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Alaska's Public Energy Resources, Rural Research Agency, July 1985
8 ALASKA’S PUBLIC ENERGY RESOURCES rural research agency july 1985 ALASKA'S PUBLIC ENERGY RESOURCES Distribution Of Benefits Of Thermal Energy And Electric Power Energy Resource Consumption July 1985 Rural Research Agency Alaska State Senate By: Richard Rainery Allison Fargnoli Jennifer Klein ‘AB OF CONTENTS Chapter Summary Introduction Tie Energy Resource Utilization in Alaska A) Energy Usage Background B) Thermal Energy Sources C) Electric Power Generation by Fuel ea, Natural Gas Prices and Consumption A) The Basis for Price Comparisons B) Gas Prices C) Economic Benefits of Gas Use D) Future Gas Prices E) Gas Reserves and Future Consumption F) The People's Gas: Volume and Revaluations G) The Question of Equity III. Fuel Oil Prices and Consumption A) Sources of Fuel Oil Consumed in Alaska B) Fuel Oil Prices C) Fuel Consumption D) Royalty Oil: Can It Meet Alaskan Demand? IV. Coal Prices and Consumption A) Alaskan Coal Resources B) Western Arctic Coal Development C) State Coal Leases D) Coal as a Fuel Source E) Economic Benefits of Coal Use F) Future Coal Prices Page sl LS 47 60 Vv. Hydroelectric Power 75 A) State Hydroelectric Law and Policy B) Four Dam Pool Projects: Resources and Recipients C) Other Hydroelectric Projects D) Hydroelectric Power Benefits E) Current Rates F) Distribution of Benefits vI. Comparative Energy Costs 92 A) The Relationship Between Fuels and Energy B) Energy Costs Across Alaska VII. Options for Legislative Action 98 A) Program Options B) The Prospects for Local Resource Access and Distribution C) The Basis of Thermal Energy Cost Equalization VIII. The Cost of Thermal Energy Cost Equalization 115 A) Consumption Encouraged? B) Cost Calculations C) Cost Reduction Measures Appendix A-1 Bibliography BI oe Iv vI VII VELL Ix xI xXII xIII xIV XVII XVIII xIX XX XXI XXII XXIII XXIV XXV XXVI XXVII LISTING OF TABLES AND FIGURES Petroleum Production and Royalty Oil Production Thermal Energy Consumption by Source Electric Power Generation by Energy Source Natural Gas Prices to Electric Utilities Natural Gas Prices to Gas Utilities Cost of Gas to Residential and Commercial Customers Residential Electric Power Rates Gas Utility Revenues and Monthly Consumer Bills Cost of Utility Gas Purchases Contract Prices for Cook Inlet Natural Gas Future Prices of Natural Gas to Utilities Cook Inlet Gas Production and Reserves Cook Inlet Natural Gas Contract Volumes and Consumption Cook Inlet Natural Gas Revenues and Costs 1983 Regional Fuel Oil Prices Spaceheating Fuel Oil Consumption Royalty Oil Volume and Spaceheat Demand Alaskan Coal Resources Usibelli Coal Mine State Royalty Payments Comparison of Average U.S. and Alaskan Coal Prices Coal Generated Power FMUS Coal Use UAF Coal Use Projected Prices of Coal No. 2 Fuel Prices - Anchorage Selected 1984 Residential Power Rates Comparative Cost of Thermal Energy Sources 20 22 25 27 34 36 38 40 44 50 oi: 56 61 64 67 67 68 69 73 83 87 97 Map Chart Chart Chart Alaskan Energy Consumption Regions Thermal Energy Consumption by Source Electric Power Generation By Energy Source 1983 Residential Energy Costs 12 96 List of Acronyms and Abbreviations ADCED Alaska Department of Commerce and Economic Development ADHSS Alaska Department of Health and Social Services ADNR Alaska Department of Natural Resources ADOR Alaska Department of Revenue AELP Alaska Electric Light and Power Company APA Alaska Power Authority APUC Alaska Public Utilities Commission AOGCC Alaska Oil and Gas Conservation Commission AVEC Alaska Village Electric Cooperative AMLP Anchorage Municipal Light and Power AVCP Association of Village Council Presidents BBTU Billions of british thermal units BUEC Barrow Electric and Utility Cooperative, Inc. BCF Billion of cubic feet (of natural gas) BTU British thermal unit CEA Chugach Electric Association CES Community Energy Survey CFS Community Fuel Survey CINA Cook Inlet Native Association DOE United States Department of Energy Enstar Enstar Natural Gas Company FMUS Fairbanks Municipal Utility System FDP Four Dam Pool GAL Gallon (of petroleum or fuel oil) GVEA Golden Valley Electric Association ISER Institute of Social and Economic Research (University of Alaska) Kentco KWH KUSCO LIHEAP MMBTU MMGAL MWH MCF OPEC ORC Onc PCAP PCEP PSA RurALCAP RRA Tce TECEP THCC TCF USGS UAF William Kent and Company Kilowatt hour Kenai Utilities Service Company Low Income Home Energy Assistance Program (federal) Millions of british thermal units Millions of gallons Megawatt hours (thousands of KWH) Thousands of cubic feet Organization of Petroleum Exporting Countries Organic Rankine Cycle engine Orutsararmiut Native Corporation Power Cost Assistance Program Power Cost Equalization Program Power sales agreement Rural Alaska Community Action Program Rural Research Agency Tanana Chiefs Conference Thermal Energy Cost Equalization Program Tlingit-Haida Central Council Trillions of cubic feet United States Geological Survey University of Alaska, Fairbanks SUMMARY The purpose of this study is to examine the instate uses of Alaska's energy resources in order to determine how the use cof those resources (primarily those owned, at least partially, by the State) has benefitted Alaskan consumers. This inquiry is restricted to consideration of the disposition and pricing of the major resources (and their products) producing electric power and thermal energy. Whether the use of Alaska's energy resources afforded equitable benefits to all Alaskans is the central question. Cha source Ut zation b askans The four major instate energy resources providing electric power and thermal energy in Alaska are petroleum, natural gas, coal, and water. State ownership and royalty shares of the first three are substantial. Only petroleum products are imported to any real degree, despite Alaska's self-sufficiency in volume of crude oil production. Thermal energy across Alaska is primarily fuel oil produced, the major exception being the southcentral region, which relies upon natural gas. The State's 1983 Long Term Energy Plan identified 1981 statewide thermal energy (space and water heat) consumption as produced by these sources: Petroleum - 41.8% Natural Gas - 38.3% Coal = 3.0% Electricity - 7.1% Other = 9.7% The natural gas share has since increased, at the expense of fuel oil, as gas use expands in the Cook Inlet market. sl Regional power generation fuel use is more diverse. Most electricity in Southeast Alaska is water driven. Natural gas turbines energize the bulk of the southcentral area, while coal boilers produce the lion's share of electricity in the Interior. Most power in rural Alaska is diesel fuel generated. Statewide generation in 1983 had these sources: Fuel oil =~ 13-52% Natural Gas - 64.7% Coal - 8.0% Hydro - 14.1% The hydro share has increased since 1983, eroding oil's base slightly. Most __o the state except the Bush had alternatives to petroleum produced energy. Chapter II: Natural Gas Prices and Consumption Consumer use of natural gas is limited to the Cook Inlet vicinity and Barrow. The limited regional use of gas within Alaska dictated that benefit comparisons be made with the national market. The Cook Inlet consumer enjoyed a substantial economic advantage. For example, residential natural gas rates there averaged $1.72 per thousand cubic feet (mcf) in 1979, compared to a national average of $2.98. By 1984, Cook Inlet rates had climbed 53% to $2.63/mcf, but national rates had increased 103% to $6.06. Cook Inlet rates were only 43% of national rates. Wed. gas) cost disparities were of the same magnitude. The actual average monthly bill to Cook Inlet residential users in 1984 was about $40; the bill would have been $93 at national prices. Over the five year period, 1979 - 1984, these price differentials "saved" Alaskan gas consumers close to $300 million, relative to national prices. s2 This advantage should continue for the next seven or eight years under the terms of major utility contracts with producers. Some contract prices will actually be declining in real dollar value. Forecasts show Cook Inlet gas prices. to be well below national prices at least until the turn of the century. Economically recoverable reserves there should be sufficient for all uses for at least twenty years. Over 60% of reserves are State-owned. While an apparent economic advantage has existed, and will persist, in Barrow and Cook Inlet, royalty gas and severance taxes do provide revenues redounding to the general benefit of all Alaskans. The FY 85 contribution to the State treasury, attributable to gas utilized for the purposes under scrutiny, will be about $7 million. le is amount wi eas ie n n oresee e ture emote a each the econo benefits, measured against national costs che s ovides to its users. fe Ts el oi ices an nsumption Analysis of fuel oil consumption and pricing in Alaska is problematic as a result of the dearth of comprehensive and current information. Alaskans rely on both royalty products, in interior and southcentral Alaska, and imported oil, in the southeast, southwest, arctic and northwest areas. Access to royalty products is but one of several salient price determinants. 1983's lowest prices were in a _ region, Southeast, almost totally dependent upon imported fuels. One survey put regional average prices per gallon at from $1.09 to $2.11, compared to a national average of $1.05. Thus, all Alaskans paid remium for fuel oils, whether consumin products refined instate from royalty crude or imported from west coast plants. A reliable calculation of the economic benefits or burdens of using fuels of different origin is s3 hampered by weaknesses in data. About 60% of fuel oil is consumed outside the Railbelt, where it is generally more expensive. Royalty oil volumes are forecast to be insufficient, past the year 2000, to replace imported thermal fuel usage statewide. ter TVs: Con sa n Alaska Although Alaskan coal resources are abundant, currently there is little production for several reasons: inaccessibility, (most coal reserves are found in the Arctic); lack of infrastructure; lower grades of coal; and lack of markets. The Usibelli Mine is the only operating mine, producing 800,000 tons annually under two State leases; most is used in the Fairbanks area for electrical generation and heating purposes. The mine's proximity to the Alaska Railroad renders this use economic. Alaskan coal prices, 1979-1983, have exceeded national prices, on an energy content basis. The future price of coal in Alaska is uncertain. Prices are affected by economy of scale. If steam coal power should become an alternative to hydroelectricity or if exports to the Pacific Rim countries increase, escalated production could lower the costs. Declining oil prices may erode coal's cost competitiveness, however. Chapter V: Hydroelectric Power Costs and Benefits In the late 1970's, State policy was formulated calling for reduction of power costs through the development of large-scale power projects. Development of hydroelectric power was considered most desirable. Alaska's unlimited hydro potential offered the incentive of energy free of S4 external cost influences. The Alaska Power Authority was created to finance and manage state power projects. Today, the State owns and operates four large-scale hydro projects: Swan Lake, near Ketchikan; Lake Tyee, near Petersburg; Solomon Gulch, near Valdez; and Terror Lake, on Kodiak Island, known collectively as the Four Dam Pool (FDP). The immediate and potential benefits accruing to these communities, representing about 6% of Alaska's population, include: cheap power, stable long-term rates, guaranteed supply, surplus generation capacity and rate subsidies. com ison ctric rates across power sources (oil as 2. hi ©) show S_ pow: n_the Anchorage ea _ to be t cheapes ns tat ollowe: hydro and coal-based rates. The he: rates a ound in 1_areas where se enerated we: ed: ates Residents _o ban eas 2 eapest electric rates egardless of the source. Of the over $1.08 billion to date appropriated for hydro projects (legal challenges may overturn some of these appropriations), $506 million has been for FDP projects, approximately $16,330 per capita for those communities. At present, only a few residents enjoy the benefits of the State's hydro projects. When considering redistribution of these benefits to the other residents of Alaska, it becomes necessary to think in terms of benefit "equivalencies" or other, indirect means of compensating those regions not benefitting from hydro resources. No other practical means of overcoming the realities of geography exists. Chapter VI: Comparative Energy Costs Comparisons between thermal energy and power costs to Alaskans in different locations, using different fuels, have been developed by calculating energy costs per million s5 British thermal units (MMBTU). The approximate statewide range of 1983 consumer costs by fuel were: Natural Gas - $2.00 to $3.00/MMBTU Coal - $7.00/MMBTU Fuel oil - $12.00 to $24.00/MMBTU Electricity - $15.00 to $81.00/MMBTU Not all fuels, of course, are employed across the state. These figures do not reflect regional differences in climate, construction standards, family size, living standards, etc. They do point to two general truths about energy costs in Alaska: 1) Consumers utilizing petroleum produced power and thermal energy pay more for those commodities than do users of other fuels; 2) Rural Alaskans, dependent on fuel oils, pay much more for equivalent energy consumption than urban Alaskans. Chapter VII: Options for Legislative Action Achieving equity in economic benefits derived from the state's energy resources, on a statewide basis, involves several practical and philosophical considerations. The major barriers to economic equity are market size and resource access. Disparities in electric power costs have been addressed by the Power Cost Equalization Program (PCEP), so an assault on these barriers is presently part of statute. The philosophical foundation of cost equalization has been embraced as public policy. The options listed below are limited to those concerned with thermal energy. S6 1) Devotion of a portion of royalty in value funds to assist in reducing energy costs, either through state involvement in the processing and distribution system or creation of an assistance fund for consumer costs. 2) Devotion of a portion of royalty in kind resources to communities proximate to resource extraction sites. This could require reductions in the prices received by the State for energy resources as an incentive to producers to provide resources locally. 3) A combination of the preceding two options. 4) Requirements that the State or State energy resource lessees study local energy resource provision and, if feasible, provide a suitable portion to local markets. 5) Required instate availability of royalty in kind thermal energy products before authorizing the export of royalty resources. This would reinforce present statutory language and petroleum industry practices. The first and the fourth options offer promise in addressing the equity issue. Local resource provision would attack the fundamental problem of access to State energy resources. Benefits, however, would be limited to areas proximate to energy development under future leases. Analysis of the impact of such a program relies so much on case by case and speculative elements, that it would be a very difficult effort. The. first. option, with statutory, policy, . and operational precedents provided by PCEP and by the federal Low Income Home Energy Assistance Program presents a broader opportunity for analysis and for unrestricted benefits. Legal challenges to the present means of funding PCEP may require that alternatives be found both for it and any thermal program. Significant program elements would include: S7 1) consumer eligibility standards; 2) cost component eligibility; 3) price eligibility floors and ceilings; 4) program structure; 5) consumer participation. Chapter VIII: osts 0 ermal Ener Cost E zation To estimate the costs of a thermal energy cost equalization program patterned after the PCEP, several assumptions were made: extant information could be extrapolated meaningfully; consumption would not increase as a result of de facto price reductions (PCEP price cuts have yet to spur greater usage); limiting eligible thermal energy sources to fuel oil was appropriate; full participation of all eligible citizens; and other public energy assistance would be deducted from State aid. Based on a price eligibility floor of $1.35/gallon of no. 1 fuel oil, program costs (in thousands) are estimated at: FY 87 - $17,714.9 PY. 83) = 18,282 .)7 EY50.— 19, 059.3 FY: 90) =" =20, 76636 PN 9 =: 222, 824.7. This represents an FY 87 per capita aid level of $325; for PCEP it will be about $280, Four Dam Pool communities have, to date, received (over five years) about $3,300 annually in State aid, and Cook Inlet natural gas consumers' effective subsidy in 1984 was about $275 per capita. Significant cost reductions could be realized by limiting aid to a portion of fuel costs or raising the eligibility floor. s8 INTRODUCTION The Rural Research Agency has been directed to examine the instate uses of Alaska's energy resources to determine how those uses or other disposition have benefitted citizens of the state. Special scrutiny has been focussed upon the State owned portion and the State royalty share of these resources. Additionally, the agency has been directed, if its analysis indicated that such was appropriate, to suggest means through which the State of Alaska might better and more equitably, on a statewide basis, distribute the benefits attributable to the extraction, processing, and use of energy resources to the citizens of Alaska. This is a significant and complex subject. As a result, it was necessary to impose some limits on the range and depth of this inquiry, as indicated following. * Although Alaska has many energy resources, both in production and still awaiting exploitation, research was limited to the four most significant of these in producution: oil, natural gas, coal, and water. * Concentration was directed to the use and pricing of those resources (or their products) prevalently utilized to provide electric power and thermal energy. Transportation, industrial, marine, and military use have not been considered herein. The economic benefits studied were restricted to cost savings resulting from price differentials, to consumers, both residential and commercial, and utilities. * The focus was on the period from 1979 through 1984. 1 This inquiry has not been restricted simply to consideration of the State's royalty shares of resources, but a broader perspective encompassing the full level of production and use of energy resources within Alaska was sought. This approach is more than justified by the fact that the bulk of petroleum, natural gas, and coal resources in current production are extracted from State owned land. The wellspring of this research request is the notion that the resources of the state, in their entirety, belong to all the citizens of the state and the benefits of the same should accrue, in as equal a fashion as possible, to all residents. The particulars of each of the four resources noted above will be considered in an effort to make a reasonable comparison of the benefits or advantages each affords to inhabitants of each of the regions of the state. It is beyond the scope of this document to consider certain long term policy issues, such as the likelihood of public assistance programs leading participants into dependency on public subsidies of uncertain duration. Debate concerning issues of this stripe belong in a forum other than this one. ak k Rk RK Our thanks to those who assisted us with our research, particularly the staffs of the various utilities across the state who provided us with much indispensable information. Footnotes ak The term "fuel oil" or "oil" will refer to the specific petroleum products # 1 or #2 heating fuel oil or comparable diesel fuels. "Gas" will refer to natural gas. Chapter I ENERGY RESOURCES UTILIZED BY ALASKANS A) Energy Usage Background To begin, an understanding of how residents of different parts of the state utilize energy resources to fulfill their space heating and electric power needs is necessary. Most, but not all, energy sources are of instate origin. Alaska does not import natural gas employed to generate electric power or for space heating purposes. Nor is hydroelectric power obtained from any other source. Only negligible amounts of coal are imported. Alaska does, despite its huge petroleum reserves, import petroleum products for instate use, including power and thermal energy generation. In 1981, 42% of refined petroleum products used in Alaska were imported. + Refinery capacity has grown little since 1981, while demand has increased as the state's population and commerce have grown. It is likely that the percentage of imports has increased as a consequence. In particular, fuel oils destined for heat and power production are imported into the southeast, southwest, northwest and arctic regions of the state, but even the railbelt corridor, with domestic refineries, one in Fairbanks and two on the Kenai Peninsula, must import some varieties of petroleum products. According to the Alaska Department of Natural Resources (ADNR), the situation is the result of two factors: 1) Instate refinery production capacity does not match to Alaskan demand for petroleum products. 2) Out of state refiners can underprice instate refiners in several regions. (Both phenomena are termed "a common feature of petroleum markets in general".”) Alaska does have sufficient instate reserves to fulfill its own petroleum product needs’, given that these price and capacity issues are understood. Unless instate refinery capacity is expanded and diversified or instate refiners discover sources of crude oil at prices which allow lower end user prices, conditions are unlikely to change. The State does, through its royalty oil allotment, have the capability, hypothetically, to provide for instate demand for all kinds of refined products, including those used for space heating and for power generation, as indicated in Table I. This capacity, according to ADNR, however, depends upon the ability of instate refineries to utilize North Slope crude to produce the products needed by the Alaskan market. It is unlikely that more than 50% of the crude volume could be translated into such petroleum liquids because of the high sulphur content of the North Slope crude. The actual amount would surely be less. Greater volumes of production and varieties of products would require costly upgrading of Alaskan refineries.* In any event, recent experience has taught that projections of the consumption and, for that matter, the prices, of petroleum Table I Petroleum Consumption And Royalty Oil Production (millions of barrels) Royalty Statewide Year Production Consumption 1985 Ge, 36.8 1986 Ord 37.6 1988 69.6 38.4 1990 S70) 39.9 1992 47.9 41.1 1994 Sites 42.9 Source: ADNR, 1/85. products, have proven to be risky efforts. While it is possible that Alaska does have the capacity at present for self-sufficiency in petroleum products, should it dedicate its royalty oil to that purpose, such a goal would be achievable only for the short term. Table I indicates that by 1994, even if all royalty oil could be refined into products demanded by Alaskans, the supply of royalty oil would fall short of forecast demand. The discovery and development of additional fields could alter this situation. B) Thermal Energy Sources By the term "thermal" (or spaceheating) energy, we refer to several uses that residential, commercial, and public consumers put to energy sources mostly obtained from electric or gas utilities or from coal and oil distributors. Such employments as water heating are included in the term. Current data on this subject of a comprehensive and precise nature is not readily available, particularly in the format required for this report. Most previous inquiries have not broken thermal energy consumption data out into one or both of the two categories important to our purposes, those being energy source and regional utilization of each source. Table II, while somewhat dated and therefore unreflective of certain changes in regional trends, such as expanded use of electric spaceheating in the Southeast region (Juneau for the greatest part), the penetration of natural gas into the Mat-Su valley, and the general expansion of the state's population and economy during the last three years, contains the most recent data relevant to our purposes. Alaska Power Authority (APA) reconnaisance studies provide the best and most recent data on a regional basis, but there are too many gaps to render them useful in this case. The table and accompanying graphs are useful, however, insofar as they 5 establish fundamentally which Alaskans use which energy sources. This is the primary element necessary to begin an assessment of the benefits accruing to residents as a result of the use of the State's energy resources. It lists 1981 consumption of thermal energy by region and by energy source within each region. The figures are in billions of British Thermal Units (BBTU), providing standard measures of consumption for different energy sources. Fuel oil was the predominant spaceheating energy source in Alaska, in all regions but one. Natural gas was the major source of thermal energy in that one region (see map) in 1981. Natural gas was the principal fuel in the Southcentral region as a consequence of its prevalence in Anchorage and Kenai. The availability of inexpensive natural gas supplies found beneath the surface of the Cook Inlet and adjacent land masses explains this situation. Over 60% of the Southcentral region's thermal needs were served by natural gas. If one considers only the Anchorage area, the figure was approximately 70%. The use of natural gas in the rest of the state for spaceheating was confined to Barrow which has a gas supply developed by federal agencies and turned over to the North Slope Borough. We will examine this issue in depth in the chapter on gas. Fuel oil was the primary source of thermal energy in the Southeast, Interior, Arctic/Northwest, and Southwest regions. The vast majority of spaceheating in the Southwest region was oil produced, as was the case, to a somewhat lesser degree, in the Arctic/Northwest. The use of electricity in all regions was likely mostly for heating water. The only region in which coal was a major thermal energy source was the Interior region. The consumption of coal there is mostly restricted to the Fairbanks area and to outlying military installations. The Usibelli mine supplies these areas. The smaller, more isolated communities in the Map I Alaskan Energy Consumption Regions 1. Southeast 2. Southcentral 3. Interior 4. Arctic/Northwest 5. Southwest nee Table II Thermal Energy By Source 1981 Fuel ‘ . F Southeast S523 1917 0 0 330 L270 54.4% 9.5% 36.1% Southcent'l 24494 6650 14925 0 2145 774 Ziel s 60.9% 8.8% 3.2% Interior 7902 4778 0 1217 326 1581 60.5% 15.4% 4.1% 20.0% Arctic/NW 1836 1342 407 0 19 68 73.1% yews} 1.0% 3.7% Southwest 2296 2060 0 0 32 205 89.7% 1.4% 8.9% Statewide 40051 16747 15332 1217 2856 3899 41.8% 38.3% 3.0% Tes 9.73% Source: ADCED, 1984. Thermal Energy By Source (1981 BBTU) Oil N. Gas (27%) S Coal Ml] elect Other —(8%) 9%) Southcentral Interior Southeast Statewide (90%) Ege) ~o2) 1%) Southwest Arctic /NW remainder of the Interior depend on oil heat and upon wood burning. The use of wood is included, for informational purposes, in the category "Other" in Table II. This category also includes fuels such as propane which is widely used in the bush and elsewhere for miscellaneous purposes such as cooking and water heating. Wood spaceheating figured strongly in the heavily forested Southeast region. Oil fuels about 42% of Alaska's thermal needs and the proportion of the total population involved is probably about 45%. It is spread over all regions of the state, in communities of all sizes. In rural Alaska, only Barrow does not rely on oil. Anchorage and Kenai, with Cook Inlet natural gas, are the only other communities which do not, to a significant degree, depend upon oil as an energy source for thermal requirements. Natural gas has just recently become available for spaceheating in the Matanuska-Susitna Valley and that area is likely to undergo a significant conversion to that source in a fairly rapid fashion. It is possible, that by 1985, natural gas has become the most commonly employed thermal fuel in Alaska. Finally, a cautionary addendum to this section must be added. The data represented in Table II was extracted from estimates made by Arthur D. Little, Inc. for the 1983 Energy Report published by the Alaska Department of Commerce and Economic Development (ADCED). There is some controversy concerning the precision of these estimates, particularly in comparison to statistics developed by the Federal Department of Energy in its annual state energy data reports. The Department of Energy report, however, does not offer regional breakdowns of energy resource use. The data utilized herein does represent the most comprehensive and the most recently compiled on a regional basis, by fuel and by use, available. The situation is one that would benefit greatly from additional research. 