perform a multitude of calculations required to generate projections of employment and earnings. The model is comprised of four blocks: the economic database; a projection of the structure of the Alaskan economy and its sectoral relationships; a projection of various development scenarios based on the specification of identified projects; and generated outputs. The Economic Database An economic database has been developed by the Bureau of Economic Analysis (BEA), United States Department of Commerce. This database provides information on employment and earnings by economic sector for the State of Alaska and for the 29 census subdivisions of the State. The State and substate area economic sectors are defined at different levels of detail. The definition of the State sectors is such that they may be aggregated to the sectors defined for the areas; thus a set of State and area accounts can be defined which are mutually consistent and over which specific accounting identities can be defined, so that projections made for the areas will be consistent with statewide projections. Projections of the Economic Structure The projection of the economic structure identifies and projects the relationship between the State's "export" or base industry sectors and the local/service sectors. It also projects the relationship of economic growth in the substate areas to that of the State. The relationship between export and local/service sectors for the State was projected by the BEA in the mid-1970s as part of a national study of regions and State economic growth. The absolute levels of activity projected by the BEA are, however, based on the very rapid growth experienced in the early and mid-1970s; they do not take into account the relative slowdown in Alaskan economic growth over the last few years. The economic development model does not rely on the absolute levels of economic activity projected by the BEA, but instead uses the projected relationships between the export sectors and local/service sectors. The structure of the substate areas within the total State economy is also developed for both historical and projected periods. This area-to- State relationship is expressed in terms of the rates of area growth relative to the growth in the State for each of the sectors. The historical pattern of relative growth is then projected over the forecast period. The relative growth rates are calculated on the basis of employment. Projections of employment in the areas are linked to the projected growth in the State by the relative growth rates for each area and sector. The earnings for each sector in each area are projected assuming that the earnings per employee for that sector will remain the same over the forecast period. These relationships are all expressed as various ratios and are used to determine a base set of projections for the State and substate areas. The base set of projections is in turn used to develop the projections for each of the specific development scenarios. Economic Projections Linked to the Development Projects The principal function of the economic development model is to estimate the impact of projected economic activity on the total State economy and its component areas. The model requires that specific projects be defined in terms of the areas and economic sectors in which their direct impact will be felt. The projects are described in terms of employment. Employment is specified from the starting year of the project over the life of the project or through the end of the projection horizon of the model. A starting date is also defined for the project. The model assigns the direct economic impact to the appropriate areas and sectors as well as to the State as a whole. The model assigns the employment impact to the appropriate model years based on the starting year of the project and the project's life cycle. The projects are treated as modifications to the base model projections developed above in the projection of the economic structure block. Once the direct impacts of all the projects included in the scenario have been calculated, the model then determines the new level of activity for the export sectors and its impact on the local/service sectors. Export/local service sector calculations are developed for the State. The area employment levels under the scenario are then estimated by assuming the same area distribution of local service activities as was projected for the base economic structure projections. This distri- bution procedure presumes that a project which generates direct employ- ment in any area of the State will generate indirect employment in other areas of the State (particularly in Anchorage where the bulk of service industry employment is located). Having projected employment, the wages and salaries per worker for each sector and for each area are then used to re-estimate the total earnings for each area and for each sector. Three final steps are then taken: first, to multiply the total employment in the State and in each area by the ratio of total employment to population to derive total population; second, to apply the ratio of households to population to the total population to generate projected households; and third, to multiply the ratio of total personal income to total earnings by the total earnings for the State and each area to derive total personal income. These steps complete the calculations required and result in a complete set of accounts for the State and areas for all sectors defined. Economic Development Model Outputs The economic model has two sets of outputs. One set is generated directly by the project scenario model. These are the complete sector accounts for each area. The second set shows the results of the three basic economic development scenarios and their two variations. Although the years to be printed can be specified in the data input for the computer program, model calculations are always based on the complete set of historical and projected years. The projections program also creates disk files of the complete model results to be read by a report-writing program capable of printing specific desired sectors across all areas. H-2 DESCRIPTION OF ENERGY DEMAND FORECASTING MODEL Introduction The Alaska energy demand forecasting model is designed to provide annual forecasts of energy