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HomeMy WebLinkAboutRural Alaska Natural Gas Study, Feb 26, 1997En evrman Rural Alaska Natural Gas Study A Profile of Natural Gas Energy Substitution in Rural Alaska Final Report February 26, 1997 Prepared for: State of Alaska Department of Community and Regional Affairs Division of Energy Prepared by: Mark Foster MAFA Anchorage, Alaska in collaboration with Advanced Resources International, Inc. Arlington, Virginia Rural Alaska Natural Gas Study A Profile of Natural Gas Energy Substitution in Rural Alaska Final Report February 26, 1997 Prepared for: State of Alaska Department of Community and Regional Affairs Division of Energy Prepared by: Mark Foster MAFA Anchorage, Alaska in collaboration with Advanced Resources International, Inc. Arlington, Virginia Executive Summary Natural Gas in Rural Alaska Executive Summary This study examines the economics of developing natural gas as a substitute for existing energy use in rural Alaska. The primary determinants of whether natural gas is a feasible energy alternative in rural Alaska are: the existence of a natural gas resource within a short distance of the rural community’ e the costs involved to find the resource e the cost of alternative energy sources e the quality of the natural gas field Distance from Resource to Market Not surprisingly, where natural gas has been discovered in Alaska, it has become a viable source of energy for nearby domestic markets. Examples include Anchorage, Kenai/Soldotna, Barrow, and Deadhorse. In addition, as domestic markets have grown, there have been expansions from the larger domestic markets into adjacent communities, i.e., expansion from the Anchorage bowl into Palmer/Wasilla and Girdwood. The expansion of Enstar into Girdwood was made possible by utilizing an existing transmission facility. The existing pipeline was a candidate for dismantlement and thus was available for a modest price compared to construction of a new facility. . More recently, natural gas companies have been exploring the option of transporting natural gas via truck over the road system into Homer and into Fairbanks.” In Alaska, unless a rural community is located within a few miles of a natural gas resource, either a nearby natural gas field or adjacent to a natural gas transportation system that serves markets orders of magnitude larger, it is unlikely that natural gas will be a competitive alternative with existing energy sources. Even if a rural community is located within a few miles of a natural gas field, it remains for someone to discover the resource. Costs of Exploration Because it is rather expensive on a per unit volume basis to move natural gas in the relatively small quantities required for domestic energy use in rural Alaska, a critical consideration for the viability of natural gas is the ability to find the resource in close proximity to the local market. Since the availability of natural gas is not readily discernible from surface investigation, significant efforts are required to find it. For the major oil and gas firms, an exploration program is a business enterprise - an investment with an expectation for returns primarily looking at markets that are orders of magnitude larger than the domestic ' For the purpose of this general discussion, a natural gas resource may be thought of as either a natural gas pipeline or a natural gas field. ? Applications pending before the Alaska Public Utilities Commission. MAFA/ARI page 2 26-Feb-97 Executive Summary Natural Gas in Rural Alaska markets in rural Alaska. Under this business model, it does not appear that exploration for natural gas will be driven by efforts to serve rural Alaska markets anytime soon. Nonetheless, natural gas reserves which have already been identified might become available for larger communities located along the TAGS transportation corridor - Fairbanks and Valdez - if and when world markets drive that development. In addition, exploration activities aimed at finding larger world markets may again find a field in proximity to an Alaskan community -- not unlike the current sources of supply to Anchorage, Barrow and Kenai. In contrast to the oil and gas “majors,” an exploration program for /ocal entrepreneurial independents does not have to meet traditional payback analysis to be undertaken.’ Often, the independent is attracted to prospects with a relatively low probability of success and what appears to be a big payoff. The basic ingredients for an entrepreneurial exploration program are equipment, material, sweat equity, and luck. Under this model, exploration for natural gas aimed at serving domestic Alaskan markets may occur if exploration equipment is available to local entrepreneurs at a significant discount. “Exploration is becoming, quite decisively, a __ technologically sophisticated and systematic research and development activity rather than the far more romantic but decidedly more uncertain “intuitive geology” that was characteristic of natural gas exploration until the late 1980s.” Vinod K. Dar “Management Perspective” Oil and Gas Journal January 2, 1995 A sharp entrepreneur with a good instincts, favorable pre- existing geologic information , and a higher than average success rate may be able to find a commercial prospect for as little as $1,000,000 in out of pocket cash expenses.’ Alternatively, assuming a success rate of somewhere between 10-20%, a more typical modern exploration program for coalbed methar:z may run between $5 million and $10 million, depending in part upon the amount and quality of data available prior to starting the program. Explorations programs of this magnitude effectively preclude the economic development of natural gas resources targeted at rural Alaskan markets. One way the federal government has considered to help overcome the otherwise high hurdle of exploration costs is to provide direct subsidies for exploration in the form of grants for “demonstration projects.”° Cost of Energy Alternatives For natural gas to be a viable alternative, it must cost less than the alternative sources of energy. Energy costs in Alaska are literally all over the map depending upon electrical generation technology and heating fuel. This study focuses on diesel fuel used in heating and electrical generation as a point of reference. > Some historians would point to the Gold Rush as an example of where something other than a traditional payback analysis may have been at work. * This assumes that the entrepreneur considers labor and equipment an in-kind contribution and is primarily using exploratory coreholes which may cost as little as $100,000 a piece as the direct subsurface exploration method. Also note that this report assumes that if a commercial prospect has been discovered, the entrepreneur will seek to recover all the costs associated with field development -- including labor and equipment costs that may have been considered an in-kind contribution during the exploration phase. ° For example, the U.S. Department of Energy, Morgantown Energy Technology Center (METC) has expressed an interest in funding a demonstration project at Chignik Lagoon. MAFA/ARI page 3 26-Feb-97 Executive Summary Natural Gas in Rural Alaska Diesel At long-term average prices for diesel, domestic development of natural gas appears competitive for a fairly narrow range of circumstances: e —_/Jarger rural communities (more than 500 households, population of roughly 1750 or more) located on or within two or three miles of a good quality gas field If the real long term average price for diesel fuel increases, natural gas becomes an increasingly competitive alternative. However, even if the /ong term average price for diesel were to increase 50 cents per gallon, smaller rural communities are likely to find that diesel remains the more attractively priced energy alternative. : Largely driven by the high fixed costs associated with gas field development, rural communities with less than 200 households (population of roughly 600 or more) do not appear to be viable candidates for natural gas energy substitution, unless they are located within a few miles of a larger regional center and can take advantage of lower incremental costs associated with connecting to the larger market. In addition, if the long term average price for diesel increases significantly, it is also possible that other energy sources such as coal or hydroelectric may become more competitive alternatives than natural gas depending on the proximity of the alternative resources to the particular community. Environmental Considerations While current environmental considerations such as improvements in fuel storage and handling along with reductions in emissions from diesel combustion sources appear to put considerable upward pressure on the real cost of diesel fuel use, it is not clear that this upward pressure will translate into a long term trend relative to natural gas. First, the diesel tank farm improvements may only translate into a one-time increment in annualized capital and operating costs. Second, while emissions controls may create initial incremental capital and operating costs, diesel engine manufacturers have incentives to make additional improvements in combustion and post-combustion clean- up technologies which may help offset the incremental costs of emissions standards. Finally, for the purpose of this reconnaissance study, the focus is the relative real price of diesel compared to the real price of natural gas. While natural gas has a cost advantage since it is generally a cleaner burning fuel than diesel, this advantage is not absolute. Emissions standards for NO, , particulates, CO, and Hydrocarbons often require combustion modifications for natural gas engines (both turbine and reciprocating). Indeed, in some instances post-combustion controls are beginning to be imposed on natural gas engines. Quality of Natural Gas Field Even if one is fortunate enough to find a source of natural gas, there is no guarantee that the source will be of sufficient quality and quantity to develop. For this initial screening study, the base case assumes a coalbed methane field of good coal thickness and high gas content. It appears that a good or excellent quality coalbed methane field is necessary to be competitive with existing diesel sources of energy. ° “Prime Mover Environmental Update”, Gas Research Institute, July 1995. MAFA/ARI page 4 26-Feb-97 Executive Summary Natural Gas in Rural Alaska If the gas prospect has low pressure, low permeability, or is within a thin coal seem, it quickly becomes uneconomic. Conclusion At current prices for alternative sources of energy, the development of natural gas as a substitute for current energy use in rural Alaska may be attractive where a rural community is extremely fortunate and inexpensively discovers that it resides over a natural gas or coal bed methane resource of high quality. For example, natural gas becomes competitive with diesel under the following circumstances: e rural community of approximately 1400 households (3500 population) © community is of moderate density (50 customers per mile) © community sits on top of or adjacent to a coal bed methane resource of high quality e — successful exploration program of less than $3 million As the community size drops down toward 500 households (pop. 1750) under the heroic set of assumptions to make gas viable, the unit cost for delivered natural gas increases, but the rate of increase appears to be of the same order of magnitude as the increase for the unit cost for delivered diesel-generated electricity. However, if the community size is much smaller than 500 households, or the density of the community is much less than 50 customers per mile of distribution system, scale economies favor diesel over natural gas. Thus, without the considerable good fortune of having located a community near a high quality gas or coalbed methane field, it would appear that the overall economic prospects for natural gas in rural Alaska are poor. MAFA/ARI page 5 26-Feb-97 Table of Contents Natural Gas in Rural Alaska Table of Contents EX@OCUTIVO; SUMMARY cescserecrscecssserarcsetascrescscsecestcanecacteancccsecceccsecccecssecascessaacsseansedes 2 Introduction .... Study Overview. Base Case Assumptions... Sensitivity Analysis stetectscecsvsesssorsenstarecevcscrestosestvatactsasnensssors! wsnsvsssuenceesssessosuneasursacocsetsrsornetseresecvesstoataenses Overview of Natural Gas Developme nt ...........::ccsssssseecceessesseeseseeeeeeseeeesneeee asco S Cost Estimates necncccccccccccrccorcrercrcscvenctoccvccccesvouscvorerertererereserstnterssesencsceesansvenees see) Introduction... Energy Use Profile Natural Gas Costs. Cost of Alternatives.. Analysis - Key Economic Drivers. Environmental Considerations ...........:cccsssssccssessssssssssneessesseeesssnsesssseasesssseeseeeD Resource Ownership Issues... Natural Gas Development Risks........... secneccnectesensseeteceed nesernsusenstessersns seeeeeeeeeeeO4 Reliability Issues.............:scscsseeeeee Neseseueaasenereceesensesee peusstenssranseccnececes Bevenesensesss OO) Permitting & Licensing Requirements ...........sssssssersseesseesseessessseessserseesses 69 Conclusions....... peneneereraseennnastesnssece Pessensesusscrereusetene Ressesserorsesersnassecsnncseenrnssernssers ((2, Appendices.............. senenenerensseres secatesctscsceauscerssrenesersssnnensserresscernetenceesene sesereneseeeel 4 Sources of Data/Bibliography ... Methods Used Applicable Conversion Tables .. Acronyms ... MAFA/ARI page 6 26-Feb-97 Introduction Natural Gas in Rural Alaska Introduction Purpose The purpose of the study is to develop an economic screening tool to assess under what conditions natural gas might become an attractive energy alternative in rural Alaska. The study and underlying spreadsheet model are designed to be used as a reconnaissance level guide to determine whether natural gas may be a competitive source of energy for heating and electrical generation competitive with diesel heating and diesel-fired electrical generation in rural Alaska. The study focuses on diesel as a point of reference due to its widespread use throughout the state. This study is not intended to provide an in-depth analysis of all available economic data. The intent is not to distinguish between narrowly differentiated costs but rather to separate obviously infeasible circumstances from potentially attractive ones. Cost differentials of less than 10% are not considered particularly significant in this study. Study Overview Basic Study Flow The basic study flow is as follows: il Develop “typical” energy profiles for a range of rural community sizes i Estimate the costs associated with natural gas development to meet the energy profile a) Exploration b) Drilling & Completion c) Operations & Maintenance of gas field development d) Transmission to the City Gate/Existing Power Generating Station eh Estimate the costs associated with natural gas heating a) Distribution system, from city gate to end-users, including service lines and meters b) Operations & Maintenance of distribution system c) Conversion from existing heating oil systems to natural gas heat 4. Estimate the costs associated with natural gas-fired electrical generation a) Conversion from existing diesel-fired electricity to gas-fired electricity b) Incremental Operations & Maintenance costs Ds Estimate the costs associated with diesel supplied energy a) Diesel-fired electrical generation b) Heating fuel oil MAFA/ARI page 7 26-Feb-97 Introduction Natural Gas in Rural Alaska 6. Compare the cost of energy for natural gas vs. diesel a) Electricity (¢/kWh) b) Heating ($/MMBtu) c) “Typical Residential Bill” for Energy (electricity + heating) ($/month) de Test sensitivity of key assumptions on comparison between natural gas and diesel Cost Methodology For the purpose of this initial screening, costs are developed based on a levelized revenue requirements 7 approach. Capital investments are levelized by applying an annual capital recovery factor to include the cost of capital and depreciation expense. Operations and maintenance, fuel costs, and other expenses are added to the cost of capital and depreciation expense to produce a utility “revenue requirement.” The revenue requirement is then divided by the demand to arrive at an average unit cost. The average unit cost for natural gas is then compared to the average unit cost for diesel. Allocation of Common Costs This analysis assumes that natural gas will displace both diesel fuel home heating and diesel-fired electrical generation. Both of the domestic heating and electricity product lines receive natural gas from a field which is developed adjacent to the community. The costs of the natural gas development are treated as common costs which are allocated to the product lines of electricity and heating based on an average $ per mcf of gas delivered to the power generating station and the city gate of the gas distribution system. Product Line Costs The cost of electricity is then calculated based on: e fuel: $ per mcf for natural gas ¢ capital cost for converting to natural gas-fired generators © operations and maintenance for natural gas-fired generators The cost of heating is then calculated based on: e fuel: $ per mcf for natural gas ¢ capital cost for natural gas distribution system, including customer services and meters e capital cost for converting to natural gas-fired heating systems 7 See Appendix “Method Used” for more detail. For a recent local example see the Kenai Peninsula Natural Gas Study, ISER, 1995. * A capital recovery factor of 20% includes roughly 5% for depreciation and 15% for the cost of capital. MAFA/ARI page 8 26-Feb-97 Introduction Natural Gas in Rural Alaska e operations and maintenance for distribution & heating systems “Typical” residential bill comparisons The cost of natural gas home heating and natural gas-fired electricity is added together to obtain a “typical” residential bill for the purpose of comparisons with other fuels.’ In this case, diesel fuel oil heating and diesel-fired electrical generation are used as the point of reference. Other Costs not Considered Costs which are common to both natural gas and diesel alternatives are not included in this study since they do not help distinguish between the alternatives. Examples of these costs include utility management and billing and collection operations. Natural Gas and Coalbed Methane This study primarily focuses on the development of coalbed methane. At this initial reconnaissance level, the study findings are generally applicable to “shallow” natural gas. The Base Case The study develops a base case which covers a range of rural community sizes which roughly translate in size to Nome on the large end of the scale on down to Russian Mission on the small end of the scale. Table 1: Basic Demographic Assumptions Size Large Medium | L-Small | M-Small Households 1380 575 | 160 | 80 Population 3500 2000 500 Domestic energy profiles are estimated for electricity and heating based on existing energy consumption patterns for “typical” rural communities with households in the size ranges identified. © The load is assumed to remain level for the base case. Some heroic assumptions are made to simplify this generic non-site specific analysis. The first heroic assumption is that a coal bed methane field of good quality is assumed to underlie the community. This assumes there is no appreciable transportation required to move the gas from the field to the electrical generating station and the “city gate” of the gas distribution system. Transportation costs are reviewed in the sensitivity analysis. The second heroic assumption is that most of the costs to explore for the gas field have not been included in the base case, but are reviewed in the sensitivity analysis. ° For the purposes of this initial screening, administrative and overhead costs which are not incremental to the choice of gas over diesel along with costs which are not incremental to the citizens of the State of Alaska (such as taxes), have not been included. An actual residential bill would include these costs. "© See Appendix “Schedules”, Residential Heating Estimates. MAFA/ARI page 9 26-Feb-97 Introduction Natural Gas in Rural Alaska Where the cost of energy from natural gas is competitive with diesel based on this reconnaissance model, and the prospect for a natural gas resource has been identified, a more detailed analysis of the feasibility of exploring and developing the natural gas resource may be warranted. Sensitivity Analysis A number of assumptions have been varied from the base case to examine the sensitivity of those parameters upon the competitiveness of natural gas compared to diesel. These include: e Base price of diesel fuel ($/gallon) e Distance from the natural gas field to the market (miles) ¢ Quality of the natural gas field (high, medium, low) e Costs associated with exploration activities ($ millions) ¢ Use of electric heat instead of natural gas end-use heating Base Price of Diesel Fuel The base price of diesel fuel is based on a review of the prices paid by a selection of rural Alaskan communities which fit within the general community size criteria. Prices were reviewed for the period 1990 through 1996, which includes two price spikes - one for the gulf war and one this fall. These nominal prices were converted to real prices and averaged to arrive at an estimated average long term real price in 1996 dollars.” The base price estimate for diesel fuel delivered to rural utilities is: Table 2: Basic Fuel Price Assumptions Community M-Small | S-Small Size $0.80/gallon $0.90/gallon $1.80/gallon $1.90/gallon $2.00/gallon The base price estimate for heating fuel delivered to residential end-users adds from 40-75 cents per gallon to the base price paid by utilities.'’ These costs may include the cost of delivery, some costs associated with fuel storage, and some common overhead costs. For the purposes of the base case, a mid-range estimate of a 60 cents per gallon residential premium was applied. Real Price Escalation of Diesel Fuel The base case assumes no real price escalation in the price of diesel fuel.'* " The costs associated with the “successful” exploration well are included in the field development costs in the base case since it is assumed an exploration well will become a production well. Costs associated with unsuccessful exploration wells are included in the sensitivity analysis as an exploration cost. ? See Appendix “Schedules”, Diesel Fuel Price Review. > Based on verbal quotations from vendors and municipalities for the fall of 1996. “* See Energy Security and Policy: Analysis of the Pricing of Crude Oil and Petroleum Products, United States General Accounting Office, GAO/RCED-93-17, March 1993, for an example of a study which supports the assumption that the long run real price of diesel fuel is likely to be flat, if not declining. MAFA/ARI page 10 26-Feb-97 Introduction Natural Gas in Rural Alaska The sensitivity analysis tests a levelized cost increase of 25 and 50 cents per gallon in the price of diesel to account for environmental considerations and other factors which may contribute to an increase in the real long term price of diesel fuel. Distance from the Natural Gas Field to the Market The base case assumes that there is not appreciable transportation to move the natural gas from the field to the market. Cost estimates were developed for transportation of the natural gas to the domestic market at a distance of 2, 15, and 30 miles. For short distances where lower pressures are sufficient to push the gas through the pipeline, cost estimates were developed assuming the use of a polyethylene pipeline. For greater distances, cost estimates were developed assuming the use of a steel pipeline to transmit the gas to the city gate and existing electrical generation station. For long distances an additional cost increment is included to account for a field electrical generating plant to supply the gas field with electrical power. Quality of the Natural Gas Field A critical assumption in the consideration of whether natural gas is a competitive energy substitute is the quality of the natural gas field. The base case assumes a coalbed methane field with “average” characteristics - 1.4 Bcf of reserves and a peak production rate of 400 Mcfd. A high and low case are developed for sensitivity purposes. The range of variation in key parameters could provide a well with reserves from 3 Bcf and a peak production rate 900 Mcfd to reserves of 0.5 Bcfd and a peak production rate of 150 Mcfd. The commercial feasibility of natural gas is virtually nil unless the gas field quality is good or excellent. Indeed, a high quality field could provide sufficient economic value to justify the construction of a pipeline to reach a community. Density of the Market The density of the market assumption is based on a review of the number of customers per mile reported by electric utilities for a selection of rural Alaskan communities which fit within the general community size criteria selected for this study. The following assumptions are used in the base case: Table 3: Customer Density by Community Size Community Size (Households) Density (Customers per mile) Large - 1380 households 3500 population Medium - 575 households 2000 population L-Small - 160 households 500 population MAFA/ARI page 11 26-Feb-97 Introduction Natural Gas in Rural Alaska M-Small - 80 households 350 population S-Small - 50 households 250 population This is a significant assumption in the base case since it appears from electric utility data that the customer per mile of distribution varies greatly across small rural communities. For many small rural communities, the effects of the high fixed costs associated with a natural gas development are compounded even further by the high unit costs associated with the distribution system due to the relatively low density of the communities. Polyethylene pipe is assumed to be used in the distribution system for all cases. Costs Associated with Exploration Activities In the base case, the costs of exploration, other than the direct costs associated with the “successful” exploration well has been designed to become a production well, are ignored to simplify the analysis and highlight the critical importance of the cost of exploration on the feasibility of gas development. The sensitivity analysis adds an increment of $1 million and $7 million to assess the impact of potential exploration programs on the economic feasibility of the development. As the incremental costs associated with exploration activities increase, one has to assume higher quality gas fields or significant escalation in the real cost of diesel or both in order to justify the development. The relatively high risk and low reward profile of natural gas exploration activities aimed at serving the rural Alaskan market does not appear attractive under standard economic analysis where higher risks typically require higher potential rewards. The Electric Heat Alternative General An alternative to distributing natural gas to end-users who are then required to convert to natural gas is to convert end-users to electric heat and increase the natural gas-fired electrical generating capacity to meet the increased electrical demand. Under the base case, the benefits associated with the natural gas end-use heating alternative outway the incremental costs associated with the electric heat alternative. '° This is primarily due to the substantial capital costs associated with the incremental natural gas-fired electrical generation capacity required to meet the increase in peak load due to electric heating. 