9 C) Electric Power Generation By Fuel Identifying the resources utilized for the production of electric power in Alaska is a simpler task than that of measuring the use of resources to produce thermal energy. For one thing, many of the electric power utilities in the state are regulated by the Alaska Public Utilities Commission and must report certain information to that agency. Secondly, many utilities are required to supply information to the federal government as a condition of Rural Electrification Administration loans without which they would find it difficult to operate. Thirdly, a large number of utilities, down to very small entities serving very small communities, are participants in the State of Alaska's Power Cost Assistance Program (now known as Power Cost Equalization Program) and much information is available therefrom. Despite this relative abundance of precise information, we have estimated that the data represented in Table III and the associated graphs is lacking relevant facts concerning approximately eighty communities with a population of about eight thousand. Most of these are remote communities with fewer than 200 inhabitants; likely about four fifths fall into this category. There is little reliable information for these locales. In fact, it is not certain that all have community electrical generation facilities of any kind. Nearly 200 communities, with about 98% of the state's July 1, 1983 population of some 510,000, are included and the data concerning them is reliable. The table lists total megawatt hours (MWH - thousands of kilowatt hours) generated in each region and the amounts generated by each fuel source. The primary energy source statewide was natural gas, but the same was true in only one region, the populous Southcentral. Ninety-two percent of that region's 1983 electric power was produced with Cook Inlet gas. All other 10 sources were negligible in comparison. Residents of the Kenai Peninsula, Anchorage and environs and on up to the Matanuska-Susitna Valley turned on their lights and appliances with electricity produced by gas turbines. A small portion of the region's power originated from hydroelectric facilities at Eklutna, outside Anchorage, and Solomon Gulch near Valdez. More isolated locations relied upon fuel oil for power production. There is slightly more diversity in electric power energy sources statewide than is the case with thermal production. Southeast depends mostly on hydroelectric power, with over three quarters of 1983 generation derived from the force of water. That percentage has since increased somewhat as the two Alaska Power Authority projects at Swan Lake and Lake Tyee have now come on line to supplement the existing hydro Table III Electric Power Generation By Energy Source Region 1983 MWH oil N. Gas Coal Hydro Southeast 513321 118378 0 0 394943 23.1% 76.9% Southcentral 2923089 32976 2692855 0 197258 Lethe 92.1% 6.7% Interior 518225 183939 0 334286 0 35.5% 64.5% Arctic/NW 99194 70694 28500 0 0 71.3% 28.7% Southwest 149267 149267 0 0 0 100.0% Statewide 4203096 555254 2721355 334286 592201 13.2% 64.7% 8.0% 14.1% Source: Alaska Power Administration, Sept, 1984; APA, 1984. ae) { i 2 Southwest plants in the region at Juneau, Sitka, Petersburg, Skagway, Metlakatla, and Ketchikan. Oil powered generation is still the order of the day in smaller communities in the region. In central Alaska, power production, for Fairbanks and vicinity, and on a regionwide basis, is predominantly by coal-fired steam boiler. The rural communities of the region, those that have power, burn diesel to produce it. The two regions of the state without urban centers, the Southwest and the Arctic/Northwest, are "oil" country. In fact, these areas relied almost exclusively on that fuel for production of power in 1983. The only community with an alternative source of power is Barrow, with natural gas available to it from the South Barrow and East Barrow fields. All other communities rely on imported fuel oils, although Kodiak and Port Lions will switch over to hydroelectric power when the Terror Lake APA project becomes fully operational, as is scheduled for the spring of 1985. Overall, the impact of the three APA dams, if they eliminate all use of diesel power in the four affected communities, will be to reduce the oil powered generation of power to about 10% of the state total and to increase the hydro share to approximately 17%, a change of some three per cent for each category. Southeast's hydro power component will increase to about nine tenths of total production, from the current three quarters. Kodiak's conversion to water generated electricity will transform the Southwest region into one that receives about 40% of its power from hydro. These predictions assume that current community generation ratios, for the fuel utilized in power production, in both regions remain similar otherwise into the future. That assumption is relatively safe, in rural areas in particular. Only a small part of the state's population, perhaps 16% or 17%, currently relies upon diesel oil to fulfill power generation needs. The majority of these Alaskans are rural 13 residents, although a segment of power generation in larger communities, such as Fairbanks and Juneau, paticularly during peak use periods, is oil fueled. These statewide patterns of power generation and thermal energy usage provide the basic building blocks needed to assess the benefits of energy resource utilization to the residents of different regions of the state. Two features stand out: 1) Regions with urban populations have a greater diversity of energy sources available. 2) Rural areas depend primarily upon fuel oil for their energy needs. In ensuing chapters on natural gas, oil, coal and hydro power, we will attempt to define patterns of resource utilization, and the potential for future uses, and to contrast energy prices within the state and on a national basis, as well. Our purpose will be to determine whether any portion of Alaska's population, as a result of its use of the state's energy resources, derives any substantial economic advantage in comparison to other population groups. Footnotes li Alaska Department of Commerce and Economic Development, 1983 Long Term Energy Plan, p. II-24. as ADNR, Historical and Projected Oil and Gas Consumption, January, 1984, p. 5.1. and ADNR, Supplemental Findings, Competitive Royalty Oil Sale, 11/28/84, p. 2. 3. ADNR, op. cit., 11/28/84, p. 2. 4. Katherine Fortney, ADNR, interview, 1/23/85. 14 Chapter II NATURAL GAS PRICES AND CONSUMPTION A) The Basis for Price Comparisons Natural gas is the most widely used fuel, when the combined needs for electric power and thermal energy are considered, in Alaska. In arriving at a determination of whether any segment of the populace or region of the state has enjoyed an economic advantage, when compared to any other group or region, as a result of access to and consumption of natural gas, the initial point of inquiry must be the prices paid for the resource by the groups/regions in question. Such price comparisons can be made in at least two fashions: 1) a comparison of Alaskan prices for natural gas on an interregional basis; 2) a comparison of Alaskan and national natural gas prices. Insofar as natural gas is concerned, little in the way of an interregional comparison can be made. Instate use, excluding that for gas and oil field operations, is restricted to the Cook Inlet area and Barrow. About three thousand people outside Cook Inlet have access to gas for the production of power or heat, while as many as 200,000 people (60,000 residential customers in 1984) there employ gas for those purposes. This pattern of use renders of small consequence any comparative analysis of instate prices. A comparison of instate prices for natural gas to prices for gas in the rest of the nation, which employs the resource extensively for power generation and spaceheating, may be more profitably made. If a significant price differential exists between Alaskan and national gas rates, 15 then there is reason to continue to the next part of the analysis. That step would be the determination whether that price difference constitutes a plus or a minus to Alaskan consumers. (Once that determination has been made, a comparison of the differences in costs on an interregional and "interfuel" basis can be made. This comparison will be attempted following analyses of individual energy resources.) Returning to the gas price determination issue, if a meaningful price differential is discovered, then the investigation warrants continuation to determine whether this differential is a temporary or anomalous phenomenon or one that can be expected to hold true for some time into the future. That will require that natural gas reserves and consumption patterns be the subject of scrutiny. B) Gas Prices The consideration of gas prices involves three distinct elements: 1) The prices charged to utility companies, both gas and electric; 2) The prices charged to consumers, both residential and commercial; 3) Projected prices for some future period. Prices under the first category are available as wellhead prices as well as delivered prices, including pipeline transport charges. The three Alaskan gas utilities, Enstar Natural Gas Company (Enstar), Kenai Utilities and Service Company (KUSCO), and Barrow Utilities and Electric Cooperative (BUEC), own pipeline delivery systems. Wellhead 16 prices will be the basis for comparison herein. Pipeline facilities are not owned by all electric utilities employing natural gas. Chugach Electric Association (CEA; which energizes Anchorage and vicinity and sells power to neighboring utilities) has its major production plant on the site of the principal source its natural gas, the Beluga River field, and thus pays no added charges to a pipeline company. CEA does purchase significant amounts of gas from Enstar and pays a transportation charge for that gas. Anchorage Municipal Light and Power (AMLP) purchases all its gas from Enstar and so pays for transport of that gas. BUEC does not pay such charges since the existing delivery system at Barrow was transferred to the North Slope Borough by its builder, the Bureau of Indian Affairs. So, for electric utilities we will be examining the delivered price of gas for comparision with national prices. There is essentially no difference for our purposes, since the delivered prices constitute what the utility pays for gas at its plant. Table IV lists the average prices per thousand cubic feet (mcf) of natural gas, based on total volumes and total revenues, paid by national utilities and by Alaskan electric utilities from 1979 to the end of 1984. One quickly notes that prices in Barrow have remained constant while others have not. BUEC gas is supplied by the North Slope Borough , at a fixed price. While this gas is included for the sake of completeness, it originates from Federal fields and the volume used for power generation in Barrow was only about one percent of total statewide 1984 consumption. It is the contrast between Cook Inlet and national prices that is instructive. Since 1979, Cook Inlet prices have ranged from 15.8% to 27.8% of national levels. From 1979 to 1982, the gap between the two widened each year. Cook Inlet prices increased substantially in 1983, primarily as a result of new contracts negotiated by Enstar with producers 7, Table IV Natural Gas Prices To Electric Utilities Year Cook Inlet Barrow National 1979 $.50/mcf $.32/mcf $1.80/mcf 1980 51 32 2.28 1981 -58 232 2.91 1982 co 032 3.49 1983 -78 aoe S199) 1984 -78 32 Senses Source: CEA, 1/11/85 & 4/22/85; AMLP, 12/28/84 & 4/2/85; BUEC, 1/4/85; DOE, 3/85. in late 1982. Prices during 1984 held steady in the region, while average national prices continued upward; Cook Inlet prices were only 21% of the national average price. Alaskan electric utilities enjoyed a substantial price advantage for purchases of natural gas over their compatriots in the remainder of the United States. The explanation is quite simple. Major contracts with suppliers of Cook Inlet natural gas were consummated in the middle 1960's and early 1970's when there was scant market for that gas. Accordingly, natural gas producers were willing to sell at quite favorable prices to utilities in order to be able to sell at all. The most significant of these contracts will be considered in some detail later. The next chart tabulates average prices of natural gas to gas utilities for subsequent distribution to end users, mostly for spaceheating purposes. The two patterns apparent in Table IV are also manifested with respect to prices for gas sold to gas utilities. First, the constant price to the Barrow utility is reflected. Secondly, the price to Cook Inlet gas utilities was well below the average price per thousand cubic feet paid by nationwide utilities, as an aggregated whole. The difference was not quite so pronounced in this sector as it was in that for gas sales to 18 Table V Natural Gas Prices To Gas Utilities Year Cook Inlet Barrow National 1979 $.58/mcf $.32/mcf $1.22/mcf 1980 62 32 1.63 1981 75 oan aes 1982 64 32 eae 1983 1.02 sae 2.93 1984 1.04 «aa 2.92 Source: Enstar 1/9/85 & 4/9/85; KUSCO 12/27/84 & 1/16/85; BUEC, 1/4/85; DOE, 3/85. electric utilities (the reason for which will become readily apparent when contracts are scrutinized more closely). The Cook Inlet price ranged between 23.5% and 47.5% of the average national price over the period. Again, Cook Inlet prices, as a percentage of the national average price, steadily declined between 1979 and 1982 and jumped higher significantly in 1983 (presumably as a result of higher contract prices paid by Enstar). In 1984, the two appeared to grow closer together, but only to an insignificant amount, eliminating only about two percent of the differential between the two averages. Exactly what do these low cost supplies of natural gas mean for the end user, the Cook Inlet consumer of natural gas thermal heat? In the table on the following page are listed the average rates per thousand cubic feet for both residential and commercial users of natural _ gas, as purchased from gas utilities. Table VI does not include gas used by industrial facilities, such as the Phillips-Marathon liquified natural gas plant or the Union Chemical plant (these two burn about 62% of net production, excluding field operations) which make purchases directly from producers. The commercial category combines the two classifications of customers, small and large, established by Enstar and KUSCO. aS) Again rates are based upon total sales and total revenues for each class. Average costs for Barrow are not included in this table because the information was not available under the recording format used by BUEC. As can be seen, Cook Inlet consumer prices are considerably lower than prices on a nationwide basis (this latter figure, by the way includes Cook Inlet consumption, but this is such a small portion of national consumption that it alters that average but imperceptibly). The ratio of Cook Inlet rates to national rates has fallen from a peak of 57.7% in 1979 to Table VI Cost of Gas to Residential and Commercial Consumers Cook Inlet Nat'l Cook Inlet Nat'l Year Resident'1l Resident'1 Commerc'1 Commerc'1 1979 $1.72/mcf $2.98/mcf $1.33/mcf $2.73/mcf 1980 1.74 3.68 Wa 3i7, 339 1981 1.92 4.29 ee 4.00 1982 1.84 Sips, 1.46 4.82 1983 Zoo) 5.99 1.94 5.59) 1984 2.63 6.06 Zee 5.69% * estimate. Sources: Enstar, 1/9/85 & 4/9/85; KUSCO, 12/27/84 & 1/16/85; DOE, 3/85, 1/85 & 5/85. 37.3% in 1984 for residential users and from 48.7% to 36.2% for commercial users of natural gas. During the period examined, the price per thousand cubic feet, for residential users, increased by 52.9% in the Cook Inlet, compared to 103.4 per cent on a countrywide basis. On the commercial side of the ledger, Cook Inlet prices climbed 59.4%, while national rates increased by 104.9%. This is a substantial difference, both for price level and annual price movement. Price changes in both consumer classifications were similar 20 as concerned direction of movement within both geographic categories, but the changes were not at all similar on a category to category basis. These patterns mirror those found in our review of prices to gas utilities. Comparisons of prices to electric power consumers are somewhat more difficult to make. One difficulty is in determining the portion of electric power rates to consumers which can be attributed to gas prices paid by utilities. That portion varies widely within Alaska. In Barrow, BUEC calculated the portion of rates required to cover gas costs to be 6.7%, while AMLP and CEA stated that fuel costs represented about 49% and 15%, respectively, of the cost of power.+ The dollar costs for gas to each of these utilities differ substantially, also. We have no such breakouts of fuel costs to nationwide electric utilities for any type of fuel, much less for natural gas. Additionally, national information available does not include the type of information on commercial rates required for our purposes, i.e. a national average rate for commercial customers. The national averages for electric power rates utilized herein do not allow for any differentiation concerning the type of fuel used. Lastly, natural gas is rarely used as a base generation fuel outside of Alaska. Comparisons are somewhat suspect as a result. Table VII, recalling these shortcomings, contrasts Alaskan and national power prices. Average monthly consumption per residential customer of the Cook Inlet utilities was 895 kilowatt hours (KWH) in 1983. In Barrow, average monthly consumption was 445 KWH. On the one hand, Cook Inlet electric power rates were lower than the national average by anywhere from 10% in 1983 to 60% in 1980, while Barrow rates were higher, by 99% in 1980 and 60% in 1983. The validity of these comparisons are limited, at best, without the appropriate nationwide information, which would allow a real 21 Table VII Residential Electric Power Rates ($/Kwh) Year Cook Inlet National* Barrow National 1980 $.0368 $.0587 $.1298 $.0652 1981 -0419 - 0668 -1266 0739 1982 -0524 -0703 -1254 -0767 1983 -0665 -0730 -1283 -0804 * Average rate for 1/1 of following year for 750 kwh/mon. # Average rate for 1/1 of following year for 500 kwh/mon. Average rates in Alaska are for the entire year. Source: Alaska Power Administration, 1981 to 1984; DOE, 12/84; BUEC, 1/28/85. likening of end-user rates for natural gas fueled electric power. Relatively accurate information is available for comparisons of costs of gas to heating and power utilities in Alaska and nationally. Information to make a comparison of the costs of natural gas for thermal uses by residential and commercial customers in the Cook Inlet area and the nation as a whole also exists. In the next section, we will zero in on the relative price advantages or disadvantages that consumption of Alaska's natural gas has afforded to Alaskans with have access to those resources. C) Economic Benefits of Natural Gas Use The focus of analysis now will shift to an examination of the situation with regard to natural gas use by individual consumers. To restate the question at hand: Have any Alaskan consumers enjoyed an economic bonus as a consequence of the use of natural gas, as compared to 22 natural gas users nationwide or have any suffered an economic penalty as a result of the use of natural gas in relation to national users? In the most basic terms, did Alaskans pay more or less to use this energy resource than did comparable users across the United States? As is demonstrated in Table VI, Cook Inlet natural gas spaceheating consumers have _ paid substantially less than have nationwide users. However, the tabulation of costs per thousand cubic feet of gas has limited real meaning, either for the policymaker or the individual citizen. There are two alternative means of arriving at the aimed for measurements. Simply, in one case, we can look at the differences in prices paid by the individual consumer. In the other case, we can examine the differences in costs to gas utilities for gas purchases. To begin, we will examine consumer prices. In the ensuing table, two comparisons clarify what this price differential has meant to Alaskan consumers. First the total revenues to the two Cook Inlet gas utilities from residential and commercial sales are listed. What the revenues would have been had Cook Inlet prices been equal to national prices follow. This contrast suggests what the total benefit to customers of Enstar and KUSCO, as a result of cheaply priced natural gas, has been, from 1979 to 1984. Secondly, the comparison between the average monthly gas bill for the two utilities' customers at actual prices and what it would have been at national average prices is made. Each of these comparisons is based upon average annual revenues per customer. This table, Table VIII, is most instructive, giving a more concrete idea of just what the magnitude of the economic advantage enjoyed by Cook Inlet natural gas spaceheating consumers has been, both on an individual and an aggregate footing. On a collective basis, Cook Inlet residential gas 23 consumers have paid between $9 million and $37 million less per year than would have been paid by their hypothetical "average" counterparts elsewhere in the country for the same volume of consumption. For the six year period studied, prices in the Cook Inlet equal to those charged nationally would have generated $261 million, compared to actual revenues collected of $111 million. This represents an effective economic benefit of about $150 million to Cook Inlet residential consumers as a result of their access to this Alaskan energy resource. For the individual natural gas customer, the monthly savings were on the order of $20 to $58. If this same consumer had been paying national rates for the comparable amounts of natural gas, the average monthly bill would have been between 71% and 181% higher over the period. The second part of Table VIII contains the same information on the commercial customers' side of the balance sheet. The conclusions that may be drawn are similar. The sum savings due to the availability of inexpensive Cook Inlet gas to commercial enterprises was about $142 million under our scenario. Monthly bills naturally showed a_ substantial difference also, ranging from just under half to about one third of what they would have been at national prices. Combined, the two classes payed about $292 million less for natural gas than they would have if rates had been comparable to those nationwide. It hardly need be emphasized, however, that Cook Inlet consumers had no compelling reason to pay national prices, nor was there any justification for gas utilities to charge prices comparable to national prices during this time. The market conditions in the area were and are the fundamental force establishing the price of natural gas. Not, of course, the sole force, but far and away the most influential one. The expected future course of those conditions will be the subject in a later section of this chapter. 24 Table VIII Gas Utility Revenues (000s of $) And Monthly Consumer Bills Residential Actual Revenue At Actual Bill At ea Revenue Nat'l Rates Bil Nat'l Rates 1979 $11,858 $20,566 $28/mon $48/mon 1980 13,596 28,586 30 63 1981 15,273 34,116 30 67 1982 18,398 51,634 32 90 1983 24,008 61,144 37. 