demand in Alaska over the period 1982-2005. The State is defined in terms of fourteen geographic regions (Tabie H-1) and a separate sub-model was built for each region. Within each region, the model typically recognizes four main types of energy from among electricity, distillate fuel oil, natural gas, wood, and coal. Coal is accounted for in the Fairbanks regional model only, since it is not used in significant quantities elsewhere. Energy demand is defined both in terms of retail (e.g., mostly residential) and wholesale (e.g., mostly public and industrial) submarkets, which reflect substantially different prices. In most regions, forecasts focus on future demand for electricity, fuel oil, and natural gas. Although wood and coal demand are not explicitly forecasted in most regional models for the various end-use sectors, their future prices are incorporated into the model, to trace their possible substitition effects on demand for the three main energy types. In the model, each type of energy is defined as a market; each market has various end-use functional categories associated with it which define the demand sectors. The demand sectors in the model for each region cover residential, commercial, public, and industrial consumers and are defined in terms of detailed end-use functional categories (e.g., residential space heating, residential hot water heating, residential lighting and other). The industrial user group, for example, can consist of as many as 11 specific industry categories in any given region. Table H-2 lists the specific residential, commercial, and public end-use categories for the Anchorage region to illustrate how the end-use categories are defined in detail at the regional level. Table H-3 lists the industrial sector definitions used in the model. The model provides forecasts of energy prices and energy demand in response to demographic and economic forecasts submitted as exogenous variables for any forecast year. These exogenous variables, obtained from a separate population and economic forecasting system for Alaska, include number of households, average household income, average number of persons per household, and employment levels in different sectors of the economy. Given these externally-derived population and economic projections, the model then forecasts energy demand levels. TABLE H-1 DEFINITION OF REGIONS Census Region Area Area Description (Census Subareas in Parenthesis) 1 13 Municipality of Anchorage (1362) 2 05 Fairbanks North Star Borough (0544, 0545) 3 16 Valdez-Cordova Census Area (1675, 1676, 1677) 4 19 City and Borough of Juneau (1986) 5 14 Kenai Peninsula Borough (1471, 1472) 6 12 Matanuska-Susitna Borough (1261) 7 06 Southeast Fairbanks Census Area (0646) 8 ol North Slope (0131, 0132) 9 04 Yukon-Koyukuk (0441, 0442, 0443) 10 02,03 Kobuk-Nome (0233, 0334) ll 07,08 Wade-Hampton-Bethel (0751, 0852, 0853) 12 09,10,15 Dillingham, Bristol Bay, Kodiak Island (0954, 1055, 1573, 1574) 13 ll Aleutian Islands (1156) 14 17,18,20, Other Southeast, which consists of: 31,22,23 Skagway-Yakutat~Angoon (17) Haines Borough (18) City and Borough of Sitka (20) Wrangell-Petersburgh (21) Prince of Wales (22) Ketchikan (23) TABLE H-2 ENERGY END-USE CATEGORIES FOR THE ANCHORAGE REGION MODEL Electricity Residential space heating Residential hot water heating Residential lighting and other Commercial space heating Commercial other Public space heating Public other Distillate Fuel Oil Residential space heating and/or hot water heating Commercial/Public space heating and/or hot water heating Natural Gas Residential space heating Residential hot water heating Residential other Commercial/Public space heating Commercial other Propane Residential space heating Residential hot water heating 1. 2s TABLE H-3 DEFINITION OF INDUSTRIAL SECTORS Sector 1 2 Number Description BEA Code SIC’ 1 Agriculture 150(=50,100) 01,02 2 Oil & Gas Extraction 1300 13 3 Minerals Mining 1100(=1000, 1400) 10,14 4 Coal Mining 1200 12 5 Food Processing 2000 20 6 Lumber & Wood Products 2400 24 7 Pulp & Paper 2600 26 8 Petroleum Refining & Chemicals 2800, 2900 28,29 9 Construction 1500,1520,1550 15,16,17 10 Pipeline Transportation 4600 46 ll Other Industries 500(=200,300,400,789) 07,08,22, 1920 | 23,25;27, 30-39 United States Department of Commerce, Bureau of Economic Analysis code designations. Standard Industrial Classification. H-10 In addition to the demand sectors or categories within each regional model, the model also has a transportation component that provides statewide forecasts of demand for the following transportation fuels: Motor Gasoline Highway Marine Diesel Highway Marine Rail Other Aviation Gasoline Jet Fuel Domestic International The model is specifically designed to address the sensitivity of various groups of end-users to changes in energy prices, through the incorporation of own-price demand elasticities. It also deals directly with interfuel substitution, through the use of cross-price elasticities of demand. For example, forecasts thus show the implications of future increases in natural gas prices on demand for fuel oil, electricity, or other types of energy in any specific end-use category. Model Structure For a given region, the model consists of a system of constant elasticity (log-log) demand equations for each energy type for various distinct end-use categories. The model also contains supply equations for each energy type. The presence of the supply functions in the model allows for greater flexibility in forecasting and policy simulation. First, the model can be used to solve for future energy prices endogenously, in which case all energy markets are equilibrated simultaneously in terms of both prices and quantities by taking into account the interdependent supply and demand adjustments affecting the various markets. Given reasonable specifications of long-run supply functions and elasticities, the model can simulate both energy prices and quantities under alternative economic growth scenarios. Second, the model can be used to generate a comprehensive and internally consistent analytical framework for developing conditional demand forecasts for different types of energy, under alternative economic growth scenarios, with energy prices supplied exogenously. The model then quantitatively depicts all market interactions on the demand side, via the own-price and cross-price elasticities of demand. For example, if the price of natural gas increases in the Anchorage region relative H-11 to other types of energy, the model is designed to capture the effects of such a price increase not only in terms of demand for natural gas in all end-use functional categories, but also in terms of demand for all other types of energy. Thus, an increase in natural gas prices has both direct and indirect effects on demand for all other types of energy in all end-use categories captured by the model. The general mathematical functional form of the equations used in the model is: Demand Q,, = Ap, Pip,P2 KIX, 2 x 4mw® ij P, IP, se PL xy 2 oe Xm Supply es Ate ot Q, = Alp "i where Qa. : Quantity of demand in physical units J for energy type i (i = 1,2,...,n) in end-use functional category j (j = 1,2,...,k)3 bysbys.