'S See Appendix “Schedules”, Electric Heating vs. Natural Gas Heating. MAFA/ARI page 12 26-Feb-97 Overview of Natural Gas Development Natural Gas in Rural Alaska Overview of Natural Gas Development Introduction Since its discovery in the United States, reported to be at Fredonia, New York, in 1821, natural gas has been used as a fuel in areas immediately surrounding the gas fields. In the 1920's and 1930's, a few long pipelines from 22 to 24 in. in diameter, operating at 400 to 600 psi, were installed to transport gas to industrial areas remote from the field sources. However, as late as the 1930's produced natural gas was flared and blown to the air in large volumes. When gas accompanied crude oil, the gas had to find a market or be flared and, in the absence of effective conservation practices in earlier years, oil-well gas was often flared in huge quantities. Consequently, gas production at that time was often short-lived, and gas could be purchased for as little as one or two cents per 1,000 cu. ft. in the field. A combination of factors, including market prices, assurance of continuing supply of gas by conservation practices, new discoveries, and satisfactory financial returns to pipeline companies contributed to the growth of the natural gas industry in recent years. The modern natural gas industry began immediately following World War II when a number of long-distance pipelines were constructed to serve markets in the populated areas of the country. By that time, advances in welding and manufacture of pipe permitted pressures up to 1,000 psi and diameters up to 30 in. Today virtually every area of the continental United States is served by natural gas. The facilities normally operated in the handling of gas in the field are those required to condition the gas to make it marketable -- the removal of impurities, water, and excess hydrocarbon liquids and the control of delivery pressure. Principal reserves of natural gas for the continental U.S. are found along the Gulf Coast, through the Mid- Continent, and on the eastern slope of the Rocky Mountains. In addition the continental United States relies on imported natural gas from Canada to meet projected demands. In Alaska, principal reserves of natural gas are found on the North Slope and the Cook Inlet. The Cook Inlet gas is used to produce ammonia and urea for export to other states and is liquefied to prepare LNG for export to Japan. A portion of the Cook Inlet gas is used for domestic heating and electrical generation. Table 4: Overall Cook Inlet Gas Supply and Demand (1993) Cook Inlet Remaining Reserves | 2187 Bef Total Sales of Cook Inlet Gas | 180 Bef/year to LNG Plant | 67 Bcf/year to Ammonia Plant 57 Bef/year to Electric Power Generation 32 Bef/year to ENSTAR for resale 24 Bef/year Source: Alaska Department of Natural Resources, “Historical and Projected Oil and Gas Consumption,” February 1994. The North Slope gas is used in field operations and sold to Trans-Alaska Pipeline System (TAPS) for power and as natural gas liquids (NGLs). A small portion of North Slope gas is used for domestic heating and electrical generation for the oil field support facilities and in Barrow. MAFA/ARI page 13 26-Feb-97 Overview of Natural Gas Development Natural Gas in Rural Alaska Table 5: Overall North Slope Gas Supply and Demand (1993) North Slope Remaining Reserves | 23,455 Bef Total Sales of North Slope Gas 45 Bcf/year to Barrow Utilities Power 0.7 Bef/year to Barrow & Norgasco Gas 0.5 Bef/year Utilities TAPS (Trans Alaska Pipeline 12 Bef/year System) NGLs (Natural Gas Liquids) | 23 Bef/year Other 9 Bef/year Source: Alaska Department of Natural Resources, “Historical and Projected Oil and Gas Consumption,” February 1994. Natural Gas Production Petroleum Accumulations For natural gas to accumulate, there must first be a source of gas; second, a porous bed must exist, which is permeable enough to permit the gas the flow through it - the reservoir rock; and, third there must be a trap, which is a barrier to fluid flow so that accumulation can occur against it. Migration of Petroleum It is generally accepted that any present accumulation of gas is a result of migration of widely dispersed and relatively small individual quantities of hydrocarbons to a more concentrated deposit as found in a reservoir. In some cases, the source material may be in close proximity to the present pool. However, it is believed that in most instances the organic source material from which petroleum was formed is widely disseminated in the sediments and that a present accumulation is the result of the combination of many minute portions of petroleum from near and far. Petroleum Reservoirs The accumulation of oil and gas into a commercial deposit required a reservoir to contain the gas along with some water and a trap, which represents a set of geologic conditions that retained the oil and gas in the reservoir until discovery. A petroleum reservoir is a rock capable of containing oil, gas, or water, To be commercially productive, it must have sufficient thickness, pore space to contain an appreciable volume of hydrocarbons, and it must yield the contained fluids at a satisfactory rate when penetrated by a well. Sandstones and carbonates are the most common reservoir rocks. In order to contain fluids, the rocks must have porosity. Porosity is the ratio of void space to the bulk volume of the rock, usually expressed in percentage. Dependent upon the method of determination, porosity may represent either total or effective porosity. In many porous rocks, there are a certain number of blind or unconnected pores. Effective porosity refers to only those pores that are connected so as to permit fluid passage. Permeability is a quantitative measure of the ease with which a porous rock will permit the passage of fluids through it under the pressure gradient. Like porosity, it is dependent upon rock grain shape, MAFA/ARI page 14 26-Feb-97 Overview of Natural Gas Development Natural Gas in Rural Alaska angularity and size distribution. In addition, it is very strongly dependent on the size of the grains. The smaller the grains, the larger will be the surface area exposed to the flowing fluid. The additional drag or frictional resistance of the larger surface area lowers the flow rate at a given pressure differential, and thus the smaller grain size will result in a lower permeability. Reservoir pressure is a controlling factor in the ability of a well to produce. A decease in the bottom-hole pressure of a gas well is reflected by a drop in its productivity. Reservoir pressure is always a consideration in the final stages of depletion of a gas reservoir. For most gas reservoirs, the estimated reserves, the forecast of producing rates, and the estimated producing life are based on a prediction of pressure decline and estimated abandonment pressure. Considerations also usually include a determination of the economic feasibility of gas compression at the wellhead to boost the pressure of the gas for sale into a pipeline and lower the abandonment reservoir pressure. A trap is a set of geologic conditions that has stopped the migration of oil and gas and caused the oil and gas to be retained in a porous reservoir. Commonly these traps are related to structural highs (anticlines and domes) or against faults and unconformities. They may be placed in two general classes: (1) those in which the reservoir has an arched upper surface and (2) those in which there is an up-dip termination of the reservoir. Reservoir Drives There are two general types of reservoir drives: depletion drive and water drive. Depletion drive is operative where the reservoir can be termed a closed reservoir; that is, the hydrocarbon accumulation is not in contact with a large body of permeable water-bearing sand. Expansion of the hydrocarbons and other reservoir materials that occurs as pressure is reduced furnishes the only energy for movement of fluids through the formation and to the surface. Estimation of Reserves In order to understand the art and science of reserve estimation, it is necessary to define certain terms that are commonly used and recognize the sources of the data represented by these terms. Abandonment pressure is the average reservoir pressure at which insufficient gas is expelled to permit continued economic operation of a producing gas well. Operating and abandonment pressures vary from basin to basin depending upon depth, initial reservoir pressure, and method of water-lifting. In the relatively shallow Warrior Basin, operations and abandonment pressures range from 20-50 psi. In the deeper San Juan Basin, operating and abandonment pressure typically range from 50-150 psi. Gas saturation is the percentage of the total pore space occupied by gas. Within the pore structure of the reservoir rock, a portion of the pore space may be occupied by gas. Hydrocarbon pore volume is the volume of the pore space in the reservoir occupied by natural gas or other hydrocarbons (including nonhydrocarbon impurities) and is expressed in cubic feet. Porosity is the percentage of the total reservoir that is not occupied by rock. Various methods to determine porosity are available including electric logs and core analysis. Permeability is the term used to describe the flow capacity of a reservoir rock. Permeability may be reported in darcys or millidarcys. Well-log correlations, core analysis, and pressure buildup (or drawdown) tests are the usual sources of permeability data. Absolute permeability is the permeability of a rock to a single fluid if the rock is 100 percent saturated with that fluid. Effective permeability is the permeability of a rock to a fluid when the saturation of the fluid is less than 100 percent. MAFA/ARI page 15 26-Feb-97 Overview of Natural Gas Development Natural Gas in Rural Alaska Pressure depletion is the method of production of a gas reservoir that is not associated with a water drive. This is the process where gas is removed and reservoir pressure declines until all the recoverable gas has been expelled. Reservoir pressure is the average pressure within the reservoir at any given time. Determination of this value is best made by bottom-hole pressure measurements with adequate shut-in time. Reservoir temperature is the average temperature within the reservoir and is measured during logging, drill-stem testing, or bottom-hole pressure testing using a bottom-hole temperature recorder. The initial estimate made on a newly discovered gas reservoir will usually be a volumetric calculation. Factors needed to arrive at this estimate would include the type of reservoir, its area, its thickness, its porosity, and its water saturation, and the temperature, pressure, and composition of the gas. Well Equipment General Equipment The selection and size of casing, tubing, and wellhead equipment must take into account the expected rates of flow, fluid erosion, and chemical corrosion. Casing size will limit the size tubing that can be installed, and tubing size will limit the gas flow that can be produced with a given pressure drawdown. Safety shutoff equipment, some of which functions by flow velocity, is mandatory by government regulations in many cases and desirable in most gas wells. This equipment is usually installed in the tubing, and in many cases, the wellhead. Tubing and Packer The final string of pipe usually run in a well is the tubing. The small diameter of the tubing permits more efficient production of fluid than casing and makes possibly a safer completion because fluid may be circulated down the tubing and up the casing to remove undesirable fluid in the well. Tubing constitutes a string of pipe that can be removed if it becomes plugged or damaged. Tubing, in conjunction with a packer, keeps well fluid and pressure away from the casing because the packer seals the annual space between the tubing and casing. Climate and Topography Cold climates present continual or at least seasonal difficulties in relation to hydrates, equipment operation, and worker exposure. The climate must be considered when designing the well equipment and gathering system. Location of the system in relation to topographical features such as mountains, swamps, open water, rocky terrain, and remote locations also affect the system design. Producing Equipment The gathering system facilities can be grouped in two major categories. First, there are those items of basic equipment that are needed to transport the gas; to start, stop, and measure the flow; and to control and measure gas pressure and temperature. Secondly, there is the equipment needed to condition the gas so that it will flow safely and reliably. MAFA/ARI page 16 26-Feb-97 Overview of Natural Gas Development Natural Gas in Rural Alaska ‘ Basic Equipment The pipe through which the gas flows is the basic and most important part of the gathering system. It is made of steel or plastic, which is selected in accordance with proper codes and regulations. The diameter of the pipe is determined by the amount of gas that is to be transported through the pipe, and the thickness of the pipe wall as determined by the pressure of the gas. Flow of the gas is stopped or allowed to continued by the use of valves. Block valves are used to stop the flow; they are usually completely open or completely closed. Throttling valves to regulate the rate of flow are usually only partially open or closed; the inner valve is often positioned by a mechanical operating device controlled automatically by instruments or sometimes by a remote-control arrangement. Some degree of automation has been used in gas gathering systems for years, such as the control of pressure, flow rates, and temperatures. Expansion of the use of such regulating equipment to permit automatic control of whole systems is now common practice. The use of electronic communications and computers often enables field operations of a very complex nature to de directed instantly from a remote location accurately and automatically. Gas-Conditioning Equipment Equipment needed to condition the gas may be located at any one of several places in the gathering system; it may be needed at the wellhead, or it may be possible to locate it at a more central point. Separators are vessels that function as a wide place in the pipeline so that the flowing fluids slow down and gravity separates the vapors and solids from the liquids. Heaters are usually low-pressure vessels that contain a liquid - most often water - which is heated by a gas burner using fuel from the line. Pipe of sufficient strength is coiled and placed in the hot liquid, and the gas to be heated is passed through the coiled pipe. Gas heaters may be directly or indirectly fired. Dehydrators prevent hydrate formation by removing water vapor from the gas. The gas is brought into contact with either a liquid or solid desiccant, which takes water vapor from the gas. The desiccant is then regenerated for reuse by applying heat, which drives off the water picked up from the gas. Compressors are installed to increase the pressure of the gas so that it can flow through the pipeline. Friction is developed by flow through the pipe; so if the pipeline is very long, additional compressors may have to be installed along the line. Reciprocating piston compressors are the type most often used; the smaller, high-speed units are used for small volumes, the larger, low-speed, integral units for large volumes. Centrifugal compressors are becoming more common, particularly for main gas-transmission lines. Coal Bed Methane Generation and Storage Coal is a heterogeneous, carbon-rich material that is formed by the biochemical and geochemical alteration of peat, an organic material that is the source of most of the world’s coal deposits. During the process of coal formation, commonly called coalification, methane and other by-products such as water and carbon dioxide are generated. Once generated, methane is stored in the coal as a monomolecular layer adsorbed on the internal surfaces of the coal matrix. Significant quantities of methane can be adsorbed in this fashion since the molecules are tightly packed and because coal has a very large internal surface areas, over | billion square feet per ton of coal. MAFA/ARI page 17 26-Feb-97 Overview of Natural Gas Development Natural Gas in Rural Alaska As a result, coal can hold two to three times as much gas in place as the same volume of a conventional sandstone reservoir. The amount of methane stored in coal is related to the rank and the depth of coal. The higher the coal rank and the deeper the coal seam is presently buried (causing pressure on the coal), the greater its capacity to hold gas. Releasing this adsorbed methane is accomplished by lowering the pressure on the coal, which generally involves removing the water and lowering the hydrostatic pressure in the coal reservoir. Gas Flow After the gas desorbs from the coal, the released gas must diffuse through the coal matrix until reaching a coal cleet, the natural fracture network in coal. The gas then flows through the cleats or other fractures into the well bore. Gas diffusion through the coal matrix is controlled by the gas concentration, the inherent diffusivity properties of the coal matrix, and the distance that gas travels to reach the cleat or fracture. Once the gas reaches the cleat or fracture, the gas flow is governed by permeability and pressure. However, because both gas and water are flowing through the cleat system, one must calculate the continually changing relative permeabilities of the gas and water phases to accurately describe this two- phase flow. Industry Overview In mid-1995, the San Juan and Warrior basins - still the dominant regions for coalbed methane reserves and production - have developed into mature gas provinces. Emerging areas, such as the Central Appalachian, Uinta, and Raton basins, are onstream and contributing increasing volumes of production. Small operators in the Cherokee, Forest City, Ardoma, and Powder River basins remain active in these low productivity, low cost plays. Frontier coalbed methane areas, including the Piceance and Greater Green River basins, offer large resource potential, but exploration and production technology for these for challenging settings remains inadequate. Meanwhile, the success of the U.S. coalbed methane industry has encouraged Amoco, Enron, and other to initiate aggressive exploration programs overseas in coal rich countries such as Australia and China in pursuit of large, low risk reserves. Future Prospects The Gas Research Institute (GRI) projects that the price to acquire gas in the continental U.S. will remain around $2.00 per MMBtu in real terms over the next twenty years due to improvements in technology throughout the production chain. iS GRI contends that the cost of drilling both on-shore and off-shore wells will continue to decline during the forecast period. In addition, success rates should improve, reducing the risk in exploring new areas. On the transportation and distribution side, continued improvements in the pressure handling capability of reinforced high-density polyethylene (HDPE) pipe could provide a realistic alternative to steel pipe '© See “GRI: U.S. Gas Use to Increase, Prices Fall”, Oil & Gas Journal, September 2, 1996, p. 36. MAFA/ARI page 18 26-Feb-97 Overview of Natural Gas Development Natural Gas in Rural Alaska transportation in many cases, with a possibility for significant cost savings due to less expensive material costs, lower freight costs, and reductions in the labor required to install the lightweight polyethylene pipe.’” GRI expects efficiency improvements to continue in end-user markets which may include gas-fired furnaces and gas-fired direct vent heating units. In addition, there may be continuing efficiency improvements in gas-fired turbines and reciprocating engines. "7 See “Tests confirm polyethylene pipe for high-pressure oil, gas service”, Oil & Gas Journal, September 9, 1996, p. 52. However, it should be noted that mechanical testing of materials properties often do not take into the account the environmental extremes experienced during installation and for in-situ conditions found across Alaska. The reinforced thermo plastic (RTP) pipe cited in the article was tested from -22°F to 86°F -- a range that may not include the full range of actual Alaskan field conditions. Prior to the successful introduction of these new materials into the Alaskan marketplace, additional testing may be advisable. MAFA/ARI page 19 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska Cost Estimates Introduction Cost estimates for the development of a coalbed methane field for a rural Alaskan domestic energy market were developed for a variety of circumstances and compared to the existing and future costs of diesel- generated electricity and fuel oil heating. “Typical” Energy Use Profiles Introduction Conditions in rural Alaska vary considerably from commercial fishing and timber communities in Southeast to a wide variety of subsistence communities along the coast and rivers in the Interior, Arctic, Western and Southcentral portions of the State. A wide range of climate, cash incomes and prices for goods and services tends to create a wide range of per capita energy consumption. The study reflects part of this range of per capital energy consumption by varying the per capita electrical and heating energy consumption across the community size profiles. This parameter should be examined in detail in any site specific evaluation. Energy Demand Profiles The base case assumes the following energy demand profiles: Table 6: Energy Demand Profiles Community Size Large Medium L-Small S-Small Residential Households 1380 575 160 50 Commercial/Industrial/ 290 260 52 12 Other Customers'* Avg. Residential 6500 6500 Demand (kwh/year)”? Avg. C/I/O Demand 65000 56000 (kwh/year)” Avg. Residential 120 120 Demand (mcf/year)” 8 The natural gas field itself is assumed to be included as a commercial customer of electrical power which will average around 100,000 kWh per year per well. '® Average residential demand is based on a review of average residential demand for rural communities reported in the Alaska Electric Power Statistics, 1995. " Average commercial, industrial, and other demand is based on a review of the weighted average demand for rural communities reported in the Alaska Electric Power Statistics, 1995. = Average residential gas demand is based on adjusting actual railbelt natural gas heating demand: © upward to reflect higher heating degree days typical in rural Alaska, MAFA/ARI page 20 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska Table 6: Energy Demand Profiles Community Size Large Medium | L-Small S-Small Avg. C/I/O Demand 500 500 | 500 500 (mcf/year)” Customer Density 45 20 (meters/mile)” Natural Gas Costs Costs estimates are developed or assessed for the following basic activities: e Exploration ($) e Development & Production ($/mcf) e Field Development Costs © Per-well Costs © Operations & Maintenance e Transmission ($/mcf) e Electrical (cents/kwh) ¢ Cost of fuel = cost for development and production of coalbed methane © Cost to convert existing system to natural gas-fired electrical generation e Incremental O&M e Heating ($/MMBtu) ¢ Cost of fuel = cost for development and production of coalbed methane e Distribution System - including piping and meters e Cost to convert existing heating systems to natural gas-fired heat e Incremental O&M Exploration Exploration costs depend in significant part upon whether exploration is conducted by the majors, by independent entrepreneurs, or the government as each has different discount rates. Scale and scope economies can work in interesting ways depending upon the value a firm places on the small scale market. © lower to reflect the smaller average square footages found in rural community housing stock. The net effect is that the projected average residential demand for gas is slightly lower for rural areas than for the railbelt. See also Appendix “Schedules” - Residential Heating Estimates. ” Based on Kenai Natural Gas Study estimate. ? Based on a review of the electric utility customer per mile of distribution data in “Selected Alaskan Electric