94 1984 28,335 65,003 40 93 Total 111,378 261,049 Commercial 1979 $ 9,516 $ 19,474 $145 $298 1980 10,301 25,578 150 372 1981 i S25 345,35 167 439 1982 13, 180 43,598 170 562 1983 17,244 ‘ 49,807 194 584 1984 27s $3,851 179 474 Total 83,201 225,623 GRAND TOTAL 194,579 486,672 Source: Enstar, 1/9/85 & 4/9/85; KUSCO, 12/27/84 & 1/16/85; DOE, 5/85 & 1/85. While this hypothetical exercise suggests the likely impact of past and present market conditions on Cook Inlet natural gas prices, it, admittedly, is not a complete analysis. Our procedure does not make any allowances for two elements of influence. The first of these is the difference in the cost of living and incomes between Alaska and the rest of the country. While costs in Anchorage, in particular, have been recently moving closer to national costs, Alaskan living is still more expensive, as a long list of consumer price indices have shown. Gas is cheaper, though. Incomes are lower outside Alaska, but gas is more costly. The effect, 25 thus is to render, as a percentage of disposable income, gas still more expensive nationally and less expensive in Alaska. Second, these cost differentials have existed for more than the six year span investigated herein. Since at least 1965, electric power consumers have benefitted from a cheap fuel source, while gas users have likewise done so since the early 1970's. There is a second perspective from which this subject may be viewed. The revenue question may be approached from the angle of gas purchases made by utilities, both electric and gas. In this case, we will attempt to make the same correlation between Alaskan prices and national prices that has previously been made; namely, what would utilities in the Cook Inlet or Barrow have been billed for gas if national average prices had prevailed? Table IX indicates those differences on an annual basis. This method also reveals some interesting comparisons. In the Cook Inlet some significant savings to utilities are demonstrated. Annual price differences resulted in gas costs that ranged from 16% to 28% of what would have been the annual costs had electric utilities been faced with national average prices for natural gas (this assertion obviously ignores the likelihood that had utilities had to pay such prices, they would have been considering and perhaps employing an alternative generation fuel). The hypothetical savings over the period could have amounted to over $427 million. Gas utilities paid only from 23% to 47% annually of what national prices would have required. Savings over the time span would have been in the area of $319,000,000. In Barrow, the advantages afforded by inexpensive natural gas supplies would have been considerably less due to the small market there. Total economic benefits to the utility 26 Table Ix Cost of Utility Gas Purchases (000's of $) Electric Gas Actual Gas Cost At Actual Gas Cost At Yea Gas Cost Nat'l Prices Gas Cost Nat'l Prices Cook Inlet 1979 $14,096 $50,665 SE7235 $37,622 1980 14,810 65,603 20,241 53,149 1981 16,985 84,587 24,139 69,654 1982 17,058 108,149 23,425 99,555 1983 24,746 13, G30 38,502 110,608 1984 24,467 17/100 40,331 112,840 Total 112,162 $39,164 164,374 483,418 Barrow# 1979 Sin7.6 $ 424 $ 88 $ 330 1980 84 592 LEO S52 1981 112 1, 007 119 793 1982 : i381 1,625 115 1,238 1983 161 Lyd aD 114 1,030 1984 156 1,861 143 L302: Total 741 7,289 689 5,245 # Excludes federal agency customers. Source: Enstar, 1/9/84 & 4/9/85; KUSCO, 12/27/84 & 1/16/85; BUEC, 1/4/84; CEA, 1/11/85 & 4/22/85; AMLP, 12/28/84 & 4/2/85; DOE, 12/84, 1/85, & 3/85. there are estimated to have been on the order of $4.5 million for thermal energy gas and $6.5 million for power generation gas. Not surprisingly, we have developed figures via our two methods that do not precisely agree. The only two figures that are strictly comparable are those developed for gas consumption by individual consumers (Table VIII) and gas purchases by natural gas utilities in the Cook Inlet (Table IX). Both statistics should represent the approximate equivalent of the statistics for the average cost _of gas at 27 national prices. Differences in gas costs for utility purchases should translate relatively directly into cost changes to individual and aggregated consumers. Gas tariffs approved by the Alaska Public Utilities Commission for Enstar, KUSCO, and BUEC require that base gas prices to customers be founded on the actual cost of gas to the utility. Our calculations for probable costs to Cook Inlet consumers based on national average rates produced a total economic benefit figure of approximately $292,100,000. The benefit resulting from the actual costs for Cook Inlet utility gas purchases compared to costs at national gas prices was $319,500,000. The difference between these two sums is just about nine percent. That seems relatively close for estimates of this nature, considering that we did not delve into greater detail. We must admit that we cannot, at this point, identify the components of this difference. It is possible that our estimate of savings to consumers is less than our estimate of savings to utilities simply as a consequence of the fact that a difference in gas prices does not cause a difference in other costs that utilities pass on to consumers. In our construct, one portion of costs, fuel, is changing, while others, for example, distribution and administration, remain fixed. What we can reasonably say is that the economic benefit to Cook Inlet natural gas users, in relation to national users, has been approximately $292.1 million to $319.5 million over the period from 1979 to 1984. We do not, unfortunately, have figures of this sort with which we can examine the cost of gas to Barrow thermal customers or the costs to Barrow and Cook Inlet electric power consumers. We must simply examine the figures we have developed and accept them as rough estimates. It is more than likely that there is a margin for error associated with these calculations also. However, all data are utilities' costs, so, if our suppposition concerning the repercussions 28 of changing but a portion of fixed costs is valid, we must treat these figures as the maximum possible advantage enjoyed by local resource users. We must further assume that the benefits accruing to end-users could well have been somewhat less than the savings to utilities. Benefits to Barrow residents using gas for thermal heating were about $4.5 million over six years, at maximum. Electric customers in Barrow have enjoyed up to a $6.5 million advantage. Cook Inlet electricity users have benefitted to the tune of perhaps as much as $413.7 million over the study period. While these statistics cannot be accepted as a precise calculation of the "windfall" to these Alaskans (such probably cannot be made with currently available information) they serve as reliable limits on the level of benefit derived from the favorable natural gas pricing situation found in the Cook Inlet and at Barrow at the present time. Insofar as this one of Alaska's energy resources is concerned, a specific segment of the state's population is without doubt party to a happy circumstance that has greatly reduced the prices it must pay for spaceheating and electric energy. Other parts of the state do not have pleasure of such profit simply because they do not have access to the resource, which is, essentially, a demographic and geologic coincidence. D) Future Gas Prices If Alaskan natural gas consumers are the recipients of an economic boon, compared to other users of natural gas nationally, a new question arises: Is this economic advantage a temporary phenomenon or one that will persevere for some time to come? 29 In an effort to answer this question, three separate areas of interest must be examined. Those are: 1) Existing contracts between energy utilities and natural gas producers. 2) Projections of future prices of natural gas in Alaska and the United States as a whole. 3) Alaskan gas reserves and projected consumption. A brief description of the salient features of the major contracts between Cook Inlet gas producers and utilities follows. Recall that AMLP purchases its gas from Enstar. It should also be noted here that Enstar is in the process of acquiring Kenai Utilities Service Company, so, there will, within the very near future, be only two utilities, Enstar and CEA, directly purchasing Cook Inlet gas from producers. - Chugach Electric Association - * Field: Beluga River * Producers: Standard Oil of CA, Shell Oil, and Chevron Oil. * Contract Duration: 5/14/65 (revised several times) to 1/1/98 or until contracted volume is depleted, whichever iis) first. * Price: $.152/mcf originally, now at $.2103/mcf (1984), does not include severance tax. * Volume: 60,000 mcf/day or 21.9 billion cubic feet (bcf) annually, up to a total of 373 bcf. Notes: CEA has obtained additional gas from this field under separate contracts. Source of 79.6% of 1984 gas purchases (remainder purchased from Enstar). 30 - Enstar Natural Gas Company - * Field: Kenai * Producers: Union Oil and Marathon Oil. * Contract Duration: 1/1/75 to 12/31/92, or volume fulfillment, whichever first. * Price: Original $.195, now $.617 (1984), excluding severance tax. * Gas Volume: 140,000 - 160,000 mcf/day, up to 550 bcf. Note: Source of 72.6% of 1984 gas purchases. * Field: Beaver Creek * Producer: Marathon Oil * Contract Duration: 12/16/82 - 12/31/97, or until volume fulfillment, whichever comes first. * Price: $2.32/mcf originally, now $2.147/mcf (1984), excluding tax. * Volume: 250 bcf, at varying yearly amounts. Notes: Source of 24.0% of 1984 gas purchases. Enstar also has contracts for Lewis River and Beluga River gas, supplying about three percent of its 1984 gas. It is apparent from these contract outlines why natural gas prices in Alaska are so much lower than national prices. Utilities here are paying less for their gas purchases. The two largest volume contracts were signed at a time when there was little competition for massive volumes of gas, most of it discovered during the process of oil exploration. The most recent contract, Enstar's pact for Beaver Creek gas, has a much higher price than do earlier contracts (although it is still 27.5% below the average price paid by national utilities in 1984). 32 In Barrow, natural gas has been supplied from federally owned reserves at a price that has not changed for a decade. The North Slope Borough, which operates the Barrow gas fields, has fixed the price for gas from the fields at $.324/mcf.? Again, this price is well below that paid by utilities outside Alaska. What does the future hold for natural gas prices in Alaska? There are two elements to the answer to this question, one of which can be stated with some precision, the other of which is subject to the usual doubts and vagaries that afflict any attempt to make specific predictions of future events and their impact upon present reality. The former element, the one to which we can fit relatively accurate calipers, is the price of natural gas under existing contracts. Only in Barrow is there a document governing gas price which calls for a fixed price as it stands now. All of the other documents have clauses calling for changes in prices. Some, like CEA's contract with Beluga River producers, include an mechanism which specifies price change, independent of external influence. Others, the Enstar contracts with Beaver Creek, Lewis River, and Beluga River producers, contain clauses hinging gas price changes on price changes in No. 2 fuel oil at Tesoro's Nikiski refinery. The first and third of these contracts also include a deliverability charge, based on the producers’ maintenance of the ability to deliver daily quantities of gas in excess of the contracted daily average. Enstar's contract with Union and Marathon for Kenai field gas calls for prices, beginning in 1986, to be contingent on the price of applicable third party sales by those producers. So, while we have said that the price changes mandated by contract can be precisely calculated, we meant that only in a relative sense, in comparison with price changes triggered by other factors. Elements of each contract call for the educated guesswork inherent in all economic projection. 32 Table X lists scheduled changes in prices for the five major Cook Inlet contracts. It should be noted that contracts may be renegotiated and that inflation assumptions and oil price change assumptions are not impervious to change nor are particular scenarios universally accepted by authorities in the field. Some of the assumptions and methodology employed to arrive at the data displayed in this table should be made explicit. We based our calculations upon contractual price escalators and charges, but external factors such as inflation trends and changes in No. 2 fuel oil prices at Tesoro's Nikiski refinery, which key changes in each of Enstar's contracts with the exception of that for Kenai field gas, were selected independently. For the former, we utilized inflation projections supplied by the Alaska Department of Revenue (ADOR), which the department utilizes in predicting oil prices in constant dollars. For changes in the nominal price of Tesoro's No. 2 fuel oil, in the absence of specific projections, we utilized ADOR projections of changes in world crude oil prices as a proxy. Since petroleum fuel markets are very competitive at this time and likely to remain so, it is probable that specific petroleum products will respond fairly directly to changes in world crude prices. CEA's contract calls for specific prices, developed through a fairly simple mechanism, which remain constant in nominal terms at $.27/mcf beginning in 1987. Table X indicates the eroding effect of inflation on that price. Enstar's Kenai contract price drops precipitously on 1/1/86 as a deliverability charge of about $.35/mcf is phased out and the price is set at the greater of $.27/mcf or the average of applicable third party sales by the producers. There have been, to this point, no such third party sales. Enstar does expect that negotiations with producers may alter the contractual gas price.? Again the present price will be the victim of inflation and will be falling in terms of constant 33 Table X Contract Prices for Cook Inlet Natural Gas (1985 $/mcf excluding taxes) CEA Enstar* Year Beluga R. Kenai Beaver Ck. Beluga R. Lewis R. 1985 S221 $.62 $2.23 $2.32 $1.76 1986 oad -26 aiese 2.22 1.67 1987 eo wee 2.22 Zep 1.60 1988 es Or 3e! 2.19 2.06 Le ror7 1989 wee «22 Ze 6 2.06 1.57 1990 seu ole 2.19 2.08 1.58 1991 -20 -20 gewe 2.08 1.58 1992 19 19 2.22 2.08 LoS 1993 -18 ci ane Solas 1.60 1994 Spl, - 2.24 2.14 1.62 1995 Lo = Zeal 2.14 1.62 1996 et = aera, 7a 1.64 1997 14 - Zes2 2.19 1.66 1998 es - - 2.22 1.69 1999 - - - 2.27 sey 3. * Kenai field prices as of 1/1/86 may be altered by negotiations between producers and Enstar. Other contract prices based on changes in oil prices and inflation trends supplied by Alaska Department of Revenue. Beaver Creek (beginning in 1986) and Beluga River prices assume $.35 deliverability charge is incurred each year. Source: CEA and Enstar contracts; ADOR, 1/17/85. dollars. The other three Enstar contracts establish base prices which are adjusted by changes in fuel oil prices as noted. Applicable deliverability charges are also subject to the same adjustments. As the table indicates, projections of price changes and inflation suggest that gas prices from the Beaver Creek, Beluga River, and Lewis River fields will fall, in terms of constant dollars, for several years before climbing again in the next decade. The Beaver Creek price does show a significant increase in 1986, the result of the addition of the deliverability charge to the base price. 34 Since the vast majority of gas used by Cook Inlet utilities is, at present, extracted from the Beluga River, Kenai, and Beaver Creek fields, it is apparent, given what we know today, that users of that gas will continue to enjoy quite favorable overall (blended) prices at least until 1992 when the Kenai Field contract expires. That field supplied about 50% of the 53 bef of natural gas used in the Cook Inlet for thermal and power generation purposes in 1984. The continuation of low price levels assumes that adequate volumes of gas remain available. That matter will be addressed shortly, but first the relationship of the price projections in Table X to other price prognostications, national and Alaskan, should be established. Table XI offers a.U. S. Department of Energy national price outlook and a variety of forecasts of the trends in prices of natural gas for utilities, both electric and natural gas, in Alaska. All of these forecasts are somewhat suspect in this era of constant and significant declines in world petroleum prices. This suspicion arises from the fact that all of these predictions base their forecast of Cook Inlet natural gas prices on changes in world oil prices. Without launching into a detailed discussion of the wisdom of this convention, particularly in Alaska's case,“ suffice it to say, as oil prices continue to sag as of this writing, that predictions based on those prices become outdated almost as soon as they are seen in the crystal balls of the soothsayers. All forecasts are buffeted by an infinity of variables, some of which can foreseen, in kind and degree, and others of which cannot, even by the sagest of analysts. A cautionary note must precede consideration of the information in Table XI. Be aware that the constant dollars in this table (which, unfortunately, as a consequence of the diversity of the materials from which it was aggregated, are 35 not uniform among themselves) are not the same as those used in Table X, which are present day (1985) dollars. The effect of this discrepancy is to require that we, when comparing the two forecasts, make the mental note that 1982 dollars in Table XI are worth more (perhaps 10% or slightly more, based on inflation over the last three years) than the 1985 dollars of Table X. Naturally, 1983 and 1984 dollars are somewhere in between 1982 and 1985 dollars in value. What that means is that the prices we have listed as contractually based would actually be somewhat lower if expressed in terms of the constant dollars used for general price predictions (Table XI). Keeping that caveat firmly in mind, it can be seen that contracted prices for gas deliverable to Cook Inlet utilities will probably be lower than national prices for the next decade. If forecasts of Table xXI Future Prices Of Natural Gas To Utilities (1983 $/mcf) National Cook Inlet Year DOE/EIA@ APA Kentco Battelle* Acres# 1985 Se Ze) -86 DEL 1.79-2.22 1986 soe ex} 2.07-2.51 1987 Sela, -66 1.99=-2.51 1988 3.94 -70 1.97=-3.11 1989 4.16 -78 1.95-3.82 1990 4.50 2.80 -90 1.83-3.82 1993 1.65-4.17 1995 6.10 Scale rela 1.59-4.43 1996 SnD) 1.5774.56 2000 S75 4.91 149-5. 13 2005 4.94 4.39 1.38-6.09 @ 1984 dollars * 1982 dollars # Range based on several forecasts. Source: DOE, 1/85; APA, 8/84; Kentco, 1/84; Battelle, 3/82; Acres, 2/83. 36 prices based upon the need for gas beyond that which is presently contracted for are examined, it still appears as though Cook Inlet prices will be significantly below national prices into the next century. The economic advantage enjoyed by users of that gas will continue, at ast one ossibly two decades, assuming that there is su ient gas for the utili s_to burn. E) Gas Reserves and Future Consumption Much of the debate swirling about the proposal to build the Susitna hydropower project over the last several years has revolved around this question: How much gas is there and how long will it suffice to serve the various needs of Cook Inlet users? To find enlightenment, we will consider two subjects; 1) the present status of Cook Inlet reserves of natural gas and 2) the projected consumption of that gas by all users, including utilities. The first topic includes two items, proven reserves and indicated reserves. The first part of Table XII lists proven reserves of Cook Inlet natural gas as of January 1, 1985. The second contains a short inventory of estimates of indicated gas, which consists of proven and unproven reserves. A few notes concerning the table are in order. Reserves listed in the second part are not necessarily economically recoverable in full. The eight largest gas fields are listed separately in the first part, with others grouped. The Swanson River field has been and continues to be injected with natural gas from the Kenai field to aid in petroleum recovery, so in reality the Kenai field is not being depleted quite so quickly as it might appear. Associated gas is gas produced in conjunction with 37 Table XII Cook Inlet Gas Production and Reserves (billions of cubic feet - bcf) T1785 1984 Reserves/ 1/1/84 Field Reserves Production Production Reserves Beaver Ck. 230 9.2 25 231 Beluga R. 800 19.9 40 778 Cannery L. 300 0.0 - - Ivan/Lewis 600 0-7. 857 - Kenai 850 eS. 8 845 McArt./Trad. 650 9.9 66 119 N. Cook 650 47.0 14 859 Swanson R. 260 0.0 - 260 Others 63 0.7 90 72 Assoc. Gas 130.7 - - Total 4,463 329.9 - 3,264 Reinjected (93.7) - - Net 4,463 236ce 19 3,264 Indicated Reserves in Cook Inlet ADNR (1983) = 3,360 ADNR (undated)- 3,370 to 13,350* USGS (1981) - 3,000 to 12,000 ISER (1982) - 5,000 to 10,000 * Average to maximum simulated value. Source: AOGCC, 3/84 to 2/85; ISER, 11/4/82; Acres, 2/83; ADNR, 1/85 & undated draft; APA, 2/27/84. oil. For field life at current production rates, refer to the column headed "Reserves/Production". The r/p ratio is the expected length of life of a field. For the entire Cook Inlet proven reserves pool, the r/p ratio is about nineteen years, under present conditions. It varies from field to field, with the two major fields supplying utilities, Beluga River and Kenai, pretty much at extreme opposing ends of the 38 spectrum of expected life. Although the reserves to production ratio, at yearend 1984, suggests that the Kenai field will be depleted in 1991 or 1992, which is about the same time at which Enstar's contract for gas from the field expires, it should not be assumed that Enstar will lose three quarters of its gas supply. Note that the pool of proven reserves, according to ADNR's estimate, has increased in the last year by about 1,200 bef. Although much of the increase was due to new fields being added to the economically recoverable list, several fields are now estimated to contain more gas than previously thought. As gas prices rise and recovery techniques improve, it is likely that the level of economically recoverable will continue to rise, at least for a time. Reserve estimation is a fluid and continuous process. The following chart inventories gas quantities contracted to Enstar and CEA. Both utilities are likely to have adequate supplies of gas at least through 1992. 1984 consumption was approximately 52.7 bcf. 57.1 ber —_is contractually obligated for calendar year 1985 and that total increases until 1992. Depending upon which projection, if any, one elects to accept as valid, contracted gas volumes could be sufficient for utility needs to 1992 and possible through 1995. The three most recent divinations peg the year as 1993. Utilities thus have ample time to negotiate for supplements to their current reserves. As of 1984, about 1.9 tcf of the proven reserves in the region®, or approximately 43% of the latest estimate of recoverable reserves, were committed to buyers. Utilities consumed about a quarter of net 1984 production, it seems likely they will be able to obtain new resources after 1993. Given that these contracts ensure a secure and adequate supply of natural gas, at prices well below the national averages, until 1992 in the most pessimistic outlook, we are 39 Table XIII Cook Inlet Natural Gas Contract Volumes and Consumption (utilities - bcf) Contracted Volumes Projected Consumption Year Enstar CEA Total _Bat'le Kentco APA Acres _ADNR 1985 35.2 2169) S57 a. 60.7 64.1 55.9 Vas) 55.7 1986 45.2 21.9 67.1 62.5 67.9 56.9 75.4 58.8 1987 50.2 21.9 Vail 63.3 70.7 58.9 78.3 595 1988 Sve 21.9 Vaio 61.3 68.3 56.9 Seo) 60.5 1989 57.2 21.9 79k 62.7 71.0 59.0 78.8 6253 1990 59.2 21.9 Sioa: 64.2 73.8 60.9 81.6 64.1 1991 65.2 21.9 Sie 67.4 75.9 62.5 83.9 66.1 1992 65.2 21.9 Sick: 70.2 78.1 64.2 86.1 67.6 1993 47.0 21.9 68.9 74.4 80.3 67-0 88.5 64.9 1994 47.0 13.0 60.0 77.8 82.6 68.9 90.9 67755 1995 47.0 47.0 81.3 60.2 70.9 68.6 69.5 1996 3760) ja ofa) 84.6 61.8 Dai 70.3 70.6 1997 27.0 27.0 88.2 63.5 7 Sra) i312) 72.8 1998 L550 5 )10) 91.9 65.2 76.7 74.1 W318 1999 10.0 10.0 95.7 66.9 78.5 Dr) 76.8 2000 10.0 10.0 99.7 68.7 - 80.5 77.8 Total 662.6 210.0 872.7 1205.7 1118.9 1066.1 1250.3 990.8 Note: current contracts. Source: Contracted volumes represent the maximum amounts per Acres and Kentco projections assume that Susitna hydro project on line in 1995; Lake hydro on line in 1993. Enstar & CEA contracts; Battelle, 3/82; Kentco, ADNR assumes Bradley 1/84; APA, 8/84; Acres, 2/83; ADNR, 1/85. safe in stating that the benefits accruing to users of that gas, which we have identified as in the hundreds of millions of dollars over the period 1979 through 1984, are likely to continue until that time. All extant recent forecasts of Cook Inlet gas prices affirm that they will continue to be below the national average well into the future. We close this discussion by acknowledging that very little mention of the situation in Barrow has been made for some time. While it has not been our intent to simply ignore the 40 Barrow market, this silence has been imposed by the somewhat sketchy information available for analysis. The kind of studies of Railbelt energy resources prompted by the Susitna debate have not been conducted for other regions. One evaluation of the Barrow market concluded that demand could begin to outstrip supply there as soon as the end of 1985 with possible depletion of existing tapped resources during 1991. The capacity to expand the reserves available to the community does exist, but the impact on costs to the utility or end-users of new production is not clearly established. Capital costs would be great, estimated at as much as $277 million. ® How this might impact rates is not discussed. Would the borough be able to maintain its fixed price on gas? In the absence of more precise information, it is difficult to gauge future market conditions. At least for a time, Barrow will continue to enjoy a relative advantage as a result of favorable gas prices. F) The People's Gas: Volume and Revaluations A major focus of this document is on State owned resources. The bulk the proven gas reserves in the State are the property of the people of the Alaska. A one eighth share of reserves in production are dedicated as royalties to the State, either in-kind or in-value. The bulk of recoverable gas is in North Slope formations, most of it, at this time, found on State land. Some 33,700 to 38,600 bcf of natural gas reserves are there. The State royalty share is on the order of 4,200 to 4,800 bet.” None of this gas is presently available for other than field operations. The remainder of recoverable reserves are found in the Cook Inlet (see previous section). The people own a significant share of this supply also, 2,700 bef, about 61%. 41 The royalty cut is 338 bet.