-+sb, : Own-price and cross-price elasticities of demand for energy type i in end-use category j (i.e.,long-run elasticities); Income (activity) elasticities of demand for energy type i in end-use category j (i.e., long-run elasticities); AyprBoeee esa Supply of energy type i in physical units; oO He The price of energy type i; ~ BS The long-run price elasticity of supply for energy type i; < He Py oPo2+eP The prices of various types of energy that LZ n ; Fi may be used in end-use functional category j The exogenous (independent) variables affecting the demand for energy type i in end-use category j (e.g., number of households, average household income, employment in specific economic/industrial sectors) ; Xp oXyoee eX, H-12 W : Energy conservation variable, allowing for the introduction of shifts in energy use due to technological change and in government policies and programs aimed at energy conservation, where the superscript s reflects the rate of change in energy consumption due to technological change and/or policy-induced energy conservation; A,A' : Scalars computed through model calibration for the base year (i.e., 1981). The specific set of energy types, prices, and end-use categories vary across the fourteen regions, depending on the availability and use of different types of energy in each region, at various levels of end-use disaggregation. For all regions, the exogenous (independent) variables used in the residential equations of the model include average number of persons per household (as a proxy for population density per dwelling unit), average number of rooms per household (as a proxy for floor space), average household income (in constant dollars), and total number of households. Since the individual regions reflect a high degree of homogeneity in terms of average annual heating degree days, this variable is not currently used in the model. The model can, however, easily accommodate the introduction of such a variable to simulate the effects of variations in weather conditions on energy consumption patterns. The following selected residential energy demand equations for the Anchorage region are generally illustrative. (The conservation factor and the time subscript are omitted): RESIDENTIAL ELECTRICITY USE FOR SPACE HEATING (Millions of Kilowatt-hours) 6\4| kp Tae, 0.20, 0.20,0.80_0.90,1.00,0.60,,1.00 e 0 g RESIDENTIAL DISTILLATE FUEL OIL USE FOR SPACE AND WATER HEATING (Millions of Gallons) Q = Ap 0.20), -0.80 Pee Pogo eae tt eet eae e ° Py H-13 RESIDENTIAL NATURAL GAS USE FOR SPACE HEATING (Millions of Cubic Feet) Ol=Wao e205 O30 Se PO Ot Seat ee e ° g where Q : Quantity of electricity, fuel oil, or natural gas consumed for space heating; ParPorPy : Prices of electricity, fuel oil, and natural gas, respectively, raised to their respective own-price and cross-price elasticities; 8,r,d,y,H : Average number of persons per household, average number of rooms per household, average annual heating degree days, average household income, and total number of households, respectively, each raised to its own elasticity; and A : A scalar computed when the equation is calibrated for 1981 (the base year of the model), which is numerically different in each equation The commercial and public sector equations are similar in form. The commercial (or public) sector electricity demand equation for space heating in the Anchorage region is: -0.80 0.20 0.20,1.00 P P E Oy TApe fs g where E : Total commercial (or public) sector employment. H-14 The industrial sector energy demand equations are also similar in form. The electricity demand equation for the food processing industry is: -0.50 0.06 0.10,1.00 P P E Q = Ap, 5 7 where E : Total commercial (or public) sector employment. The transportation sector equations follow the same functional form. The statewide demand equation for motor gasoline for highway use is: 7 0.30. 0.10 0.60,1.00 Q= Ap Pg P where Q : Total demand for motor gasoline for highway use (in millions of gallons); PrPg : The prices of motor gasoline and diesel, with the exponents representing own-price and cross-price elasticities of demand; y : Per capita income (in real terms in thousands of dollars); and, P : Total population (in thousands of persons). The model forecast results for each region are organized in considerable detail to show the specific energy types, end-use categories, exogenous variables, price and income elasticities used, as well as intermediate computational results. This simplifies the screening and checking of all numerical data inputs and outputs. For more detail, the reader is referred to a listing of the energy demand forecasts for the various regions, presented in Appendix or available from DEPD. Model Solution The model is designed to be solved in two fundamentally different ways: prices are assumed to be endogenous to the model, or prices are assumed to be exogenous to the model. H-15 Exogenous Prices: First, demographic and economic variables, derived exogenously, are inputed; again, these variables act to shift out (or shift in) the various demand functions. Second, the initialized prices are set equal to the exogenously forecasted energy prices. Then, at these prices, all demand equations are evaluated, taking into account the intermarket interactions on the demand side via the own-price and cross-price elasticities. In this way, although supply-side interactions are ignored, demand-side interactions, linking the various markets for