Utilities at a Glance,” August 1995. MAFA/ARI page 21 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska For the majors, exploration activities need to meet certain return on investment hurdle rates for the probability of success compared to other exploration opportunities available to the firm. It is estimated that a modern exploration program designed to recover its costs would run somewhere in the $5 million to $10 million range assuming a success rate of somewhere between 10-20%. The sensitivity analysis uses a figure of $7 million for a modern exploration case. For independent Alaskan entrepreneurs with other basic lines of business that generate cash for at least part of the year, exploration may be seen as an activity that takes place within the context of the overall firm’s cash flow. In other words, if exploration costs are recovered by cash flow from other activities, an entrepreneur may view the activity as a “loss-leader.” In addition, from the entrepreneur’s point of view alternative investments with the cash may not return nearly the same value as exploration for gas in Alaska -- even if the exploration is not successful. The real question is how many exploratory wells can an entrepreneur drill before cash flow considerations restrain further drilling or an economic prospect is found. Assuming the entrepreneur can treat labor and equipment as contributions, under favorable circumstances an entreprenear might be able to drill five exploratory holes and find a commercial prospect (success rate of 20%). The sensitivity analysis uses a figure of $1 million for an entrepreneurial exploration case. Finally, it appears that government agencies may provide funds to drill exploration wells, effectively subsidizing some portion of the exploration costs. si Given this wide range of potential exploration costs that could occur in the rural Alaskan market, the base case includes the exploration costs directly associated with the successful well, but leaves the exploration costs associated with activities that occur prior to the successful well, i.e., geologic investigations, dry holes, etc. for the sensitivity analysis. Field Development Costs Overall field development costs need to include: ¢ Cost of drilling and completion of wells e Surface equipment and infrastructure e Operations and maintenance of wells and lease Field Location Two basic geographic settings are assumed: 1. Transportation Corridor Access: Near to road or major waterway access (within 5 miles) and near to a regional service center (within 50 miles); 2. Remote from Transportation Corridor Access: Remote from road or major waterway access (more than 5 miles) and remote from a service center (more than 50 miles); Drilling and Completion Costs The primary cost included in drilling and completing a coalbed methane well are: ¢ Performing the initial geological and geophysical work (if any) e Acquiring the lease ** The Federal Department of Energy has developed an interest in funding an exploratory coalbed methane well in Chignik lagoon. MAFA/ARI page 22 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska e Building the well site and access road e Drilling the well e Logging the well e Completing the well, including casing, cementing and perforation e Hydraulic fracturing the formation e Installing well and lease equipment, including pumping unit or gas lift system (if needed), gas and water separation unit (if needed) and appropriate gas gathering, metering and lease compression (if needed) e Installing a water disposal system, depending on the volume and quality of produced water All of the facilities would need to be constructed for low temperature operations. Appropriate engineering and administrative costs accompany the well drilling and completion operations. Cost estimates for drilling and completion costs have been organized into fixed costs associated with the overall field development and variable costs associated with the drilling of additional wells. The base case assumes a coalbed methane well drilled to a depth of 3000 feet. The basic rules of thumb for field development and well completion costs for “typical” small communities requiring five wells to be drilled are: e Near to Transportation System & Service Center $1,000,000 per well e Remote from Transportation System $1,400,000 per well e Alaskan Entrepreneur Near to Transportation & Service Center $ 800,000 per well The breakdown of the estimate for 5 wells near to a transportation system and service center is: “Near to Transportation System & Service Center" Avg. Wells 5 per Well | Fixed | PerWell| Total | Cost 1|Lease , permits, bonds, survey, insurance $50,000 | $10,000 | $100,000 | $20,000 2|Site Preparation, access road $200,000 | $10,000 | $250,000 | $50,000 3|Well Drilling Rig Mobilization $250,000 | $10,000 | $300,000 | $60,000 4|Well Drilling $300,000 | $1,500,000 | $300,000 5|Well Logging, including mob & analysis $120,000 | $10,000 | $170,000 | $34,000 6|Well Completion, casing, tubing, wellhead $250,000 | $150,000 | $1,000,000 | $200,000 cementing, perforation, mobilization 7\Well Stimulation, 100,000# of sand $250,000 | $50,000 | $500,000 | $100,000 8/|Well and lease equipment, pumps, $300,000 | $40,000 | $500,000 | $100,000 separator, metering and gathering lines 9| Engineering/Supervision 5% $216,000 | $43,200 10|Contingency 10% $432,000 | $86,400 | 11| TOTAL $4,968,000 | $993,600 5 See Appendix “Schedules” for additional detail on estimates. MAFA/ARI page 23 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska Review of Industry Cost Data The Joint Association Survey provides annual data on the industry’s well drilling and equipping costs for onshore Alaska. The table below provides a tabulation of the number and the average costs for shallower wells drilled in Alaska in the past three years. As the table shows, very few shallow wells have been drilled in the onshore of Alaska, resulting in the higher costs due to "one at a time" type of effects. However, should the mobilization and road/site construction costs be reasonable, the recent industry data support a cost estimate of about $1,000,000 for drilling and completing a 3,000 foot well. TABLE 8: ESTIMATED COSTS OF DRILLING AND ENGINEERING WELLS, BY DEPTH (ALASKA ONSHORE) 1992 1993 1994 Depth Interval Number of Cost per Number of Cost per Number of Cost per Wells Well Wells Well Wells Well (feet) ($000) ($000) ($000) < 2,500 $1,875 2,500 - 3,749 $2,525 3,750 - 4,999 5,000 - 7,499 7,500 - 9,999 Source: Joint Association Survey (1992 - 1994) Other Estimates A cost estimate has been prepared by the College of West Virginia for the U.S. Department of Energy for a shallow 1,400 foot coalbed methane well located near Chignik Lagoon in the Bristol Bay region. This estimate was $855,000 for directly related costs, including permits, mobilization and housing for workers. Well Operating and Maintenance Costs Operating and maintenance costs will include: e Basic operation and maintenance of the lease and well e Water handling and disposal e Gas treating and compression Basic Operations & Maintenance (O & M) Operations and maintenance includes field manpower, well workers, facilities maintenance and power. Typical O&M costs will range from $500 per month per well for conventional gas wells to $2,000 per month per well for coalbed methane wells.”° *° Published operating, maintenance, and general and administrative costs for coalbed methane wells include $1,500 per month per well for Zimbabwe, $2200 for Black Warrior, and $1500 for San Juan. MAFA/ARI page 24 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska Operating and maintenance costs for a coalbed methane well are generally higher than those of a conventional well because of the water lifting and handling required. This adds expenses in the following areas: e = Electricity ¢ Pump and well workovers « In the case of Alaska, all equipment associated with water production will have to be insulated and heat taped. Where only a few wells (around 5) are involved, the basic O&M costs are estimated at $2,000 per month per well or roughly $10,000 per month for the field. As the number of wells in the field increases, the unit cost of basic O&M per well declines. For a field with 20 wells for example, the basic O&M costs are estimated at roughly $16,000 per month for the field or $800 per month per well. Water Handling and Disposal Water handling and disposal will depend on the quantity and quality of the water. For the purposes of this reconnaissance level study a water disposal well is assumed to be part of the cost of developing the field and the incremental operations and maintenance associated with the disposal well is assumed to be roughly equivalent to the incremental O&M associated with an additional gas well. Gas Treating and Compression The costs for gas treating will depend on the carbon dioxide and moisture content of the produced natural gas. The typical cost for this is $0.20 to $0.30/Mcf. “Field O&M” estimates include the mid-range cost of $0.25 per mcf for gas treatment and compression. Field Characteristics Cost Drivers Four reservoir variables have a significant influence on the costs of developing natural gas and coalbed methane. These are: e Net coal, that establishes the volume of the reservoir as well as its flow e Gas content and saturation, that determines how much methane is held in a unit of coal e Permeability, that directly controls the flow of methane through a reservoir and to the wellbore e Pressure, that provides the drilling force for the methane flow The first two variables (net coal and gas content) are grouped under the category resource concentration that establishes how much resource is in place. The second two variables (permeability and pressure) are grouped under the category flow capacity that governs how much of the resource is producible and at what rates. Resource Concentration The necessary requirement for attractive, sustained rates of gas flow is adequate resource concentration consisting of good coal thickness and high gas content. These two parameters establish the volume of methane in place for a given unit of area. Resource concentration is reported in units such as x Bef per MAFA/ARI page 25 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska square mile (section). Attractive volumes of resource concentration may range from 7 Bcf per section in the shallower, thin coals of the Warrior basin to 25 Bef per section in the deeper, thick coals of the San Juan basin. Of the two parameters that determine resource concentration, coal thickness is of first importance. This is because coal thickness not only directly relates to resource concentration, but also because thickness governs the rate of gas flow. For two areas of equal gas concentration, all else being the same, the area with thicker coal will have higher gas flow. In general, coal thicknesses of 10 to 20 feet are being commercially developed in the U.S. Often, multiple seams will need to be developed in a given wellbore to achieve sufficient coal thickness. The second component of resource concentration is the gas content of the coal. While the specific gas content relationships are basin specific, in general, gas content varies directly with coal rank and depth of burial -- the higher the coal rank (or greater its maturity) and the deeper the coal, the greater its potential gas content. Again, higher gas contents are preferred, all else being equal. However the shape of the gas desorption curve that holds the methane in place, discussed further below, is as important, and often more important, than the absolute gas content itself. The gas content of commercially pursued coalbed methane projects in the U.S. range upward from 200 ft per ton. Beyond coal rank and depth, the methane content of the coal is influenced by the ash content in the coal, the amount of CO, or other gases (or liquids) held by the coal, the maceral composition of the coal, and other factors. Flow Capacity While adequate resource concentration is a necessary condition, attractive gas flow capacity or rate is the sufficient condition for a commercial project. Gas flow rates, in turn, are governed by permeability (absolute and relative), pressure, and the gas sorption isotherm (in addition to coal thickness as discussed above). Broadly speaking, while each variable is important, the primary variable controlling gas flow is permeability. The range of gas production and the measured values of gas permeability may range by four orders of magnitude, from 0.1 millidarcy [md] (or less) to 100 md (or more). While sufficient gas pressure needs to exist to drive the gas from the interior of the reservoir to the well, the pressures generally encountered in coalbed methane reservoirs are adequate and fall into a range of 500 psi to 2,000 psi. Considerable research is underway to better understand what conditions lead to good permeability in coal. Briefly, for good permeability, the coal needs to have a well-developed face and butt cleat system. Research from the San Juan basin shows that coal cleat development is particularly favorable in the vitrain rich bands in a coal sequence. Second, the coal reservoir needs to be naturally fractured or jointed to provide additional conduits for gas flow. Third, these cleat and joint systems need to be open. Here, the permeability or "openness" of these cleat and joint systems is greatly influenced by the in-situ stress on the cleat/joint systems. The third variable governing gas release and flow is the shape of the desorption isotherm and how extensively the coals are gas saturated. If the coals are undersaturated with gas, the gas release and its subsequent flow will be constrained until the pressure in the formation is sufficiently reduced. Several reservoir properties govern the productive capacity and economic feasibility of producing coalbed methane and natural gas in rural Alaska. For coalbed methane, the key field characteristics are net coal thickness, coal rank gas content, reservoir pressure, and permeability. For the simpler case of conventional gas, the three key field characteristics are net pay, reservoir pressure, and gas filled porosity. A coalbed methane prospect can withstand one poor or low reservoir property and still provide relatively attractive gas flow rates. However, when a prospect has several low properties such as low net coal, low pressure and low permeability, the compound effect is to make the prospect uneconomic. MAFA/ARI page 26 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska Field Quality To represent the potential diversity of field characteristics, three field qualities are assumed -- high, base case, and low, as set forth below: Table 9: Field Characteristics L High Ow Reserves per Well 2.8 Bef 1.4 Bef 0.5 Bef 900 Mcfd 400 Mcfd 150 Mcfd Average Rate (First 10 years) 500 Mcfd 250 Mcfd 100 Mcfd Average Rate (Next 15 years) 200 Mcfd 100 Mcfd 40 Mcfd These field quality parameters are significant drivers of economic feasibility as they drive a major capital cost -- the number of wells required to supply the peak and average requirements of the market -- both for the initial development and in the later years of the development as the productivity of the field and individual wells decline and replacement wells are needed to maintain capacity. Summary of Field Development Costs To meet the estimated demand for each of the community sizes, a number of wells need to be drilled initially and additional wells are expected to be needed over the life of the field which is assumed to be 25 years. The number of wells needed is estimated based on the following assumptions: e The successful exploration well is expected to become a production well e The number of wells needed for initial development must be sufficient to meet the higher of: e the peak gas production rate required e — the average daily gas production rate required e A reliability well is added for each 12 wells to ensure continuous production during planned and forced outages e A reinjection well for produced water is added for each 30 production wells e During the years 12 - 20 in the life of the field, additional wells are added in order to meet demand as the average rate of production of the wells declines Thus, for the base case the following field development requirements are estimated for the medium quality coalbed methane field: Table 10: Number of Wells Required Community Size Initial Number of Well Required Additional Wells Required (years 12-20) MAFA/ARI page 27 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska For the small community size range, the need for a reliability well and a water reinjection well become prominent cost drivers which raise the capital cost per mef of produced gas as much as five times higher than the unit cost per mef in the large community. Heating Costs The system to deliver natural gas heat to end-users includes the following cost elements: e Distribution e Services & Meters e Conversion to Natural Gas Heating Distribution Costs Unit Costs For an initial reconnaissance level estimate, actual installed costs based on Norgasco experience on the North Slope were used to estimate unfavorable conditions.” The basic cost of a buried polyethylene distribution system was estimated as $60,000/mile Buried vs. Ground Level or Overhead Piping This reconnaisance level study assumes that the natural gas distribution piping will be buried. Where soil types and natural drainage patterns permit, direct burial of the gas distribution system is the most desirable installation from the viewpoint of economics, security, and area utilization.” In addition direct burial is generally favored since placing the natural gas pipeline above ground would expose it to extreme arctic temperatures, increasing the probability of blockages due to condensation and increasing the hazards associated with the brittle behavior of steel subjected to low temperatures.” Nonetheless, there may be circumstances where ground level or overhead distribution systems may be feasible and desirable. The costs of those installations should be developed in light of the specific field conditions and incorporated into this analysis by adjusting the unit cost per mile for natural gas distribution piping. 27 Interview with Charlie Helm, Norgasco. *8 See Cold Regions Utilities Monograph, ASCE, 3rd Edition (1996), page 17-8. ?° See Quimby and Fitzpatrick, “Upheaval Buckling of a Pipeline in an Arctic Environment”, Cold Regions Engineering, Proceedings of the Eighth International Conference on Cold Regions Engineering, ASCE, 1996, p. 216. MAFA/ARI page 28 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska All Electric Heat For the all electric heat case, upgrades to the distribution system were assumed to cost on the order of $10,000 per mile to enable the electric distribution system to carry the substantial increase in peak load. Community Density Community density is a key cost driver in the distribution system.. Using existing electrical systems as a surrogate measure of the density of rural communities, one finds the customers per mile of distribution exhibits considerable variation across Alaska. Table 11: Sample of Community Density Utility Customers per mile of distribution Alaska Power - Skagway 46 Alaska Power - Tok 36 Alaska Power - Prince of Wales 61 Alaska Village Electric Cooperative 17 Barrow Utilities & Electric Cooperative 41 Bethel Utilities Corp. 77 Cordova 33 Haines Light & Power 29 Homer Electric 11 Kodiak Metlakatla Naknek Nome Joint Utilities Nushagak Petersburg (Source: Selected Alaskan Electric Utilities at a Glance; Alaska Systems Coordinating Council/State of Alaska Division of Energy, August 1995) For the base case, a selection of distribution system density and costs were estimated to be somewhere between Nome with 45 customers per mile and AVEC with 20 customers per mile as follows: MAFA/ARI page 29 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska Table 12: Distribution System Capital c a Large Medium ~~ L-Small- ~~ M-Small’ | S-Small Customers 1670 Moco) tele min Os minnnoe! Density (customers/mile) 45 35 20) 20! 20 ‘Miles of Distribution ~ ies tr 1923'S eel UG imino! 2 ie enosl | Cost per Mile ' ~~ $60,000 $60,000 ~~ $60,000 =~“ $60,000 = $60,000 | Capital Cost $2,226,667 $1,431,429 $636,000 $309,000 $186,000 Capital Cost per Customer $1,333 $1,714 $3,000 | $3,000 | $3,000 Services and Meters Capital cost for services to end-users and meters were estimated to average $1,000 per customer. This is comparable to estimates used in the Kenai Peninsula Natural Gas Study. For the all electric heat case, the overall costs associated with individual service upgrades were assumed to be neglible. Conversion to Natural Gas Heating For the purposes of this economic screening model, the tendency for end-user conversions to occur over several years is not modeled. It is assumed that all end-users will convert to gas heat if gas heat is available at a discount compared to existing diesel heat. End-user conversions can be assisted with loans or grants from the local “gas and electric” utility, especially where cash flow is a concern for households. Residential For the reconnaissance base case, it is assumed that all residential end-users would convert to gas heat and that the weighted average cost of conversion would average $2500 per customer in rural Alaska. After allowing for additional freight to deliver the gas-fired heating equipment to remote communities and inflation, this compares with a figure for Anchorage where a weighted average conversion estimate of $1840 was used by ISER in their study of the Gas Pipeline between Cook Inlet and Fairbanks published in 1989.° For the all electric heat case, it is assumed that all residential and commercial end-users would convert to electric heat and that the weighted average cost of conversion would be $1000 per customer. Commercial/Industrial/Other For the reconnaissance base case, it is assumed that all commercial end-users would convert to gas heat and that the cost of conversion would average around $2,500 per customer. Operations & Maintenance Annual O&M costs associated with heating units are estimated as: e Fuel Oil-Fired Units $80/year e Gas-Fired units $36/year e Allelectric heat $10/year % Railbelt Intertie Reconnaissance Study, Benefit/Cost Analysis, Decision Focus, Inc, Appendix I, “Gas Pipeline Between Cook Inlet and Fairbanks: Benefits Outside the Electric Power Sector.”, pages I-20 and I-21. MAFA/ARI page 30 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska After adjusting for modest inflation, these estimates are comparable to those used in the ISER Natural Gas Pipeline Study from 1989.