® With annual consumption for power and thermal requirements only in excess of 50 bcf, the royalty share, the disposition of which the State controls directly, would fulfill needs for only six years. Gas produced by lessees of State owned Cook Inlet tracts will be supplying these and other needs for decades to come. Net production in the basin is approximately 200 bcf annually.” Recent developments concerning the valuation of State royalties derived from Cook Inlet natural gas will cause some disturbance to the situation described in this chapter. Effective April 15, 1985, ADNR has declared, royalties will be assessed based on the market value of the gas in question. The department has estimated that this reassessment will add $8 million to the State's coffers annually?®, thus benefitting all Alaskans. Prior to ADNR's action, royalties had been based upon the contract price of the resource. The contract prices for much of Cook Inlet gas remains quite low, as previously illustrated. Based upon recent contracts between producers and purchasers, ADNR has determined that the market value of gas in the Beluga and Kenai fields is $2.055/mcf. This compares to present contract prices in the $0.21 and $0.62 range, respectively. As a result of the pattern of State ownership in the two fields, only about two percent of Enstar's purchases from the Kenai field would be subject to the higher price and about 7.5% of Chugach Electric's Beluga purchases would climb to the $2.055/mcf valuation for royalties. CEA and Enstar would, together, see an increase in gas purchase costs in the vicinity of $3.5 million per annum, based upon 1984 data. The APUC approved rate structure of these utilities would allow this increase to be passed through to end consumers. Enstar's blended cost per mcf would increase about three cents and CEA's thirteen uy cents. These cost hikes would alter only very slightly 42 the present price differentials between Alaskan natural gas and national gas, as calculated in Tables IV and V. This would do little to reduce the vast gap between market costs in Cook Inlet and elsewhere and the large economic benefits accruing to Cook Inlet consumers (see Tables VIII and IX). The al te of the conclusions to be drawn from our an. sis wi emain unchanged by the royalty revaluation. G) The Question of Equity Natural gas utilities and their customers have been and continue to be the beneficiaries of a substantial economic advantage relative to other Alaskans as a consequence of their proximity to the state's most inexpensive energy resource. The Alaska Constitution (Article VII, Section 2) holds that such energy resources are the property of all citizens of the state, yet only a segment of the population receives any direct benefit from this particular resource. The State of Alaska does receive severance taxes and royalties due from gas production, and income and property taxes from producing firms, in addition to bonus and rental payments. These provide a significant portion of General Fund revenues and Permanent Fund contributions, both employed for the general benefit of all Alaskans. Is the revenue derived from Cook Inlet natural gas comparable to the effective benefits that users of that gas enjoy? The latest estimates of FY 1985 royalties and severance taxes (the statewide proceeds of which, for oil and gas, totaled about 72% of all FY 84 unrestricted revenues) attributable to Cook Inlet gas production were $15.10 million and $11.44 million, respectively, for a total of $25.54 million.1? year 1984 on Cook Inlet gas production and distribution Additionally, property taxes in calendar 43 properties tallied up to approximately 1.89 million dollars, - Only about 16% of the State's royalty share of gas is destined for power or heating purposes, as a result of the mixed federal-State ownership of the Beluga Field (60.44% State owned) and the 14 as nearly as can be determined. numerous uses to which Kenai Field gas is put. (Beaver Creek and the Barrow fields are federally owned.) Total usage for heating and power is about 26% of production. As a result, about seven million dollars should flow into the State treasury during FY 85, compared to the savings of $160 million in 1984 by Cook Inlet utilities (Table IX). State royalty gas amounted to only 7.6% of proven Cook Inlet an Although royalties and production taxes will increase as consumption increases and reserves as of January 1, 1985. prices rise, revenues in the foreseeable future cannot be expected to approach the level of benefit realized by gas consumers, as shown in Table XIV. Although by 1995, royalties and severance taxes on gas used for power generation and thermal energy should grow to about $27 million, the differential between Alaskan prices and national prices should be producing an advantage of about $190,000,000 to Alaskans. This includes the impact of the Table XIV Cook Inlet Natural Gas Revenues and Costs (Gas sold to Utilities - millions 1984 $) Fiscal State Additional Cost Year Revenues* At National Prices 1985 LO.20 158.19 1990 16.37 188.45 1995 22S 191.82 2000 44.65 NA * Severance taxes and royalties only. Source: ADOR, 3/85; RRA, 4/11/85; Table XI & XIII. 44 recent ADNR royalty revaluation. This table should not be interpreted as a precise prediction of future revenues and cost differentials. Using data contained in Tables XI and XIII, an estimate of the future economic benefit of low gas prices to Cook Inlet utilities was developed. A number of assumptions and adjustments to the data were necessary to achieve that end. Dollars from other than 1984 base years were adjusted to that level. Batelle's 1982 forecast (Table XI) of the magnitude of gas price changes was utilized since it was the only one for the period which included all gas produced, not just that covered by "new" contracts. A five percent increase in the 1984 blended price of gas was assumed for the estimate of the 1985 price for Cook Inlet gas. ADNR's prognostication of consumption (Table XIII), the latest available, was employed. ADOR forecasts of gas revenues were adjusted by the portion of gas consumed for the relevant purposes and that component of total production was assumed to remain constant over the period. Finally, revenues other than royalties and severance taxes were excluded (these are relatively minor in comparison). While the methodology is relatively simple, the magnitude of the difference between revenues accruing to the State and the effective economic benefit accruing to Cook Inlet gas consumers is so great, that precision becomes a moot point. The disparity is well in excess of one hundred million dollars annually. It is all too obvious that the cost savings enjoyed by Alaskan natural gas users compared to national users is far and away beyond the general benefit accruing to all citizens of the state as a result of the revenues due the State pursuant to its ownership of natural gas resources. There appears to be legitimate question whether benefits derived from the use of energy resources, which, in theory, belong (at least its bulk) to all Alaskans, have been, or will be in the future, distributed equitably to all residents across the state. 45 9. 10. Die 12. 13. 14. 15. Footnotes BUEC, letter to Rural Research Agency, 1/4/85; AMLP, letter to Rural Research Agency, 12/27/84; CEA, letter to Rural Research Agency, 1/11/85. North Slope Borough, Resolution Serial No. 10B-82. Daniel Dieckgraeff, Enstar, interview, 1/16/85. See Tussing and Erickson, Alaska Energy Planning Studies, Institute of Social and Economic Research, 11/4/82, for some interesting insights into the relevance and historic verifiability of the interrelationship of world oil prices to the prices of other energy resources. APA, sitna Hydroelectric roject Economic and Financial Update (draft), 2/27/84, p. 4-4. Coffman Engineers, Inc., Barrow Gas Study, 4/29/83, p. 2ueltigae. ADNRLOD CLUS opp lL Esther Wunnicke, ADNR, letter to Senator Don Bennett, 3/12/85. ADNR Op. CLt.i | 1/185, (pels Wunnicke, ADNR, written statement, 4/2/85. See Rural Research Agency, Memorandum to Senator Jan Faiks, April 11, 1985 for further details. ADOR, Petroleum Production Revenue Forecast, 3/85, p. 22 and 41-42. Gerald Heier, ADOR, interview, 1/31/85. ADNR, Cook Inlet Gas Disposition - 1983, 12/26/84. Wunnicke, op. cit., 3/12/85. 46 Chapter III FUEL OIL PRICES AND CONSUMPTION A) Sources of Fuel Oil Consumed in Alaska Alaskans utilize petroleum distillates for a number of purposes, including spaceheating and electric power production. Fuel oils, specifically No. 1 and No. 2 fuel oil, accounted for about 42% of the state's thermal energy consumption in 1981 and for about 13% of its power generation in 1983. As we have noted, the use of petroleum products in Alaska is not limited to fuels produced in Alaska from Alaskan crudes. A significant portion of instate consumption is imported (29.2% of diesel/fuel oil), almost exclusively from the west coast of the United states. This situation both simplifies and complicates our analysis of the question at hand. The percentage of instate diesel and fuel oil products (for all purposes) used in different regions of Alaska in 1981 was as follows: Southeast = Weiss) Southcentral = 96.1% Interior - 100.0% Southwest & Arctic/Northwest - 23.8% 2 Usage of diesel fuels for power generation is also discussed in the section on hydroelectric power in this report and has been dealt with in depth previously by this agency in its series of memorandums on the Power Cost Assistance Program during the the 1984 legislative session. Those memorandums, we believe, revealed the basic economic advantages or disadvantages relevant to the use of diesel fuels for power generation. 47 Spaceheating with oil has been the subject of much attention over the past several years. Numerous studies and surveys have dissected the issue, most attaching some importance to the issues of prices and consumption, the basic elements of an analysis of comparative economic advantage or disadvantage. Extensive surveys were published in 1980, 1981, 1983, and 1985 by the Division of Energy and Power Development or Office of Energy (of ADCED) in conjunction with the annual Long Term Energy Plan. RurALCAP has surveyed costs in various parts of the state, as have the Alaska Department of Community and Regional Affairs and the House Finance Committee, among others. B) Fuel Oil Prices Despite this work on cost and consumption, the information available on thermal uses of fuel oil in Alaska is incomplete and imprecise. No single source has comprehensive data. The salient reason is that the task is a massive one. Such a compilation would require that hundreds of individual communities, many isolated and/or unincorporated, be contacted. Survey responses have been notoriously incomplete in the past and their validity open to question, for a number of reasons (for example, surveys have often been answered by individuals willing, but not necessarily expert). Hundreds of independent distributors of heating oil operate across the state. They are not regulated and required to report data, as are energy utilities. Due to the recent volatility of fuel prices, results are often outdated in short order. Finally, many available sources were inappropriate for our purposes; fuel use totals have often not been broken down into different components, of which there are many in addition to power generation and spaceheating. Prices presumably are 48 identical for similar fuels, regardless of usage, unless _ purchases are made by a relatively large entity such as an electric cooperative or a rural school district, which may qualify for a volume discount. Consumption records, when reported (much less often than simple price information), usually have not been compiled on a regional basis. Independent research was not attempted as a part of this project. The failures of previous efforts to develop comprehensive information warned of dismal prospects for a successful survey of the sort within the capabilities of this agency. Despite these problems, some informative data has been gathered on the subject of oil prices across the state. The results of two 1983 surveys are displayed in the accompanying table. The Community Energy Survey (CES) and Community Fuel Survey (CFS) are the most recent efforts to compile both price and consumption data. More timely, but less comprehensive, information from a variety of sources is available and will be considered later. The purpose of presenting this data is to provide a picture of the magnitude of price differences across the state. Incomplete survey responses required that we fill in gaps in the data in a few places in the CES. This of course means that the data is not entirely uniform, but that is a hazard of the subject. The CES did garner price responses from 165 communities, more than any other poll. The two surveys are not in comparable format, the CES compiling results by federal census areas and the CFS listing average prices within the boundaries of Native Regional Corporations, but with a little cross comparison, one can see that the two arrived at similar results. For example, the North Slope Borough average price quoted in the CES was $2.11 per gallon, while the CFS developed a $2.17 price for the Arctic Slope region. The two surveys identify patterns of pricing on a regional basis. Both indicate that prices were highest 49 Table XV 1983 Regional Fuel Oil Prices ($/gallon #1 fuel) CES CFS Census Area Price Regional Corp Price N. Slope $2.11 Arctic Slope $2.17 Kobuk 2.10 NANA 2.03 Nome 2.09 Bering Str. 2.06 Yuk-Koy 1.89 Calista 1.92 Fbks Bor. er L7, Bristol Bay 1.62 S.E. Fbks 1.86 Aleutians 1.60 Wade Hampton 2.07 Koniag 1.45 Bethel 1.80 Chugach 1.22 Dillingham 1.41 CINA 130) Bristol Bay 1.38 Doyon 2.05 Aleutians 1.38 Sealaska 38 Mat-Su Bor. 1.25* Anchorage 1.20 Kenai Pen. 1.20 Kodiak Is. 1.48 Valdez-Cord. 1.18 Sgy-Yak-Ang 1.34 Haines Bor. 1.13 Juneau Bor. 1.21 Sitka Bor. 1.14 Wgl-Ptbrg 1.09+ POW-O.Kkn 1.41 Ketchikan B. 1.30 * Palmer only. + Petersburg only. Source: Fuel retailors, 2/85; Adams, 7/83; ADCED, 5/83. for the state's west coast, arctic and interior regions. These first two coincide with the Arctic/Northwest region in Map I, which imported about 76% of its diesel fuels from the west coast of the contiguous United States in 1981. But one cannot directly equate the steeper costs of fuel oils with their place of origin. Both surveys showed that interior Alaska also paid high prices for oil, virtually all obtained from the MAPCO refinery near Fairbanks, which processes North Slope crude, some of which is distributed to Interior 50 villages. On the other hand, in southeastern Alaska which imported over 90% of its fuel oils from the lower 48 (mostly Washington state) paid considerably less for its fuel than did these other areas. Prices there were quite comparable to Southcentral costs for Alaskan crude products. The total distance which imports must travel and other factors impact the prices consumers ultimately pay. For an indepth review of all of these factors, the House Research Agency's report Fuel Pricing and Consumption in Alaska: A Regional Analysis is an excellent source. Factors cited as contributing to higher western Alaska prices were climatic conditions, volume, and capital and loan costs. We close this review of fuel oil prices by re-emphasizing that information in this field is imperfect. Any attempt to develop average prices for geographic regions will encounter an obstacle in the lack of precise and comprehensive consumption records. C) Fuel Oil Consumption At this juncture, it will be appropriate to switch the focus to existing useful consumption estimates. ADNR annually makes estimates of future consumption of petroleum liquids for all purposes within the state, including spaceheating purposes. Theirs is the most recent such forecast available, the department, in cooperation with ISER, has made these calculations for about a decade now. Most other projections have been done for specific purposes (i. e. analyses of the feasibility of the Susitna hydroelectric project) and have concentrated on limited regions of Alaska. ADNR's forecasts are statewide in nature. The principal drawback is that these forecasts are not done on a regional basis, but only on a Railbelt and rest of the State division, as displayed in Table XVI. The table also lists the change in consumption on an annual basis. Our previous 51 Table XVI Spaceheating Fuel Oil Consumption (millions of gallons) Railbelt Rest of State Year Consumption % Change Consumption % Change 1985 Taiee = LOSS - 1986 74.8 2.19 106.2 Zo 1987 74.6 Oca 109.7 37530) 1988 74.6 - 110.8 1.00 1989 75.5 ere L365) 2.38 1990 76.3 1.06 aL ks 3.07 Source: ADNR, 1/85. analysis (see Chapter II) indicated that the bulk of oil spaceheating took place outside of the Railbelt and the forecast calls for this trend to continue. The nonrailbelt share of fuel consumption is projected to increase from 58.5% of the state total in 1985 to 60.1% in 1990. The rest of state category shows an increase in consumption over the period, while the Railbelt is predicted to show a decline from 1986 to 1987 and no change the next year. This is likely due to the increasing penetration of natural gas thermal energy into the Matanuska-Susitna Valley. Successive rates of increase for the Railbelt are forecast to be well below those for the rest of the state. A calculation of the economic benefits or liabilities accruing to different regions of the state is difficult without specific, uniform, annual information on prices and consumption and how these relate to imported and domestic OL The regional price calculations suggest that the origin of fuel supplies, in Alaska or outside, has not had a significant impact on the final price of heating fuel compared to other factors. Much of interior Alaska, using domestically processed fuels, paid nearly the same for fuels 52 as did western and arctic areas, which rely principally upon imported products. Southcentral consumers have paid prices for domestically refined oil similar to those paid by Southeast consumers for imported fuel. Comparisons to national prices for No.1 fuel oil are also hampered by a lack of data. The national average for 1983 was $1.05 per gallon’, which suggests that all Alaskans consumers, to a greater or a lesser degree, suffer a price disadvantage, assuming this price difference has sustained. This is not unexpected, given the higher costs of production in the state and transportation costs from the West Coast. D) Royalty Oil: Can It Fulfill Alaskan Demand? Does the evidence outlined thus far suggest that Alaskans with access to petroleum products refined from royalty oil have gained any substantial economic advantage over Alaskans without such access? Deductive reasoning should suffice to illuminate the answer in this instance. Two clues provide the basis for analysis: 1) Two areas utilize instate products almost exclusively for thermal needs, the Interior and the Southcentral regions. Virtually all of the products burned in these regions are refined from royalty oil at local refineries. Southeast Alaska, on the other hand, depends almost exclusively on products from out of state. 2) The lowest prices in Alaska for heating fuel oil were found in the three regions cited above. Southeast consumers enjoyed the lowest prices, however, while consuming imported fuels. 53 The combination of these two factors seems to suggest that, as far as fuel oil was concerned, price advantages seemed to rest substantially on factors which may have included access to royalty oil, but also depended heavily on the other elements discussed earlier in this chapter. Instate use of royalty oil, in one fashion or another, represents the most direct and most significant benefit to Alaskans attributable to the State's petroleum resources. The importance of royalty oil in this respect was recognized by the legislature, which established statutory provisions regarding its disposition. AS 38.05.183 (d) proscribes the sale of royalty in kind oil or gas for export from the state without a determination by ADNR that the oil or gas in question is surplus to "present and projected intrastate domestic and industrial needs". Section (e) of the statute requires that sales other than by competitive bid offer "the maximum benefits to citizens of the state", requiring that ADNR consider of the effects of sales on the state's economy, the advantages of instate refining or processing, and the ability of buyers to provide products instate with supply or price benefits to residents. ADNR has heretofore found that, when offering royalty oil for sale, that the oil has been surplus to instate needs for two fundamental reasons. First, there has been no shortage of petroleum products in any part of the state and, second, there has been no evidence that restricting royalty oil to instate uses would have substantial impact on the price structure or supply of petroleum products throughout Alaska (Chapter I for further details on this subject). Leaving aside the issues of whether a surplus exists or whether petroleum products refined in Alaska can compete on a price and supply basis with imported products, some Alaskans do have access to royalty oil products and others do not. Several Alaskan firms hold long term or short term contracts 54 for North Slope and Cook Inlet royalty crude. The MAPCO refinery in Fairbanks has a contract extending through 2003 for 35,000 barrels per day of North Slope oil. Tesoro has two contracts for North Slope crude which will supply it with over 38% of the State's share of North Slope oil until January 1, 1995. Chevron will be taking 9.6% of this volume until the same date. Golden Valley Electric Association has a one year contract (it had been seeking a ten year pact), expiring in 1986, for a 2.667% portion of Prudhoe Bay royalty oil. A number of shorter term contracts, six to twelve months in length, will provide several other companies approximately 90,000 barrels per day in 1985 and 1986. As discussed in the first section of this document, the products produced instate from crude oil supplied under the terms of these contracts are available to Alaskans, primarily in the Southcentral and Interior regions. These products do include spaceheating fuels. The potential for increased production of petroleum products from royalty oil does exist, as the supply figures presented in Table I revealed. This potential for greater volume of production could be translated into wider distribution of these products instate. This proposition, in reality, would run up against certain limitations, these being the capacity of instate refineries and the ability of out of state refiners to under cut the price of products refined in Alaska, at least in some regions of the state. Absent those limitations, the potential for increased instate use of royalty oil does, in theory, exist. Table XVII displays the latest ADNR estimates of North Slope royalty oil volume, the royalty volume remaining after subtracting present and proposed sales (this volume constitutes the State's present royalty in value share and could be taken in kind and sold, with legislative approval), and projections of demand for spaceheating fuels, both outside the Railbelt and statewide. 55 The period covers the duration of all royalty contracts now in force. The State will continue to receive royalty crude beyond 2003, the amounts, however, barring significant new developments, will fall to about 75,000,000 gallons annually within 10 years of that date. After short term contracts are fulfilled, there will remain, for a number of years, relatively large uncommitted North Slope royalty volumes, particularly in regard to annual thermal consumption, which represents only about twelve percent of total demand for petroleum products. The question is whether the royalty oil available could, in theory, satisfy demand for heating fuels. The use of this resource to satisfy competing demands for petroleum products is not dealt with in this case, although such competition will likely exist. Table XVII Royalty Oil Volume and Spaceheat Demand (millions of gallons) Total Royalty Total Non-Rlbt Year Royalty In Value Demand Demand 1985 Set oeS 230.0 176.4 103.3 1986 3,219.3 1,226.4 181.0 106.2 1987 Spas & 1,202.8 184.3 109.7 1988 2,922.3 1,099.3 185.4 110.8 1989 2,634.8 957.5 189.0 DSi) 1990 2,395.3 839.3 193.4 LAT ot 1991 2,185.6 744.8 194.6 aS L7ierd, 1992 2,012.1 650.3 198.6 27, 1993 1,820.4 555007, 202.8 LZ Ser? 1994 Oe) 403.7 7A0}7 LO) 128.8 1995 Lo Sieud: 843.2 212.3 133.8 1996 1,207.7 670.7 220.7 141.9 1997 abo eloa | 536.6 223.8 143.7 1998 958.1 421.6 235.0 154.8 1999 871.9 335.3 236.8 154.4 2000 862.3 239.05 = — 2001 680.3 143.7 — So 2002 613.2 76.7 = oS 2003 536.6 0.0 = - Source: ADNR, 1/85. 56 Assays of Prudhoe Bay crude indicate that 28.6% of its volume can be refined into distillate fuels.* Distillate products include No. 1, No. 2, and No. 4 fuel oils and No. 1, No. 2, and No. 4 diesel fuels, the first category of which are used for space heating and the second for transportation and power generation, among others.> Diesels and fuel oils are very similar, with the diesels meeting slightly higher performance specifications. Although most of the 28.6% portion could be refined into no. 1 and no. 2 heating fuels, the actual conversion ratio of crude oil into these middle distillates, as they are also known, depends upon the refinery in question. Alaskan refineries in 1982 produced 204,900,000 gallons of No. 1 and No. 2 distillates®, an amount that would have been adequate to have heated the state's buildings, but not to slake the state's total thirst, which, in that year, was 510.4 million gallons, including consumption for aviation, marine, and other transportation categories. To return to the pertinent issue, the middle distillate cut of Prudhoe Bay royalty in value crude, if all taken in kind and refined into heating fuels for Alaskan use, would produce about 350 millions gallons of such fuel in 1986. This would be more than enough to sate instate appetites, without even considering present production levels. Uncommitted royalty oil would only suffice for this purpose until 1991, however. If we channel our consideration to demand in the non-Railbelt portion of the state, in which fuel oil is the primary thermal energy source now, where consumption is growing faster than in the Railbelt, and imported products fulfill much of the demand, volumes would be sufficient until 1993. That date would be extended further into the future if current instate royalty products destined for use outside the Railbelt, mostly in the Interior, were considered, although how far is unknown given the lack of precise knowledge available on the end uses of Si: No. 1 and No. 2 distillates in the state. Additionally, if the provision of royalty heating products was determined through some manner of need based criteria, the total volume available could suffice for a number of additional years. How long would depend upon the scheme design. This scenario's props, however, do not include such major items as the provision of the required refinery capacity to produce the fuel needed or development of a price structure aimed at providing an economic advantage to Alaskans who currently do not enjoy any direct benefits attributable to use of the state's petroleum resources. Refinery construction would be an expensive proposition. It is possible that private enterprise would be interested, but certainly not without some incentives offered by the State. Dedication of royalty oil to this purpose would cost the State's General Fund substantial revenues. For example, 1986 spaceheating demand is projected at 181.0 million gallons by ADNR. If that amount were dedicated to production of heating fuel, with no return to the State as part of the program and the value of the oil was $18.50 per barrel (bid prices at the 1984 royalty sale averaged about that), the loss to the General Fund would be about $47 million dollars. Even this would result in a cost savings of only $.44 per gallon, which theoretically could be passed on to consumers. This, as we have seen (Table XV), would still leave fuel prices in parts of Alaska well above what the bulk of residents pay. There would have to be a cost reckoning at some point. To extend an economic advantage to citizens not now enjoying one would require a redirection of the State's energy resource derived wealth. 