various types of energy, are fully reflected. The "exogenous prices" approach allows the model to reflect long-run supply prices based on detailed analyses of capacity expansion, input, and transportation costs, as well as analyses of world crude oil prices and their implications for energy prices in Alaska. These factors could not realistically be addressed by long-run supply functions and hypothesized elasticities within the model. Consequently, the "exogenous prices" approach puts a stop to the simultaneous supply-demand equilibration process that the model performs under the "endogenous prices" approach. The exogenously stipulated prices do still permit the model to trace quantitatively all demand-side interactions in all markets via the presence of own-price and cross-price elasticities. Based on our historical model validation efforts, it is clear that the cross-price elasticities exert a significant influence in the various interlinked energy markets in Alaska. H-16 H-3 DESCRIPTION OF UTILITY SUPPLY MODELS Utility supply models were developed to calculate average electric rates for the Railbelt, Southeast, and Bush regions. In the Railbelt, alternate runs of the models were made incorporating: the Susitna hydroelectric project; an alternate, the Chakachamna hydroelectric project; and two thermal generation alternatives using coal or natural gas. In the Railbelt analysis, the forecast period is extended to 2050 for all alternatives to cover the full life of the hydroelectric projects. This allows meaningful comparison with thermal generation since the hydroelectric projects involve high capital costs, hence high fixed costs, in the early years of their operation, but with relatively low energy costs in later years. In the Southeast, model runs incorporated hydropower and oil-fired generation or, alternatively, hydropower, wind and wood generation with increased conservation. In the Bush, model runs incorporated a continuation of oil-fired generation and the introduction of wood and wind alternatives. Table H-4 lists the alternatives for the utility supply models. Alternative scenarios are evaluated on the basis of the average electric rate for the forecast period. The models forecast electric prices in nominal dollars; the prices are then discounted to 1981 based on opportunity costs for investments, and their average annual prices are compared. The average discounted electricity price is simply an average of the discounted price for each year in the forecast period, applying nominal discount rates for typical utility industry projects. It is the single best measure of comparison among the different scenarios. Because the discount rate is greater than the rate of price escalation, the average discounted price is below today's price. Levelized electricity costs are calculated by dividing through by the capital recovery factor for which economic comparisons over a very long time period equals the discount rate. These are shown in Table IV-11 in Chapter IV of the Plan report. Description of Models The main component of the utility supply models is the production costing module. All existing and planned units in the region, including those operated by military or industrial users, are modeled with respect to their type, size, fuel use, efficiency or heat rate, and operation and maintenance costs (excluding fuel). Where available, this information was taken from the annual reports filed with the Federal Energy Regulatory Commission and the Alaska Public Utilities Commission. Missing data was estimated using typical generation unit parameters. The model simulates electric generation in region by dispatching all units in an efficient manner to meet electricity demand. Price escalators used in determining fuel costs are listed in Appendix E. Operation and maintenance costs are escalated at the labor cost inflation rate. All inflation rates to the year 2050 are the same as for the year 2000. Operation and maintenance expenses such as transmission, distribution, and general expenses are estimated as a function of electricity H-17 TABLE H-4 UTILITY SUPPLY MODELS ALTERNATIVES RAILBELT: o Susitna o Chakachamna o Natural Gas-Fired Generation in Anchorage with Coal-Fired Generation in Fairbanks o Coal-Fired Generation in Anchorage and Fairbanks SOUTHEAST: o Hydropower and Oil-Fired Generation o Hydropower and Oil-Fired Generation with Wood and Wind Alternatives BUSH: o Oil-Fired Generation o Oil-Fired with Wood and Wind Alternatives H-18 generation at a ratio of $8.75 per megawatt-hour in 1981. This ratio is escalated annually by the general inflation rate. In addition to the cost of electric generation, the production costing module estimates the amount of fuel used for electric generation, which becomes a part of the Alaska energy balance. The second component of the utility supply models is the financial module. Fixed costs for utilities (e.g., depreciation, return on equity) are estimated by applying the fixed charge rate as found in Appendix D to the estimated net utility assets, or rate base, for the region. A utility industry fixed charge rate is used for all assets except Susitna and Chakachamna assets where a fixed charge rate for public projects must be used to account for lower fixed costs, e.g., taxes, depreciation, etc. The utility models estimate net assets for each year taking into account depreciation and capital additions for the year. The models depreciate utility assets at the rate of three percent per year, except for Susitna and Chakachamna assets which are depreciated at the rate of two percent per year. Generating plant capacity was added to maintain a 20 percent margin, excluding military and industrial capacity, or in the Susitna and Chakachamna runs, to maintain the minimum spinning reserve margin of the larges unit on the system. Military capacity was allowed to drop to 25 percent of 1981 capacity in the Susitna runs, assuming that the military will buy the lowest cost power and only maintain emergency standby capability. Transmission and distribution plant capacity is added as a function of the change in electricity generation at a ratio of $30 per additional megawatt-hour of generation each year. This ratio is escalated annually by the escalation rate for equipment prices (see Appendix E). In years where there is