°! Transmission Costs For the purposes of this generic screening study, the transmission costs are largely a function of the distance from the natural gas resource to the market. Under actual field conditions, topography, soils, and land ownership may have a material effect upon transmission costs. Base Case To simplify the analysis, the base case assumes the market sits on top of the resource and there are no transmission costs. As part of the sensivity analysis circumstances are modeled where the resource and market are separated. Alternatives If the community is not located on or adjacent to the natural gas field, moving the gas energy to the community and providing electrical power to the natural gas field become significant cost considerations. There are three basic alternatives: A: Gas Line & Intertie B: Gas Line & Field G Cl 7 Pipeli NG Field NG Field NG Field Field Gen Field Gen Converted Converted NG Cit Power Plant easy Power Plant Electric NG Electric NG Electric Distribution Distribution Distribution Distribution Distribution End-User End-User End-User Conversion Conversion Conversion to Nat Gas to Nat Gas to Electric Heat Heat Heat Short Distance When the market is within 2 miles of the resource, polyethylene pipe appears to be the most economical transmission mode. * Id. page I-20. MAFA/ARI page 31 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska The limitations on the working pressure of current commercial applications of polyethylene pipe constrain its use to short distances. Improvements in polyethylene pipe technology are expected to enable it to economically provide transmission over increasingly longer distances. Currently at short ranges of under a few miles, polyethylene pipe appears to be the most economical approach to hauling gas energy. Based on actual installed costs from Norgasco on the North Slope, polyethylene pipe is estimated to run approximately $15 per foot under unfavorable conditions, or roughly $80,000 per mile. The basic cost of a buried polyethylene transmission system is estimated as $60,000/mile. Then the consideration becomes the trade-off between modifications within the existing power plant to accomodate the incremental capacity associated with the natural gas field and shipping electricity back over a small intertie vs. building a new field generation station building and support facilities on the natural gas field site. If the existing power plant has room to inexpensively expand capacity, an intertie may make sense for shortdistances. As the distance increases, a new field generation station is likely to become an increasingly attractive economic alternative. Assume the incremental costs of the building and support facilities associated with the new generation station sized to meet the natural gas field load is roughly $120,000 + $40,000. Assuming a small intertie is used to feed power back to the field on the short distances, it is estimated to cost roughly $30,000 per mile. The All-Electric Heat Scenario Under the All-Electric Heat Scenario, one could provide energy transport either via pipeline to the expanded generating station or build a new generating station at the gas field and ship power to the community over a large capacity intertie. In either event, since the overall system energy conversion efficiency is less under the all-electric case, the transmission capacity of either the pipeline or the intertie will need to be larger than what would be required under the natural gas heating case. The basic trade-off is between a pipeline vs. an intertie and the net incremental costs associated with a new building and switching facilities located at the gas field as compared to expanding the existing power plant facilities. Estimate the large capacity polyethylene pipeline as roughly $70K/mile. Estimate the large capacity intertie as roughly $60K/mile. Assume the incremental costs of the building and support facilities associated with the new generation station to meet the entire electric load is roughly $250,000 + $50,000. Summary Table 13: Comparison of Short Distance Transmission Costs (2 miles) Medium Sized Community (835 customers) Typical Favorable Unfavorable A: Gas Line + Small $180,000 $120,000 $240,000 Intertie $43/customer per year $29/customer per year $58/customer per year B: Gas Line + Small $180,000 $120,000 $240,000 MAFA/ARI page 32 26-Feb-97 Cost Estimates Field Gen $43/customer per year Natural Gas in Rural Alaska $29/customer per year $58/customer per year Cl: Lg Field Generation + Lg Intertie $370,000 $89/customer per year $300,000 $72/customer per year $440,000 $105/customer per year C2: Gas Line to Converted Power Plant + Small Intertie $200,000 $48/customer per year Medium and Long Distance $160,000 $38/customer per year $240,000 $58/customer per year Over longer distances higher pressures are required to move natural gas through a pipeline and steel pipelines become the natural gas transmission medium of choice. Steel Pipeline For longer distances, a steel pipeline is estimated to average roughly $150,000 per mile. It should be noted that topography, soils, the diameter of the pipe and wall thickness required for the particular application, the cost to haul steel pipe to a specific remote site, and skilled labor shortages can generate significant cost adders to the base figure of $150,000 per mile for small diameter transmission facilities. Table 14: Comparison of Medium Distance Transmission Costs (20 miles) Medium Sized Community (835 customers) Typical Favorable A: Gas Line + Small Intertie $3.6 million $862/customer per year $2.9 million $695/customer per year Unfavorable $4.3 million $1030/customer per year B: Gas Line + Sm Field Gen Cl: Lg Field Generation + Lg Intertie $3.1 million $747/customer per year $1.4 million $347/customer per year C3: Gas Line to Converted Power Plant + Sm Field Gen $3.1 million $747/customer per year $2.6 million $618/customer per year $1.2 million $287/customer per year $2.6 million $618/customer per year $3.7 million $877/customer per year $1.7 million $407/customer per year $3.7 million $877/customer per year Note that while the transmission alternatives for the all-electric case are less expensive than the natural gas heating scenario, the net savings on transmission is relatively small compared to the large incremental expenses associated with the additional generating capacity required under the all electric case.” Thus, when one totals the net differences in costs across generation, transmission, distribution, and end- users, the economic trade-offs examined in this report tend to favor natural gas heat over electric heat. >? See Appendix “Schedules” - Electric Heating vs. Natural Gas Heating MAFA/ARI page 33 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska Transmission O&M The incremental operations and maintenance costs associated with transmission facilities are estimated as 2.5% of the capital cost. Revenue Requirement Estimate Thus for a 20 mile pipeline serving the medium sized community, the costs associated with O&M for transmission are: (20 miles * $150,000/mile) + ($120,000) = $3.12 million Capital $3.12 million capital * 0.2 capital recovery factor = $624,000 annualized capital cost $624,000 million * 2.5% O&M percentage = $15,600 annual O&M expense Total Annualized Expense = $639,600 + 835 customers = $766 per customer per year Electrical Generation There are several alternatives to convert existing diesel-fired electrical generation systems to natural gas including: e Convert existing diesel-fired engine to gas-fired operation e Replace diesel-fired engine with gas-fired engine; leave existing generator in place e Add new gas-fired generator sets The basic trade-offs between these alternatives involve the following considerations: ¢ Capital cost vs. operational efficiency e Fuel supply risk ¢ Need for a new building to house generating equipment Gas Conversion Alternatives Convert Existing Diesel to Gas CAT estimates complete field conversion of its prime movers will require on the order of 300 hours of custom labor plus parts and basic new control systems. At $20 per hour, $6,000 labor + $40,000 parts and equipment, $46,000. At $100 per hour, $30,000 labor + $40,000 parts and equipment, $70,000. Due to the variability of field conditions and the impact of fuel quality on efficiency, it appears that attempts to complete a field conversion run a risk of a material loss of efficiency. This alternative does mitigate against prolonged fuel supply disruption because of the ability to switch back to diesel. MAFA/ARI page 34 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska In the short term, a disruption of the natural gas fuel supply remains a risk over the timeframe it takes to convert back to diesel. Replace Existing Diesel with Gas Engine Another approach is to replace the existing diesel engine with a new gas-fired engine and reconnect the generator to the new engine. However, due to the variability of field conditions and the ability to match a new engine to an existing generator, this conversion alternative runs a risk of an overall efficiency loss compared to a new installation. This alternative mitigates against prolonged fuel supply disruption because of the potential ability to reinstall the diesel-fired engine. In the short term, disruption of the natural gas fuel supply remains a risk over the timeframe it takes to switch back to diesel. Replace Existing Diesel Gen Set with Gas Gen Set This alternative requires a higher up-front capital cost with the promise of higher efficiencies due to an optimized match between the engine and generator and controls. If the existing diesel engine generator set is removed and sold for surplus, this alternative appears to run higher risks due to natural gas fuel supply disruption. If the existing diesel engine generator set remains in “maintained inventory,” the risks due to natural gas fuel supply disruption are mitigated. Add a new Gas-fired Gen Set Leaving existing diesel-fired equipment in place and adding new gas-fired generation units may be appropriate where the new gas-fired units can be housed in existing facilities or facilities to house the new units can be constructed for a modest amount. The advantage of this alternative is that it provides a hedge against fuel-supply disruption risks and should enable highly efficient natural gas-fired operations relative to other alternatives. Estimated Order of Magnitude of Trade-Offs To illustrate the order of magnitude of these trade-offs, a simple life-cycle cost analysis is used to develop a sense of the break-even values for capital cost and efficiency. Assume 60,000 hour life, 35% plant use, 500 kW rating, avg. load of 400 kW (400k Wh/h*.35*8760 = 1,226,400kwh/year), 4.5% discount rate. Table 15: Natural Gas Conversion Options | New Engine/Generator New Gas-fired Engine | Convert Existing Engine Set Capital Cost $550,000 $385,000 Avg. Fuel Efficiency 10,250 (Btu/kwh) Fuel Cost $62,853/yr $69,138/yr $82,966/yr Incremental O&M $28,170/yr ee — New Building Possible MAFA/ARI page 35 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska If a new building is not required to house the new engine/generator set, it appears that the various approaches are all within 10% of life cycle cost of the other alternatives assuming differences in performance that have been reported for conversions. Given the wide variety of field conditions present in rural Alaska, it is entirely possible that any one of the alternatives may make sense for a particular installation. Base Case Assumption Given that the difference in life cycle cost among the approaches does not appear significant at the reconnaissance level, the base case assumes the addition of a new gas-fired generator set within an existing structure. It is conceivable that some power plant operators will want to maintain their diesel fired generator sets in parallel with their new natural gas fired generator sets for reliability purposes. The base case assumes that the costs associated with any diesel units that may remain in place for reliability purposes are negligible. However, it should be noted that maintaining diesel backup capability may increase the overall O&M costs and thereby reduce the feasibility of the natural gas alternative. New Gas-Fired Engine Generator Set Capital Based on conversations with CAT and Cummins vendors and utility managers, the following rules of thumb have been developed to compare the installed capital cost of gas-fired vs. diesel-fired engine- generator sets for rural Alaska utility installations. Table 16: Installed Capital Cost Diesel & Natural Gas Engine-Generator Sets Diesel-Fired $500/kW Natural Gas-Fired $1000/kW Other Studies This compares to the range of recent estimates from studies performed for the Division of Energy and Alaskan Utilities and actual installed costs reported by utilities. Stone & Webster used a figure of $470/kW for diesels in a 1990 Least Cost Plan for Copper Valley Electric Association.” R.W. Beck and CH2M-Hill in conjunction with the Sutton-Glennallen intertie studies estimated installed diesel costs around $800/kW - $900/kW for units in the 1600 - 2200 kW range which appear to have included paralleling switchgear and a significant contingency. 3 As quoted by Analysis North in its Economic Analysis of Coal-Fired Power Plants, September 19, 1991. MAFA/ARI page 36 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska Fuel Efficiency Efficiencies reported on technical data sheets supplied by vendors include figures in the following range: e¢ Low No, Configuration (<0.8 gram/horsepower-hour NO,) 6920 Btu/hp-hr e High Efficiency Configuration (>2 gram/horsepower-hour NO,) 6700 Btu/hp-hr Field fuel efficiency for gas-fired generation is assumed to average around 7644 BTU/hp-hr; which is roughly equivalent to 10,250 Btu/kWh This compares to actual field efficiencies achieved in rural Alaska for diesel-fired electric generation for utilities on the PCE program which run the gambit from down under 6 kwh/gallon to around 16 kwh/gallon at the generator set. This study assumes station use and distribution losses in total average around 10%, with slightly higher percentage losses in smaller community systems. Thus, the system fuel efficiency is assumed to be around 89 kwh,,,4 per mef burned in the gas-fired engine in the medium and large communities. In summary, natural gas-fired reciprocating engines are estimated to provide fuel efficiency in the following ranges: Table 17 Fuel Efficiency Estimates - Natural Gas Reciprocating Engines S-Small Engine Spec (BTU/hp-hr) Field Efficiency (BTU/hp-hr) Station Use & Distribution Loss System Fuel 89 kwh,,14/mef | 89 kwh,,)4/mef 8ikwh,,\/mef | 78 kwh,,)./mef Efficiency Operations & Maintenance The cost of operations & maintenance associated with the gas-fired generator is assumed to be roughly 33- 50% more than diesel due to the higher top-end operating temperature and the associated need for more frequent top end overhauls.** This is incorporated into this study as follows: Table 18: Operations & Maintenance Expenses Annual O&M per kW O&M per kWh * State of Alaska, Division of Energy, R.W. Beck Copper Valley Intertie Study, 1994. *5 Estimates provided by natural gas reciprocating engine vendors. MAFA/ARI page 37 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska The operations and maintenance estimates are roughly comparable to those used by R.W. Beck in the Copper Valley Intertie Feasibility Study - where O&M expenses for new diesel-fired generating units were estimated at $12/kW + $0.01 per kWh in 1993.°° The R.W. Beck figures have been adjusted upward to reflect the smaller scale operations of most rural Alaska operations. It should be noted that the actual fixed and variable components of O&M for diesel-fired electrical generation vary greatly among utilities in rural Alaska due to differences in labor rates, equipment and material costs, and approaches to maintenance. °° See page IX-12, R.W.Beck, Copper Valley Intertie Feasibility Study, State of Alaska, Division of Energy, 1994. MAFA/ARI page 38 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska Cost of Alternatives Electrical Diesel fuel remains the primary fuel source for electrical generation in much of rural Alaska.*” The cost of electrical generation runs from around 14¢/kWh to as much as 45¢/kWh or more in some rural Alaska settings. A consideration in the future price of diesel-generated electricity is the impact of environmental regulation concerning fuel storage, transportation, and emissions restrictions. A discussion of these possibilities is included in the section entitled Environmental Considerations. Heating Fuel Oil is widely used as a fuel source for domestic hearing in rural Alaska. Price for delivered fuel oil ranges from $1.10 to over $2.50 per gallon. Wood is used where available. Price ranges from essentially zero to around $150 per cord. Propane is widely used for cooking and for some heating. Prices range from $1.59 to $4.00 per gallon. Coal is used for heating in Healy. Current prices for subbituminous coal in Healy run $45/ton for retail with delivery charges added based on driver time. Natural gas from Enstar in Anchorage is currently running around $3.20 per mcf for a residential customer. The estimated cost of natural gas for small rural communities in this study run upwards of $50 per mcf. Table 19: Range of Prices Among Alternative Fuel Sources in Alaska Natural Gas | Diesel (#2) | Propane | Wood Coal | Electric Retail Price $3.20/mef | $1.10/gal $1.60/gal $0 $45/ton 15¢/kWh (low) Retail Price $50.00/mcf | $2.60/gal $4.00/gal | $150/cord | $150/ton 45¢/kWh (high) Heat Content 1,000,000 137,750 90,300 15,000,000 | 15,000,000 3413 Units Btu/mcf Btu/gal Btu/gal Btu/cord Btu/ton Btu/k Wh Efficiency 70% 65% 70% 55% 60% 100% ftow see | sizz [ 32530 | so | $500 | 0390 | >” See Alaska Electric Power Statistics, 12th Edition, October 1995, Utility Installed Capacity, pp. 12-18. *8 Power Cost Equalization data from the APUC, 1995 Annual Updates. MAFA/ARI page 39 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska Figure 2: Residential Cost of Delivered Heat ($ per million Btu) 140 120 100 ao Oo glow gHigh a o $ per million Btu os Oo nN Oo oO Fuel Oil Wood Propane Electric Natural Coal Gas Comparison Case There are three basic product lines to consider in the comparison case: e Electricity (Diesel) e Domestic heat (Diesel) ¢ Cooking fuel (Propane) Diesel-Fired Electrical Generation The costs associated with diesel-fired electrical generation are broken down into four areas: ¢ Capital e Fuel ¢ Operations & Maintenance e Administrative Common Costs Capital By utilizing a revenue requirements approach for the initial screening, the capital cost of new diesel generators is incorporated into the study as the cost of capital plus depreciation expense -- which for this study is an average annual capital cost recovery factor of roughly 20%. Based on anecdotal evidence from actual utility installations in the last four years and discussions with vendors, diesel capital costs in rural Alaska appear to run a wide range between $300/kW on up to around $800/kW depending in part on the size of the unit, whether it is designed for stand-by or prime mover service, whether existing switchgear and related facilities are already in place, whether a new building is required to house the unit, the costs for delivery, and specific installation requirements. For the basic comparison case, the following conditions are assumed: MAFA/ARI page 40 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska ¢ Base unit sizes range from under 100 kW in the small communities up over 1000kW in the large community e Units are assumed to be designed for prime mover service e Paralleling switchgear exists and only a basic transfer switch is required for new units e Anew building is not required e Delivery is estimated to range from $0.20 up to $3.00 per pound Based on these assumptions the total installed capital costs are estimated to range from around $400/kW up to $700/kW, with $500/kW used in the base case to represent a typical mid-range case.” Environmental Considerations - Emissions Controls Base Case The base case assumes that incremental tightening of emission control standards are roughly offset by technical improvements. Sensitivity Analysis It is also possible that emission control standards may raise the capital cost of new diesel-fired generator installations. Air quality permit requirements are generally triggered by a major new or modified source where the source has potential emissions which exceed a certain amount of tons per year depending upon circumstances.” If permit requirements are triggered and a Best Available Control Technology (BACT) analysis is required, the potential range of costs appears to be on the order of $150/kW or less. Taller Stacks For example, a basic BACT analysis which results in a taller stack to help disperse the emissions may cost roughly:* BACT Analysis Capital Site Specific Permit $10,000 Testing $20,000 Taller Stack $ 5,000 Total $35,000 For the low end of the range of generators to which this may be applied, say a generator of 500kW, this represents an addition of $70 per kW. Catalytic Reduction In a situation where more rigorous controls are required, the costs may be roughly: >? See also Natural Gas Cost Estimates, Capital Cost discussion. “ See 40 CFR 52.21, Prevention of Significant Deterioration (PSD) permit requirements. *! These estimates are based on a review of actual requirements imposed in Alaska as well as Western States when BACT analysis and controls have been triggered. Source: Lorenzen Engineering. ° Id. MAFA/ARI page 41 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska BACT Controls Required Capital Site Specific Permit $10,000 Testing $20,000 Air Fuel Modifications + Catalytic Reduction $50,000 Total $80,000 A non-selective catalytic reduction system basically involves installing a large catalytic converter on the exhaust stream of the engine along with combustion controls that maintain the air-fuel mixture slightly to the fuel-rich side. This may result in some modest increment in fuel use, typically less than 5%, and some additional O&M associated with monitoring the catalytic converter. On the low end of the range of generators to which this may be applied, say a generator of 500kW, this represents an addition of $160 per kW. Assuming a 500kW generator in a prime mover application, operating at an average 400 kW load, with a 35% usage over the year, an average efficiency of 13kWh/gallon, the impact on a revenue requirement calculation would be as follows: Capital $80,000 Capital Recovery Factor 20% Annualized Capital Expense $16,000 Fuel Increment $ 4,000 O&M Increment $ 4,000 Total Annual Incremental Expense $24,000 Assuming 1.2 million kWh per year on the unit, the total incremental expense is around 2¢/kWh, or the equivalent of an increase of roughly 25¢ per gallon of diesel fuel. Diesel Fuel Price To develop a base case for the price of diesel fuel, prices of diesel fuel reported by rural utilities in PCE filings were reviewed for the period 1990 - 1996. This sample of fuel prices includes two price “spikes” - one during the Gulf War, and one during the fall of 1996. For some /arge rural utilities, delivered diesel fuel averaged somewhere around the 80¢ per gallon range for the past five years in real terms.*° For small remote rural utilities, delivered diesel fuel ranged from around $1.60 per gallon on up to around $2.00 per gallon for the past five years in real terms.“ For the initial screening study, the following diesel cost profile was assumed: e Large Community 80¢ per gallon ¢ Medium Community 90¢ per gallon *® See Appendix, Fuel Prices, Nome, Naknek. “* See Appendix, Fuel Prices, Venetie, AVEC. MAFA/ARI page 42 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska The estimates for diesel-fired generation provided by R.W. Beck for the Copper Valley Intertie Feasibility Study are adjusted upward to reflect the generally smaller scale operations in more rural settings.° Administrative Overhead For this analysis, a number of administrative functions are assumed to be common activities which occur regardless of whether diesel or natural gas is the energy source. Examples of these common costs include: e Labor - management, accounting, payroll, billing and collection activities e Other - office rent, heat, utilities e Electric distribution system - labor, parts, and equipment to maintain the electrical distribution system These common administrative costs are not included in the basic comparison between diesel and natural gas alternatives since they do not help distinguish between the alternatives. These costs need to considered if one is attempting to estimate the price of alternative sources of energy. Diesel Fuel Heating The costs associated with diesel fuel for domestic heat are separated into two areas: e Cost of delivered fuel e Cost of Oil-fired heat source Delivered Fuel To estimate the price of retail delivered fuel oil, calls were placed to several communities to assess the differential between the price delivered to utilities and the price delivered to residences.” The price of delivered fuel oil tends to run between 40 - 75¢ more per gallon for retail as compared to utility delivery. Delivery quantities of less than 100 gallons tend to pay premiums as high as 100¢ more per gallon than the local utility.” The base case assumes the delivered price of fuel oil to be 60 cents per gallon more than the price paid by the utility. Oil-Fired Heat Source Similar to the capital cost of diesel-fired electrical generator sets, there are two basic alternatives. One can assume existing stock of oil burners is not required to be replaced vs. all need to be replaced. 5! R.W. Beck, State of Alaska, Division of Energy, Copper Valley Intertie Feasibility Study, p. IX-12, 1994. 52 Anecdotal evidence was collected from Nome, Teller, Nikolai, and Galena. 3 Verbal quotes from Bonanza Fuel, Nome. eae EEE EEE SSE MAFA/ARI page 45 26-Feb-97 ee Cost Estimates Natural Gas in Rural Alaska For the purposes of the screening study, if one remains on diesel heat, it is assumed that oil burners are not required to be replaced. The annual maintenance on an oil burner is assumed to be roughly $80 per year compared to the annual maintenance on a gas burner of $36 per year.** In the all-electric heating case, it is assumed the annual maintenance for electric heating averages $10 per year. Cooking Base Case For the purposes of the initial screening, if one remains on diesel heat, it is assumed that electricity is the primary source of cooking energy which is reflected in the annual electrical energy usage assumed in the base case. Sensitivity Analysis - Propane Cooking Assuming that the annual electricity usage does not include an amount associated with cooking because it is primarily provided by propane, the net impact of propane cooking on the comparison between the status quo and natural gas amounts to the difference between the annualized cost of fuel for propane vs. the annualized cost of fuel for natural gas plus the annualized capital conversion cost. To estimate the impact of propane cooking on this screening model, one can add roughly $150 per household per year in the base case. This is based on two seven-eighths refills of a 100# (23 gallon) propane tank in Nome at $77 per refill. This amounts to roughly $3.82 per gallon and calculates to $42.30 per million BTUs.** Assuming the conversion efficiencies of propane and natural gas are roughly the same, this is equivalent to natural gas at around $40 per mcf. The capital cost to convert from propane to natural gas is expected to be around $200 to change nozzles. With a capital recovery of 20%, the annualized cost is around $40. Thus, assuming about 3% million BTUs in household cooking loads, natural gas is a viable substitute for propane in those cases where the delivered price of natural gas is under $30 per mcf. At values of $15 per mcf, converting to natural gas should save households about $50 per year over propane. * See previous discussion on Gas-fired end-user maintenance. °> Verbal quote from Bonanza Fuel, Nome, 1996. °° Assuming a gallon of propane contains roughly 90,300 BTUs. MAFA/ARI page 46 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska e L-Small Community 180¢ per gallon e M-Small Community 190¢ per gallon e = §-Small Community 200¢ per gallon In the base case, the real price of diesel fuel is assumed to remain around these average values when averaged over the course of the study horizon (25 years). While nominal prices may be volatile depending on short-term market supply, demand, and profit opportunities, a recent study by the General Accounting Office suggests that over a longer run the real price of refined products may even decline.