58 Footnotes House Research Agency, Fuel Consumption and Pricing in Alaska, 1/84, p. 19. House Research Agency, op. cit. DOE/EIA, Annual Ener Outlook 1984, 1/85, p. 219. ADNR, Historical and Projected Oil and Gas Consumption, 1/88, p. 62. DOE/EIA, etroleum Marketing Monthl September 1984 11/84, pp. 121-122. House Research Agency, op. cit., p.14. 59 Chapter IV COAL PRICES AND CONSUMPTION A) Alaskan Coal Resources Coal resources in Alaska are abundant. Estimates by the Alaska Department of Natural Resources, Division of Geological and Geophysical Surveys, show the State possessing almost 50% of U.S. reserves or 25% of the world's coal reserves. Given current U.S. energy consumption, this translates into a 5000 year supply of coal.? These figures are impressive, however, the quality and accessibility of much of the state's coal are significant issues. Known reserves in Alaska contain basically four types of coal that range in quality from one end of the spectrum to the other. The ranks of coal include: anthracite, bituminous, subbituminous, and lignite. The progressive quality or coalification of these ranks is usually indicated by the higher heating values or number of Btu's per pound. According to the U.S. Energy Information Administration, lignite contains approximately 9 to 17 million BTU's per short ton; subbituminous - 16 to 24 million BTU's per short ton; bituminous - 19 to 30 million BTU's per short ton; and anthracite - approximately 22 to 28 million BTU's per short ton. These heating values can be affected by the amount of moisture, ash, or sulfur content found in a particular rank. The average BTU rating per pound of coal used for electric steam plants in all of the U.S. is 10,568. Alaska's interior region for the same purpose is ranked as Coal mined in subbituminous with an average of 7,500 BTU's per pound or 15.5 million BTU's per short ton.? These factors define this coal as lower quality within the subbituminous rank. Coal found in the arctic region of the state ranges from 60 6,500 BTU's (lignite) to 13,500 BTU's (anthracite) .4 The arctic region also holds the majority of Alaska's identified and undiscovered coal resources as shown in Table XVIII. Although some arctic coal is of high quality, factors such as transportation costs and lack of infrastructure have prevented large scale coal production. Recently, there have been several studies examining means of utilizing the coal found in the western arctic region of Alaska. Possible utilizations will be discussed in the next section. Table XVIII Alaskan Coal Resources (millions of tons) Identified Undiscovered Region Resources Resources Arctic 60,000-146,000 402,000-4,000,000 Northwest - - Interior 6,940 10,400 Southwest - 3,290 Southcentral 10,700 1,480,000 Southeast Ca - TOTAL 77,600-164,000 1,900,000-5,500,000 Source: Davis, 1984 B) Western Arctic Coal Development While the arctic region contains vast quantities of coal, most of the region is dependent on imported fuel oil as the main source of energy for electrical generation and spaceheating. Several studies in the last few years have investigated the possibility of substituting coal for fuel 61 oil in this region.5 Paramount for these studies has been the tenet that coal and oil must be priced equivalently per BTU. Transition from fuel oil to coal for both spaceheating and electrical generation involves many changes, all of which are expensive. As much has been written elsewhere on this subject and because this report is concerned primarily with actual fuel costs, there will be no in-depth discussion of potential coal prices for this region. However, some of the factors involved in a change from fuel oil to coal are discussed briefly below. * Transportation costs appear to play the most significant role when considering use of local coal deposits. According to a study by Dames & Moore, Assessment of Coal Resources of Northwest Alaska, transportation costs would represent 2/3 to 3/4 of the delivered cost of coal. The building of access roads to and from mines plus trucking and barging costs to the remote villages are included in estimates. * Using coal for spaceheating purposes would require that residents convert from oil burning stoves to coal burning stoves. Estimated prices for these stoves range from $1,000 to $6,000. This amount represents quite a large expense for a rural household. © * Substituting coal generated electrical power for diesel generated power poses more _ problems. As stated earlier, in the Northwest Arctic region of Alaska approximately 12% of energy requirements are for electricity. Steam turbine plants are the most economic means to utilize coal for power generation, but operate most efficiently when generating over 10 megawatts. Since not even the larger regional centers in the Northwest Arctic region have peak demands over 5 megawatts, steam turbine plants may not be appropriate 62 in this area.’ However, the possibility of building regional power plants and transmitting electricity to smaller villages via overland lines is currently being considered in a report by Arctic Slope Consulting Engineers. Another solution may be an Organic Rankine Cycle Engine (ORC) with which the North Slope Borough is currently experimenting. Although not as efficient as steam turbines, ORC engines require less maintenance and can be operated using cogeneration (using more than one fuel source, such as waste material). The use of coal as a substitute for diesel and fuel oil in the arctic region is still in the development stage. At this time, according to House Research report 81-2, there are only three villages, Atkasook, Wainwright, and Point Hope, all in the North Slope Borough, actually exploring the use of local coal resources. C) State Coal Leases Since the major focus of this report is the benefits accrued from producing energy sources to which the State holds title, this section will concentrate on the Nenana Field, located in the [Interior Region of the state. More specifically, the levels of production, consumption, and revenues attributable to the Usibelli Mine near Healy, which is presently the only operating coal mine in the state, will be examined. Other state coal leases that may come into production in the near future will also be discussed. Considering the immense coal resources of Alaska, current production is very limited. As stated above, the Usibelli Coal Mine is the only mine operating at this time, and is 63 the only source of coal royalty payments to the State. Production is estimated at approximately 800,000 short tons per year. The mine operates under two State leases. The first calls for a royalty of five cents per short ton (2000 lbs) for production and a dollar per acre annual rental fee. The second lease has a ten cent royalty and the same annual rental fee. The five cent royalty is a 1920 minimum set by the Federal government. ® Table XIX shows royalty payments for state coal leases from Usibelli for the last four fiscal years. Both leases will expire before the end of this decade. The new leases will most likely include a fifty cent royalty, or 5% of the adjusted gross revenue from coal sales and a three dollar per acre annual rental fee.? Table XIX Usibelli Coal Mine State Royalty Payments FY 81 $ 67,553.25 FY 82 $ 52,898.31 FY 83 $158,638.62 FY 84 $191,120.36 Source: ADNR, 1/8/85. Production at the mine is expected to increase twofold because of an export contract to Korea through the Suneel Alaska Corporation. According to Bill Noll, Vice President of Suneel, the firm has already started exporting the coal via the Alaska Railroad to the company's coal handling facility in Seward where it is shipped to Korea. Over the 15 year contract period more than 11 million metric tons (2,240 lbs per ton) of coal is expected to be exported to the Korea Electric Power Corporation. Coal production at the Usibelli mine could increase even more in the next few years if a plan to export coal to Finland by another Alaskan 64 firm, International Alaska Enterprises, is developed. The amount of coal that would be exported to Finland has not been determined as yet.2° With the new leases conditions coming into force and anticipated increases in production, ADNR personnel have projected that royalty payments from Usibelli will increase to over $800,000 annually in the next few years. In other areas of the State, land has been leased for coal production, but operations have yet to begin. These leased areas include the Beluga field, on the west side of the Cook Inlet, and the Mat-Su Field. Production at these mines is dependent on markets for the coal. Coal in the Beluga fields is aimed primarily for the export market, as low natural gas prices in Cook Inlet presently dampen the likelihood of developing a domestic market. The proximity to deep water ports and international shipping lanes will allow access to Pacific Rim markets such as Japan, Korea, and Taiwan. If one or more of these markets is secured, production at the Beluga fields could start in the late 1980's. t+ A coal lease sale was held in December of 1984 by ADNR, Division of Mining. This sale (Matanuska Coal Lease Sale #6) tentatively awarded three lease tracts to the Rock Spring Royalty Company of Colorado. While a percentage of this coal will be designated for the export market, partners involved with development of the new leases are investigating the possibility of constructing a $410,000,000, one hundred seventy megawatt mine-mouth power plant to provide electricity to the Matanuska Valley. They estimate their adjacent existing lease sites, in conjunction with the new lease sites, could contain enough coal to support a 700,000 ton annual operation for about twenty years. +? 65 D) Coal as a Fuel Source Coal from the Usibelli Mine is utilized for both electrical generation and spaceheating in the Fairbanks area. Glacier Valley Electric Association (GVEA), Fairbanks Municipal Utilities System (FMUS) , the University of Alaska, Fairbanks, and area military installations all use coal to generate electricity. With the exception of GVEA, they all use coal for spaceheating as well. Coal usage in the Lower 48 for electrical generation and heat is much greater than in Alaska. Coal is the traditional fuel for electrical generation in many states. However, in Alaska, coal usage is thus far a regional phenomenon. Proximity to the only producing coal mine and available transportation such as the Alaska Railroad allows coal to be a viable fuel source for the Fairbanks area. However, neither GVEA or FMUS depend solely on coal for power generation. Oil is purchased from the Mapco Refinery by both utilities to augment their generating needs. When the electric intertie between Anchorage and Fairbanks is energized this spring, most oil fueled power will be displaced by excess Anchorage power. = Information concerning the price and consumption of coal, when possible broken down into electrical generation and spaceheating use, is provided in Table XX. The national price of coal is included to permit an analysis of the advantages or disadvantages of using Alaskan coal, since intrastate usage is so limited to preclude intrastate comparisons. It should be noted that Alaskan prices paid per ton are included in the national average price. Also the national figures include all ranks of coal. As stated before, much of the coal used in the lower states is of better quality and therefore higher priced than the Alaskan coal. For example, based upon the BTU's per pound quoted on the first 66 Table XxX Average U.S. and Alaskan Coal Prices ($ per delivered ton) Year Nat'l GVEA FMUS UAF 1379 $26.16 $22.79 $26.02 1980 28.78 $15.60 25.93 29.72 1981 32.32 18.90 28.76 SL. 97 1982 34.91 19.39 30.12 34.73 1983 34.99 22.12 31.20 40.43 Sources: GVEA, 1/4/85; FMUS, 1/8/85; UAF, 1/11/85; DOE, 7/84. page of this chapter, the U. S. average cost per million BTU of coal energy in 1983 was $1.66, while the Fairbanks utilities paid $1.84. U. S. million BTU costs were lower in all years. Lower prices per ton in Fairbanks have not meant a_ nominally cheaper energy source in recent years. The next table breaks out the levels of coal generated electric power from each of the Fairbanks area utilities. Price data and the generation figures in Table XXI suggest that Alaskan coal prices are influenced by economies of scale. UAF prices were the highest, likely due to lesser volume needs and the higher transportation costs associated with those smaller purchases. GVEA generated more power Table XXI Coal Generated Power (megawatt hours) Year GVEA FMUS UAF 1980 183932 112406 23234 1981 198207 LS6137 26456 1982 185669 163787 38816 1983 187520 146758 33459 Sources: Alaska Power Administration, 1984; UAF, 1/22/85. 67 and their coal purchase prices were the lowest among the utilities. GVEA's plant is located in Healy near the mine, minimizing transportation costs, also. As mentioned earlier, coal is used for spaceheating as well as electrical generation. FMUS heats a small area in downtown Fairbanks with coal generated steam heat from their generating plant. The utility has provided a breakdown of tons of coal used for spaceheating and for electrical generation in Table xxrr.14 Actual coal tonnage is not set aside for either spaceheat or electrical generation. Coal fired generators produce steam to operate the utility's turbines and a percentage of this steam is redirected for spaceheating purposes. This spaceheat, then, is basically a by-product of the coal fired generators. Table XXII FMUS Coal Use (tons per year) Year Spaceheat Power Gen Total 1979 16,335 103,434 119,769 1980 TiS 117,420 134,593 1981 14,739 149,537 164,272 1982 25,180 147,740 172,920 1983 29,863 3 re 5 161,078 Source: FMUS, 1/8/85. Because a constant steam pressure must be continually maintained more coal must be utilized to compensate for the steam redirected for spaceheat. As Table XXII indicates, most of the coal was used for electrical generation. The UAF power plant utilizes steam heat in much the same manner as FMUS. While FMUS redirects only a small amount of its coal produced steam for spaceheating, the University 68 uses coal as its main heating source. However, no data was available on how coal consumed at the university might be apportioned between thermal energy and power production, so Table XXIII, UAF Coal Use, indicates only total usage for each year considered. Table XXIII UAF Coal Use (tons per year) Year Total 1979 62,869 1980 62,437 1981 61,356 1982 59,020 1983 58,120 Source: UAF, 1/11/85. As the data makes clear, the UAF power plant is not a major consumer of coal and precise identification of allocation of coal tonnage to end energy products was not pursued. Coal is also used in the Fairbanks area for spaceheating in small boilers and stoves by both residential and commercial users. Institutions such as schools and hotels purchased over 8,000 tons of stoker coal from one local dealer for $66.50 per ton delivered price in 1984. Residential users purchased about 5,000 tons at $69.30 per ton to be used in LS small stoves, such as airtights, in 1984. In addition, the Usibelli mine sold 20,000 tons directly to residential +4 Coal burns very efficiently in heating consumers in 1983. appropriate stoves and may be used alone or in conjunction with wood. Problems associated with burning coal include a high ash content, requiring frequent stove cleaning, and large storage requirements for purchases of bulk coal. 69 Little data is available concerning the use of coal in small stoves in other regions of the state. However, a small coal cooperative located in Seward imported 59 tons of coal from the Usibelli mine for $55/ton, a savings of $14.30 per ton over the retail price in Fairbanks. Demand is expected to increase during the next year.2’ In another example, coal imported from Utah is sold for residential spaceheating purposes in Juneau. This coal sells in one hundred pound sacks for $16.80, or $336.00 per ton, over five times the price residential users have been paying in Fairbanks. Five 18 short tons were sold in Juneau in 1984. Use of coal in Alaska, outside an institutional or utility context, is quite limited both as regards volume and geographic distribution. E) Economic Benefits of Coal Use Alaskans paid less, per ton, for coal than the nation as a whole, for the period 1979 - 1983, so witnesses the data presented in Table XX. The same data indicates that the cost of the energy produced from coal in Alaska was more expensive, as a consequence of the lower quality resource here. Alaskans would have had to buy less coal for equal energy production had the higher BTU content coal utilized in the contiguous United States been available. Averaged for all utilities, Fairbanks prices have consistently been about 30% less for local power generation coal than have prices prevelant in the rest of the nation. On the other hand, the price for the energy content of Alaska has been about four to six percent higher than the national average price, until 1983 when the differential leaped to nearly eleven percent. Only about 10% of U. S. consumption is of 70 coal of BTU content comparable to Alaskan consumption. The price per ton of lower heat value coal, nationwide, is substantially lower than that of higher grade coal. Generally, coal with less than 8,000 BTU/pound (as is Alaskan produced coal) sold for well under $15.00 per ton, much less than the price of coal in Alaska. Such coal accounted for only about 10% of national use in 1984.29 Alaskan consumers have, it appears, not enjoyed any price advantage in comparison to national users. This assertion assumes that cost of living differences would not reverse the advantage of national users. The price of coal used to generate electricity and thermal has, however, offered Fairbanks area consumers’ less expensive energy than consumers in other areas of the state (see Chapter VI for details). This is particularly true for electric power, while thermal benefits are more restricted to institutional users. The current limited production makes it economically unfeasible to transport coal to other areas within the state in order that they may also share the benefits. Coal as fuel source, for the time being, will remain a regional phenomenon in Alaska. F) Future Coal Prices Several studies have been targeted at identifying the future costs of meeting Alaska's energy requirements. Many were spawned by the Susitna Hydroelectric project, and discuss alternatives for the power and spaceheat needs of the Railbelt area. Coal is a viable, if not a preferred, alternative for the region, at least according to the conclusions of most of the relevant studies. The price projections for Alaskan coal listed in Table XXIV are based on two such studies. TA Table XXIV Projected Prices of U.S. Avg and Alaskan Coal ($ per ton) Alaska U.S. Year Battelle Acres Year Price/change Price/change Price/change 1985 $30.36 $30.23 $38.54 1986 30.66/2% 30.93/2.3% 38.93/10.1% 1987 31.27/2 31.64/2.3 39.35/10.8 1988 31.90/2 326377203 39.66/7.9 1989 32.54/2 33.11/2.3 39.84/4.5 1990 33.19/2 33.87/2.3 40.24/10.0 Sources: Acres, 2/83; Battelle, 3/82; U.S. DOE, 1985. These price projection figures are somewhat suspect as current market prices in Alaska (1984) have already met the price per ton that is projected for 1985 in the table below. Some hard realities that could affect the price of coal in the lower 48 states in the future include acid rain, coal legislation, higher transportation costs, and, in some states, the shifting of surface mine regulation implementation and enforcement from the Federal government to state agencies. The grade of Alaskan coal that is currently being mined is very low in sulphur so acid rain legislation would most likely not affect coal production in this state. Transportation costs may, of course, increase in Alaska. However, as Alaskan transportation costs are high already and current coal markets only exist along the Alaskan Railroad corridor, demand and, therefore, production would have to increase tremendously to justify transporting coal out of the confines of the existing rail system. As for surface mining regulations, the State has’ been responsible for their implementation since May of 1983. 72 Coal prices are, however, affected greatly by economy of scale. If coal were used more widely, larger more efficient plants could be built. This, along with increased production, could reduce the price of coal. Even if coal is not used as an alternative in the Railbelt, exports to the Pacific Rim countries could have the same price dampening effect. However, with declining oil prices, coal may not be as cost competitive a fuel as was believed when it was thought oil prices would continue to increase. It is very difficult to project coal prices without knowing whether coal will remain a regional fuel source, become a major export, or the main generator of power for the Railbelt region. Footnotes 1. William Kent and Company, Electric Power Generation for the Alaska Railbelt Region, pg. 93. ais Energy Information Administration, Cost and Quality of Fuels for Electric Utility Plants, 1983, pg. 8. Sle Kent, op. cit., pp. 106. 4. House Research Agency, Potential for Local Coal Use in Rural Alaska, pg.15. 5. These include: Dames & Moore, Assessment of Coal Resources of Northwest Alaska, December 1980; Arctic Slope Consulting Engineers, Western Arctic Coal Development _ Project, and House Research Agency, Potential for Local Coal Use in Rural Alaska. (AG Arctic Slope Consulting Engineers, Western Arctic Coal Development Project, Technical Memorandum, pg.37. ie Alaska Power Administration, Alaska Electric Power Statistics, 1960-1983, pg.6. 8. ADNR, interview, Mary Hession, 1/8/85. 9. Ibid. 10. Alaska Daily News, 2/5/85 11. ADNR interview, op. cit. 12. Alaska Daily News, 12/13/84. 13. Fairbanks Municipal Utilities System, letter from Alan Martin, 1//8/85; Golden Valley Electric Association Inc., letter from Bert Sharp, 1/4/85. 14. Alan Martin, FMUS Power Plant Ass't Supt. compiled the information concerning coal usage at FMUS, utilizing the plant's computer to provide ratios of energy produced, thus breaking down coal tonnage into use for spaceheat and electrical generation. 73 15. The Coal Bunker, telephone interview, 2/7/85. 16. ADCED, Alaska's Energy Plan 1985, 2/15/85, p. 20. 17. House Research Agency, Coa Purchases _b Seward Residents, pg. 2. 18. Alaska Ship Chandlers, telephone interview, 2/7/85. 19. DOE, Cost and Quality of Fuels for Electric Utility Plants 1984, July, 1985, pp. 62-66. 74 Chapter V HYDRO CTRIC POWER COSTS AND BENEFITS This chapter summarizes the types and distribution of economic benefits accruing to certain communities and residents resulting from State-owned hydroelectric power projects being located nearby. The focus throughout is principally on the Four Dam Pool (FDP) projects, the only power projects of any significance owned by the State, for the following reasons. One is that the FDP projects collectively represent a good portion of hydroelectric activity in Alaska today, and thus circumscribe virtually all of the benefits here under review. The second is that, by virtue of constituting the initial phase in the State's power development program, these projects and their benefits may be viewed as typical or indicative of the distribution of economic benefits in future State-owned power projects. The third reason, largely a practical one, has to do with the fact that State policy can effectively address only those hydroelectric projects (or benefits therefrom) over which the State exercises direct control--i.e. State ownership. A brief discussion of other hydroelectric projects, in various stages of progress, for which the state has appropriated funds, is also included. The central question of whether benefits deriving from development of one of the State's major resources, hydroelectric power, are distributed equitably among Alaska's residents is discussed in the remainder of this chapter. 75 A) State Hydroelectric Law and Policy In 1976 Governor Hammond signed into law a bill (Chapter 278, SLA 1976) which declared it to be State policy to reduce consumer power costs and to otherwise encourage the long-term economic growth of the state, including development of its natural resources, through the establishment of power projects. This legislation created the Alaska Power Authority (APA) to finance, manage and operate future State power projects.