a decrease in generation, no transmission and distribution capacity is added. Then, the average electric rate is calculated from the total revenue requirements of the utility, industrial, and military generators in the region divided by the amount of electric energy sold. Revenue requirements include operation and maintenance expenses and fixed costs. Operation and maintenance expenses are the costs of generating and delivering electric power to consumers. Fixed costs include depreciation expenses and a reasonable return on investment based on utility fixed charge rates. Alternative supply scenarios are compared. Sample Energy Supply Model Analysis The results from the utility supply model runs for the three subregions of the Railbelt, incorporating the medium ("Moderate Growth") demand growth rates for electricity, both with and without Susitna, are described in this section. H-19 The nominal electric rates for the forecast period and the average discounted values are shown on Table H-5 for the Railbelt. The Railbelt has been divided into three subregions: Anchorage, Kenai Peninsula, and Matanuska-Susitna; Fairbanks and Southeast Fairbanks; and Valdez-Cordova. Two scenarios are presented, with and without Susitna. In all three subregions, the average discounted value with Susitna is lower than that without Susitna. For the Railbelt region as a whole, the Susitna advantage is a lowering of the average discounted value of electric rates by three percent. Table H-6 shows the procedure used to calculate the average discounted values. The nominal and discounted rates for one model run are presented for selected years along with the average discounted rate which incorporates the 70 years (1981-2050) of the model run. Electric generation, load, capacity, and capacity retirements for the Railbelt are shown in Table H-7 for the model run with Susitna. Capacity additions, based on the load forecast and _ retirement assumptions in Table H-7, are shown in Table H-8. In the two scenarios, thermal capacity is fired by natural gas in Anchorage, coal in Fairbanks, and fuel oil in Valdez-Cordova. Tables H-9 and H-10 present the fuel and hydropower mix used to generate power in the Railbelt, both with and without Susitna. These figures make up part of the Alaska energy balance. Additional runs of the utility supply models for the Anchorage, Kenai Peninsula, and Matanuska-Susitna subregion compared the attractiveness of the Susitna project to the Chakachamna project and also with the thermal generation alternatives with gas or coal-fired capacity additions. Sensitivity analyses were performed, varying generation growth rates, fuel price escalators, and the discount rate. The Susitna alternative held its advantage over both Chakachamna and gas or coal-fired generation when generation growth rates were as low as three percent per year. Table H-1l presents the nominal electric rates and average discounted rates for the four alternatives. Chakachamna and gas-fired generation only became marginally more desirable than Susitna when growth rates were dropped to a low of 1.5 percent per year. Variations of the fuel price escalators and of the discount rate did not change the economic order of preference. Coal and natural gas price growth rates were varied by plus or minus one percent and the discounted rate was lowered to 13.5 percent with no loss of the Susitna advantage. H-20 TABLE H-5 ELECTRIC RATES - RAILBELT (¢/KWH) With Susitna! Without Susitna Anchorage Valdez- Anchorage Valdez- Area Fairbanks Cordova Area Fairbanks Cordova 1981 3.92 9.20 20.24 3.92 9.20 20.24 1985 5.18 11.46 25.51 5.24 11.42 25.72 1990 10.56 17.02 29.94 10.94 16.84 30.22 1995 13.49 16.16 26.61 14.29 22.28 34.54 2000 18.46 18.2 34.24 17.05 24.00 45.07 2010 29.06 45.76 51.97 31.39 35.37 81.14 2020 54.24 55.48 85.28 76.80 64.67 168.30 2030 89.40 79.10 198.34 151.53 93.36 329.51 2040 186.00 150.06 373.25 298.56 382.23 623.71 2050 329.73 165.95 815.47 522.88 435.84 1250.59 Average Discounted Value” - 8803 1.4371 3.0181 0.9035 1.4837 3.2814 Levelized Cost of Electricity 9.67 15.79 33.17 9.93 16.31 36.06 Average Weighted Discounted Value for the Railbelt” 1.0400 1.0729 Average Weighted Levelized Cost of Electricity 11.43 11.79 Based on Susitna financed with interest payments starting at one percent real in 1993, going to 2.5 percent real in 2003 when Devil's Canyon comes on line, with principal payments rolled over and refunded for the first ten years. A discount rate of 15.7 percent, based on an average of the industry and public projects discount rates weighted equally and over the time periods covered from Appendix D, was employed to calculate the discounted values of the electric rates. Levelized electricity cost = average discounted value x 70 = capital recovery factor. Weighted on the basis of electric consumption in the three subregions of the Railbelt. H-21 TABLE H-6 NOMINAL AND DISCOUNTED ELECTRIC RATES ANCHORAGE-KENAI-MATANUSKA-SUSITNA (¢/KWH) Nominal Discounted Rate Rate 1981 3.92 3.92 1985 Siie 2.89 1990 10.56 2.84 1995 13.49 1.75 2000 18.46 1.16 2010 29.06 0.42 2020 54.24 0.18 2030 89.40 0.07 2040 186.00 0.03 2050 329.73 0.01 Average Discounted Value 0.8803 Levelized Cost of Electricity 9.67 H-22 €?c-H Year 1981 1985 1990 1995 2005 1981 1985 1990 1995 2000 2005 TABLE H-7 ELECTRIC GENERATION, LOAD CAPACITY AND RETIREMENTS IN THE RAILBELT, 1981-2005 Generation Load Capacity Retirements Generation Load Capacity Retirements* ~~ (GWHY (MW) (Mw) (MW) (GWE) (MW) (MW) (Wy Anchorage-Kenai-Matanuska-Susitna Region Fairbanks Region 2,649 549.8 784.5 0.0 662 137.4 385.7 0.0 3,976 8,25.3 942.9 0.0 904 187.5 385.7 0.0 4,521 938.3 1,239.9 0.0 931 193.2 376.7 9.0 6,140 1,274.1 1,879.0 148.4 1,183 245.4 460.1 128.7 6,374 1,323.0 2,001.6 238.3 i+ ie 234.9 ices 46.0 Capacity includes Susitna Valdez-Cordova Region Total Railbelt 101 21.0 67.3 0.0 3,412 708.2 1,237.5 0.0 152 31.6 79.3 0.0 5,032 1,044.4 1,407.9 0.0 156 3259 93 0 5,608 1,164.0 1,695.9 9.0 192 39.8 90.1 9.6 7,515 1,559.3 oySl dun 286.7 197 40.9 82.4 7.7 7,313 i,a17.8 2,227.8 201.4 210 43.6 91.4 3.0 7,716 1,001. 