*° Environmental Considerations - Impact on the Cost of Diesel Fuel Base Case The base case assumes that the real long-run average price of diesel fuel will remain constant over the study period. Sensitivity Analysis Tank Farms For the purposes of the sensitivity analysis, the following costs associated with environmental considerations may become impounded in the cost of diesel fuel: Utility Tank Farm Improvements” $200 million Other Transportation & Storage Improvements” $50 million Diesel Fuel Capital Improvements $250 million Capital Recovery Factor®® 20% Annualized Cost $50 million Avg. Annual kwh” 600,000,000 kWh Avg. Cost per kWh $0.08/kWh? Change in Fuel to Reduce Emissions Where SO, emissions concerns have been raised by the Alaska Department of Environmental Conservation, reduced emissions requirements have been meet by burning low sulfur diesel fuel. This is typically accomplished by increasing the proportion of #1 Diesel Fuel (Jet Fuel) that is burned. *S See Energy Security and Policy: Analysis of the Pricing of Crude Oil and Petroleum Products, GAO, March 1993. “° State of Alaska, Division of Energy Estimate. “” SWAG which represents the capital costs associated with environmental considerations of entities supplying fuel to utility tank farms. “8 CRF = 15% return on capital + 5% depreciation * Total Generation by Alaska Utilities with diesel, rounded up from 591 GWh, as reported for 1995, Alaska Electric Power Statistics. °° Note that an increase of 8¢/kWh is roughly equivalent to an increase of roughly $1.00 a gallon in diesel fuel; assuming efficiencies of around 12 kWh/gallon. MAFA/ARI page 43 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska Assuming that 100% #1 Diesel Fuel is required to meet the emissions standard may result in the following cost increases: e incremental increase of as much as 10¢ per gallon for fuel e incremental decrease of roughly 4% in net BTU’s per gallon e net increase in cost of as much as 11¢ per gallon of equivalent BTU content fuel Efficiency To develop a base case for the efficiency of diesel electricity generation, efficiencies reported by rural utilities in PCE filings with the APUC were reviewed. Typical fuel efficiencies reported by the APUC are based on total kwh’s billed divided by total gallons consumed. Thus station use and line loss in the range of 8-12% are implicitly included within these efficiency figures. Fuel efficiencies for rural utilities ranged from above 14 kwh/gallon for Nome to under 6 kwh/gallon for some small remote operations. For the initial screening study, the following diesel efficiency profile was assumed: e Large Community 14kWh,,ig per gallon ¢ Medium Community 14kWh,,\4 per gallon e L-Small Community 12kWh,,ig per gallon e M-Small Community 11kWh,,ig per gallon e = S-Small Community 10kWh,,i4 per gallon Operations & Maintenance (O&M) Significant volumes of operations and maintenance cost data are filed with the APUC as part of the annual Power Cost Equalization updates. There appears to be a wide range of costs reported for operations and maintenance activities across rural Alaska. In addition, a number of studies for the Division of Energy have generated varying estimates for the operations and maintenance associated with diesel-fired electrical generation. For the base comparison case, the cost of operations & maintenance associated with diesel is estimated as follows: Table 20: Operations & Maintenance Cost Estimates Diesel Natural Gas Annual O&M per kW $15/kW $22/kW O&M per kWh 1.0 ¢ per kWh 1.4 ¢ per kWh MAFA/ARI page 44 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska Analysis Key Economic Drivers The factors which appear to drive the feasibility of natural gas a substitute fuel in rural Alaska include: e — gas field characteristics e the cost of exploration to find the natural gas e the cost of alternative energy sources e the distance from the gas resource to the community Base Case For the purposes of an initial screening, it would appear that a local small scale natural gas development might be competitive with diesel for communities with 500 households or more (1750 population) under the optimistic base case conditions. Table 21 Relative Cost of Gas Energy Compared to Diesel Base Case (indexed for each community size) Community Size Largely due to the costs associated with development of a remote small scale natural gas field, diesel appears to be a more competitive energy alternative in much of rural Alaska where communities have less than 200 households (600 population). Sensitivity Analysis A number of factors may influence whether gas remains a competitive alternative with diesel in larger rural communities. Quality of Gas Field A key consideration is the quality of the gas field. Unless the gas field quality is good or very good, it appears that diesel remains a more competitive alternative. Also note, that for the small communities, even a high quality gas field does not appear to overcome the cost advantage of diesel. MAFA/ARI page 47 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska Table 22 Relative Cost of Gas Energy Compared to Diesel Gas Field Quality Sensitivity Analysis (indexed for each community size) Community Size Medium | L-Small Gas Field Quality Lo 0.85 | 1.27 1.00 | 1.00 Quality Gas Diesel Exploration Costs Associated with Gas Under a successful “minimalist” approach to gas exploration, a gas field development may be competitive with diesel for communities of over 500 households (1750 population) if one also assumes a modest permanent increase (12¢/gallon) in the the cost of diesel fuel. However, the costs associated with a more typical modern exploration program appears to effectively preclude the economic attractiveness of natural gas from small scale remote developments to meet the needs of rural Alaska. Absent a solid indication from key parameters which improve the competitiveness of gas or decrease the attractiveness of diesel, it appears that the margins associated with developing natural gas fields to serve rural Alaskan markets do not support the risks associated with the exploration and development of natural gas. Table 23 Relative Cost of Gas Energy Compared to Diesel Gas Exploration Cost Sensitivity Analysis (indexed for each community size) Community Size Large Medium | L-Small MAFA/ARI page 48 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska 2S 1.30 2:35) Diesel 1.00 1.00 Cost of Diesel Fuel Supplied Energy A key consideration in whether the risks associated with gas exploration and development are worth the reward is one’s assessment of whether the cost of diesel fuel for rural Alaska will increase in real terms. Given historic trends, it would appear that while environmental considerations may place upward pressure on the cost of diesel fuel supplied energy, a number of mitigating factors tend to constrain the upward movement in costs, not the least of which is a vigorous marketplace which has responded with improvements in technology which improve productivity. Nonetheless, there is some potential for a permanent increase in the price of diesel fuel due to environmental considerations. To estimate the impact of this possibility upon the feasibility of natural gas, an “environmental considerations” adders of 25¢ and 50¢ per gallon yields the following results. Table 24 Relative Cost of Gas Energy Compared to Diesel Relative Increase in Diesel Prices (indexed for each community size) Community Size L-Small If one has a good indication that the price of diesel will experience a permanent increase on the order of 25 cents per gallon or more, then the margins this creates for gas begin to support some modest exploration programs for natural gas for larger rural communities. The problem remains that the margins for gas need to be large enough to support both an exploration program and a transportation system to get the gas from the field to the domestic market. Distance from Gas Field to Local Community For the base case, it was assumed that the local community was on top of or adjacent to the natural gas field. MAFA/ARI page 49 26-Feb-97 Cost Estimates Natural Gas in Rural Alaska As the distance between the market and the gas field grow, the costs to transport the gas can eat into the competitive margin gas may have over diesel. Under the base case, the break-even distance is around 2 miles - fields that are more than 2 miles away from a community in the base case become increasingly uneconomic. Table 25 Relative Cost of Gas Energy Compared to Diesel Distance from Gas Field to Domestic Market (indexed for each community size) Community Size Medium L-Small Finally, some interesting break-even cases can be constructed using combinations of the above sensitivity analysis. Table 26 Relative Cost of Gas Energy Compared to Diesel Sensitivity Analysis Combinations (indexed for each community size) Community Size L-Small Gas Diesel MAFA/ARI page 50 26-Feb-97 Environmental Considerations Natural Gas in Rural Alaska Environmental Considerations Introduction This section provides an overview of the environmental considerations associated with natural gas compared to existing energy alternatives. For the general overview, the environmental considerations are divided into two areas: e Environmental considerations which are currently associated with an explicit cost - such as permitting or performance standards which impose easily measurable costs e Environmental considerations which are currently characterized as “externalities” - costs which are not currently impounded in permitting or performance standards For the specifics of the trade-offs between natural gas and diesel, the report organizes a review of environmental considerations into the following subsections: e Natural Gas Energy Use ¢ Coalbed Methane Field Development e — Transportation Considerations e Electric Generation Considerations e End-User Heating Considerations e Diesel Energy Use e Transportation and Storage Considerations e Electrical Generation Considerations e End-User Heating Considerations MAFA/ARI page 51 26-Feb-97 Environmental Considerations Natural Gas in Rural Alaska TABLE 27: SUMMARY OF ENVIRONMENTAL CONSIDERATIONS Natural Gas / Coal Bed Methane Explorstion & Developent Costs Accounted For in Estimates Water disposal, site development, reclamation Many costs impounded in delivered price Many costs impounded in delivered price Reclamation costs impounded in delivered price Unlikely that many costs are impounded in delivered price Externalities CBM Mitigates atmospheric methane releases associated with coal production More rigorous waste disposal requirements may become impounded in the future More rigorous waste disposal requirements may become impounded in the future Methane production Cutting trees reduces carbon storage Costs Accounted for in Estimates Some storage costs impounded in current price Externalities Methane dissipation in handling, accidents Additional costs associated with tank farms may become impounded in price BLEVE hazards may require relocation of tanks Runoff from coal storage may require containment Costs Accounted for in Estimates Externalities Relatively clean burning fuel Relatively clean; additional costs may become impounded in price due to tightening emissions standards Many costs impounded in price Additional costs may become impounded in price due to tightening emissions standards Relatively clean burning fuel Many costs impounded in price Relatively clean MAFA/ARI page 52 Additional costs likely to become impounded in price due to tightening emissions standards Air emissions have limited wood burning in certain areas - Juneau 26-Feb-97 Environmental Considerations Natural Gas in Rural Alaska Natural Gas Exploration & Development Introduction Intensive development of shallow gas reservoirs in the U.S., such as coal seams in the Warrior basin of Alabama and the Antrim shale of the Michigan basin -- involving thousands of wells -- has raised environmental concerns that, initially, threatened to seriously constrain production. However, the development and application of new cost-effective technologies and environmentally sound planning enabled operators to mitigate these problems in most basins. Environmental conflicts -- primarily the disposal of large volumes of water produced from drilling coalbed methane operations or the development of several hundred well programs on environmentally sensitive lands -- have occasionally slowed the pace, but not the overall extent of development. Externality Benefits Simultaneously, natural gas development, especially coalbed methane, may create a tangible environmental benefit by reducing the potential for global warming caused by emissions of methane. Methane, which is suspected of being a potent greenhouse gas, is vented to the atmosphere in significant quantities during routine underground coal mining operations (EPA, 1994). The perception within the international environmental community is that methane emissions from coal mining is cause for concern and should be mitigated. By capturing methane from coal seams prior to mining, coalbed methane production can reduce future emissions of methane to the atmosphere. Legislative initiatives are under discussion in several countries to allow coalbed methane operators to earn tradeable emissions credits, which would promote coalbed methane recovery in mining and non-mining areas. In Alaska, the production and utilization of natural gas would have significant local environmental benefits. From wellhead to burner tip, natural gas is the cleanest burning and one of the most versatile hydrocarbon energy resource available. It can be used for power generation, as a transportation fuel, or for residential heating and cooking. More importantly, in most of these applications it results in lower emissions of gases and particulate matter than the diesel/gasoline or wood it replaces. Natural Gas Drilling & Production Environmental concerns related to the production of natural gas are raised primarily during two stages of development. The first is during drilling which involves establishing a wellsite and the drilling operations themselves. The second concerns the fluids which are produced from the formations in conjunction with the gas. Surface Footprint Establishing the initial wellsite location will require a site large enough to accommodate the drilling rig and associated equipment (i.e., drill pipe, casing), hydraulic fracturing equipment, and mud pits/settling ponds. In general, this would encompass an area of approximately 2 acres. After drilling and completion, the size of the “footprint” can be reduced form 2 acres down to an area of approximately 500 square feet. This reduced area would support the wellhead, pumpjack, and separation/metering facilities. The construction of the location, as well as the service road into it, would most likely take place during the winter months to minimize vehicle related surface damage. MAFA/ARI page 53 26-Feb-97 Environmental Considerations Water Associated with Production Produced waters and their disposal, especially during coalbed methane production, probably represent the most prominent environmental consideration at the present time. Conventional gas production operations can also produce fluids, but generally at very low volumes. Therefore, because the disposal technologies for conventional and coalbed produced waters are the same, the following discussion focuses on coalbed methane because of its higher volumes. Natural Gas in Rural Alaska Coalbed methane production relies on the concurrent production of large volumes of coal seam formation water to reduce initial reservoir pressure and elicit desorption of gas from the coal reservoir. The rate of water production from a CBM well varies widely, depending primarily on reservoir thickness, porosity, permeability, well spacing, pump rates, and proximity to aquiferous sandstones or intrusions and meteoric recharge. CBM wells typically produce 100 to 500 barrels per day (bwpd) of formation water during the early phases of coalbed methane production, which may range from six months to many years depending on permeability, pump rates, and well spacing. Although water production rates decline over time, total production from a typical CBM project involving hundreds of wells can be considerable and must be carefully managed to meet local environmental requirements. Coal seam formation water varies widely in composition. Produced water from permeable, shallow coal reservoirs close to meteoric recharge is often quite fresh, such as in the Powder River basin or in the northernmost San Juan basin. More commonly, however, coal seam formation water contains significant levels of total dissolved solids (TDS) and requires special treatment and/or disposal under most environmental regulatory regimes. The levels of total dissolved solids range from as low as 500 ppm in the Warrior basin to as high as 50,000ppm in the Central Appalacian Basin. The primary dissolved constituents of produced water from coal seams in the U.S. are sodium chloride or sodium bicarbonate, with minor levels of iron, manganese, and occasionally low but still problematic levels of constituents such as boron or silica. Typical water analyses for produced water from coal seams in the Warrior basin are shown in Exhibit 1-1, and for the San Juan basin in Exhibit 1-2. Exhibit 1-1: Produced Water Quality by Field in the Warrior Basin Parameter] Brookwood | Cedar Deerlick | Moundville Oak Grove Creek Grove pH 5.8-8.9 ~ 6.3-9.0 6.7-8.9 | 5.6-8.0 7.0-8.8 TDS (ppm) 430- 920- 4,200-27,500 | 8,100-60,000 300- 31,100 25,100 17,100 Chloride 80- | 100- 2,500-13,500 | 4,000-36,000 40- 18,800 14,900 18,000 ‘oa Avg Cl 3,000 3,000- 4,000- 28,000 1,500 8,000 6,000 Sodium 60- 570- 3,200-11,000 | 2,700-21,500 500- 14,41 6,200 11,600 Sulfate 1,590 1-8 3-33 5 2-1,350 Iron 1-112 0.1-78 0.6-33 10-202 0.4-400 Manganese 0.1-2.8 0.1-3.2 0.1-0.2 0.1-1.3 0.1-4.2 Source: GRI, 1993 7 i MAFA/ARI page 54 26-Feb-97 Environmental Considerations Natural Gas in Rural Alaska Exhibit 1-2: Produced Water Quality in the San Juan Basin Constituent (ppm) : Colorado New Mexico. _—‘| Chloride SS 0-800 600-1,600 Sodium 600-3 ,000 2,500-7,500 | Bicarbonate 1,500-7 ,000 6,000-18 ,000 TDS 2,000-8,000 10,000-20,000 Source: Stevens, 1993 Formation water TDS generally increases with longer residence time within the coal reservoir: low permeability and or location far from meteoric discharge increase residence time, increasing dissolution of even relatively insoluble solids. For example, coal seams in the Central Appalachian basin far from recharge are highly saline, typically containing over 50,000 ppm of dissolved NaCl, yet water production rates are very low at several bwpd per well or less. In contrast, produced water in the western Raton basin close to recharge along the outcrop of Vermejo from coal seams in the Sangre de Cristo Mountains is very low, typically under 1,000 TDS, but production averages 1,500 bwpd per well with no apparent decline. Because of the interrelationship between coal seam hydrology, permeability, and water chemistry, TDS commonly is inversely related to water production rate. There is no established technology for reducing water production without adversely affecting gas production rates. Consequently, mitigation technologies have focused either on disposing produced water using underground injection or surface evaporation, or on surface treatment of produced water for disposal or utilization. In the U.S., CBM produced water is disposed using several alternative approaches. The most appropriate method depends on many variables, including water volume, TDS levels and composition, as well as on non-reservoir factors such as local climate, surface drainage, and environmental regulations. The three most widely used water disposal options for CBM produced water are: 1) Underground injection using dedicated water disposal wells; 2) Surface disposal in evaporation ponds; and 3) Surface treatment and discharge into rivers. These methods exhibit a wide range of investment and operating costs, which are summarized in Exhibit 1- 3: Exhibit 1-3: Disposal Costs for CBM Produced Water in the U.S. (US $) Technology ; Cost ($/bbl) Cost ($/Mcf)* Surface Evaporation (San Juan) $0.05 to 0.10 $0.005 to 0.01 | Surface Treatment/Discharge (Warrior) $0.05 to 0.15 $0.005 to 0.015 Surface Treatment Using | $0.17 to 0.20 | $0.017 to 0.02 | Electrodialysis and Use/Discharge (Experimental) MAFA/ARI page 55 26-Feb-97 Environmental Considerations Natural Gas in Rural Alaska Surface Treatment Using Reverse $0.40 to 1.00 $0.05 to 0.10 Osmosis and Use/Discharge (Experimental) Underground Injection (San Juan) $0.50 to 1.50 $0.05 to 0.15 * Assuming gas/water production ratio of 10 Mcf/bbl. Source: Stevens, 1993 Alaskan Options Given the climatic conditions in Alaska which largely presume an annual sustained hard freeze, it appears that the only viable disposal option will be underground injection. For the purposes of this study, an underground injection well is assumed to be needed in all cases. While it is conceivable that the produced water from a coalbed methane production well would be of sufficiently high quality and sufficiently low quantity to allow for some form of year round surface discharge, it seems more likely that an injection well would be required. An overview of underground injection costs and technology is provided below. Underground Injection Underground Injection in disposal wells is used to handle most CBM (as well as conventional oil and gas) produced water in the U.S., particularly in the San Juan basin. During the early development phase of the San Juan basin much of the CBM produced water was disposed at low cost using evaporation ponds. However, with expanded development during the 1990's, and environmental concerns regarding their large area and high visibility, limits on construction of evaporation ponds led to most of the water today -- a staggering 180,000 bwpd in 1995 -- being disposed using underground injection wells. Disposal wells in the San Juan basin cost about US $1.5 to $2 million to drill and complete, including a large hydraulic stimulation treatment to enhance injectivity in the relatively tight available disposal zones. Operating costs, primarily for electricity to inject water at high pressure at rates of several thousand bbls per day, are also considerable. Total investment and operating costs for underground injection range from $0.50 to $1.50 per bbl in the San Juan basin, which corresponds to $0.05 to $0.15 per Mcf of gas production, assuming a gas/water production ratio of 10 Mcf/bbl (See Exhibit 1-3). Fuel Storage Since natural gas dissipates quickly under normal atmospheric conditions there have not been any prominent environmental considerations concerned with leaks. Natural gas boils at around -250°F and is less dense than air, thus a leak tends to dissipate fairly quickly. In the U.S. there have been some concerns expressed by local residents concerning separations between residential communities and natural gas storage facilities in heavy populated areas. These separations concerns do not appear to be a significant consideration in rural Alaska. MAFA/ARI page 56 26-Feb-97 Environmental Considerations Natural Gas in Rural Alaska Transportation The natural gas development and any associated pipeline transportation system may need to be routed around existing land designations, i.e., national parks, and avoid certain habitats depending on local conditions. This may add costs to the development of a natural gas resource. Gas-Fired Electrical Generation While natural gas has a cost advantage since it is generally a cleaner burning fuel than diesel, this advantage is not absolute. Emissions standards for NO, , particulates, CO, and Hydrocarbons often require combustion modifications for natural gas engines (both turbine and reciprocating). In some instances post- combustion controls are beginning to be imposed.” In addition, the water vapor associated with natural gas combustion may generate a significant amount of “ice fog” under certain winter conditions in Alaska.” This could conceivably create a desire on the part of local residents to either relocate the power generating station or relocate residents. For the purposes of this study, it is assumed that these requirements do not rise to the level of requiring an additional incremental cost estimate at the present time. Gas-Fired End-Use Heating & Cooking Natural gas used in the end-use heating market does not appear to be subject to emissions controls at the present time. In addition, it appears that end-users value the cleanliness of gas-fired heat over other “dirtier” fuels such as coal. This study has not attempted to estimate that value. Diesel Comparison Case Heating Fuel Oil Tank farm improvements by fuel companies, municipalities, and utilities put upward pressure on the price of fuel oil. In the base case, it is assumed that the real price of diesel fuel does not escalate. In the sensitivity analysis, a one time 25¢ per gallon and 50¢ per gallon premium has been added to the price of diesel fuel attempts to account for the potential costs of these improvements. This is based on the following SWAG: Transportation & Storage Improvements” $100 million 57 “Prime Mover Environmental Update”, Gas Research Institute, July 1995. 58 This consideration has been included in reviews of the feasibility of converting Fairbanks Municipal Utility System’s 20MW Chena #5 Boiler from coal to natural gas. MAFA/ARI page 57 26-Feb-97 Environmental Considerations Natural Gas in Rural Alaska Capital Recovery Factor” 20% Annualized Cost $20 million Avg. Annual Gallons’! 