+ At that time it was also felt that Alaska should begin to decrease its use of energy sources over which it had relatively little control with respect to supply and/or price. It became, then, necessary to choose energy sources that were, "...insulated to some extent from inflation, extreme competition and from price pressures in other markets outside Alaska." In order to achieve these goals, the development of hydroelectric projects was considered the most desirable new resource option as hydroelectrically generated power appeared to ensure the state of a supply of long-term, secure electrical power with a stable price.? A driving force behind this decision was the fact that Alaska has the nation's most extensive hydroelectric power potential, the greater part of which has yet to be harnessed. * Most of the resource potential and all of the currently operating major hydro projects are located in two areas of the state, Southeast and Southcentral Alaska. Until 1982, all operating hydroelectric projects in the State were either federally, municipally or privately owned. The two largest projects - Snettisham, near Juneau, and Eklutna, near Anchorage - are both federally owned and operated. Smaller, less powerful hydroelectric generating projects, almost all located in Southeast Alaska, are either owned 76 privately or by municipalities. With the 1982 acquisition of the Solomon Gulch hydroelectric project, near Valdez, from the Copper Valley Electric Association, the State began its involvement with hydro on an owner/operator basis. B) Four Dam Pool Projects: Resources and Recipients Today the State of Alaska, under the auspices of the Alaska Power Authority, owns, manages and operates four hydroelectric projects: Swan Lake, Lake Tyee, Terror Lake and Solomon Gulch. They are now known collectively as the Four Dam Pool (FDP); each is briefly described below. 1. Swan Lake: The Swan Lake hydroelectric project is located near and serves the City and Borough of Ketchikan, Alaska. With transmission being provided by the Ketchikan Public Utility, Swan Lake began producing power in 1984 and, with two other small hydro projects (Beaver Falls and Silvas Lake), serves most of the electrical needs of approximately 13,000 area residents. The project has an installed capacity of 22 megawatts. APA currently sells Swan Lake power to the utility at a rate of $.0593/kwh.°> Should the proposed (July, 1985) long term power sales agreement for the FDP be ratified, this rate would change to about $.0565 per kwh and would be the same for all communities.© The average kwh rate for the first 750 kwh of residential power is $.086/kwh.” State appropriations of approximately $74,115,00 have thus far been made for the project.® CE Lake Tyee: The Lake Tyee hydroelectric project also began operation in 1984. Power generated by the project provides electricity to two Southeast communities, ae Petersburg, with a population of approximately 3,050 residents, and Wrangell, with an estimated population of 2,500.9 The Lake Tyee project has an installed capacity of 20 megawatts. Both the Petersburg and Wrangell Public Utilities, the local electric power distributors, purchase power from the APA at a rate of $.0723/kwh.?° The average residential charge per kwh for the first 750 kwh's in Petersburg is $.091. The average rate in Wrangell is slightly higher, at $.137/kwh. + Thus far, the State has 12 appropriated a total of $82,464,000 for this project. 3. Terror Lake: The Terror Lake hydroelectric project is the latest of the FDP projects to begin operation. Located on the Island of Kodiak, Terror Lake has an installed capacity of 20 MW and serves the city of Kodiak, which has a population of over 7,500 residents. (According to the Alaska Power Authority, the testing phase of the project was completed as of April 1, 1985, and the project is currently in the commercial operation phase.) Terror Lake will also serve the small community of Port Lions, with its population of around 320 residents. +? The Kodiak Electric Association purchases power from APA at a rate of $.0407/kwh. 14 Currently, Kodiak residents are paying $.168 per kwh for the a To date, the State has appropriated approximately $86,650,000 for this 16 first 750 kwh's of residential power. project. 4. Solomon Gulch: The Solomon Gulch hydro project was constructed by the Copper Valley Electric Association and purchased by the State in 1982. With an installed capacity of 12 MW, it is the oldest of the Four Dam Pool projects and the only one of the four not built by the State. Solomon Gulch serves the cities of Valdez (population around 3,700) and the Glennallen vicinity's approximately 1,000 residents. The Copper Valley Electric Association, which serves both of these communities, purchases power from the APA at a rate of 78 $.0495/kwh.?7 Valdez residents pay an average residential rate of $.147/kwh for the first 750 kwh's, while Glennallen area residents pay a slightly more, $.187.28 To date, the State has appropriated $53,000,000 for this project. 2? These communities now rely on the Four Dam Pool projects for the bulk of their power. In most cases diesel fuel is used when demand requires and a fuel cost adjustment is added to the monthly nti: APA is currently selling wholesale power to utilities under temporary power sales agreements until long-term power sales agreements can be signed, the rates cited above are temporary and subject to change. In total, the Four Dam Pool projects, located in Southeast and Southcentral Alaska, now serve roughly 31,000 residents or approximately 6% of the state's population. C) Other Hydroelectric Projects Other hydro projects for which the Alaska State Legislature has appropriated funds include one municipally owned and one privately owned project, both currently in operation in Southeast Alaska, and a number of proposed projects in various areas of the state and stages of progress. als The Green Lake hydroelectric project located near Sitka and owned by that municipality. In 1982, the Legislature appropriated $15,000,000 as a loan to the city of Sitka for the Green Lake project. The Legislature also appropriated some $3,200,000 in 1980-1981 for the Salmon Creek hydro project, located near Juneau and owned by the Alaska Electric Light and Power Company. 2+ Ao 2. The two largest State hydroelectric projects are the proposed Susitna and Bradley Lake projects. As of the end of the 1985 session, the Legislature had appropriated $415,310,800 for Susitna and $118,080,000 for Bradley Lake, for a total of $533,390,800.77 The constitutionality of statutes (AS 44.83.410-420) establishing continuing appropriations for these projects is in doubt, however. If a Superior Court decision rendering FY 86 appropriations invalid is upheld on appeal, appropriations for the two projects would be reduced by $250,000,000. Fy 85 funding of $150,000,000 would be voided if the court holds, and is subsequently affirmed in that decision, that the statutes also violated the constitutional prohibition against mingling substantive law and appropriations in the same measure. 3. Other proposed hydroelectric projects for which the State has appropriated funds are of a much smaller size than that of Susitna and Bradley Lake, and are scattered throughout the State although the bulk of these sites are in the southcentral or southeast regions. A total of approximately $28.5 million has been appropriated for these projects. 2? D) Hydroelectric Power Benefits There appears to be little disagreement that the potential exists for substantial economic benefits resulting from the development of the State's hydroelectric resources. The precise magnitude and timing of these benefits remains speculation, dependent largely on demand and _ price projections extending up to fifty years in the future. That 80 such benefits probably will occur at one point or another, however, and to one degree or another, does not seem to be the issue. Should current long-term price projections and feasibility determinations prove accurate, several distinct types of economic benefit are expected to derive from hydro power development such as that in the case of the Four Dam Pool. 24 Chief among potential benefits are the following: o Cheaper power in future than thermal alternatives o Insured, long-term rates o Guaranteed power supply o Surplus generation capability o Potential rate subsidy in early years Cheaper Power - Due to the unstable recent history of oil prices, future oil price speculation is risky at best. However, the Department of Revenue is expecting oil prices to begin escalating in real dollar terms in the early 1990's, and, by the year 2000, they expect a continuing real growth of 1% per year.?> If these expectations hold true, hydro power recipients will, in the future, enjoy cheaper power than they would if relying on alternative sources. Insured Long-term Power Rates - Once long-term power sales agreements are signed with the FDP communities, those rate payers will begin to enjoy the security of guaranteed long-term, stable rates. Again, if the assumptions relative to the cost of future thermal power holds true, the FDP communities will be insulated from the fluctuating cost of fuel and will enjoy sustained low cost power. As an example of the recent fluctuations in the price of diesel fuel, 81 Table XXV, below, shows the cost per gallon of No. 2 diesel fuel and the percentage change in that cost from 1979 through 1984, in the Anchorage area. The recent instability of prices from year to year is only too evident here. Table XXV No. 2 Fuel Prices - Anchorage (Wholesale Price per gal.) Percent Year Rate Change 1979 $0.55 1980 0.89 +61.80 1981 105 +17.98 1982 1.02 -02.86 1983 0.88 135073 1984 0.89 +01.14 Source: Chevron USA, 1985. Guaranteed Power Supply - The very nature of hydro projects themselves (i.e. long project life expectancy - usually more than 50 years, unlimited supply of water power, and independence from outside cost factors) usually guarantees participating communities have, through the building and operation of these projects, and aside from any kind of rate structure benefits, a guaranteed supply of power for years to come. The FDP communities can now count on this benefit. Surplus Generation Capability - A comparison of installed capacity to 1984 demand indicates that each of the FDP projects has a surplus generation capacity of at least 50%. Terror Lake 50% Solomon Gulch 61% Lake Tyee 73% Swan Lake 83% = 82 Surplus generation capability may stimulate economic development in a community, attracting new business and employment. Although surplus power capacity, in and of itself, would not trigger development, it could help tip the scales in some. situations. This potential is not an insignificant benefit at the local level or, if interties are contemplated, the regional level. All of the FDP communities, for some years, will be able to point to this bonus when development prospects are discussed. Subsidy In Early Years - With many large power projects, the "up-front" or early years are the most costly to the rate payers as debt is then at its highest and rates tend to escalate. The concept of rate stabilization, which addresses this problem in the form of a rate subsidy in early years, has, in the past, been discussed with respect to the FDP communities. A subsidy appears unlikely to find its way into the long-term power sales agreements currently being negotiated between the APA and the FDP participants. State funding for rate stabilization has also figured in planning for the Bradley Lake and Susitna projects. These funds, whether in the form of a outright grant or long-term, low interest loan, could be considered a direct rate subsidy. E) Current Rates As stated earlier, the Alaska Power Authority is currently selling power generated by the Four Dam Pool projects to the involved utilities, under short-term temporary agreements, while interim agreements are being negotiated and until long-term Power Sales Agreements are signed. Consequently, the average residential power rates presented below are subject to change at any time. Table xXXVI provides 83 average residential power rates for the first 750 kwh for FDP area rate payers. For purposes of comparison, average power rates derived from other power sources (diesel oil, gas and coal) are also given for selected areas in the state. Also shown are hydro rates for two Pacific Northwest areas of the United States and two mixed power electric rates from the lower 48, again for purposes of comparison. The figures in Table XXVI were obtained by averaging the selected utilities' filed block rates for the first 750 kwh for residential power. Here a note of caution: when comparisons are made between different areas and various power sources it should be remembered that these average power rates are exclusive of influencing factors such as fuel surcharges and credits, customer service or minimum monthly charges, power cost equalization assistance, etc. These factors must be taken into consideration when determining actual rates paid by utility customers. As can be seen, FDP average power rates range from a low of $.086/kwh in Ketchikan to a high of $.187/kwh in Glennallen. The FDP rates are slightly higher than other hydro rates (i.e. Juneau, which has the lowest average per kwh residential power rate in the State), and also higher than natural gas power rates enjoyed in the Anchorage, Kenai, Homer and Mat-Su areas. FDP rates, except for the higher Valdez and Glennallen rates, are comparable to the oil/coal rates experienced in the Fairbanks area. All of these rates, whether for hydro, gas or coal generated electricity, fall into the range of between $.086 and $.187/kwh and are, of course, lower than most of the diesel generated power rates experienced in rural Alaska. An attempt was made to gather and compare residential rates for hydro power in the continental United States. This task proved to be very difficult; most utilities utilizing hydro 84 Table XXVI Selected Residential Power Rates (As of December, 1984) Community Avg. kwh Rate Ketchikan -086 (Swan) Petersburg -091 (Tyee) Wrangell -137 (Tyee) Valdez -147 (Solomon) Glennallen -187 (Solomon) Kodiak -168 (Terror) Juneau -044 Skagway 119 Washington State -041 (7 Counties) Eugene, Oregon -026 Anchorage -055 Barrow -120 Homer -064 Kenai Ninilchik Soldotna Sterling Fairbanks -083 Delta Junction oO Healy Nenana North Pole AVEC Communities* BU?) Allakaket -600 Bethel 756 Cold Bay ob22 Dillingham 3a20 Egegik 532 Iguigig -581 Kotzebue ~257 McGrath ~328 Nenana -110 Rampart -600 Sacramento, Cal. -120 New York, N. Y. -140 Power Source Hydro Hydro Hydro Hydro Hydro Hydro Hydro Hydro/O0il Hydro Hydro Gas Gas Gas 0il/Coal 0il/coal oil oil oil oil oil oil oil oil oil oil oil Mix Mix Average rate for first 750 KWH consumption each month. * Includes 48 Villages Source: APA, APUC, Various Utilities 85 27 do so as part of a mix of energy sources and, consequently, do not break out retail prices according to power source. Certain regions of Washington and Oregon are exceptions. Hydroelectrically generated power rates in those areas, are lower than the FDP rates. Mixed rates (New York City and Sacramento) are relatively comparable to rates paid by FDP customers. The rates presented do seem to indicate that those Alaska residents living in proximity to State-owned hydroelectric projects (FDP participants) do enjoy electric rates which, although certainly not the least costly, are among the group of rates which fall significantly below those of oil-generated power rates experienced by the State's rural residents. In the case of the FDP communities, however, it cannot be said that hydroelectrically generated power automatically assumes low electric rates, for the simple reason that current FDP rates, as stated earlier, are interim rates and subject to change at any time. It can be said, though, that residing in urban areas of Alaska will almost guarantee relatively low electric rates, regardless of the power source. Almost all of the urban areas of the state currently enjoy comparatively low power rates, whether the source be hydro, natural gas or a mix of coal and oil. Rural rate payers, however, those residents heavily dependent on diesel generated power, pay the highest electric rates in the State as can be seen by the rates for 58 rural areas represented in Table XxXVI. Factors including lack of economies of scale, remoteness, transportation costs, etc. account for the disparity. One response to this situation is the Power Cost Equalization Program (PCEP). Although PCEP helps 86 alleviate some of the burden of high diesel costs, rural residents still pay more for electric power than most urban area residents. It seems apparent that, although recipients of hydro power do enjoy relatively low rates when compared to rates paid for diesel oil in more northern areas of Alaska, these low rates are not solely attributable to hydro power as coal and gas generated power is also cheap. Low cost electricity seems also to be a function of market size, with urban rates, as indicated herein, much the lowest in the state. However, it should be again noted that hydro consumer rates shown are temporary and, when PSA's are implemented, could climb sharply. F) Distribution of Benefits The scale of actual State appropriations for hydropower in Alaska is revealed by the following approximate figures. ae Hydro Appropriations Through FY 86 4-Dam Pool Appropriations Solomon Gulch $ 53,000,000 Swan Lake 74,115,000 Tyee Lake 82,464,000 Terror Lake 86,650,000 Loan to ADCED for FDP 210,000,000 Subtotal $506,229,000 Other Existing Hydro Green Lake $ 15,000,000 Salmon Creek 3,200,000 Subtotal $ 18,200,000 Other Proposed Hydro Susitna $415,310,800 Bradley Lake 118,080,000 Smaller Hydro 28,500,000 Subtotal $561,890,800 TOTAL $1,086,389,800 87 In all, $858,389,800 has been appropriated to APA for hydroelectric projects in one form or another through the end of the 1985 legislative session. The sum of $210,000,000 was also appropriated as a loan to the Alaska Department of Commerce and Economic Development for the Four Dam Pool, bringing the overall total appropriated to State agencies for hydroelectric projects to approximately $1,068,389,800.-" Of this total, roughly 53% ($561,890,800) has been appropriated for projects yet to be built (this includes both Susitna and Bradley Lake, some appropriations for which have been legally contested, as well as smaller proposed projects scattered throughout the State.) Approximately 47% ($506,000,000) has been appropriated for the Four Dam Pool. The remaining amount, $18,200,000, has been appropriated directly to communities for two smaller projects, Salmon Creek near Juneau and Green Lake in Sitka. At present, the "pool" of current State-owned hydro power recipients (FDP participants) is approximately 31,000. Given the total of $506,000,000 appropriated for the Four Dam Pool as of 1985, a figure of approximately $16,330 per capita of state money has been appropriated for citizens served by the FDP. If one desires to exclude the ADCED loan, then the per capita figure declines to about $9,550, still a substantial amount. Until the size of the pool changes (i.e. until more residents become real beneficiaries of hydro power, in one way or another) these figures will not change. Additionally, FDP power users will be the recipients of a de facto rate subsidy as the State will realize less than a market rate of return on its final loan through ADCED. If $16,330 per capita were channeled to users of diesel fuel (as the sole source of electrical power), roughly 77,000 residents, the amount would equal approximately $1,143,100,000. Currently, the Power Cost Equalization Program, which is directed at users of diesel 88 fuel has an annual appropriation of $21.7 million. Small annual grants for electrification are also available to those residents, almost exclusively rural, who are dependent on diesel fuel for power. These program appropriations, taken together, do not in any way approximate the per capita appropriation for hydro discussed above. Review of the State's current major hydro projects shows clearly that the residents and communities participating in those projects either are or will be the primary, if not sole, beneficiaries of their utilization. To a large extent, of course, this narrow disbursement of economic benefits is due, for the most part, to the geographic structure of the State. The geography of Alaska generally prohibits the use of long-range transmission grids. Without the kind of cross-regional transmission grid such as that enjoyed in the lower forty-eight states, for example, it is virtually impossible to directly distribute hydro benefits in the form of electricity to other regions in Alaska. The fact remains that the spread of hydro benefits is confined to a relatively small population of beneficiaries in Alaska. Currently, only about 6% of the total State population are enjoying the direct benefits of large-scale hydro, through the Four Dam Pool. The question remains open, therefore, as to whether and how residents of the other regions might be included in the enjoyment of these hydro power benefits. In considering approaches to more equitable distribution of hydro power benefits, it may be helpful to emphasize that such benefits do not constitute a kind of currency or coin that can simply be handed out in differing amounts to different combinations of recipients. In effect, the direct benefits of hydro power development--cushion against rate shock, rate savings, guaranteed power source, economic 89 stimulation, etc.--cannot themselves literally be shared or redistributed. Ketchikan cannot "give" part of its potential future rate savings to Kotzebue or to Akhiok. In this respect, if redistribution is to be the goal, it may become necessary to think in terms of benefit "equivalencies". By this is meant some other, indirect means of compensating regions or communities that simply by happenstance are distant from the location of State-owned resources and, thus, the benefits therefrom. One example of this type of indirect compensation or approximation of benefit equivalency is the Power Cost Equalization Program, discussed earlier. Other, similarly constructed means of compensation are discussed in Chapter VII. Footnotes 1. House Research Agency, Power Project Development and Financing in Alaska, Report 82-C, January 1983. 2. Ibid. 3. Ibid. a John Whitehead, Hydroelectric Power in Twentieth Century Alaska, 1983. Se Mike Hubbard, Alaska Power Authority, interview, 1/17/85. 67 This rate was estimated by employing the formula to calculate the wholesale power rate for a given contract year, presented in Exhibit E of "Long Term Power Sales Agreement Four Dam Pool - Initial Project of the Alaska Power Authority", utilizing data provided in Exhibit D and considering the community contribution required by section 5 (repair and replacement fund - $500,000 annually) of that document and with FY 86 Operations and maintenance costs ($5,027,000) estimated by APA (Mike Hubbard, 10/14/85). hae Jim Griffin, Legislative Audit, Alaska State Legislature, 4/5/85. 8. Ibid. 9. Petersburg Municipal Utility also operates a small hydro project at Crystal Lake. 10. Mike Hubbard, op. cit. Lise uamy, Gri ttin es Opeics tr. 2 eee dds 13. John Longacres, APA, interview, 4/4/85. 14. Mike Hubbard, op. cit. Seaepod mnGrt tan Open Cat. 90 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. Ibid. Mike Hubbard, op. cit. Jim Griffin, op. cit. Ibid. A fuel cost adjustment can show up as a credit or a charge on a monthly electric bill, depending upon the price of oil over the billing period. Specific fuel costs are usually built into basic rates. If a utility's built-in base price is higher than the current price of oil (which is adjusted approximately every six months) the difference will result in a billing credit. If the price of oil is higher, a per kwh charge is levied. The total amount of fuel used and the number of kwh's sold also play a part in determining the fuel surcharge. This practice came about as a response to fluctuating fuel prices. Currently two FDP participants, Valdez and Glennallen, are enjoying a $.0061/kwh power cost adjustment credit. Karen Rosen, APUC Interview, 1/17/85 and 2/4/85. Jim Griffin, op. ci¢. Ibid and AS 44.83.410-420. Ibid. It is generally accepted that the potential benefits listed may often be associated with hydro projects. Chuck Logsdon, Petroleum Economist, Alaska Department of Revenue, interview, 4/22/85. To obtain these percentages, megawatt capacity (MW) was translated into megawatt hours (MWH) and gigawatt hours (GWH) were translated into MWH. Installed MWH were divided by MWH annual demand, to arrive at unused capacity. Demand figures were taken from House Research Report 82-C. Table XXVI utility sources: Alaska Electric Light and Power, Anchorage Municipal Utility, Alaska Public Utilities Commission, Chugach Electric Association, Copper Valley Electric Association, Eugene (Oregon) Water and Light, Fairbanks Municipal Utility, Golden Valley Electric Association, Ketchikan Public Utility, Kodiak, Electric Association, New York State Power Authority, Petersburg Municipal Utility, Puget Sound Power and Light, Sacramento (Ca.) Municipal Utility, Wrangell Public Utility. Jim Griffin, op. cit and AS 44.83.410-420. The total for Susitna and Bradley Lake includes appropriations called into doubt by legal challenge. This loan appropriation has been included because, although it is a loan, it does represent a large quantity of funds tied up in the FDP projects and, consequently, not available for other uses. Additionally, the expected’ rate of return on the proposed FDP agreement is in the 5-6% range (Gordon Harrison, Associate Director, Office Management and Budget, interview, 10/9/85), which is below current market rates and thus constitutes a subsidy. 91 Chapter VI COMPARATIVE ENERGY COSTS A) The Relationship Between Fuels and Energy Four major sources, natural gas, coal, fuel oil, and electricity, fulfill Alaskan demand for energy. Each of those sources have been examined in detail in preceding chapters, the intent being to identify how the use of Alaskan resources employed for certain types of energy production have benefitted residents of the state. In each case, we pinpointed the users of particular resources, especially State-owned resources, and direct economic benefit accorded to groups of users of that resource, relative to other Alaskans. We based our comparisons on the relationship between national and Alaskan markets, as well as scrutinizing intrastate associations. For example, we found that natural gas users in Alaska enjoy a significant price advantage over comparable national gas users. This was the only meaningful comparison we could make, since gas is used only in two areas of the state. Oil prices varied widely across the state, with the highest prices being found in the areas most remote from product sources, whether of instate or imported point of origin. The relationship between the prices Anchorage consumers pay for thermal energy produced with natural gas and the prices paid by Barrow users of the same resource is fairly obvious. The linkage between the costs of natural gas to end users in Anchorage and the prices paid by Dillingham residents to spaceheat with fuel oil is not so readily apparent, however. In this section, clarification of the varied costs of using different fuels for thermal purposes, with distinctions between different areas of the state, will be attempted. 