2,465.5 387.3 97-H TABLE H-8 CAPACITY ADDITIONS — RAILBELT (Megawatts) With Susitna Without Susitna Anchorage Valdez- Anchorage Valdez- Area Fairbanks Cordova TOTAL Area Fairbanks Cordova TOTAL 1982 158.4 0.0 12.0 170.4 158.4 0.0 12.0 170.4 1988 9750 0.0 0.0 97.0 97.0 0.0 0.0 97.0 1990 200.0 0.0 0.0 200.0 200.0 0.0 0.0 200.0 1993 787.5 212.1 20.4 1,020.0 200.0 0.0 10.0 210.0 1995 0.0 0.0 0.0 0.0 200.0 0.0 0.0 200.0 1997 0.0 0.0 0.0 0.0 0.0 150.0 10.0 160.0 2002 493.1 94.0 12.0 600.0 0.0 50.0 0.0 50.0 2003 0.0 0.0 0.0 0.0 200.0 0.0 0.0 200.0 2005 0.0 25.0 0.0 25/30) 400.0 25.0 0.0 425.0 TOTAL 1,736.0 332.0 44.4 2,112.4 1,455.4 225.0 32.0 1,712.4 Sc-H TABLE H-9 FUEL CONSUMPTION AND HYDRO POWER FOR ELECTRIC POWER GENERATION Anchorage-Kenai-Matanuska Valdez-Cordova with Susitna Fairbanks with Susitna with Susitna Total with Susitna Gas Oil Hydro Coal Oil Hydro Oil Hydro Gas Coal Oil Hydro (MMCF ) (K gal) (GWH) (K ton) (K gal) (GWH) (K gal) (GWH) (MMCF) (K ton) (K gal) (GWH) 1981 34,552 555 280 498 10,545 0 8,476 0 34,552 498 19,576 280 1982 36,430 585 280 503 13,778 0 7,348 27 36,430 503 21,711 307 1983 42,878 585 280 497 27,061 0 6,233 55 42,878 497 33,879 335 1984 47,323 585 280 512 32,150 0 7,160 55 47,323 512 39,895 335 1985 52,226 585 280 530 38,000 0 8,169 55 52,226 530 46,754 335 1990 49,443 626 510 490 48,079 0 8,506 55 49,443 490 57,211 565 1995 35,786 0 3,033 243 24,484 705 5,731 123 35,786 243 30,215 3,861 2000 34,281 0 3,033 319 1,100 705 6,251 i273 34,281 319 7,351 | 3,861 2003 7,916 0 5,521 31 667 = 1,073 3,752 160 7,916 31 4,419 6,754 2005 7,493 0 5,678 0 2,888 1,104 3,827 165 7,493 0 6,715 6,947 9¢-H TABLE H-10 FUEL CONSUMPTION AND HYDRO POWER FOR ELECTRIC POWER GENERATION Fairbanks without Susitna Anchorage-Kenai-Matanuska without Susitna Susitna Gas Oil Hydro Coal oil (MMCF) (K gal) GWH) (K ton) (K gal) 1981 34,552 555 280 498 10,545 1982 36,430 585 280 503 13,778 1983 42,550 585 280 497 26,555 1984 45,953 585 280 512 30,162 1985 49,574 585 280 az2 35,423 1990 44,218 626 510 478 42,880 1995 56,184 0 510 535 72,952 2000 54,435 0 510 752 1,166 2003 50,857 0 510 737 1,166 2005 50,569 0 454 719 3,388 Valdez-Cordova without Susitna Total without Oil Hydro Gas Coal oil Hydro (K gal) (GWH) (MMCF) (K ton) (K gal) (GWH) 8,476 0 34,552 498 19,576 280 7,348 27 36,430 503 Qe iadel, 335 6,210 55 42,550 497 33,350 335 7,022 D>. 45,953 D2 37,769 335) 7,902 55 49,574 523 43,910 335 7,958 55 44,218 478 51,464 565 11,194 55 56,184 535 84,146 565 11,579 55 54,435 752 12,745 565 12,270 55 50,857 737 13,436 565 WAR 7/272 55) 50,569 719 16,110 509 * The precipitous drop in oil consumption from 1995 to 2000 is due to generation and the retirement of a large oil-fired unit in the model. the introduction of coal-fired TABLE H-11 SENSITIVITY ANALYSIS ALTERNATIVE GENERATION PLANS WITH 3 PERCENT ELECTRICITY GROWTH RATE ELECTRIC RATES ANCHORAGE-KENAI~MATANUSKA-SUSITNA (¢/KWH) Susitna Chakachamna Natural Gas Coal Year Plan Plan Plan Plan 1981 3.92 3,92 3.92 3.92 1985 5.56 5.65 5.65 5.56 1990 10.13 10.62 11.20 13.92 1995 13.98 17.48 14.65 15.14 2000 19.38 19,32 19.91 21.97 2010 29.76 28.73 30.97 43.69 2020 51.95 59.13 75.06 82.65 2030 95.63 114.10 147.65 141.60 2040 OTe 5) 257.45 329.80 340.91 2050 427.64 422.37 654.60 611.89 Average Discounted Rate 0.9184 0.9570 0.9460 1.0074 Levelized Electricity Cost 10.09 10.52 10.40 11.07 Susitna Plan assumes expansion of Beluga generating capacity in 1982, Bradley Lake in 1988, Susitna in 1993 and 2002, and gas-fired combined cycle and combustion turbine capacity added after 2010. Chakachamna Plan assumes expansion of Beluga generating capacity in 1982, Bradley Lake in 1988, a hydroelectric project on Lake Chakachamna in 1993, and gas-fired combined cycle and combustion turbine capacity added after 2010. Natural Gas Plan assumes expansion of Beluga generating capacity in 1982, Bradley Lake in 1988, and gas-fired combined cycle and combustion turbine capacity added in 1990. Coal Plan assumes expansion of Beluga generating capacity in 1982, Bradley Lake in 1988, and coal-fired steam electric and gas-fired combustion turbine capacity added in 1990. H-27 APPENDIX | SUMMARY OF PUBLIC REVIEW COMMENTS SUMMARY OF PUBLIC REVIEW COMMENTS The 1983 Long Term Energy Plan was presented to the public at hearings held in Fairbanks, Anchorage, and Juneau in January 1983, and went through the Governor's review process. A total of 26 written comments were received from the following sources: o State agencies - Alaska Power Authority - Division of Minerals and Energy Management - Department of Transportation and Public Facilities = Division of Community Planning — Division of Petroleum Revenue CS Alaska Public Utilities Commission - Division of Strategic Planning o United States Government Agencies - Bureau of Indian Affairs - Department of the Army, Corps of Engineers o Alaska Municipalities a City of Cordova - Fairbanks North Star Borough = Municipality of Anchorage o Private Corporations - Alaska Pacific Bank Corporation - Alaska Bush Energy Systems - Alaska Electric Light & Power Company - Calista Corporation - CSM Inc. - Heat Loss Analysis, Inc. I-1 oO - Koyukon Development Corporation - Municipal Light & Power Other Groups and Individuals - Rural Alaska Community Action Program, Inc. - Resource Development Council for Alaska, Inc. - University of Alaska, Institute of Social & Economic Research These written comments, along with comments from key staff at the Division of Energy and Power Development and the Office of Management and Budget in the State, can be grouped into three major categories: oO General comments - regarding the scope and specific analyses presented in the 1983 Plan. Technical questions - regarding data accuracy, analytical methodologies, and calculation procedures used in the 1983 Plan. Policy and procedural concerns - regarding policy recommendations and the process whereby the information in the 1983 Long Term Energy Plan, the computer model analyses, the 1982 Long Term Energy Plan, and other State information and models can be utilized to support planning, as well as economic and financial research in the State of Alaska. The following discussion provides a brief overview of the major types of comments in each category and outlines, in general terms, how the 1983 Long Term Energy Plan responded to these comments. Ie General Concerns General concerns regarding the tone of the report and the relative emphasis given to specific energy issues were raised. oO Many reviewers commented on the fact that the review process was too short