221,000,000 gallons Avg. Cost per Gallon $0.09 per gallon Propane Due to its density, propane vapor may pool and present a combustion hazard. In addition, if a propane tank fails during a fire, a catastrophic release of large amounts of burning fuel can occur, known as a boiling liquid-expanding vapor explosion or BLEVE.” These safety issues associated with propane storage may potentially effect its location relative to residential and other sensitive areas. Wood Emissions associated with wood have been sufficient to generate local limitations on its use in Alaska.” These concerns do not appear widespread in rural Alaska at the present time. Coal Storage, handling, and emissions considerations have been sufficient for end-users in the heating market to switch to cleaner fuels such as heating oil even when the direct cost paid for capital, operations & maintenance, and the fuel itself would appear to favor coal use. Apparently even without specific environmental regulations, the experience in Fairbanks from the 1960s is that end-users have tended to switch to oil even though coal appeared to be a less expensive source of heat. In short, the market appears to value cleaner fuels that involve less end-user labor at a premium. This suggests that while a “cost of service” screening study may favor coal for end-use, end-users may not value coal. °° SWAG. It is unclear whether the $200 million estimate for diesel tank farm improvements also includes diesel fuel storage that will be sold to end-users. It seems possible that there are some diesel tank farm and transportation system improvements that are not captured in the utility estimate developed by the Division of Energy, especially given the separate tax status of utility vs. end-user diesel fuel. © CRF = 15% return on capital + 5% depreciation * It is assumed that the number of gallons used for oil heating across the state is roughly 221,000,000. See Table 5A - Historic Oil Consumption, Diesel fuel sales, taxable, p. 24, Historic and Projected Oil and Gas Consumption, Alaska Department of Natural Resources, Division of Oil & Gas, February 1994. ° Battelle Columbus and Gannett Fleming, “Effects of Alternative Fuels on the U.S. Trucking Industry,” prepared for the Trucking Research Institute, November, 1990. ® Juneau has limitations on wood burning during winter months. * Some have speculated that coal has always been more expensive when one factors in the costs associated with end- user storage and handling of coal and ash disposal. Historically this labor may have been contributed on the part of younger family members who have since become less interested in such chores, leaving it for others in the family. The others in the family may have then discovered the value of cleaner fuels and switched to oil. In contrast, a recent visit to China confirms that a great deal of coal is still used to heat buildings. MAFA/ARI page 58 26-Feb-97 Environmental Considerations Natural Gas in Rural Alaska Electrical Generation Diesel-Fired Internal Combustion Engines Environmental considerations which may create costs which may become internalized in the cost of diesel- fired electrical generation include: e Diesel fuel transportation & utility storage improvements involving new tank farms e Fuel modification requirements ¢ Modifications of diesel-fired engines to reduce emissions e Post-combustion control systems While current environmental considerations may appear to put considerable upward pressure on the cost of diesel fuel use, it is not clear that this upward pressure will translate into a long term upward trend in cost. First, the tank farm improvements may only translate into a one-time increment in annualized capital and operating costs. In addition, the actual tank farm improvements will inevitably be spread out over time due to their capital requirements and the real limitations on capital available in rural Alaska. Second, while emissions controls may require modifications to engine combustion, diesel engine manufacturers have incentives to make additional improvements in combustion technology which may help offset the incremental costs of emissions standards. For example, requirements which call for fuel injection/timing retard controls have basically been incorporated into current production run diesel engines. In other words, in order to stay competitive in the marketplace, diesel engine manufacturers have made the adjustments to meet the current set of standards and the real capital cost of diesel engines has not increased, and may have even decreased in some cases due to improvements in technology. Third, the regulators have an incentive to find cost-effective emissions control approaches. Regulators who impose inefficient control approaches create an incentive on the part of industry to seek more cost- effective alternatives through the political process. Thus, in the long term emissions reduction requirements may provoke a marketplace response to find the most cost-effective way to meet those standards and actually spur improvements in technology which cause the overall real cost of diesel energy over time to remain flat or even decline. For these reasons, the base case does not include an increment for additional costs of diesel energy due to environmental considerations. In recognition of the potential of some of the environmental requirements to impose incremental costs relative to other fuels such as natural gas, some reconnaissance level estimates have been developed in this study. Diesel Fuel Transportation & Utility Storage For the purposes of the sensitivity analysis, the following costs associated with environmental considerations are assumed to become impounded in the cost of diesel fuel: Utility Tank Farm Improvements” $200 million Upstream Transportation & Storage Improvements” $50 million °5 Confirmed by CAT and Cummins vendors and ADEC. © State of Alaska, Division of Energy Estimate. ° SWAG representing the capital costs imposed on the entities providing fuel to the utilities. MAFA/ARI page 59 26-Feb-97 SSS OO uo —-— *=— +> Environmental Considerations Natural Gas in Rural Alaska Diesel Fuel Capital Improvements $250 million Capital Recovery Factor™ 20% Annualized Cost $50 million Avg. Annual kWh” 600,000,000 kWh Avg. Cost per kWh $0.08/kWh Diesel-Fired Emissions In the event that a Prevention of Significant Deterioration (PSD) permit is required, emissions controls may be required. There are three basic types of controls: e controls involving modifications to the fuel burned e controls involving modifications to the combustion process e controls directed at cleaning up the exhaust after the combustion process Fuel Composition Modifications The Alaska Department of Environmental Conservation has required reduced SO, emissions for some diesel-fired generators in Alaska, including Dutch Harbor, St. Paul, and Bethel.” In recognition of the considerable expense associated with post combustion controls, reduced emissions requirements have been met by burning low sulfur diesel fuel. The premium for the low sulfur fuel runs between 3-10 cents per gallon depending upon location and the percentage of sulfur required. Fuel suppliers have met the need for low sulfur fuel through blending of #1 Diesel (Jet Fuel) with sulfur contents running around 0.07% by weight with #2 Diesel with sulfur content running around 0.4% - 0.43% by weight. And in the case of Dutch Harbor, which is required to burn fuel with no more than 0.1% sulfur by weight, #1 Diesel has been substituted for #2 Diesel. For much of Alaska, this substitution is quite familiar to many because the superior flow characteristics of #1 Diesel in subzero temperatures already make it the fuel of choice. In addition to the premium on the per gallon price, the BTU content difference is basically between 131,500 Btu/gal and 126,000 Btu/gal, a four percent decline. Combustion System Modifications To remain competitive, the manufacturers of diesel engines have incorporated combustion system modifications to reduce emissions into their production run engines. To the extent that these modifications impose additional capital costs, reduce fuel efficiency and increase maintenance costs, these costs are assumed to be impounded within the cost to purchase and operate currently manufactured engines. Post-Combustion Emissions Controls Where a Prevention of Significant Deterioration (PSD) permit is required, post-combustion emissions controls may be imposed. From least to most expensive, these post combustion emissions controls may include: °8 CRF = 15% return on capital + 5% depreciation © Total Generation by Alaska Utilities with diesel, rounded up from 591 GWh, as reported for 1995, Alaska Electric Power Statistics. ” State of Alaska, Department of Environmental Conservation. MAFA/ARI page 60 26-Feb-97 Environmental Considerations Natural Gas in Rural Alaska e taller stacks to assist in dispersion of emissions e non-selective catalytic reduction Taller Stacks For example, a basic Best Available Control Technology (BACT) analysis which results in a taller stack to help disperse the emissions may cost roughly:”" BACT Analysis Capital Site Specific Permit $10,000 Testing $20,000 Taller Stack $ 5,000 Total $35,000 For the low end of the range of generators to which this may be applied, say a generator of SOOkW, this represents an addition of $70 per kW. Non-Selective Catalytic Reduction In a situation where more rigorous controls are required, the costs may be roughly: BACT Controls Required Capital Site Specific Permit $10,000 Testing $20,000 Air Fuel Modifications + Catalytic Reduction $50,000 Total $80,000 A non-selective catalytic reduction system basically involves installing a large catalytic converter on the exhaust stream of the engine along with combustion controls that maintain the air-fuel mixture slightly to the fuel-rich side. This may result in some modest increment in fuel use, typically less than 5%, and some additional O&M associated with monitoring the catalytic converter. On the low end of the range of generators to which this may be applied, say a generator of 500kW, this represents an addition of $160 per kW. ”| These estimates are based on a review of actual requirements imposed in Alaska as well as Western States when BACT analysis and controls have been triggered. Source: Lorenzen Engineering. ? Id. MAFA/ARI page 61 26-Feb-97 Resource Ownership Issues Natural Gas in Rural Alaska Resource Ownership Issues Review Of Ownership Rights And Leasing Policies Recent Legislation On July 11, 1996 Governor Knowles signed House Bill 394 (HB 394) which establishes special leasing provisions for shallow gas fields located on state lands. The goal of the new legislation is to encourage natural gas development and usage in rural areas to lower energy costs to communities. The bill defines shallow gas reservoirs as gas reservoirs occurring at depths of 3,000 feet or less. An interesting aspect of the bill is that it does not differentiate between conventional gas found in sandstones and other formations and unconventional gas such as coalbed methane. This appears to solve an ownership issue controversy, i.e., does the coal owner or conventional gas lease holder have title to the gas, which has hindered coalbed methane development in several states as well as foreign countries. Basic terms of the new leasing provisions for shallow gas fields are outlined below: e Lease rental is set at $0.50 per acre. e The royalty rate is lowered to 6.25% (versus 12.5% for conventional gas) provided that the gas is used within the state and that it is not competing with gas subject to the 12.5% royalty rate. e Primary term leases are for 3 years and allow for the exploration, development, and production of gas. The primary lease term is automatically extended as long as commercial quantities of gas are being produced and other leasing requirements are met. If a well is drilled just prior to the expiration of a lease, a one-year extension is granted to establish the commercial feasibility of the well. e A single lease block cannot exceed 5,760 acres and no company may control more than a total of 46,080 acres. e All leases require a $500 application fee. e Leases are non-transferable until a commercial well is drilled. e Removes the requirement that the director of the Division of Oil and Gas (DOG) make a written finding that a lease is in the best interest of the state. ¢ — The bill does not apply to lands that: 1) Are currently leased for oil and gas or have been proposed for leasing (note: this may be waived by the Commissioner of Natural Resources); 2) Are held under a coal lease, unless coal lessee has applied for both coal and shallow natural gas rights; 3) Land designated for Alaska Mental Health Trust Authority. Potential Ambiguities While the bill seeks to clarify the leasing procedures for shallow gas development, it does present some ambiguity with respect to concurrent uses of mineral resources. Parts of the bill seem to favor the rights of the coal lease owner over the coalbed methane lease owner as the coal lease owner has the right to: e Vent or remove gas associated with the coal to ensure safe mining (without any specific consideration for paying any royalty to potential shallow gas leaseholders) and e The coal lessee may apply for a shallow gas lease on the same acreage. MAFA/ARI page 62 26-Feb-97 Resource Ownership Issues Natural Gas in Rural Alaska However, in section L of the bill, it states that coal may not be mined by the coal lessee without prior written consent of the shallow gas lessee. Further clarification regarding reasonable concurrent uses may be required in statute or regulation to ensure that the interests of the coalbed methane developer are balanced with the interests of the coal seam owner, other landowner interests, and the State of Alaska.” These considerations may not be as prominent in Alaska as they are in other states since the coal either being mined or generally under consideration for mining in Alaska is predominantly “surface” coal that exists at depths of less than 500 feet, while the coal seams that are candidates for commercial quality and quantities of coalbed methane are likely to be at depths in excess of 1000 ft. However, there remains a potential for conflict between potential coalbed methane leaseholders who file on top of a coal seam where there is the potential for a separate coal leaseholder. ® See requirements of Article VIII, Sec. 8 of the State Constitution. MAFA/ARI page 63 26-Feb-97 Development Risks Natural Gas in Rural Alaska Natural Gas Development Risks Developing a natural resource such as coalbed methane or conventional natural gas carries with it a series of inherent risks such as uncertainties in well productivity, variability in gas reserves, and operations in a cold climate. Over the years, the industry has developed a variety of strategies for mitigating and managing project risks. Well Productivity The standard method for reducing the risks and uncertainties in the gas productivity or deliverability of a coalbed methane well is to drill low cost slim hole core and test wells to provide data on the key reservoir variables (discussed above) such as gas content, core thickness, permeability and reservoir pressure. Combining the above data into a well test analysis package or a reservoir simulator would provide improved estimates for the expected gas production from the well. For conventional gas wells, the testing procedure would be simpler, involving the logging and testing of an exploration well for deliverability. If properly planned, the exploration well, if productive, could be converted into a long term production well. Gas Reserve The longer term producibility and life of the well will depend greatly on the volume of gas reserves connected to the well. First order estimates of gas reserves can be made from the data collected during the initial well testing. Once the well has been producing for three months, more reliable estimates can be made by matching the early time performance of the well using a reservoir simulator, such as COMET 28, and projecting the performance of the well and its ultimate recovery (or reserves) into the future. Staged Development A standard way to reduce capital investment risk is to stage the drilling and field development over time. Under the strategy, the information on well productivity and gas reserves gained on the initial group of wells would be used to plan the development of the future wells and the field layout. A typical sequence might involve the drilling of an exploration or test well, the drilling of an initial five well pattern to demonstrate performance and then staging the drilling of wells over time to reach and then maintain the design productivity of the field. The final step in staged field development will be to add new wells to maintain the productivity and expected gas rates of the field. These wells would be drilled in future years as the gas rates from the initial wells decline. Staged development thus provides a way to manage risks for the larger capital requirements of a field requiring multiple wells. Where a project only involves a few wells and less capital investment, the staged field development strategy is less applicable and greater emphasis will need to be placed on initially establishing well productivity and gas reserves. MAFA/ARI page 64 26-Feb-97 Reliability Issues Natural Gas in Rural Alaska Reliability Issues Introduction The natural gas systems modeled are designed to meet industry standards for reliable service. The range of reliability for the natural gas systems covered in this study is assumed to be roughly comparable to the existing reliability of diesel-fired electrical generation, transmission, and distribution systems and heating oil storage, delivery, and burning systems. Natural Gas System Reliability An issue important to a local community or industry looking toward natural gas is the following -- is natural gas a reliable energy source. Experience elsewhere has shown that a natural gas based energy system, properly planned and implemented, can be highly reliable. Natural gas systems are analyzed by examining each of the following stages of production: Field Production Transmission Distribution End-Use Electrical Generation Field Production A series of testing monitoring and design considerations can add to the reliability of a natural gas producing field, as discussed below. Well Testing One important step to increase the reliability of estimating production well testing is to establish reservoir properties during the exploration phase, as well as during the subsequent field development phase. The more rigorous the well testing and analysis, the more reliable will be the values of reservoir pressure and permeability that would result from the well test. Reservoir Modeling The use of a sophisticated reservoir model, such as the COMET 2® fractured reservoir model (with specific capacity to examine coalbed methane reservoirs) helps add to the rigor and reliability of the assessment of near term and long term production and reserves. The reservoir model can be used to determine in advance when new wells would be required and can help in the design of remedial actions should the field experience production problems. Well Performance An important aspect of maintaining reliability is to initiate an ongoing well monitoring and measurement program to assure that wells are performing as expected. The ongoing monitoring program would also quickly identify when wells are experiencing any operating difficulties. MAFA/ARI page 65 26-Feb-97 Reliability Issues Natural Gas in Rural Alaska Number Of Wells A final important aspect of assuring a reliable gas supply is to have sufficient wells to meet fluctuations in demand, to allow for scheduled maintenance on wells, and to have backup wells in case of problems. The base case models this by estimating the basic number of production wells based on the higher of peak demand and average demand and adding a “reliability” well for each 12 wells to ensure continuous production during planned and forced outages. In addition, these requirements are applied over time, so that replacement wells are added in years 12-20 to maintain adequate reliability. These assumptions drive costs in a step function for each 12 basic production wells. For the village profiles under consideration in this study, these requirements drive the unit costs up considerably for communities with less than 200 households. As can be seen below, for the medium community profile of about 600 households the one reliability well covers nine production wells - roughly 11%. While in the small community profiles the reliability wells add a premium of 25%, 50%, and 100% respectively. Figure 3: Production Wells & Reliability Wells by Community Size 9 2 § aia i 3 74 ele er = 64 Oe $$ 5 54 : —________________| ™ Production Wells So 44 |_| g Reliability Wells 3 = | (Reliability Weks | s 2; — ——— 7 i 0 € € —E E 2 12 12 12 3 ao =3 ae = = = = Community Size Transmission Piped transmission systems are generally reliable as long as they are well marked and backhoe operators are paying attention. Heating Distribution Piped distribution systems are reliable as long as they are well marked and backhoe operators are paying attention. Surface piped systems are subject to greater wear and tear and potential failure due to collision. End-Users Fuel Burning Natural gas-fired end-use heating appliances are very reliable. Modest maintenance requirements are assumed to be sufficient to maintain high reliability. Electrical Generation Natural gas-fired reciprocating engine reliability is a function of: MAFA/ARI page 66 26-Feb-97 Reliability Issues Natural Gas in Rural Alaska e adequate and consistent fuel quality e adequate and consistent maintenance Fuel Quality Natural gas is likely to contain some impurities. Most of these impurities are assumed to be removed and the costs accounted for by including appropriate equipment in the field development costs and allowing for adequate operations and maintenance of that equipment. In addition, the quality of the natural gas from individual wells and over the life of the field may vary. This may result in incremental improvements or degradation in combustion performance over time - both heating output and emissions produced. Sophisticated combustion controls can mitigate, but not eliminate the risk that variable fuel quality will degrade performance. Maintenance The cost model includes an operations and maintenance premium of 33%-50% above comparably sized diesel-fired generators due to the higher top-end operating temperatures which results in additional requirements for cooling systems and shorter intervals between top-end overhauls. These additional operations and maintenance costs should be sufficient for the natural gas engines to maintain reliability that is comparable to diesel engines. Existing Energy Sources Diesel-Generated Electricity Existing sources of diesel-generated electricity in rural Alaska exhibit an extremely wide range of reliability depending upon rural community. Over time reliability has increased as people involved throughout the process of delivering diesel-generated electricity have made incremental adjustments to improve reliability based on accumulated experience. Electrical Distribution This study assumes reuse of existing electrical distribution system. No net change in reliability should result. Heating Generation Existing end-use diesel-fired heating appliances are very reliable. Modest maintenance requirements are assumed to be sufficient to maintain high reliability. Heating Distribution Heating oil storage and distribution systems appear to be fairly robust. However, late break-up and low water have historically presented risks to barge delivered oil. In these circumstances, alternative methods of delivery, such as air transportation or small scale relays with snowmobiles have been called into service to provide an adequate supply of fuel. MAFA/ARI page 67 26-Feb-97 Reliability Issues Natural Gas in Rural Alaska How Robust Are Fuel Delivery Systems under Stress Finally, it appears that diesel starts out with some qualitative advantages over natural gas in rural Alaska. The existing system which supplies fuel oil for heating and electrical generation has been in place for a number of decades and the overall system flexibility in handling contingencies is noteworthy. For example, when fuel runs short, some villages have been known to round up a posse of snow mobilers and sleds to go on down river to borrow fuel to make it through until other alternatives can be found. Other alternatives include chartering a plane to fly fuel as in the case of White Mountain this year. The flexibility inherent in the handling of diesel fuel is not matched by most small scale natural gas systems in the sense that if the natural gas field supply is disrupted, it is unlikely that there will be readily available supplies that can be obtained from neighboring communities. While engineers will do their best to design systems that are appropriate to the conditions, their design will inevitably be limited by the amount of capital available to invest, especially early in any process that is aimed at converting from diesel to natural gas. Reliability failures may occur. It is conceivable that small scale natural gas systems may not be as reliable as the existing diesel systems until people have had a chance to solve some field problems and learn from experience. In the long term, for natural gas reliability to be comparable to existing diesel systems under the stressful conditions of rural Alaska, some minimal level of infrastructure and a base of experience may be required to be built. MAFA/ARI page 68 26-Feb-97 —_———_ Permitting & Licensing Natural Gas in Rural Alaska Permitting & Licensing Requirements Field Development General Land Development Requirements Depending upon the particular site under consideration, permits may be required from: Alaska Department of Natural Resources, Alaska Department of Fish and Game, Alaska Department of Transportation and Public Facilities, U.S. Army Corps of Engineers (Wetlands), Federal Bureau of Land Management, Local Government, Private Land Owners, U.S. Environmental Protection Agency (Environmental Assessment or Environmental Impact Statement). HB 394 - Specific Requirements for Shallow Gas As discussed above in Resource Ownership Issues, the Governor of Alaska recently signed House Bill 394 which seeks to encourage the development of shallow natural reservoirs located near rural communities. In addition to amending leasing procedures for shallow gas fields, the bill also provides for less stringent permitting and licensing requirements. Key provisions under HB 394 pertaining to the permitting and licensing of shallow gas fields are: ¢ Lowering of the proof of financial liability from $1,000,000 per incident to $25,000 per incident. e Exemptions from obtaining a waste disposal permit from the DEC before a discharge if the discharge is incidental to drilling and the drilling operations do not produce a discharge from a point source directly into state surface waters. e Shallow gas exploration and production activities may operate without a DEC approved oil discharge prevention and contingency plan. Proof of Financial Liability Reducing the proof of financial liability from $1,000,000 per incident to $25,000 per incident reduced costs to the developer by approximately $14,500.” Exemptions from Waste Disposal Permit The potential for environmental damage resulting from shallow gas development is discussed in detail above in the section entitled Environmental Considerations. The production of large quantities of water and their disposal is the most prominent environmental consideration. Mitigation efforts have focused on disposing produced water using underground injection, surface evaporation, or on surface treatment of produced water for disposal or utilization. The cost impact of the exemption provided in HB 394 depends upon the cost of a permit, actual field conditions, the interpretation of the statutory language and ultimately whether a waste disposal permit would allow a settling pond/surface discharge arrangement as opposed to requiring a reinjection well. Actual produced water from coalbed methane operations may be clean enough and of a small enough volume that some form of surface discharge would be acceptable under a permit system. However, it is also possible that produced water volume and quality is sufficient to require a reinjection well. ” Proof of liability requirements typically run around 1.5%. A reduction of $975,000 in liability value is probably worth on the order of $14,500 to a developer in reduced costs. MAFA/ARI page 69 26-Feb-97 Permitting & Licensing Natural Gas in Rural Alaska Regardless of the requirements associated with a waste disposal permit, other operational and public relations considerations may be sufficient to warrant a reinjection well. Thus the avoided cost associated with the exemption from a waste disposal permit could range from: e somewhere around $1 million in those circumstances where a reinjection well is required by the permit and the reinjection well would not have been installed otherwise e somewhere around zero in those circumstances where a reinjection well would be installed regardless of the specific permit requirement Oil Discharge Prevention and Contingency Plan In the case of coalbed methane, there does not appear to be any generic need for an oil discharge prevention and contingency plan. This provision may have saved the cost of preparing and filing an oil prevention and contingency plan where it does not appear to be applicable. Alaska Oil & Gas Conservation Commission The Alaska Oil & Gas Conservation Commission has reduced per well bonding requirements from $100,000 to $10,000 in the case of coalbed methane in the case of at least one project.”