92 Although we have concerned ourselves with the costs of electricity also, the final costs of power to consumers have been established in some detail in a number of sources and interested readers are referred to them for further information on the subject.+ We will, however, make note of electric power costs. In order to illustrate price comparisons based upon energy source, we have converted the price per unit of each of the fuels considered into the price per British thermal unit (BTU) .2 Using BTU's as the standard, we may compare what the Fairbanks resident heating with oil pays to the cost incurred by a Juneau homeowner with electric spaceheating. The end product, spaceheat or hot water, is measured in common terms thus. B) Thermal Energy Costs Across Alaska Table XXVII, and the accompanying chart, offer a sample of thermal energy costs in the state. While not an exhaustive survey of energy costs, the table and chart together represent a sound basis for making fundamental comparisons of the cost of similar amounts of thermal energy in an inter-fuel and interregional context. The data are from 1983 for consistency of data across various fuels represented. The impact of State or Federal energy programs presently in operation is not reflected. The authors believe that the fuel prices quoted are valid in establishing differences between regions, if not on a precise footing, then on an order of magnitude basis. The Table XXVII lists the costs of consumer purchase of one million BTU's of thermal energy for each major source. Different regional or community breakdowns are utilized for the various heating stocks; natural gas and coal reflect 93 Table XXVII Comparative Cost of Thermal Energy Sources (1983 $/million BTU) Community/Region Residential Commercial Natural Gas Barrow 2.09 2.09 City of Kenai 2.85 2.41 Anchorage/Mat-Su 3.15 2.59 Coal Fairbanks 7.01 6.71 Electricity Juneau (AELP) 14.86 16.34 Anchorage (AMLP) 16.79 15.03 (CEA) 17.05 15.62 Sitka 21.13 23.85 Kenai Pen. 21.77 16.91 Fairbanks (FMUS) 23.09 23.62 Mat-Su 24.47 18.81 Ketchikan 25.93 25.32 Fairbanks (GVEA) 31.03 26.75 Rural Alaska* 81.72 81.72 Fuel oOil# Wrngll-Ptrsbg 12.15 Aleutians 15.39 Haines 12.60 Dillingham 15.72 Sitka LZ a7k POW-O. Ktchkn 1S iie Fairbanks 13.04 Kodiak Island 16.50 Valdez-Cordova 13.16 Bethel 20.07 Anch. & Kenai 13.38 S.E. Fairbanks 20.74 Juneau 13.49 Yukon-Koyukuk 21.07 Mat-Su 13.94 Wade Hampton 23.08 Ketchikan 14.50 Nome 23.30 Skgy-Ykt-Angn 14.94 Kobuk 23.42 Bristol Bay 15.39 North Slope 23.53 * Average cost per PCAP eligible kwh for all consumption. # By census areas, priced by volume, not consumer category. Assumptions: Natural Gas - 1,000,000 btu/mcf; 75% efficiency. Coal - 15,400,000 btu/ton; 60% efficiency. Electricity - 3,413 btu/kwh; 100% efficiency. Fuel Oil - 138,000 btu/gal; 65% efficiency. Utilities; fuel distributors; APA, 5/83; Cornell University, 1980; RRA, 1983; ADCED, 1984. Source: 94 virtually complete consumer populations and electricity and fuel oil are general outlines rather than an attempt to construct a comprehensive, detailed picture of the situation (both from data presented in earlier chapters.) What is the heat value of a million BTU's (MMBTU)? To draw a simple illustration, if, during one month, a family used 100 gallons of fuel oil to heat their home with a furnace operating at 65 per cent efficiency (meaning that the heat produced by its burner was equivalent to 65% of the potential BTU's in each gallon of fuel; efficiency varies from furnace to furnace, 65% is a representative figure of heater efficiencies as are all those employed herein), the heat output would be about nine million BTU's. So, one million BTU's would be about three or four days worth of heat. In 1981, residential thermal energy consumption in Alaska averaged about 65 MMBTU per capita.? There were significant gaps in the cost scale for different fuels in 1983. Natural gas was far and away the cheapest fuel, costing from about one half to one third as much as its closest price competitor, coal, and five to seven times as little as its most often employed rival, fuel oil. As we have noted, gas use is restricted to the Cook Inlet and Barrow, providing cheap energy in both places. Coal fired thermal energy is centered almost exclusively in the Fairbanks area. Nearly all coal is burned by institutions such as military bases, utilities, and the University of Alaska. Employment by individual consumers has been relatively minor, despite the fact coal is nominally less expensive than the alternatives, fuel oil or electricity. Most of the state, geographically speaking, relies upon fuel oil for spaceheat. The price range for oil was fairly small in urban areas in 1983, with a spread of perhaps just over two dollars per MMBTU. In rural Alaska, on the other hand, 95 1983 Residential Energy Costs $/mmbtu 105 5 904 7575 $/mmbtu 3 —t SSS SSSR SET PSSSAS YSIS SSS SSSI AS SEN SR RRR RRC RORONG (OOo ad WABABwaBasasaeay SSNS Kotzebue —R&Se oe ee SSSI SSSA) IWYYYYyI [XA xxx] <x Xe xX] Anchorag Barrow Kenai Juneau Fairbank Dillingh Cordova Wrangell Aniak Unalakle Nuigqsut ranged from Wrangell-Petersburg's $12.15/MMBTU to the North Slope's $23.53/MMBTU, a difference of over 90%, with other rural areas falling betwixt. Oil spaceheat is the most expensive of the heat sources. Although the cost of electric spaceheat would be more expensive in most areas, its actual use is restricted almost totally to urban areas. Even there, only in Juneau (where it is relatively common) was electric space heat comparable to oil heat in cost, being only about 10% dearer. With the exception of Barrow, as a consequence of its natural gas supply, rural areas have paid considerably more for their thermal energy than have urban centers. The same can be said for electric power. On a BTU basis, 1983 energy consumption, according to the statistics of Tables II and III, consisted, roughly, of 20% electric power and 80% energy derived from other sources. On a regional basis, electric power use ranged from about 30% of consumption in Southeast to about 12% of use in the Arctic/Northwest, with converse lows and highs in thermal 96 energy use in the two regions. Electric BTU's were 16%, 22%, and 23% of the total in the Interior, Southwest, and Southcentral regions, respectively. The cost figures displayed in this section are, so to speak, vacuum-packed. They do not represent true energy costs to the residents of different regions and users of different fuels. They do not take into account actual usage patterns based on climate, individual home size and construction, or burner efficiency. They are pure representations, however, in that they demonstrate what a consumer in Nome must pay to use a certain level of thermal energy in a fashion that allows that cost to be measured against that of a consumer in Kenai for equivalent energy use. Thus a valid comparison of costs, given equal conditions of fuel BTU content and burner efficiency, can be made. The inescapable conclusions are that fuel oil costs more than any other energy thermal source in general use and that rural Alaskans rely more on oil than other Alaskans do and thus pay more for comparable ene consumption than do urban Alaskans. That, as has been demonstrated, is at least partially due to the local unavailability to rural Alaskans of ener resources owned by the people of Alaska. Footnotes als The Rural Research Agency published a series of memoranda from February through May, 1984 and the Alaska Power Administration annually published Alaska Electric Power Statistics through 1984. 2. The BTU is the standard measure of heat energy; one BTU is the amount of energy required to raise the temperature of one pound of water by one degree fahrenheit. Se ADCED, 1983 Energy Report, 1983, p. II-21. S77) Chapter VII OPTIONS FOR LEGISLATIVE ACTION How imbalances in distribution of concrete benefits derived from the accessibility and pricing of Alaska's energy resources, as identified in the preceding chapters, might be redressed or mitigated is the subject of this chapter. The imbalance in electric power costs resulting, in part, from the accessibility of cheap energy sources in many parts of the state has already been addressed by the implementation and subsequent revisions of the Power Cost Assistance Program, now known as the Power Cost Equalization Program. The program "equalizes" the costs of power from utilities which rely principally upon diesel fuel for generation with the costs of power from urban utilities which have access to cheaper fuels such as coal, natural gas, or hydro. It does not truly equalize rates, however. The average urban rate was about $.07/kwh for 1984} kick in until a utility's rates surpass $.085/kwh. Nor are and power cost aid does not all costs to utilities or consumers eligible for assistance. The PCEP does not ameliorate spaceheating costs for homes without electric space heat, which, as we have seen in the first chapter of this report, are the vast majority. The monthly kilowatt hour limit eligible for assistance is not substantial enough to allow spaceheating on a significant basis in most places. The central economic issues are those of resource access and of market size. As it stands now, only those communities with direct access to reasonably priced resources, such as natural gas in the Cook Inlet area, have any hope of receiving any direct economic benefit from use of those resources. Interregional transportation and distribution systems, except for fuel oil, do not presently exist. Even 98 local systems are often lacking. The community of Nuiqsut is only some fifty miles from the 30 trillion plus cubic feet of natural gas reserves of the Prudhoe Bay and Kuparuk River fields, where gas is produced and utilized, yet derives no benefit at all from that resource (four tcf of which is the State royalty share). Nuiqsut is thus much more proximate to these reserves than are most of the Cook Inlet consumers to the gas fields which provide them with such staggering price derived benefits. The impediment to the development of a gas transportation system to Nuiqsut is the lack of a market large enough to attract a commercial interest. Some utilities are private enterprises, in search of a profit. Nuiqsut, with its population of just over 300, does not offer the revenue opportunity required for such a profit. Other utilities are cooperatives or government entities which must have a membership or tax base large enough to support their construction and operation. Even in Barrow, with a population ten times that of Nuiqsut, it is extremely unlikely that the community would be enjoying the use of low priced gas had not the source been developed and the distribution system constructed by the federal government. A) Program Options What can be done to offer to Alaskan communities without access to local energy resources and which suffer economic disadvantage as a result, some of the advantages enjoyed by those communities with such access? There are numerous options which policymakers may consider, some of which we will outline below. The options fall into two general groups: Ee) 1) The provision of financial assistance to residents suffering an economic disadvantage. 2) The provision of energy resources or products to such people. Keeping in mind that each plan will require a different design to establish eligibility, the form assistance would assume, the method of distribution, and ultimate costs to the State, several are worthy of consideration. If they, in part, are familiar, it is because some are not original to this document and others, while arrived at independently, have also been so arrived at by others. Our recommendation of the most practical alternatives will follow discussion of all options. That will include our estimate, if such can be made, of associated costs over the next five years. (1) Devotion of Royalty In Value Revenues: A portion of the revenues derived by the State from royalty in value payments from energy resource production would be set aside for the provision of energy resources or products to communities or individuals eligible for electric power and spaceheating assistance. Such a fund could take two forms. One would involve the use of these revenues for the construction of transportation, distribution, storage, and/or treatment facilities required to make energy resources or products available at reasonable cost to eligible locations. The second would establish a fund which would reduce the costs of energy sources marketed through the present structure by offering State assistance either at the point of generation or point of consumption for electric power (the former is accomplished now by the Power Cost Equalization Program) or at the point of treatment/refining, point of sale, or point of consumption for thermal energy (natural gas, coal, or 100 (2) petroleum products. Means of setting aside these funds include: a continuing appropriation (per PCEP), annual appropriations, or a constitutional dedication of funds. Any of these approaches would face challenges. Constitutional amendments are not routinely approved, either by the Legislature or the electorate. Annual appropriations would certainly undergo scrutiny informed by the political and revenue conditions of the day. The same would hold true for continuing appropriations, which, as noted previously, also would rest on tenuous constitutional ground as a result of the prohibition against dedication of funds. Aside from these fundamental problems, program quidelines similar to those established for the Power Cost Equalization Program for consumption limits by individual thermal energy consumers, ceilings and floors on the costs eligible for assistance, benefit distribution mechanics, and cost eligibility standards would have to be part of the proposal. Reservation of Royalty in Kind Resources: A portion of in kind royalties for energy resources (gas, oil, coal) could be retained by the State and expressly dedicated to instate use. These resources, in order to result in real benefit to Alaskans not now enjoying any direct economic benefit attributable to local resources, would have to be utilized under two conditions. First, the resources would have to be provided to distributors, refiners, retailers, etc. at a cost below current market cost, thus creating a savings which could be passed on to the end user. Second, an amount equal to the amount of royalty resource provided to the refiner, distributor, retailer, etc. would have to be passed on to eligible consumers at a cost reflecting the cost savings due to the first condition. In order to retain royalty oil and gas for these purposes, AS 38.05.183(d) 101 (3) (4) would have to be amended to require that a certain portion of royalties be retained for the uses described above and to alter the definition of "surplus" oil and gas. An addition to statute would be necessary to ensure that coal royalties be retained. The ability of the commissioner of the Department of Natural Resources to waive, suspend, or reduce royalties in certain cases (AS 38.05.135; 38.05.140 (d) and 38.05.181 (i)) might have to be subordinated to the intent of this option in relevant cases. Use of Both Royalty In Kind and In Value: A combination of the previous two alternatives would employ both royalty income sources, in kind to supply eligible communities with the necessary energy resources and in value to assist in construction of facilities. Local Resource Access and Distribution: This alternative would require that all future lease sales or lease agreements require that the resource in question, if developed and produced, be provided, if feasible, to communities in relative proximity to the lease site. Again there are at least two ways to achieve this goal. One method would require that ADNR, in planning for lease sales, study the feasibility and cost of providing resources such as coal and natural gas, which may not require elaborate refining prior to consumer use, to communities in the vicinity of a lease. Alternatively, lease stipulations could require that lessees undertake this study. If delivery was established as feasible, then costs associated with establishing the necessary systems and facilities could be borne by any one of a variety of sources or combinations thereof; a percentage of royalty in value payments from the site, levies on the profits of the lessees, or State capital grants, to cite several. The 102 (5) energy source supply could be some combination of royalty in kind (as in the second option above) and direct sales by a lessee, or just one of the two. Lease stipulations possible under current statute could require the participation of energy lessees in the construction of necessary infrastructure and the allocation of resources for local consumption at a reasonable cost. It must be recognized that such conditions would render some leases unattractive to bidders or for subsequent development, so it is likely that if lessees were required to participate, some form of recompense or incentive to them would have to be offered by the State. One method might be to forego any additional tax on the lessee if the same agreed to sell resources to communities on a cost of production basis. For petroleum products, such arrangements would be somewhat more involved since crude oil must undergo complex and expensive refining before it can be utilized for spaceheating or power generation. It would be next to impossible to require that refining facilities be built on most lease sites. Three Alaskan refineries presently supply products to the public. Required availability of Petroleum Products Refined from Royalty Oil: It is not a new idea to suggest that producers/refiners awarded State royalty oil contracts be required to make products available within Alaska. Current statute (AS 38.05.183) requires that royalty oil be found surplus to instate needs before it may be exported. All holders of royalty contracts with instate refining facilities do make such products available, including fuel oils utilized for power generation and thermal purposes. At present, this fuel oil is sold on the Alaskan market alone, none of it is exported. Should AS 38.05.183 be amended, rendering it 103 mandatory that all royalty volume be sold in Alaska, refinery capacity could process only about 54% of present volume. Incentives to expand capacity would have to be offered. Alternatively, fuel currently sold instate to communities ineligible for thermal energy assistance could be rerouted to eligible communities. This latter course hardly seems possible or desirable. In addition, restrictions on the export of royalty oil in crude form would have to be strengthened, since royalty in value volumes will not long be sufficient to satisfy overall Alaskan demand. Several problems develop in such a_ situation. First, would it be possible to restrict royalty fuels to use in the production of fuels employed in spaceheating and power generation? These two categories are forecast to be about 13% or 14% of annual consumption of petroleum products instate over the next fifteen years. So, if instate use of royalty oil could be restricted to such fuels, royalty in value volumes would be adequate to satisfy Alaskan needs until about 2000 (see Table XVI). The question is whether Alaskan producers and refiners would be willing to increase production of these fuels at the expense of other fuels and at significant capital expense. Would they be amenable to decreasing export volumes of royalty oil to the West Coast? A major restructuring of the present system of transportation, processing, and refining would likely be met with small enthusiasm by producers and refiners. The State would probably have to offer incentives to induce such a change. Whether it could offer enough of an incentive is the imponderable. If these markets and products were attractive to oil companies, they would, theoretically, already be fulfilling the need in the fashion we have described. The complexity of such an arrangement and the magnitude of this sort of uprooting 104 of the status quo would make this a difficult proposal to enact without significant State involvement. On the basis of the conditions outlined for each of the options, it would seem that two possibilities stand out from the rest of the list as deserving of more _ serious consideration. While none of these alternatives will miraculously or without cost alter the basic conditions of resource and population concentration and geographic incongruity which have led to present economic disparities, those two options, (1) Dedication of Royalty In Value Revenues and (4) Local Resource Access and Distribution, represent feasible alternatives for two salient reasons: 1. The foreseeable difficulties in implementation are lesser in number and magnitude than the other options; 2. The ability of the State of Alaska to control or influence the options is arguably greater. B) The Prospects for Local Resource Access and Distribution This course of action would not result in altering the situation as it stands now where energy resources are under production or leases have been awarded. It could offer some possibilities for local access to energy resources in the future, however. The benefits would be restricted to communities in relative proximity to resource developments. The opportunities for a concrete analysis of the potential benefits of such a program for Alaska are limited, unfortunately. Production or marketing of new energy resources, outside of the bounds of now-productive areas and 105 leaseholds, is not something that can be predicted with any precision at the moment. Too many factors, both internal and external to Alaska, come into play. Among the primary elements are world energy prices, location of the resources, costs of extraction and production, and lease terms and taxation levels.*> While these conditions are specifically cited in relation to petroleum production, they seem generally applicable to any energy resource. Circumstances must be favorable with most, if not all, of these factors. The difficulty in forecasting the interaction of all of these phenomena is of a high order. There may well be situations in the future in which the State is able to negotiate lease terms which would provide resource access to communities contiguous to producing sites. It would certainly be to the public advantage to specify lease provisions for such access now, rather than waiting until propitious situations develop. The prospect of influencing future Federal leasing, particularly Outer Continental Shelf oil and gas sales, from which some revenue will be accruing to the State of Alaska, to attain this goal should be examined, also. In this area, the possibilities of influencing Congress, which is considering this question now, to allocating some of these revenues directly to local communities may be worthy of consideration. State lease sales are scheduled in a number of areas over the next five years, but awarding of leases with appropriate provisions is but the first step in the process proposed herein. Subsequently, an assessment of the feasibility of resource provision to local communities must be completed and production must commence. An attempt to judge the end result of such a program, based as it would be on a lease by lease approach, would be speculative in the extreme. The best that can be done at this time is to note the sites of planned lease sales. Listed below are scheduled sales and some closeby communities (for illustrative purposes only) .* 106 State Energy Resource Lease Sales Sale Area Resource Contiguous Communities North Slope Oil & Gas Nuiqsut Holitna Basin " Sleetmute, Lime Village Hope Basin . Kotzebue, Shishmaref Kuparuk by Nuiqsut Cook Inlet Ls Homer, Pedro Bay Camden Bay bw Kaktovik Beaufort Sea ne Barrow, Nuiqsut Icy Cape be Point Lay Demarcation Pt. C Kaktovik Chignik- Coal Sand Point, Chignik Herendeen Kenai " Kenai, Homer Farewell " Stony River, Lime Village Bering River vw Cordova, McCarthy North Slope LJ Barrow, Point Lay East Matanuska WS Palmer C) The Basis of Thermal Energy Cost Equalization The establishment of a program similar to the Power Cost Equalization Program may be readily analyzed in depth since there are two comparable programs now operational. In addition, it is probably the simplest and, in that sense, the most workable proposal. Its benefits would not be restricted by resource location. Its major drawback is that it would involve the State of Alaska in a new financial assistance program during an era in which State revenues are on the decline. That fact will impact its practicality. The two programs mentioned include one funded and operated by the State of Alaska and one fueled with a grant from the 107 Federal government and administered by several entities. The first program, now in its fifth year of operation, is the Power Cost Equalization Program. It provides a philosophical basis in statute for achieving the goal of equity in energy costs by equalizing energy prices. The latter, the Low Income Home Energy Assistance Program, was created in 1979. It demonstrates the viability of consumer assistance plans designed to alleviate high thermal energy costs. The PCEP is codified in AS 44.83.162 - 165. It provides consumer electric power rate equalization assistance to utilities in about 150 communities, serving some 22,000 customers. > The fundamental features of the program are: - Equalization of power costs statewide to a cost close or equal to the average of electric rates in Anchorage, Fairbanks, and Juneau (actual equalization leaves assisted costs about 33% over this urban mean) ; - Assistance goes directly to eligible utilities for approved costs above a minimum and below a maximum level and is reflected in consumer bills. Both Alaska Public Utilities Commission (APUC) regulated utilities and unregulated utilities may participate. - A continuing appropriation of $21.7 million funds the program (pending legal decisions discussed earlier). Eligible costs are monitored and certified by the APUC and the program itself is administered by the APA. The Low Income Home Energy Assistance Block Grant is a federally funded program dating from the era of OPEC inflated energy prices. The program serves some 235 6 communities and about 20,000 households. The salient elements of the LIHEAP include: 108 - Assistance is based upon the need of participants, based on income (virtually all sources) and household size. Eligibility for several Federal entitlement programs, such as Food Stamps, also qualifies a household. Consumers generally must apply themselves, although some payments are made automatically. Grant amounts vary widely and are principally for home heating expenses, but may also be applied to other home energy costs in certain cases. - Payments, in the form of individual grants, may be made either to qualifying households or, in most cases, to participating energy vendors. Grants are for the period between November 1 and June 30. Regional heating degree days and local fuel costs are utilized to determine grant amounts. Participating fuel vendors number between 330 and 340. Additionally, 46 electric utilities participated in 1984.7 - Federal funding for FY 85 amounted to $11.7 million. Nearly $10 million went to the Alaska Department of Health and Social Services (ADHSS), with the remainder in separate grants to seven tribal organizations.