considering the volume of economic and energy forecast data developed for the 1983 Long Term Energy Plan. A review time of 2-3 weeks was felt to be insufficient for a comprehensive review. The fact that this year's report does not present specific recommendations was a concern raised by several commentators. Several requests were made to expand and/or clarify discussions on specific energy-related issues. These included the financing of Susitna, the State's energy research and I-2 development programs, and the impact of federal laws and regulations on Alaska's energy demands and exports. We recognize that the 1983 Long Term Energy Plan did not present specific recommendations; its charter was to present factual information and trade-offs on a range of economic and energy developments possible for the State. This information was to provide State Legislators with the necessary data to support its decision-making concerning future energy developments and plans for the State. Specific issues, such as the financing of Susitna, energy research and development programs, and the impact of Federal laws on Alaska's energy plans, were further clarified in the report itself or through supplemental memorandum filed with the Division of Energy and Power Development. In certain cases, comments concerning the scope and detail of the 1983 Long Term Energy Plan came from reviewers who had received an abbreviated Appendix. Their comments noted the lack of any assessment of energy use by end-use, list of research and development projects, and detailed balance of energy output and energy input. The fully appended report covers these issues. Several reviewers commented that the analysis of conservation options and state conservation programs was not addressed in sufficient detail. The scope of the study effort for 1983 Long Term Energy Plan precluded a region-by-region assessment of conservation status in end-use sectors or specific State programs. Only a broad generalization of the further conservation developments could be introduced into the 1983 Long Term Energy Plan because of the lack of available data and the complexity of the required analysis. It is important to note that detailed computerized information was not available to the study team to evaluate the effectiveness of existing State conservation programs. A general assessment was undertaken, however, based on a review by the study team's specialists of the conservation programs status to-date. Furthermore, the effect of price on conservation is incorporated in the end-use analysis. The effects of future energy prices on energy consumption by household for each of the 14 regions in Alaska is shown. Some reviewers expressed interest in the availability of the model analyses and the wealth of data which the 1983 Long Term Energy Plan has produced. The Division of Energy and Power Development and its consultant Arthur D. Little, Inc. are working to make the economic, energy, and supply data and models available on the State of Alaska's data processing system. Thus, specific users from within the State, as well I-3 as individuals and companies outside State agencies, can obtain access to the information and model analyses. Ze Technical Questions Several of the reviewers raised specific questions concerning the data, and brought up specific technical and methodological issues regarding the forecasts and model analyses. o Basic data used in developing the economic, energy, and supply evaluations were prepared by Arthur D. Little, Inc., from the 1982 Long Term Energy Plan as well as many State and Federal data sources. In certain cases, the data as developed was shown by several reviewers to be incorrect or inconsistent and was changed accordingly. Major data changes included historical consumption of energy by type, the costs of electricity in rural areas of the Railbelt, the net-back costs of natural gas and coal for Alaska at tidewater, and specific data concerning the availability and capacity of potential hydroelectric power projects. Several reviewers commented that some of the early year forecasts by region do not track precisely with current experience. It must be recognized that the forecast models as prepared for 1983 Long Term Energy Plan represent long term forecast models, and may understate or overstate energy use in the near term. Secondly, the forecasts start from a 1980 economic data baseline and a 1981 energy data baseline, which will naturally entail some variance in the actual value presented for the past year 1982. Some of the energy balance data by end-use and by fuel type for the various regions of Alaska was inconsistent in the draft report; it was made consistent and _ substantially clarified with footnotes. Discount rates and fixed charge rates varied in several of the analyses and were also later made consistent for the final report. In addition, several reviewers requested that average present value electricity prices be shown on a _ basis consistent with the levelized annual cost of electricity used in other forecast documents, such as Battelle's Railbelt Electric Demand forecast study and the Acres American Susitna Study. Levelized costs of electricity were added to those tables in this final report. Methodological concerns were raised with respect to the economic and energy forecast analyses. Some reviewers questioned the selection of the modelling approach and the detailed model analyses developed for the 1983 Long Term Energy Plan. The contractor, Arthur D. Little, Inc., does not endorse one method or another for its accuracy or superiority, but does wish to state that the methodology developed for this report was consistent with the desired detail of the forecast results. Some reviewers believe this approach to be inconsistent with the dynamics of the State's economy and therefore inappropriate for evaluating Alaska's economic development. The approach taken is one avenue for forecasting economic development in Alaska and has its strengths and weaknesses as do other economic forecasting approaches. Forecasts by the various methods should always be compared. It must be noted that the consultant was not contractually responsible for developing economic forecast models, but needed to do so to complete its assignment by providing the energy end-use analysis by _ regions. As a