° For the large community profiled in this study, with an initial well complement of 16, this amounts to a cost reduction to the developer of approximately $21,600; or $1350 per well.”® Transmission Depending on land use and topography along the corridor between the gas field and the community, permits may be required along the lines of those mentioned under “general land development requirements.” Distribution Depending on land use within the community, permits or permissions may be required. End-Use Heating Depending upon local codes, end-users may be required to obtain permits associated with the installation of a new gas-fired appliance.” 2 Independent producer LAPP Resources, (Alaska Petroleum News, 02/15/96) credits the recognition by various state agencies of the special circumstances required for shallow gas development to allow their coalbed methane project near Houston to move forward. For the project, the AOGCC designated their coalbed methane project a gas field and reduced its bonding requirements from $100,000 per well to $10,000 per well. Similarly, the state Department of Natural Resource waived its bonding requirements to cover any surface damage on state acreage because the prospect is on private land. 76 Bonding estimated to cost approximately 1.5% * 16 wells * $90,000 bond value savings per well = $21,600. ” For example, a permit is required in the Municipality of Anchorage for the installation of new gas appliances. This type of requirement may not be present in many other parts of the state. MAFA/ARI page 70 26-Feb-97 Permitting & Licensing Natural Gas in Rural Alaska Electrical Generation As discussed in the above section entitled Environmental Considerations, a natural gas-fired electrical generation station may require an air emissions permit. MAFA/ARI page 71 26-Feb-97 Conclusions Natural Gas in Rural Alaska Conclusions & Observations under limited set of circumstances including a) the community is located adjacent to a good quality natural gas resource (< 5 miles) b) the costs associated with exploration for the good quality natural gas resource are minimal c) the costs of alternative sources of energy, such as diesel, increase in real (inflation adjusted) terms d) the community size is in excess of 500 households (population roughly 1750) e) the average density in the community is equal to or greater than 50 customers per mile of distribution system 2. For much of rural Alaska, it is likely that diesel will remain the fuel of choice. Over the last 40 years, the installed capacity of diesel-fired utility electrical generation capacity in Alaska has remained between 20-30% and has settled around 20% since 1974.” technologies employed i in the exploration ani development of natural qx and in gas-fired generation of electricity have reduced the cost of natural gas energy and are projected to continue to do so into the next century. While these efficiency improvements may be able to make natural gas competitive in some areas, high hurdles remain for natural gas to become a competitive alternative in much of rural Alaska. in cthad aneegy slecamivan The costs for new and improved storage of diesel fuel and for emissions controls on diesel engines appear to have created upward pressure on the cost of diesel relative to other energy alternatives. However, this upward cost pressure is mitigated by the following factors: a) In many cases the costs of improvements in fuel storage are not being paid directly by the users of diesel so the price of energy does not reflect the cost b) Improvements in technology to address environmental concerns have also been accompanied by improved efficiency in some cases so that overall the cost of diesel energy has not necessarily increased a) Based on existing PCE statutes, switching from diesel to natural gas as an electric generation fuel would have no effect on eligibility for future PCE payments. If program funding is continued in future years, PCE could be a decision factor from the consumer’s point of view in whether it is less expensive to heat with electricity as compared to natural gas or diesel since at least some of the additional kWhs used for electric heat could be eligible for additional PCE support. 8 See Alaska Utility Installed Capacity by Prime Mover (1956-1995), Alaska Electric Power Statistics, September 1996, p. 29. MAFA/ARI page 72 26-Feb-97 Conclusions Natural Gas in Rural Alaska 10. li: b) For this study, PCE is not a factor for the following reasons: i) While PCE can affect the price of electricity, it does not affect its underlying cost. ii) The scope of this study is to develop and compare the underlying costs of natural gas and diesel alternatives without regard to the possible impact of present or future government subsidies. iii) This study is conducted for the State of Alaska and adopts a statewide perspective. From this perspective, PCE payments are transfers from one set of Alaskans to another and therefore do not represent net costs or net benefits. Geology is destiny. The existence of a good quality natural gas field is a necessary, but not sufficient condition, for natural gas to be a competitive energy alternative. Geography is destiny. A prominent cost driver is the distance from the resource to the community. All other things being equal, unless the natural gas resource is within five miles of an Alaskan community, the current cost to transport natural gas to the community quickly becomes prohibitive relative to other fuels. and its density. High density, larger rural communities have a better chance of being able to support the investment necessary to make natural gas a possibility. Interestingly, as the community size becomes somewhat smaller, the unit cost for delivered natural gas increases, but the rate of increase appears to be of the same order of magnitude as the increase for the unit cost for delivered diesel-generated electricity. Thus, even a moderately sized rural village may find coal bed methane an attractive alternative to diesel if the community sits directly atop a good quality coal bed methane field. However, for communities below about 200 households, the requirements for a reliability well and a reinjection well drive the costs for natural gas quickly beyond the costs of diesel. ‘relia coasanahition For ‘ixiaagle, a sufficiently large raasket at some distance from a resource may be able to justify an investment in a transportation system which in turn allows nearby communities to participate in use of the resource at a small incremental cost. This is essentially what has provided Anchorage, Kenai, and Barrow with access to natural gas. a) Wood. It would appear that proximity of many rural Alaska communities to wood resources makes wood a competitive heating fuel alternative in many cases. b) Coal. It would appear that the proximity of some rural communities to coal resources would make coal a competitive energy alternative in some cases. c) Hydroelectric. It would appear that the proximity of some rural communities to potential hydroelectric sites would make hydro a competitive energy alternative in some cases. Legislative Initiatives to Encourage Shallow Natural Gas Investment. While the passage of HB 394 probably reduces the cost of developing shallow natural gas resources, the prospects for coalbed methane still appear quite limited for much of rural Alaska at the present time. MAFA/ARI page 73 26-Feb-97 Appendices Natural Gas in Rural Alaska Appendices Sources of Information & Bibliography Cost Data Other Methods Used Applicable Conversion Tables Acronyms Glossary Schedules MAFA/ARI page 74 26-Feb-97 Appendices Natural Gas in Rural Alaska Sources of Information/Bibliography Cost Data Field Data Alaska Public Utilities Commission (APUC), Power Cost Equalization (PCE) Filings, Fuel and Non-fuel cost data. (1990-1996) Telephone Interview with Roger Jenkins, Nikolai. 1996 Telephone Interview with Rick Blodgett, Teller. 1996 Telephone Interview with Charlie Helm, Norgasco. 1996 Vendor Quotes CAT Diesel & Gas-fired Engine Generator Sets, NC Machinery, Anchorage, Alaska. 1996 Cummins Diesel & Gas-fired Engine Generator Sets, Cummins Northwest, Anchorage, Alaska. 1996 Tesoro - Diesel Fuel, Price and Specifications. 1996 Delta Western - Diesel Fuel, Price and Specifications. 1996 Recent Studies Institute of Social and Economic Research, University of Alaska - Kenai Peninsula Natural Gas Study, June 1995. R.W. Beck - Feasibility Study, Copper Valley Intertie, State of Alaska, Department of Community and Regional Affairs, Division of Energy, April 1994. CH2M-Hill - Review of Copper Valley Intertie Feasibility, 1995. Stone & Webster Engineering Corporation - Least Cost Energy Plan for Copper Valley Electric Association, 1990. Analysis North - Economic Analysis of Coal-Fired Power Plants to Serve Nome, Kotzebue, and the Red Dog Mine, September 19, 1991. Decision Focus - Railbelt Intertie Reconnaissance Study: Benefit/Cost Analysis, June 1989. Industry Data State of Alaska Division of Energy - Cost Estimates for Rural Utility Tank Farms, e-mail. 1996 National Association of Regulatory Utility Commissioners (NARUC) - Electric Power Technology, Options for Utility Generation and Storage, A Report of the Staff Technology Subcommittee of the Finance and Technology Committee, February 1991. Electric Power Research Institute (EPRI) Customer Backup Generation: Demand-Side Management Benefits for Utilities and Customers, CU-7316, Research Projection 2950-5, Final Report, July 1991. MAFA/ARI page 75 26-Feb-97 Appendices Natural Gas in Rural Alaska Gas Research Institute (GRI) Power Generation Tech Update, May 1996 “The Distributed Utility: Expanding Electric Service Using Natural Gas” “Innovative Advisory Group Tackles Reciprocating Gas Engine Challenges” Prime Mover Environmental Update, July 1995 “Review of Recent BACT/LAER Permits” “Reciprocating Engine BACT Examples” Congress of the United States, Office of Technology Assessment - New Electric Power Technologies, Problems and Prospects for the 1990s. (1985) Joint Association Survey on Drilling Costs, compiled by the American Petroleum Institute, Independent Petroleum Association of America, and Mid Continent Oil & Gas Association. The annual survey is available on paper and in electronic form from API. Data on horizontal drilling and coalbed methane are available starting in 1990. Oil & Gas Journal Oil & Gas Journal Databook, 1996 Edition “Watching Government: Gas Flareup,” November 27, 1995 “Exploration: Study to gauge impact of technology advances,” February 12, 1996 “Utah coalbed gas exploration poised for growth,” August 5, 1996 “Natural Gas and Electricity: Rise in Gas-Fired Power Generation Tracks Gains in Turbine Efficiency,” August 12, 1996 “Use of Natural Gas Boosted as Fuel for U.S. Vehicles,” July 4, 1994 “U.S. Natural Gas Industry Aims to Bolster Role in Transportation,” August 8, 1994 “Comment: Alternative Vehicle Fuels do not offer Viable Alternative to Gasoline in U.S.,” December 19, 1994 “Alternative Motor Fuels: A Slow Start toward Wider Use,” February 20, 1995 “Technology Spurs Growth of U.S. Coalbed Methane,” January 1, 1996 “Exploratory, horizontal wells pressed average depth in ‘94,” March 11, 1996. “How unconventional gas prospers without tax incentives,” December 11, 1995 “Oil shale, coalbed gas, geothermal trends sized up,” September 11, 1995 “Hunt for High Quality Basins Goes Abroad,” October 5, 1992 “U.S. 92 Horizontal. Coalbed well costs tallied,” May 23, 1994 “Why Gas Producers Should Care About Power Industry Decontrol,” January 2, 1995 “Drilled Core Holes Key to Coalbed Methane Project,” March 6, 1995 MAFA/ARI page 76 26-Feb-97 Appendices Natural Gas in Rural Alaska “Convergence of Natural Gas and Electricity Industries means Change, Opportunity for Producers in the U.S.,” March 13, 1995 ENSTAR Annual Reports, on file with the APUC. 1995 NORGASCO Annual Reports, on file with the APUC. 1995 Other Alaska Systems Coordinating Council/State of Alaska Division of Energy - Alaska Electric Power Statistics. 1995, 1996. Selected Alaskan Electric Utilities at a Glance. 1995, 1996 Alaska Public Utilities Commission, Annual Report & Statistical Information, FY 1995. Lorenzen Engineering - Diesel Air Emissions Considerations, Telephone Interview with Diane Lorenzen. 1996 Alaska Department of Environmental Conservation (ADEC) - Air Emissions Considerations, Telephone Interview with Alfred Bone. 1996 Thomas H. Lee, Ben C. Ball, Jr., Richard D. Tabors, Energy Aftermath: How we can learn form the blunders of the past to create a hopeful energy future, Harvard Business School Press. 1990. Richard J. Gilbert, Editor, Regulatory Choices: A Perspective on Devel . = University of California Press, 1991. CRC Press - Handbook of Tables for Applied Engineering Science. 1973 Neil Davis, Energy Alaska, University of Alaska Press, 1984. Washington State Energy Office, Gaseous-Fueled Vehicles: An Alternative Fuels Vehicle, Emissions and Refueling Infrastructure Assessment. 1993. Alaska Department of Natural Resources, Division of Oil & Gas - Historic and Projected Oil and Gas Consumption, February 1994. Arlon R. Tussing and Bob Tippee, The Natural Gas Industry: Evolution, Structure, and Economics, 2nd Edition, PennWell Publishing Company, 1995. American Boeay: of wm Engineers, Technical Council on Cold nagiems Engmenring, Cold Regions American Society of Civil Engineers, Technical Council on Cold Regions Engineering and Canadian Society for Civil Engineering, Cold Regions Engineering Division, Cold Regions Utilities Monograph, 3rd Edition, Technical Editor D.W. Smith, 1996. MAFA/ARI page 77 26-Feb-97 Appendices Natural Gas in Rural Alaska Methods Used In this analysis, the comparative costs of natural gas and diesel were arrived at by applying a utility revenue requirement concept to each investment and then developing a levelized cost for the investment and associated operations and maintenance. The model basically projects yearly revenue requirements, i.e., expenses,taxes, depreciation, and allowed rate of return, for the expected life of the plant. Levelized costs in cents per kilowatt-hour or dollars per million BTU are derived from this revenue requirement stream and form the basis of the gas vs. diesel comparisons. A utility’s revenue requirement is usually expressed in a formula such as: Revenue Requirement = E+ d+T+(V-D)R where: E = operating expenses, including fuel, maintenance, and insurance d = annual depreciation expense T = taxes (if applicable) v = gross valuation of the property used in providing utility service D = accumulated depreciation R = rate of return (percentage) (V-D) = Rate base (book value of property) (V-D)R = Allowable return Note that in the comparisons developed in this analysis, all plant is assumed to be new and no adjustments are made to reflect accumulated depreciation. This assumption is reasonable if one also assumes that on average the depreciation expense roughly reflects the amount of capital that is invested to maintain the capability of the current capital facility and that the relative pace of technological improvements between the two systems under comparison are roughly equal. If the relative pace of technological improvements of one system over the other is divergent, this approach will tend to overstate the cost of the system with the higher rate of technical improvements. MAFA/ARI page 78 26-Feb-97 Appendices Applicable Conversion Tables To convert from: BTU Horsepower Horsepower-hours kW kWh MAFA/ARI To: Horsepower-hours kWh BTU/minute kW BTU BTU/hour Horsepower BTU Horsepower-hours Multiply by: 0.000393 0.000293 42.44 0.7457 2546 3414 1.341 3414 1.341 Natural Gas in Rural Alaska page 79 26-Feb-97 Appendices Natural Gas in Rural Alaska Acronyms BACT Best Available Control Technology BBL Barrel, 42 U.S. gallons (as used in the petroleum industry) bef billion cubic feet BLEVE Boiling Liquid Expanding Vapor Explosion BTU British Thermal Unit, heat required to raise one pound of water one degree Fahrenheit from 58.5 to 59.5 at standard pressure CBM Coalbed Methane CC Combined cycle plant CNG Compressed natural gas, 3000 psi co Carbon Monoxide CE Combustion turbine EPRI Electric Power Research Institute GRI Gas Research Institute IT Internal combustion kWh kilo-watt hour LNG Liquified natural gas mef thousand cubic feet MMBtu Million British Thermal Units, see also BTU NGLs Natural Gas Liquids NOx Nitrogen Oxides psi pounds per square inch TAGS Trans Alaska Gas pipeline System MAFA/ARI page 80 26-Feb-97 Appendices Natural Gas in Rural Alaska Glossary bef - billion cubic feet burner tip - used to designate the delivery of natural gas to the end-user. ccf - hundred cubic feet; often the unit measure of gas delivered for residential use CNG (compressed natural gas) - natural gas that is highly compressed (typically 3000 psi). constant or real dollars - measure of dollars that has been adjusted relative to a specific year to remove the effects of inflation cost of capital - the threshold weighted average of the interest rate on debt and the return on equity that a utility must offer prospective investors in order to attract capital common costs - costs that are incurred by the firm to operate that are not readily attributed to any particular product depreciation - in accounting, a system which aims to distribute the cost of tangible capital assets, less salvage (if any), over the estimated useful life of the unit in a systematic manner. It is a process of allocation which may or may not correspond to valuation. end-user - the ultimate customer, as opposed to a customer who is purchasing for the purposes of resale exploration - the search for naturally occurring hydrocarbons, including surface studies, seismic and another geophysical surveys, and the drilling of exploratory wells. joint products - two or more different end products emanating from a single process. The cost of each of the joint products is derived by allocation. life-cycle costing - evaluation of the merits of an investment by looking at the costs of that investment over its entire serviceable life (includes capital and operations costs). load factor - the ratio of average to peak use, typically calculated at the highest day (or three-day) period for the peak-day use over the average-day use for the year. mcf - thousand cubic feet, one mcf of gas has a heating value of roughly one million BTU (1 MMBTU). methane - CH,, the simplest, lightest gaseous hydrocarbon and the primary component of natural gas. MMBTU - million BTU. natural gas - naturally occurring mixtures of energy-rich vapors (primarily methane) found beneath the earth’s surface. Often processed to remove toxic and corrosive components and adjusted to a mixture having a heating value of about 1,000 BTU per cubic foot. polyethylene - commonly referred to as “plastic.” Any of several thermoplastic resins (C,H,),, made by the polymerization of ethylene. production - the movement of hydrocarbons from the reservoir to the surface by natural or mechanical means. propane - C;Hg, a hydrocarbon component of produced natural gas and a common oil-refinery byproduct. The primary constituent of liquefied petroleum gas (LPG). Heating value is roughly 2,300 BTU per cubic foot. raw gas - natural gas as it issues from the reservoir including mainly methane and possibly other hydrocarbons, as well as hydrogen sulfide, carbon dioxide, and water. MAFA/ARI page 81 26-Feb-97 Appendices Natural Gas in Rural Alaska recovery rate - the fraction of the original oil or gas in place deemed to be recoverable with current technology, under current economic conditions. reserves - that part of the oil or gas resource which is commercially recoverable under current economic conditions with current technology. reservoir - a geologic formation or trap holding an accumulation of hydrocarbons. residential customers - a category of energy use consisting of individually billed households. resource cost (economic cost) - the cost of capital, materials, equipment and labor required to produce and market a particular resource. resources - substances that exist in nature that could hypothetically be converted into an economic asset through extraction and processing royalty - the landowner’s gross share of production under terms of a mineral lease. therm - 100,000 BTUs. transmission - the conveyance of natural gas from producing to consuming areas, typically through high pressure pipelines. wildcat drilling - drilling in a relatively unexplored geographic region or at an unexplored depth within a know hydrocarbon province. MAFA/ARI page 82 26-Feb-97 State of Alaska Division of Energy Natural Gas Recon Study A-2 A-3 A-4E A-4H A-10 A-12 A-14 A-16 A-18 A-19 A-20 A-21 A-22 A-23 A-24 A-25 A-27 A-29 A-30 A-31 A-32 MAFA/ARI List of Schedules Description Graph Natural Gas vs. Diesel Cost of Energy Comparisons Base Case & Sensitivity Analysis; Indexed Comparisons Base Case Energy Cost; "Typical" Residential Comparison Natural Gas vs Diesel Electric Cost Comparisons Natural Gas vs. Diesel Fuel Oil Heating Cost Comparisons Natural Gas vs. Diesel Electrical Generation Capacity Cost Comparison Gas Production Cost Scenario ($ per mcf produced gas) Field Development & Completion Cost Scenarios Large Community Medium Community Small Sized Communities Basic Field Development & Completion Costs Near Transportation System yes Remote From Transportation System yes Alaskan Entrepreneur; Near Transportation System yes Basic Field Operations & Maintenance Costs yes Estimated Cost of Natural Gas Distribution System Estimated Cost of Energy Transmission Systems Energy Use Profiles Total Energy Use Profile (Base Case) Electric Heating vs. Natural Gas Heating All Electric Case Energy Use Natural Gas Heating Demand (Base Case) Electrical Energy Demand (Base Case) Rural Profiles: Annual Electrical Generation vs. Installed Capacity yes Rural Profiles: Community Size vs. Customer Density yes "Typical" Village Energy Use Profiles; Selected Villages Residential Heating Estimates Diesel Fuel Price Review yes Residential Energy Cost Comparison Page 1 Schedule A-1 2/26/97 ECONMDL1.XLS Relative Cost of Natural Gas vs. Diesel Base Case and Sensitivity Analysis State of Alaska Division of Energy Natural Gas Recon Study Summary Relative Cost of Gas Energy Compared to Diesel (Indexed for each community size) BASE CASE Gas 1.04 1.00 1.40 2.23 Diesel 1.00 1.00 1.00 1.00 Natural Gas Field Quality Gas 0.88 0.85 1.22 2.23 Environmental Considerations Distance From Gas