® Some $2.2 million of the State's grant was transferred to these Native entities and another $1.1 million was transferred to the Alaska Department of Community and Regional Affairs for weatherization and conservation repairs. These features outline the State-administered portion of the LIHEAP. There are some procedural differences between the ADHSS program and the seven programs operated by Native organizations. In some communities, Native organizations serve all residents and in others, only the Native residents. In the latter, non-Native inhabitants are served by ADHSS. 109 A State sponsored thermal energy assistance or equalization program could be realized under at least basic three structures, with various permutations, depending upon the philosophical underpinnings of the program. 1) Establishment of an overall State energy cost equalization program, amending the present Power Cost Equalization Program to include assistance for thermal energy costs; 2) Establishment of a separate State thermal energy cost assistance program, based upon the precepts of the present PCEP or other precepts; 3) Retention of the present PCEP and LIHEAP structures, with the funding of a State block grant for thermal energy assistance distributed through the present LIHEAP grantees. The first option would require amendments to the present statute, creating one program to equalize statewide rates for both electric and thermal energy consumption for eligible utilities and communities. The present language for power cost equalization would be essentially unaltered and appropriate language for thermal assistance added. The second alternative would simply require the creation of a thermal energy cost assistance program without reference to power cost assistance. In all three, designing eligibility standards for thermal energy cost assistance would be somewhat more difficult than for the PCEP. The prime issues will be in defining eligibility, both for participants and fuel costs, and establishing program costs. The former would most simply be addressed, as for the PCEP, by establishing a price floor above which consumers would be eligible for assistance. This floor would be based upon an average price in urban areas, the intent would be to equalize higher rates 110 paid by rural consumers with that average. This would render thermal energy assistance an equalization program and, thus, philosophically consistent with the PCEP. In the alternative, energy cost assistance could be based upon criteria of need, per the LIHEAP. The mechanics of distribution of thermal energy assistance may be more complex than PCEP procedures. Local utilities provide a convenient and often regulated point at which electric power rate equalization can be achieved without involving the individual consumer. Such entities do not exist in the Alaskan thermal energy market, with the exception of regulated natural gas utilities. Equalization fund distributions could be directed to either of two points (as they are with the LIHEAP): - At the point of sale by local retail vendors. This would be the equivalent of the distribution scheme embodied in the PCEP and also of the manner in which the majority of funds are distributed under the ADHSS LIHEAP grant. Assurances that the State subsidy was reflected in these sales would have to be part of any legislation. At this time, distributors of fuel oil are not subject to the sort of regulation prevalent among utilities, but have been generally cooperative as regards the administration of LIHEAP grants. - At the point of consumer purchase. Individual consumers would be compensated for purchases of fuel oil directly by the State. This is the situation with approximately 16% of the households receiving LIHEAP grants through the State (another 20% receive direct, automatic payments based upon their eligibility for programs such as Food Stamps). Some concerns emerge when comparing the mechanics of the LIHEAP and PCEP. Two major aspects of operations, costs and LLL participation, suggest choices. The distribution processes for PCEP and LIHEAP dollars differ in several ways, the most significant being in the number of payments made and to whon. PCEP makes monthly distributions to less than 90 utilities. LIHEAP grants are usually made on a monthly or delivery basis of payment to more than 300 vendors and as lump sum grants to about 5,000 households. While the block grant method appears to work well enough, it involves administrative duties and costs beyond the PCEP method. ADHSS budgeted, in FY 85, some $475,000 of its federal grant for administrative expenses and employed 5 fulltime and 13 seasonal staff. Native organizations apportioned between 3% and 10% of grant monies, about $220,000, to administration and employed five or six fulltime staff and another 18-20 ° The APA and the APUC between them allocated $172,700 in continuing costs and two fulltime seasonal workers. staff and four staff devoting lesser portions of time (perhaps 10% to 60% each) to PCEP affairs.?° Much of the greater operations expense for the Federal grant agencies must be attributed to the annual processing of thousands of individual grant applications to determine eligibility and grant amount and the outreach requirements of the program. A need based program would certainly perpetuate or expand these agency administrative duties, while a cost equalization program would not do so, witness the operations of the PCEP. Additionally, the LIHEAP grant distribution structure may not be as effective as PCEP procedures in ensuring maximum participation by eligible consumers, particularly in rural areas. Requiring individuals to apply for LIHEAP grants could result in a lesser "penetration of the market" than direct payment to utilities, although the ADHSS program involves extensive outreach activities. The ADHSS program does provide for automatic payments to recipients of certain other federal benefits, but only after grants directly 112 applied for are distributed. As difficulties in obtaining timely applications from rural areas for Permanent Fund dividends suggest, information and form dissemination logistics, along with public attitudes toward government paperwork, have been obstacles to full participation. These considerations must inform selection of an administrative agency. The Alaska Power Authority, with the support of the Alaska Public Utilities Commission, administers the PCEP. If a thermal energy and power program were enacted, it must be presumed that this arrangement could continue, although neither agency has had oversight experience with a program aimed at equalizing thermal energy costs. It seems likely that the APA could administer such a program as it now administers the PCEP, if the program were similarly structured. The role of the APUC would be new to it, although the Commission does have experience regulating gas utilities. Presumably, a separate State thermal energy program would encounter the same problem. If a State block grant for thermal energy cost assistance were funded and administered through the LIHEAP organizations currently in place, these concerns would not be aroused. Other issues must be addressed, several stemming from the absence of current, reliable information on consumption and pricing of fuel oil in many parts of the state. * What levels of monthly consumption would be eligible for assistance, and for what consumer classes (residential, commercial, or public facility)? * Should all costs be eligible for assistance, or should portions be excluded, as is the case with the PCEP? * What should price levels be, both for eligibility, if any, and for actual compensation floors and ceilings? LES Would adjustments be included to allow for changes in cost factors, such as freight, labor, and volume purchases, as well as fuel price changes? Would all thermal fuels be eligible for equalization or only specific ones, based on the price and consumption patterns of each fuel? Each of these issues requires resolution in order to create a viable thermal energy cost assistance program. The final cost of a program cannot be reliably computed until then. The final chapter of this report is devoted to an estimate of the cost of equalizing thermal fuel costs on a statewide basis, based on some potential answers, chosen from the wide range of posssibilities, to the preceding questions and some assumptions required by the available information. 10. Footnotes Rural Research Agency, memorandum, Senator Faiks, 4/11/85. ADNR, Historical and Projected Oil and Gas Consumption, 1/85, p. 16. Matthew Berman, et. al., Alaska Petroleum Revenues: The Influence of Federal Policy, ISER, October 1984, pp. 51-52. ADNR, Alaska's Resource Inventory 1984, 1984, p. 11 and ADCED, Alaska's Energy Plan 1985, 2/85, pp. 22 & 123. Ernie Whitney, APA, interview, 4/16/85. Jim Dalman, ADHSS, interview, 3/22/85; Lillian Marcus, ONC, interview, 4/18/85; Alexander Nicolai, AVCP, interview, 4/30/85; Don Shircel, TCC, interview, 4/18/85; Tom Birdinground, CINA, interview, 4/18/85; Sue Lindoff, THCC, interview, 4/18/85. Ibid. Association of Village Council Presidents, Cook Inlet Native Association, Kenaitze Indian Tribe (Kenai peninsula), Ketchikan Indian Corporation, Orutsararmiut Native Corporation (Bethel), Tanana Chiefs Conference, and Tlingit Haida Central Council. Dalman, et al, op. cit. Whitney, op. cit., and Ted Moninski, APUC, interview, 4/29/85. 114 Chapter VIII THE COSTS OF THERMAL ENERGY COST EQUALIZATION Our final task of developing estimates of the annual cost of implementing a program is difficult at best with information now available on consumption and cost of thermal fuels. The information may be collectible, but the process would be time-consuming, expensive, and arduous. Cost implications would also hinge on the selection of eligibility, consumption, and cost per unit standards for the program. A principal issue is the determination of price floors and ceilings. Should these be set in such a manner intended to equalize benefits accruing to all residents of the state as a result of the use of Alaska's energy resources in general? Or should they be established to relate more to specific resources actually utilized by specific residents? If the former, it is difficult to see how the advantage that natural gas users, for example, have realized, both in comparison to national users and in comparison to the users of other fuels in Alaska, can be translated into a formula designed to compensate, as it were, the unfortunate many who have not had access to this energy source. Although this approach may be in keeping with the general tenor of the finding of this study, it is clear that it would be far simpler to devise a program based on the differences in costs of specific fuels on an interregional basis within the state. This approach resembles the Power Cost Equalization Program most closely, in intent and, presumably, in final practice. None of the options we have discussed is without problems, but a plan to equalize thermal energy costs based on the comparison of costs and consumption of the same fuels within Alaska would offer the best opportunity to construct a workable assistance program. 115 Precision of cost estimates of programs such those described in the last chapter must be limited by information shortcomings. Some of the items specified as likely to be part of any Thermal Energy Cost Equalization Program (TECEP, if we may be so bold as to coin an acronym) will not be included in our estimates. The following provisions, all elements of the PCEP, which strongly influence final program costs, will not be addressed in detail: * Per capita or other consumption limits; * Price ceilings; * Fuel cost eligibility restrictions. Each would operate to reduce TECEP costs. These cost and consumption controls that policymakers will want to consider as they ponder the merits of the program; an infinity of scenarios based on different standards could be devised. A) Consumption Encouraged? Any time a program of government assistance such as this is proposed and debated, a standard and understandable argument in opposition holds that reductions in the effective consumer price of energy resources or products will encourage increased consumption. It is further argued that the consequent impacts will likely include pressure on supplies and on distribution systems and, ultimately, increased program costs. These concerns must be the object of careful reflection. Conventional economic logic would certainly generally suggest increased consumption in response to reduced prices for consumer energy. 116 This sort of situation has yet to develop as a result of the creation of the PCEP. Price declines attributable to the Power Cost Equalization Program have not yet triggered corresponding increases in consumption. In fact, it appears as though annual increases in rural electric consumption from the mid to late 1970's, prior to the inception of the Power Cost Equalization Program and its predecessors, may have greatly exceeded consumption increases from 1981 to 1984, after the inauguration of the subsidy. Consumption increased drastically during the first period while prices were also skyrocketing. For example, From 1974 to 1978, household power consumption in the Alaska Village Electric Cooperative's (AVEC) 48 communities climbed an average 9.5% 1 a guly 1985 review by this agency of power usage in fourteen rural annually, while prices were rising 16.7% each year. communities (including the major regional centers), AVEC, and the Tlingit and Haida Regional Electrical Authority, showed that 1984 average residential . consumption was essentially unchanged from 1982 and 1983 usage, despite the fact that the inauguration of the Power Cost Assistance Program caused rates to fall by more than 30%, on the average, in a single year as utilities joined the program.” Nearly all of the 67 communities included in the review are PCEP participants. While this trend cannot now be regarded _as_ conclusively established, no reliable information suggesting that power cost assistance has encouraged increased consumption has at present been developed. Detailed research is necessary to identify the true response of rural consumers to price cuts (their price elasticity of demand, as it were) occasioned by the PCEP. It is certain that many other unrelated factors strongly influence income disposition in rural Alaska. These factors must be identified and valued in comparison to costs of increased power consumption. This manner of investigation promises to be interesting and difficult. 117 B) Cost Calculations Fuel oil is the only thermal energy source utilized extensively in all regions of the state. It is the fuel of necessity in all areas of the state in which high costs of energy, as indentified in Table XXVII, have been the norm. That being the case, our computations of the cost of a thermal energy cost equalization program will be based on the costs of "equalizing" fuel oil costs across the state, effectively restricting eligibility to that energy source. Calculation of the cost of a TECEP will require an initial assumption on our part. Fuel oil price data are not entirely consistent in a chronologic sense, with information for individual communities spanning the period 1983 to 1985. For most locations 1984 or 1985 prices for No. 1 fuel are recorded, but in some rural communities, particularly in the Southwest region, prices are current as of 1983 only. Price in rural areas does seem to have been more static than in urban communities, which have seen decreases, mostly, of up to 10% since 1983. We have utilized the most recent prices available in our computations, assuming no change in dated prices. The first step is the identification of an eligibility floor for the TECEP. In choosing a price floor for program entry, we have sought a point below which prices can be termed "normal" for urban markets and the vast majority of Alaska's population and above which prices can be termed excessive, in relation to those below it, following the philosophy of the PCEP. The eligibility floor chosen for analysis is $1.35/gallon of No. 1 fuel oil. This figure was selected by pinpointing the highest fuel price in an urban area ($1.23 in Eagle River). Then, we arbitrarily added ten percent to that amount to arrive at the $1.35/gallon eligibility entry level. The rationale for this approach posits that rural consumers should expect to pay somewhat more for fuel as a 118 result of general circumstances discussed previously. The floor price, if a program is initiated, will certainly be subject to negotiation and almost as certainly will be something other than this choice. The $1.35 marker is meant only to provide the basis for an illustrative cost example. The costs of a TECEP can be estimated by following a relatively simple five step calculation which is explained below and following that summarized in a few condensed figures and calculations (see Appendix for full data): 1) Consumption was allocated to each region and community using data from three sources. The consumption patterns established in Table II were utilized to apportion ADNR's forecasts of fuel use (Table XVI) to each of the regions utilized herein. 2) Total regional consumption was reduced by the proportion of the total 1983 population represented by : in which fuel prices* fell at or below the $1.35 level (78 such communities were identified). communities 3) Population estimates in eligible communities (141) were employed to yield an estimate of the portion of regional consumption assignable to each location. 4) The floor price was subtracted from the actual price in each community to develop the amount per gallon eligible for assistance; 5) Finally, consumption per community was multiplied by this eligible amount and all such products summed for the total annual cost. In regions in which the total eligible population was not contained in communities for which prices were available, the total was increased a proportionate amount to reflect this fact. aL 1985 Eligible Eligible Region Consumption Portion Consumption Southeast 19.62 mmgal 4.84% -95 mmgal Interior 85.35 11.47 9.79 Arctic/NW 13.73 100.00 13.73 Southwest 21.07 54523 11.43 Southcentral 36.72 95 35 Total 176.5 mmgal 20.92% 36.25 mmgal We have used population distribution as a proxy for direct community fuel consumption information. The assumption is that, having established regional consumption patterns, this approach is an accurate one. Nearly 21% of projected 1985 consumption would be of fuel priced in excess of $1.35 per gallon and eligible for assistance in this example. The cost of providing such assistance is summarized below. Eligible Average Assistance Region Consumption Price Amount (000) Southeast -95 mmgal $1.46/gal $ 108.9 Interior 9.79 2.02 6,574.0 Arctic/NW 13.73 2.00 8,992.2 Southwest 11.43 1.82 5,319.6 Southcentral 35 Died S35 TOTAL 36.25 mmgal $1.93/gal $21,128.2 The PCEP requires reduction of assistance by any amount of aid received by consumers from other sources (AS 44.83.162 (b)). If that provision were to be part of a TECEP, then the overall funding required can be reduced by excluding part of the grant monies distributed through the LIHEAP. 120 Our own estimate of the reduction for 1985, based upon the distribution of LIHEAP funds in FY 1984, the percentage of Native populations in areas served by Native grantees, and the exclusion of communities in which fuel costs fell at or below the $1.35 per gallon floor, is (in thousands): 1985 Costs: $21,128 .2 Excluded LIHEAP Grants: ae react Total State Funding: $17,350.5 The precise amount of assistance would be subject to the other parameters of the program and the influence of data inadequacies. Some consumption in the military or industrial categories may be included in our data. A few additional communities in the Southcentral and Southeast regions may be eligible at a $1.35 floor. Fuel oil consumption in the Interior region may actually be somewhat less since many remote communities rely heavily on wood and propane for thermal energy needs and petroleum use is likely most heavily concentrated, on a per capita basis, in more heavily populated areas. Finally, administrative costs are roughly estimated at $200,000 to $500,000, annually. To extend program costs into the future, changes in consumption forecast by ADNR are combined with predictions of inflation and of oil price changes obtained from ADOR (see Chapter II). Immediate full participation in the program is assumed, although this is unlikely. No increase in consumption due to effectively lower fuel oil prices is anticipated, at least over the first four or five years. Projected program costs (excluding administrative requirements) through Fiscal Year 1991 are displayed below in thousands of dollars. 121 Year Consump Inflation Oil Price Gen'l Fund FY 86 $17,350.5 FY 87 2.8% 4.5% -5.2% 17,714.9 FY 88 3.3 4.5 “4.6 18,281.7 FY 89 1.0 5.6 -1.8 19,159.3 FY 90 2.4 5.6 0.4 20,768.6 Fda 9 eloph 5.6 1.2 22,824.7 Approximately 10% to 11% of the state's July, 1983 population of 510,544, scattered from the Arctic Ocean to Dixon Entrance, would be eligible for assistance, under this scenario. Residents of over 150 communities, where latest recorded fuel costs ranged from $1.36 per gallon in Cold Bay to $3.00 per gallon in Hughes and Venetie would be eligible for thermal energy cost assistance, at a per capita cost of about $325 in Fiscal Year 1987. For urposes of rough comparison, the PCEP now provides about a $280 annual per capita subsidy, 1984 Cook Inlet gas price differentials about $275 and hydro expenditures for the Four Dam Pool (including grants and loans, over the five fiscal years appropriations were made) about $3,300 (this does not include future subsidies resulting from low return rates on the ADCED loan), to the direct beneficiaries of each. C) Cost Reduction Measures There are several specific measures that could be part of a thermal energy program and would serve to reduce the costs calculated in the preceding section. * If cost equalization were limited to 95% of energy costs, as is the case with the PCEP, the 1985 funding requirement would be cut to $16,483,000, with like 122 reductions for each following year. In this case, FY 91 funding would be about $21,683,500. * Raising the price eligibility floor would reduce funding requirements. If the floor were set at $1.45 per gallon, the total funding required for 1985 would be limited to $14.49 million, with a fiscal year 1991 allocation then of $19.06 million. A combination of this measure and the preceding one would alter these figures to $13.77 million and $18.11 million. * A number of communities have more than one fuel distributor and prices sometimes vary widely. In Bethel, fuel prices are nearly 30 cents per gallon apart. A possible cost saving measure would limit assistance in a particular community to amounts equal only to the differential between the lowest priced fuel oil readily available and the eligibility floor. Such a proviso may, however, be viewed by some retailors and others as unwarranted interference in the marketplace. The reduction in costs associated with a community price cap cannot be readily calculated. * Coordinating energy assistance with conservation and weatherization aid, as does the LIHEAP, could result in substantial longterm savings as fuel consumption is reduced by an accelerated assault on the long lingering weatherworthiness shortcomings of rural Alaskan structures. A portion of appropriations for thermal energy assistance could be devoted to weatherization and conservation, following the example of the LIHEAP. It is clear, then, that the potential cost to the state of a thermal energy cost equalization program is strongly dependent _on the parameters of that program and could be targeted at a specific amount with relative ease. 123 Footnotes Nebesky, et al, The Impact of Rising Energy Costs on Rural Alaska, ISER, 11/11/80, p.18. RRA, memorandum to Senator Frank Ferguson, July 3, 1985. Alaska Department of Labor, Alaska Population Overview 1983, 1984; U.S. Census Bureau, 1980 Census. Karen Rosen, APUC, interview, 2/7/85: Alaska Department of Health and Social Services, "Home Energy Suppliers Participating in the Energy Assistance Program", 1985: Alaska Department of Commerce and Economic Development, Communit Ener Survey, May, 1985; Tanana Chiefs Conference, Standard Utility and Energy Vendors Agreements, 1985; Stuart Brooks, Alaska Department of Community and Regional Affairs, letter, 6/19/85. 124 APPENDIX 1985 TECEP Costs 1985 TECEP Costs stnec Cost $Mill Elgty A X Figoe “8 $/gal Comt TCos $Mill Comty rice $/gal Pp ry e Comt mmgal mmgal Cons Shar Region Comty Reg'n Pop ElgPop Share Comm'ty -0039 -1295 L339 1.35 1.35 +039 -567 -606 1.5 ees) 1.73 -026 324 35 so oo -075 -925 655 655 49 606 655 Chitina Southcentral Houston 21335 35 655 Subtotal | wmonmnsnm 1mMNOMr wow LARONOMO 1OO00000 CWUOTONN Or~TOoTon NANOHOHO Southeast P Baker Angoon Tenakee Klawock M Chuck e 3130 3130 x -95 -950 1.46 1.39 1.35 -1089 Subtotal 4 S Da ° a ®eO OM -d Sts upudg 45 a “dl DO GOD YN BBLOVGYHS NADVD DBHOOGUH HI VSODVPHAG- SADACACD OMY OMG OM- GP OHA OY 0 1 AVP O OD Utd O41 0 0 Ot 9 ae Pd OOP Oo PISSSOYD HOOMAPINS & VAVY SD GO OAR OG S SSa5ea AG O-AVVGHOP GO AVUSCHDa55o HISOSH MOUTZHRHVVORhMMAMe MOS AnNUS!|MmMmpS LPONMNODASTNOANOTRTOORYREOWMONMITEANRORNN PORK HDONMMLOMOATKANANYTOONGITIRARMOW POONKHHNMNATM LTANMNTMOOMONETOOWOOTNFHMAMIN LOOCOOONOCOCCHOCOCOYPONMOOKAAHAOSAANNMMAN LOND MM NNN NM NM Nl mM nnlninnnnwn MAMMAMAMNMAMNMNMAMNMAMNMAMNMAMMMMMMMAMMNAMMMNMMMMNM AAAI AAA AAA AA ddd ddd ONOWDOHAHNOOWWDOLOCOWUDANNHNMATOOHOAMAO OFRONONWOCDHAOMNEKRONKHAAMAMANNSTONTMO AANAO *NONONON *AD sANTOMN -NMW eee ANSt © 0 oe ort 0 0 0 0 0 0 ord © rfc 0 0 eo orf co orf eo cee PAO AE NOMNMNNNNNNAME ODN NAHOORMMUONMAMNM et +O OKO OWDD -HDO edd +m +O + raed ort te ee ee ee ee ee ord ee M8 ew ON ON ON A A Adda Ae NNN NN MNOWMUALEDNODANDNOUOADKAO-OMKANANUDAN CHWOMWMMNMNADANMNMNAWDDNAPODHAYNNMOMONN AAOOCMWHOAMHAOCADNOPTOOCHANNHHAMAANYNNON eee eee eee ee eee eee eee eee eee ee eoe -072 DO OVD DVD... 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