result, the consultant prepared economic models for the State in which individual economic scenarios can be generated and then translated into unique end-use energy demands across 14 regions in the State. Technical comments addressed the linking or matching of energy supply alternatives with energy end-use demands. It is our contention that in any long term energy study, energy supplies and energy demands can only be linked in a very general or generic way. For specific analyses of individual projects, planned expansions, and resource developments, individual supply analyses must be separately analyzed and introduced into the planning equation. This is the approach used in the 1983 Long Term Energy Plan. The State's Division of Energy and Power Development has supply planning models capable of assessing individual projects or resource developments. Several reviewers commented that the assessment of energy supply and demand did not introduce a risk or probability factor for the outcome of certain events. The scope of the analysis provided by the 1983 Long Term Energy Plan was sufficiently complex and time consuming to preclude the additional sophistication that probabilistic demand analysis and supply forecasting would have required. The analyses and planning models can, however, be modified to include probability, uncertainty, and risk assessments. Specific concerns were raised that the forecast of energy prices, and in particular petroleum prices, did not match current world market prices at the time of the review. Some reviewers commented that the impact of these lower world Ind energy prices was not assessed and reintroduced into the Long Term Energy Plan. Although current world market prices appear significantly lower than those upon which the energy forecasts were based, these short term swings are not necessarily inconsistent with the longer term forecast mandated and provided in the 1983 Long Term Energy Plan. Several reviewers disagreed generally with assumptions concerning escalation rates, interest rates, and financial analyses which were presented in this_ study. These assumptions and analyses reflect the professional judgment of the study team and should be compared with reviews and evaluations prepared by other specialists in _ studies undertaken for the State of Alaska. Finally, several comments were received concerning’ the evaluation of specific projects on a project-by-project basis. The 1983 Long Term Energy Plan identified a range of electricity and thermal energy alternatives, as well as several specific projects which had to be treated on a statewide or regional basis for planning purposes. The time and scope of analysis required to evaluate each and every possible project in Alaska was not within the scope nor the intent of the 1983 Long Term Energy Plan. Many of these projects have been studied individually by other State departments and agencies. The practicality of specific options was, however, taken into consideration: the use of coal-fire power plants in the Anchorage Basin; the long term availability of natural gas for electric generation in the Railbelt without a North Slope natural gas pipeline; and specific needs for back-up generation for rural local or regional electricity systems. The thrust of the analysis and trade-offs shown in the 1983 Long Term Energy Plan reflected this additional technical information. 3. Policy and Implementation Concerns Several reviewers commented that the 1983 Long Term Energy Plan did not provide specific recommendations to permit the State to move forward in definitive energy planning, nor address or reflect some of the specific policy concerns of individual state agencies regarding energy supply and demand. oO Several commentors indicated the need for rural energy supply and conservation strategies. The 1983 Long Term Energy Plan recognizes these strategies as important. The report did not recommend specific actions since the study team is pursuaded that these energy issues must be handled on a local and community level, and can only be incorporated into the long term energy program when implemented community by community. o Several commentors indicated the difficulty in organizing all the major alternatives for Alaska into one document while incorporating all the rest of the information which is required under state law. In the 1983 Long Term Energy Plan, we attempted to identify several major alternatives and to show how these alternatives can be synthesized into strategic energy options for the State. The importance of economic development objectives for the energy planning process was also demonstrated. o Some commentors emphasized the potential for individual supply alternatives such as geothermal, peat, wind, biomass, and others. The 1983 Long Term Energy Plan recognizes that these alternatives may be practical on a site-specific basis, but that as general alternatives for the State, or even a region within the State, a recommendation to introduce them into a long term energy planning strategy for the State cannot be justified. While certain energy alternatives are practical, in specific locations, they can only be introduced into the State Energy Plan through individual study and implementation. o Other reviewers pointed out that specific policies could be developed from these strategic energy plans and recommended for adoption by the State of Alaska. The intent of the 1983 Long Term Energy Plan is only to show energy strategies and trade-offs and not to develop specific energy policies for the State. We believe that the current document has taken the energy planning process for the State two steps further down the road from the 1982 Plan: generating a spectrum of energy strategies based on several economic scenarios to show the legislature the range of tradeoffs; and developing a set of energy planning models which will be available to all parties in State government for future planning purposes. The discussion presented above is only a brief summary indicating the nature of the comments we received and our efforts to respond to them. We feel we have addressed the major concerns and questions to the fullest extent possible, given the thrust of the 1983 Long Term Energy Plan and the time constraints inherent in the preparation of this report and documentation. I-7