Field to Market 0.99 1.00 MAFA/ARI Page 1 Gas 1.05 1.00 1.43 229 ce 3 | Diesel 1.00 1.00 1.00 1.00 1.00 Mes ~ Gas 1.49 1.47 1.68 2.65 3.71 Diesel 1.00 1.00 1.00 1.00 1.00 [Increase of 25cents/galion in Diesel ‘ : 1 Gas 0.88 0.85 1.27 2.03 3.09 Diesel 1.00 1.00 1.00 1.00 1.00 Increase of 50cents/galion in Diesel : 1 Gas 0.77 0.75 1.16 1.87 2.85 Diesel 1.00 1.00 1.00 1.00 1.00} Schedule A-2 2/26/97 ECONMDL1.XLS Naturual Gas vs. Diesel "Typical" Residential Cost for Heating and Electricity | 1 |State of |_2 [Division MAFA/ARI Base Case ___|Diesel Alaska of Energy Gas-Fired Electricity Diesel-Fired Electricity Gas Heat _ [Fuel Oil Heat “Typical” Residential Comparison Gas S/MMBtu $/MMBtu D $0.125 $0.095 $15.64 $16.15 $0.139 $0.105 $15.52 $17.24 $2,767 $2,755 Page 1 | _S-Small | $0.971 $0.305 $103.86 $29.82 $18,776 $5,564 3.37 1.00 Schedule A-3 2/26/97 ECONMDL1.XLS Natural Gas vs. Diesel Fuel Domestic Heating Cost Comparison MAFAJARI ‘|Total Variable Capital Cost _ % | Annualized Distribution Cost (F+V) Total Cost per MMBTU delivered Heat Content (BTU/gal) _ Efficiency (percentage) _ Cost per MMBTU delivered Cost of Delivered Heating Oil (Sigal) | i $5.04 $2, 226, 667 $5.86 $1,431,429 $870,786 $67 539 $186,000 62 $1,000 $2,500 $217,000 $80,600 $28,030 $4,960 $113,590 11,615) “$72.71 1,000,000) 70% $103.86 Total Cost Per MMBTU delivered Page 1 Schedule A-4H 2/26/97 ECONMDL1.XLS Natural Gas vs. Diesel-Fired Electrical Cost Comparison E FE G H | | Lt Peak "Design" Load(KW) | _—7,269 5,237) 1,432 516 283 ____ Annual Demand (kwh) 30,323,800) 19,944,275| 3,135,000) 1,129,758) 551,040 | | _GA = _* pei Scics tk ibs lav Muay a ‘(Capital $1,453,881 | $1,047,302 ~ $286,301 | $103,174] $66,614 | |O&m 7 $414,423 | $95,383 | $47,166 | $33,942 Fuel i Cost of Produced Gas $5.86| $18.32) $35.56 $62.93 _ Efficiency (kwh/mef) 89, 84 81 | 78 7 Annual mcf Required 224,093 37,321 13,948 7,065 | _|CostofFuel || $1,314,245 | $683,843 | $496,036 | $444,547 _ Avg. Annual Cost per kwh $0.139 $0.340 $0.572 $0.971 ____DIESEl-fired E' we = 5 i i —_[. [Capital $726,940 | “$523, 1 $143,151] $51, 587 | $28,307 — O&M — _ $432,279 | $297,990 | $72,823 | $39,036 | __ $29,756 | [Euel — ee | ate - Base Case Fuel Cost $0.90 $1.80 $1.90 $2.00 ___|____0|Cost of Delivered Diesel $0.90, $1.80 $1.90 | $2.00 | _|Efficiency (kwh/gal) 14) 12 11|_ 10 __|___|Annual gallons required 1,424,591| 261,250 102,705; 55,104 | ___|Cost of Fuel _ | $1,282,132 | $470,250 | $195,140 | $110,208 ‘Avg. Annual Cost per kwh $0.253 $0.305 MAFA/ARI Schedule A-4E 2/26/97 ECONMDL1.XLS Ley | 1 [State of Alaska [2 [Division of Energy | 3 |Natural Gas Recon Study Cost of Electrical Generation Capacity Peak "D Capital Rect 14 |Variab! ‘Annualized Capital Cost Fixed O&M (20K + $22/KW * KW) nts per kwh * kwh)| Capital Cost for New Gas Fired Generating Units. __ 7.269) 5,237) — $1,000 | _ $1,000 20% $1,453,881 |$1,047,302 "$179,927 | $135,208 $279,220 20%| _ $1,000 $1,000} $1,000 20% 20% __ 20% $286,301 | $103,174 | $56,614 _ $51,493 | $31,349 | $26,228 _ $43,890 | $15,817 | [Annual Capital Recovery Factor _ Fixed O&M (20K + $15KW* KW) TOTAL ANNUALIZED COST $1,461,725 $381,685 | $150,340 $90,556 Capital Cost for Diesel Fired Generating Units | $523,651 | $199,443 ~ $98,548 | 11208 el =[ elle sla elele=leulelsialal lols sislels|sialalsialslaialel|-le]>- MAFAVARI TOTAL ANNUALIZED COST $1,159,219 $821,641 $90,623 Page 1 Schedule A-5 2/26/97 ECONMDL1.XLS Gas Production Cost Scenarios - Base Case Schedule A-6 Fixed Capital Investment _ = = | | 0|Exploration ; ae $0 | | $0 | $0 Field Development $14,089,657 | $10,565, 450 | 324, $4,990,227 | $4,990,227 0| Transmission System ao $0 $0 | | $0 | $0 0 | | | Total Fixed Capital Investment j $14,089,657 | $10,565,450 | $6,324,227 $4,990,227 | $4,990,227 Annualized Capital Costs F _ | | 20|Depreciation I / 5% 5% 5%| 5% 5% 0.15|Cost of Capital iia ; 15.0% 15.0% | 15.0% | 15.0% 15.0% t Annualized Field Development b/y $2,817,931 | $2,113,090 | $1,264,845 $998,045 $998,045 Annualized Transmission _ ; /y $0 $0 $0 | $0 $0 Operations & Maintenance Costs — ; = | Basic Field O&M / $148,800 $139,200 $120,000 $110,400 | $110,400 Gas Treatment & Compression O&M $156,131 $101,355 $19,419 $7,974 | $4,492 0.26 2. 5 5% | Transmission O&M i $ $0 7 $0 $0 $0 | $0 \%o 5 5.0% |Incremental General & Administrative ( (12K + 5%) | 4 $27,247 $24,028 $18,971 | $17,919 | $17,745 Total Annualized Cost 4 _ $h $3,150,109 | $2,377,672 | $1,423,235 | $1,134, 338 $1,130,682 | | Total Annual Gas Required = 624,525 _ 405,419 1876 96 17,968 ! | Costpermcf | j $5.04 $5.86 | $18.32 $35.56 $62.93 MAFAVARI Page 1 2/26/97 ECONMDL1.XLS Estimated Field Development Costs Schedule A-7 | 1 [Alaska Coalbed Methane Field Development Costs Large Rural Community Field Quality Medium Reserve/Well (Mmcf) _ 7 1400 2 | Peak Rate (mcf/day) — - 300) 400 _ 3/Average Rate (mcf/day) First ’ Ten Years (mcf/day - average) Next 15 years rs (mefiday - average) 4 Community Size Peak Rate > (mefiday) Average D Daily Rate (mcf/day) _ Annual Demand (Mmcf) 25 Year Demand (Mmcf) Number of Wells Required Reliability Produced Water Reinjection Wells | ; Subtotal \Additional V Wells Required (years 12- -20) {Initial Drilling & Completion Capital Cost __ | $5,635,000 | $8,970,000 | $19,642,000 PT oe 3 Additional Wells Drilling & Completion Capital Cost | | $2, 929,4 450 | $5, 119, 657° $8,838,909 (Discounted to NPV) ~ 9[Total Field Development Capital Costs $8,564,450 | $14,080,657 | $28,480,909 | 2 | | 3 | |4] 15 | | 6 | | 8} | 9 | | 10 | | 44 | [42 | | 13 | | 14 | | 45 | [16] [47] /18] [19] |20] | 22 | | 23 | | 24] | 25 | | 26 | | 27 | | 28 | | 29] | 30 | [31] | 32 | | 33 | EN El MAFAVARI Page 1 2/26/97 ECONMDL1.XLS Estimated Field Development Costs Schedule A-8 "Field Quality Reserve/Well (Mme Peak Rate (mcfiday) | Average | Rate ‘ate (mcf/day) First Ten Years (mefiday - - average) Next 15 years (mcfiday-average) Ss | _ 200 Community Size / / | Medium Peak Rate (mcfiday) | 2,555 Average Daily Rate (mcfiday) 1,111 Annual Demand(Mmcf) | 405 25 Year Demand (Mmcf) | 10,135 Initial Number of Wells Required Exploration Initial Development 12|Reliability 30 Produced Water Reinjection Wells Additional Wells Required (years 12-20) 3 Drilling & Completion Capital Cost ___| $4,968,000 | $7,636,000 | $15,640,000 é Additional We Wells Drilling & Completion Capital Cost | | $2,142,838 | $2, 929, 450 $5,449,468 (Discounted to NPV) Total Field Development Capital Costs $7,110,838 | $10,565,450 | $21,089,468 MAFAV/ARI Page 1 2/26/97 ECONMDL1.XLS Estimated Field Development Costs Schedule A-9 c | a ee ee G he] I J L K I L 1 |Alaska Coalbed Methane Field Development Costs | — | | | _ Field Quality | | ee -_ High | Medium Low High f Medium Low High Medium | Low rve/Well (Mmcf) oo 2800 1400 500 2800) 1400 500| 2800) 1400 500 } 2|Peak Rate (mcf/day) _ - 0) 400 150 900 400 150) 900) 400 150) 3|Average Rate (mcfiday) - | | | | First Ten Years (mcf/day - average) 500 250 100 500, 250/ 100, 500) 250) 100: |Next 15 years (mcfiday - average) 4|Community Size — [Peak Rate (mcfiday) - 851 “é I 350) | | [Average Daily Rate (mcf/day) 213 213 213/ 87| 87 87) 49) 49) 49 Annual Demand (Mmcf) 78 78 78| 32 32 32 | 18) 18) 18 25 Year Demand (Mmcf) 1,942 1,942 1,942 797 797 797) 449) 449) 449 ! : | | | 5| Initial Number of Wells Required =| | | | | | Exploration _ _ 1 1 1 1) 1| 1 1 1) 1 Initial Development 0 2 5 0| 0 2/ 0| 0 1 12|Reliability 1 1 1 1| 1 1 1 1| 1 30|Produced Water Reinjection Wells 1 1 1) 1 1| 1| 1| 1 1 Subtotal 3 5 8 3 3| 3 3) 4 6|Additional Wells Required (years 12-20) = 1 1 1 1 1 41 1 1 7|Initial Drilling & Completion Capital Cost a $3,634,000 | _ $3,634,000 | $4,968,000 | $3,634,000 | $3,634,000 | $4,301,000 | | | 8|Additional Wells Drilling & Completion Capital Cost $1,356,227 | $1,356,227 | $1,356,227 | $1,356,227 | $1,356,227 | $1,356,227 | $1,356,227 ~_|(@iscounted to NPV) a : | | | | | | ent Capital Costs $4,990,227 | $6,324,227 | $8,325,227 | $4,990,227 | $4,990,227 | $6,324,227 | $4,990,227 | $4,990,227 | $5,657,227 MAFA/ARI Page 1 2/26/97 ECONMDL1.XLS Schedule A-10 _|"Near to Transportation System” [ ____Number of Wells in Field= 8 : |__ Avg. _ | | | Per it - — — ee _ Field ; | | Well st ____| Quan | Rate Fixed | Per Well Total Cost 1|Lease acquisition, permits, bonds, survey & | | $50,000 | $10,000 $100,000 | $20,000 insurance (Wells per increment) _2|Site Preparation, access road, remediation | $200,000 | $10,000 | _$250,000 |_ $50,000 3|Well Drilling Rig Mobilization | $250,000 | $10,000| $300,000 — $60,000 “4 Welt ring _|Day Rate ($/day) _ | 10| $30,000; $300,000 | $1,500,000 | + $300,000 _5|Well logging, including mobilization and analysis | | $120,000 | $10,000 $170,000 $34,000 _ 6|Well completion, including casing, tubing, wellhead _ - _ | $250,000 | $150,000 | $1,000,000 | $200,000 |cementing, perforation, and mobilization — ‘7|Well stimulation, using 100,000# of sand _ — $250,000 | $50,000} $500,000 $100,000 __ 8|Well and lease equipment including pump, |__| $300,000 | $40,000 $500,000 | _—_ $100,000 separator, metering and gathering lines — ‘9|Engineering/Supervision $216,000 | $43,200 $432,000 $86,400 __| $4,968,000 $993,600 = — MAFA/ARI Page 1 2/26/97 ECONMDL1.XLS Lease acquisiti 2|Site Preparation, access road, Well Drilling Day Rate ($/day) uisition, permits, bonds, survey & insurance (Wells per increment) [Well Drilling Rig Mobilization remediation _ Well logging, including mobilization and analysis _ $50,000 | $10,000 —— } i $800,000 | $40,000 ~ 10) $30,000 Well stimulation, using 100,000# of sand 0 Contingency Engineering/Supervision _ Well and lease equipment including pump, —_—| separator, metering and gathering lines __ MAFA/ARI $500,000 | $50,000 Avg. Per Well Cost $20,000 $200,000 $120,000 $300,000 $60,000 $250,000 $100,000 $150,000 $60,000 $120,000 $1,380,000 Page 1 Schedule A-12 2/26/97 ECONMDL1.XLS Schedule A-13 Field Size vs. Unit Cost Per Well $4,000,000 Remote From Transportation System $3,500,000 $3,000,000 $2,500,000 $2,000,000 Unit Cost Per Well $1,500,000 $1,000,000 $500,000 $0 - - fn = oO N N Field Size 1 3 5 in 9 14 13 4 15 Ait, 19 | 25 J au 29 31 33 35 37 39 | MAFA/ARI Page 1 2/26/97 ECONMDL1.XLS MAFA/ARI 0|Contingency _ “Near to Transportation Syste _ Number of Wells in Field = Lease acquisition, permits, bonds, survey j & insurance (Wells per increment) Site Preparation, access road, remediation Well Drilling Rig Mobilization Day Rate e (S/day) Well logging, including r mobilization an and analysis ; Well completion, adeing casir |Well stimulation, using 100,000# of sand Well and lease ) equipment including pump, es separator, metering and gathering lines _ Engineering/Supervision "Alaskan Entrepreneur" - Contributed Labor, Favorable Market Conditions Field Page 1 $8,000 $8,000 $240,000 $10,000 }| $120,000 $40,000 $32,000 Total $80,000 | $140,000 | $240,000 | $1,200,000 | $150,000 | $800,000 | $400,000 | “$400,000 ~_ $170,500 $341,000 | $3,921,500 | Avg. Per Well Cost $16,000 $28,000 $48,000 $240,000 $30,000 $160,000 $80,000 $80,000 $34,100 $68,200 $784,300 Schedule A-14 2/26/97 ECONMDL1.XLS Schedule A-15 Field Size vs. Unit Cost Per Well $1,800,000 Alaskan Entrepreneur With Favorable Market Conditions $1,600,000 $1,400,000 $1,200,000 $1,000,000 $800,000 Unit Cost Per Well $600,000 $400,000 $200,000 $0 | +t o ow KR OD cr - fe re Fe NON Field Size 25 27 | 29 35 37 39 31 33 = - MAFA/ARI Page 1 2/26/97 ECONMDL1.XLS Estimated Field Operations and Maintenance Costs Schedule A-16 _ [Monthly Field O&M Estimates _ | _ _ -_ Ta an # of wells = 5 : | _ Monthly Expenses oo / ; Avg. | Pel oe ___|_ (per well) per well [Labor | $6,000 | $350 | $7,750, $1,550 | | ___|Equipment, Tools, Misc. | _- $2,000 | $50 $2,250 $450 __|Office Overhead | i a) _TotalO&M) $8,000 | = $400 |_— $10, 000 | | $2,000 | | [Notes eet al, : | ____ar|Already recovered in existing utility operations L | Gas treatment/compression is added on a per mcf basis to the cost ofp produced gas (Schedule A4) MAFAVARI Page 1 2/26/97 ECONMDL1.XLS Estimated Field Operations and Maintenance Costs Schedule A-16 B Lc [oD E Fua [eG 1 |Alaska Coalbed Methane Operations & Maintenance 2] Monthly Field O&M Estimates | 4 —_ |# of wells = 20 | Gi i Monthly Expenses | | | avg. | 6 | | _ / —_ | (per well) | | per well | 7 | |Eield Operations & Maintenance Fixed Variable | Total O&M et pe s & Maintenance — otal re] |Labor | $6,000; «$350 $13,000 $650 | | 10 | Equipment, Tools, Misc. $2,000 | $50 $3,000 $150 | }44] |Office Overhead ar ; | [42 | | “Total O&M) $8,000 $400 $16,000 $800 | } 15] ar| Already recovered in existing utility operations | | 16 | Gas treatment/compression is added on a per mcf basis to the cost of produced gas (Schedule A-6) MAFA/ARI Page 2 2/26/97 ECONMDL1.XLS $9,000 $8,000 $7,000 $6,000 $5,000 $4,000 $3,000 Monthly O&M Expense Per Well $2,000 $1,000 $0 MAFA/ARI Field Size vs. Monthly O&M Expense Per Well Field Size (# of wells) Page 1 Schedule A-17 2/26/97 ECONMDL1.XLS Estimated Cost of Natural Gas Distribution System [Commercial _ [Distribution System __|Distribution System ___ Total Customers Customers/mile _ Dollars ‘Steel | Plastic MAFA/ARI [Charlie Helm, Norgasco ‘per Foot for Installed Distribution System in $ per customer (plastic pipe) fl 260 52 835 212 35] 20 Rural Alaska (North Slope, ee eee $309,000 20 5.2 Unfavorable 20 3.1 $186,000 conditions) Page 1 Schedule A-19 2/26/97 ECONMDL1.XLS Estimated Cost of Transmission Systems Schedule A-19 State of Alaska Division of Energy | Natural Gas Recon Study Polyethylene Pipe _ Medium) $60,000 $40,000 $80,000 Large, $70,000 $50,000 $90,000 Steel Pipe : $150,000 $120,000 | $180,000 Electrical Intertie Small’ $30,000 $20,000 $50,000 Large) _ $60,000 $50,000 $100,000 MAFA/ARI Page 1 2/26/97 PROFILE.XLS TOTAL ENERGY USE PROFILE - Base Case | Households Commercial/industria/Other Customers | __ _|Heating Peak Demand (mct/day) Electric Peak Daily Demand (kwh) __ __ |Gas-Electric Conversion Efficiency (btu/kwh) | _ ~_|Gas Electrical Peak Demand (mef/day) _ [Total Gas Peak Design Demand (mcfiday) [Heating Load (mcf/day) [Electric Load (kwhiday) __|Gas Electric Load (mefiday) _ e Gas Load (mcf/day) MAFA/ARI Page 1 Schedule A-20 2/26/97 ALLELEC1.XLS Electric Heating vs. Natural Gas Heating Schedule A-21 Incremental Costs Additional Natural Gas Electrical Generation Capacity (incremental kW * S/KW*CRF)/(customers) Additional Natural Gas Electrical Generation O&M (incremental annual O&M)/(customers) Capacity upgrades in electrical distribution system (upgrade distribution per mile * miles * CRF)/(customers) _ Conversion of end-user to all electric heat (conversion per customer * CRF) All Electric Heat O&M (annual O&M percustomer) Elimination of natural gas distribution system (distribution system * CRF)/(customers) Elimination of customer service to connect to distribution (service per customer * CRF) Elimination of conversion of end-user to natural gas (conversion per customer * CRF) Natural Gas O&M (annual O&M per customer) Case MAFA/ARI All Electric Heat is roughly $1800 per customer per year more expensive when compared to natural gas heating in base Page 1 2/26/97 ALLELEC1.XLS All Electric Case Demand Estimate Schedule A-22 State of Alaska i Division of Energy iil Natural Gas Recon Study ial i Energy Use Profiles | | ail eT 777 T | ae 7 nu Large Medium ‘Small dade Large Medium Small Small Small Residential Households a 1,380) 575) 160) 83 a) | | | Commercial/industrial/Other Customers 290) 260) 52] 20/ 12 T T 1 | IL. —————— a | _ Avg. Rez Demand (Annual kwh) 6,500} 6,500) 5,300 4,600) 3,900 | 19 Avg. Com. Demand (Annual kwh) | 65,000) 56,000} 38,500 31,800 24,750 feof | | 21 | Avg Existing Elec Demand (kwh/year) | 27,820,000} 18,297,500 2,850,000 1,017,800 492,000 | 22 | | | 23 | ‘Station Use + Distribution Loss Factor | 9%) 9% 10% 11% sa 24 | | 25 Station Use + Distribution Loss (kwh) | 2,503,800 1,646,775 285,000 111,958 59,040 | 26 | | | | 27 | ‘Avg. Existing System Demand | 30,323,800 19,944,275 3,135,000 1,129,758 551,040 | 28 | | | 29 |Avg. Hourly Load (kW) | 3,462 2,277 358 129 63 [30] | | | 31 | Peak Load Factor | 2.1] 2.3 4.0 4.0) 45 T ] | | | a Peak Design Load (kW) | 7,269 5,237 1,432 516 283 | | a |Add “All Electric Heating” Demand se} | 2 [Avg. Rez Demand - Electric Heat (KWh/yr) | 20,000 19,000 18,000 17,000 16,000: | | 39] 3.5/Avg. C/O Demand - Electric Heat (kWh/yr) 70,000 66,500 63,000 59,500 56,000! | 40 | | | 41 | [Total Electric Heat Demand (kwh/yr) 47,900,000 28,215,000 6,156,000 2,601,000 1,472,000) | 42 | | | | 43 | Station Use + Distribution Loss Factor 9% 9% 10% 11% 12% | 44 | | | 45 | | Station Use + Distribution Loss (kwh) 4,311,000 2,539,350 615,600 286,110 176,640) | 46 | | | | [47| [Average Annual Demand (kwh 52,211,000 2,887,110 | 48 | | | 49 | ~ Avg. Hourly Load (KW) 5,960 3,511 773 | 50 | | [Peak Load Factor | 2.1 4.0 45 rea] | | | [53| __ [Peak "Design" Load 12,516 8,075 3,092 1,318] 847] MAFAVARI Page 1 2/26/97 PROFILE.XLS Base Case Natural Gas Heating Profile Schedule A-23 Residential Households 1,380 575 __|CommerciaV/industriaVOther Customers) ___290 260 _ |Avg. Rez Demand (meflyear) 120 120 Avg. Com. Demand (meflyear) 2) 500 Avg End Use Demand (motiyear) | _$10,600| 199,000, _|Operations & Losses Factor Operations & Losses (mcflyear) _ ~ [Average Annual Demand (mcf/year) __|Avg. Daily Load (mef/d) _ [Peak Load Factor [Peak Daily "Design" Load (mcf/d) MAFAVARI Page 1 2/26/97 PROFILE.XLS Base Case Electrical Energy Use Profile Schedule A-24 Residential Households __|Commercial/industria/Other Customers | 0} = 260 ‘Avg. Rez Demand (Annual kwh) 6,500|___5,300 — ee | 4,600) Avg. Com. Demand (Annual kwh) | 0 56,000 38,500/ 31,800 ‘Avg End Use Demand (kwh) __ | 27,820,000) 18,297,500) 2,850,000| 1,017,800 Station Use + Distribution Loss Factor | 9% 9% 10% «11% | _|Station Use + Distribution Loss (kwh) | — 1,646,775| 285,000) 19,944,275) 3,135,000 _ [Peak Load Factor | 5 | | 8 | | 9 | | 10 | | 12] [13] | 14] | 15 | | 16 | [17] | 18 | 19 | | 20 | | 24} | 22 | | 23 | | 25 | | 26 | | 27 | | 28 | | 29 | Eq MAFAVARI Page 1 2/26/97 PROFILE.XLS Installed Capacity / Av erage Hourly Demand Schedule A-25 MAFA/ARI Page 1 AR Oe er 1 |State of Alaska act | | 2 |Division of Energy ieee 3 [Natural Gas Recon Study SE 4 |Energy Use Profiles aes alt = | 5 |Utility Installed Capacity vs. Average Hourly Demand = a 6 7 |Source: Alaska Electric Power Statistics, October 1995 Eee 8 |Pull out "urban”,"outliers", "mixed generation" _ [9 [L = —_[ SORT fo; —— = (KW) (C/E) 11 (KW) (MWH) _— Average Installed 12 == Installed Net | Hourly Capacity Capacity | Generation | Generation | Factor = | | | Bethel 12,600) 34,202 3,904) 3.23 Nome 7 10,280| 30,630) 3,497 2.94 Unalaska/Dutch Harbor 7,200) 27,500 3,139 2.29 Naknek 7,685) 20,007) 2,284) 3.36 Kotzebue 10,860 19,046) 2,174 4.99 Dillingham 5,405 16,527) 1,887) 2.86 ‘Craig 4,820 14,305 1,633 2.95 ‘Haines 5,740 10,649 1,216 4.72 Galena 4,300 7,865 898 4.79 Yakutat 2,880 6,529) 745) 3.86 'St. Paul 1,775) 6,076 694) 2.56 Hoonah 2,015) 4,304 491) 4.10 Kake 2,230) 4,142 473 4.72 ‘Unalakleet 1,860 4,085 466 3.99 ‘Point Hope 1,595 4,055 463 3.45 [Wainwright 1,950 3,718 424 4.59 ‘Sand Point 2,800 3,623 414 6.77 [Cold Bay 2,145 3,143 359 5.98 ‘McGraph 2,145 3,110 355 6.04 'St. Mary's 1,386 2,813 321 4.32 Thorne Bay 1,575 2,782 318 4.96 ‘Fort Yukon | 1,890 2,736 312 6.05 Aniak 1,160 2,410 275 4.22 ~ |Anaktuvuk Pass 1,315 2,320) 265) 4.97 ‘Nuigsut | 1,025 2,309 264 3.89 |Emmonak 2,152 2,216 253 8.51 |Iliamna | 1,560 2,208 252 6.19 ‘Mountain Village | 1,858 2,206 252 7.38 Atqasuk 1,350 2,025 231) 5.84 Angoon | 1,260} 1,961 224 5.63 ‘Togiak 1,037 1,867 213 4.87 ‘Hooper Bay | 1,486 1,857) 212 7.01 'Nunapitchuk/Kasigluk | 1,858 1,824 208 ‘Kaktovik 1,380) 1,744 199 2/26/97 PROFILE.XLS Installed Capacity / Average Hourly Demand Schedule A-25 = ate (KW) (C/E) (KW) (MWh) Average Installed 7 Installed Net Hourly Capacity Capacity Generation | Generation | _ Factor PointLay 985 1,706) 195, —s—— 5.06 Northway 1,420) 1,650) | 1887-54 Tanana 1 ___2,000 1,644 188) «10.66 Gambel go2,—sis1,595) ——s«é1822 4.90 Hydaberg 1,085 1,592) ‘182 5.97 Noovik 875 1,397, 159) 5.49 "Coffman Cove a 730 1,368 «156 4.67 _ Selawik | : ee) 1,329) 182) 6.16 Chevak 875| 1,291| 147) 5.94 Shishmaref | 971 1,273| 145 6.68 Savoonga 892 1,208) 138 6.47 Kiana | 869) 1,138] 130 6.69 Kwethluk 1 750) 1,098) 125) 5.98 St. George 605) 1,096 125) 4.84 Shungnak | 972) 1,056 121 8.06 ‘Noatak | 709 1,055 120 5.89 ‘Alakanuk 850 1,039 119 7.47 Ambler | 744 1,024 117) 6.36 ‘Pilot Station | 633 1,011 115 5.48 ‘Teller 905) 1,011 115 7.84 Quinhagak 633 993 113 5.58 Toksook Bay | 823 985) 112) 7.32 Stebbins | 745| 982| 112| 6.65 Kotlik | 505) 910 104 4.86 Kivalina | 986 896 102 9.64 ‘Bettles 810 888 101 7.99 |Nulato 709 867 99 7.16 [Crooked Creek 828 866 99 8.38 ‘New Stuyahok 585 864 99 5.93 ‘|Scammon Bay 607 846 97 6.29 _Manokotak | 480 810 92 5.19 Kalskag 590 808 92 6.40 'St. Michael | 553 790 90 6.13 [Marshall | 655 759 87 7.56 Akiachak | 820 735 84 9.77 [Egegik | 500 735 84 5.96 ‘Tununak 440 718 82 5.37 Koyuk 655 716 82 8.01 Mekoryuk 577) 714 82 7.08 White Mountain | 700) 685 78 8.95 |Elim 585 665 76 7.71 [Eagle | 350 648 74 4.73 ‘Holy Cross 585 640 73 8.01 ‘Port Heiden 175 625 71 2.45 MAFA/ARI Page 2 2/26/97 PROFILE.XLS Installed Capacity / Average Hourly Demand Schedule A-25 r 5 [eo =F 10| Ti a (KW) (C/E) 11 (KW) (MWh) Average Installed 12] Installed Net Hourly Capacity & a sss Capacity Generation | Generation | Factor 9 Chefornak 400) 612 70) 5.73 Minto —<—s——C(<i‘ NH AT 70 7.37 Ruby _ Tl IL 600, += 592,st—‘ésSS 8.88] —Levelok {| ___ 320 591) 67) 4.74 —Huslia HL 600 578 | 66, 9.09 Kaltag oe 547 _ 578) 66) 8.29 Shaktoolik a4 585) 575) 66 | 8.91 Napaskiak en) 553) 63) 2.38 Russian Mission | 388) 531 61) 6.40 ___Kwigillingok name 400; s«*527 60) 6.65] ___Wales Hee 359 508) 58| 6.19 Goodnews Bay 492, 503) 57) 8.57 Grayling ee) 493, 56) 9.24 Port Allsworth | 270) 488 56) 4.85 Deering | 280) 469 54) 5.23 Eek | 484| 466 53 9.10 Brevig Mission 432) 454 52 8.34 ‘Diomede 463 412 47 9.84 Atmaultluak | 320 385 44 7.28 Anvik | 332 373 43 7.80 Nightmute 275| 361 41| 6.67 ‘Central | 125) 338 39 3.24 Nelson Lagoon | 285 332) 38 7.52 Hollis 190 325 37 5.12 ‘Manley Hot Springs | 250 315 36 6.95 ‘Perryville | 475 299 34 13.92 /Newtok 185 295 34 5.49 Atka 285 292 33 8.55 Shagelik | 282 284 32 8.70 False Palse | 225) 283 32 6.96 ‘Beaver 256 267 30 8.40 |Kolinganek 100 267 30 3.28 Tuluksak | 250 238 27 9.20 ‘Chistochina | 160 235 27 5.96 Mentasta Lake | 205 212 24 8.47 Igiugig | 60 173 20 3.04 Nikolski 185 13 MAFA/ARI Page 3 2/26/97 PROFILE.XLS 16.00 14.00 = Nn So So 10.00 8.00 Installed Capacity / Avg. Hourly Load 4.00 2.00 0.00 MAFAVARI 6.00 + Annual Generation vs. Installed Capacity Ratio ° | | ~~ mit He fi | (* « ~- | a ebb fidelbddstebts yi Seal ARETE oe whee eo ° ° bi o —___$> #1, pp - ° ? z ? we . e ° | {orci eee pe EEUEE oy | | - . 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 Annual Generation (MWH) Page 1 Schedule A-26 2/26/97 PROFILE.XLS Density: Customers per Mile 5 | ie Ue ull | 6 | 7 i 7 Customers’ | Wl 7 oa mile of | 8 | I | _No.of | distribution | 14 | [Ketchikan aL 6,650) 133 | 12 | |Fairbanks Municipal Utility System 6,000 122) | 13 | Anchorage Municipal Light & Power | 30,000 83 | 14 | [Alaska Electric Light & Power __ | 12,500 83) | 45 | Sitka Sa 4,086] 82) | 16 | Bethel | 1,800 72| Alaska Power - Craig/Klawock 650 65) | 18 | ‘Kotzebue Electric | 1,017 63) | 19 | [Barrow | 1,400) 57 | 20 | ‘Alaska Power - Skagway | 500 53 | 21 | Nome Joint Utilities | 1,912 45) | 22 | Chugach Electric | 62,000 41) | 23 | Wrangell | 1,242 41 | 24 | [Seward | 1,851) 37) | 25 | Petersburg | 1,731) 35 | 26 | |\Cordova 1,620 34 ‘Alaska Power - Hydaburg 180) 30) Ed Haines Light & Power | 848 28 | 29 | Kodiak | 5,200 24 | 30 | Alaska Power - Tok/Dot Lake/Tanacross 600 20 | 34 | |Alaska Village Electric Coop, Inc 5,400) 19 | 32 | 'Metlakatla 764) 19 | 33 | ITHREA 1,218 17 | 34 | Nushagak 1,157 15 | 35 | Golden Valley Electric Association, Inc. 18,500 14 | 36 | |Matanuska Electric 30,000 13 | 37 | |Homer Electric Association 18,200 12 | 38 | [Naknek | 760 12 Ed |Copper Valley | 2,800 9/ | 40 | | 41 | Source: | 42 | Selected Alaskan Electric Utilities Ata Glance, August 1995, | 43 | |Alaska Systems Coordinating Council/State of Alaska Division of Energy [aa | 45 | MAFA/ARI Page 1 Schedule A-27 2/26/97 PROFILE.XLS 140 Community Size vs. Customer Density 120 8 80 Average Customers per mile of Distribution MAFA/ARI 10,000 20,000 30,000 40,000 Number of Customers Page 1 50,000 60,000 70,000 Schedule A-28 2/26/97 PROFILE.XLS Rural Community Energy Use Profiles | Aggregate _| (c/mile-dist) McGraph Noatak Russian Mission Teller ‘Alaska Electric —_ Statistics, Oct 95; Alaska Electric Utilities, 1994 Energy Sales, Revenues and Customers, Alaska Department of Labor, Research & Analysis Section, Population Estimates (1994) Density: Selected Alaskan Electric Utilities At a Glance, August 1995 _ MAFA/ARI Page 1 HDD Schedule A-29 2/26/97 ALLELEC1.XLS Residential Heating Estimates Schedule A-30 ne _ | Electric Heat Residential | a Empirical 1 Sample (Railbelt) Residential _ Heating Only Gas Heating End-User Conversion Efficiency Natural Gas Energy Content (BTU/mcf) Natural Gas End-User Demand (MCF/year) All Electric Heating End-User Conversion Efficiency Electrical Energy Content (BTU/kWh) Peak Demand — BTUH | 6 | | 8 | | 9 | | 10 | [14 | | 12 | | 13 | | 14 | | 15 | | 16 | | 17 | | 18 | | 19 | | 20 | | 24 | | 22 | | 23 | | 24 | | 25 | | 26 | | 27 | | 28 | | 29 | | 30 | MAFA/ARI Page 1 2/26/97 ECONMDL1.XLS Residential Heating Cost Comparison Break-Even Retail Price | No. 1 Diesel 133,500 ost per Million BTU Delivered Heat| Assumed Heat Content Break-Even Case MAFAVARI -Btu/gal $18.09 __85%| Gas _ $/mef $12.60 1,000,000 ‘Btu/mef 70% $18.00 Page 1 Propane | __ 90,300 _Btulgal $18.04 70% | Electric + $0.062 | __ 3,413) 15,500,000 Btu/kWh | Btu/cord 100% | $18.02 | Wood $154 | 55% $18.06 | Coal $/ton $169 | 15,600,000 Btu/ton 60% $18.06 Schedule A-32 2/26/97