Loading...
HomeMy WebLinkAboutRural Energy Plan, Additional Information on Alternative Energy, May 1999RURAL ENERGY PLAN ADDITIONAL INFORMATION ON ALTERNATIVE ENERGY Prepared By: Division of Energy Department of Community and Regional Affairs State of Alaska May 21, 1999 Rural Energy Plan Additional Information on Alternative Energy Division of Energy May 21, 1999 The Rural Energy Plan issued by the Division of Energy in February 1999 includes a brief section on alternative energy development. Its central message is that, in most rural villages, diesel generators continue to be the most cost- effective source of electric power compared with alternative energy technologies. There have been exceptions — primarily small hydroelectric projects and end-use conservation measures — and the Division continues to evaluate these and other power supply alternatives. In the Division’s judgment, reliability and cost are the main criteria by which power supply alternatives should be judged in rural Alaska — reliability because of the harsh conditions and consequences of prolonged outages, and cost because retail rates in rural villages are already so high. Environmental factors — the potential for fuel contamination, air quality impacts, and noise — are important but secondary. There are few consumers and utilities in rural Alaska who would choose to pay more than they already do in order to realize environmental benefits from alternative energy. Power supply costs are not the only factor contributing to high retail power rates in rural villages. Lack of economies of scale — the need to recover fixed costs of physical plant and labor over a small sales base — is no less important. Attachment 1 includes a working paper prepared last year for the Governor's committee on Power Cost Equalization that discusses the various causes of high rural power costs and the primary options for bringing them down. This paper provides additional information on Division of Energy efforts to develop and test alternative energy proposals. Again, it is relatively brief but is intended to provide more detail on specific projects and evaluations. The listing of projects below is a significant sample but is by no means exhaustive — there are many others that have been considered in the past and many more that can be considered in the future. Continuing efforts to reduce capital costs and continuing increases in energy demand can combine to make proposals and technologies attractive in the future even if they are not cost-effective today. INTERCONNECTION OF ISOLATED VILLAGE SYSTEMS (“INTERTIES”) As discussed in Attachment 1, the average cost of diesel fuel for all electric utilities in rural Alaska is about/8 cents per gallon — about 5-6 cents higher than the fuel cost incurred by Anchorage area utilities. This is one reason for the overall cost differential between rural and urban systems but explains only a fraction of it. Most of the difference appears to be economies of scale — each isolated village requires a relatively high level of fixed costs consisting of its own May 21, 1999 power plant, operators, and management. For this reason, one approach to reducing rural power costs is to build transmission lines between villages so that one or more diesel powerplants can be turned off and the fixed costs of generating plant and labor can be reduced and spread over a larger sales base. The problem is that the distances between villages are relatively long and the electricity requirements are typically small. The result is that the cost of the intertie typically exceeds the estimated savings from interconnection. Relevant work funded by the Division in the recent past includes the following: In March 1997, a comprehensive survey of proposed transmission lines in rural Alaska was published by a consulting firm on contract to the Division. The intent of the project was to consolidate all of the published information on rural intertie alternatives and then to conduct an economic screening analysis that would identify those with greatest economic potential. Attachment 2 includes the narrative report submitted with the intertie data base. Attachment 3 includes the consultant's comments on the accuracy of the data base and the likelihood that rural interties will be cost-effective. His perspective on economic feasibility is as follows: “Most utility managers perceive little advantage in interconnecting to villages that are already being served by central station diesel generation... There may be some economy of scale by eliminating generation at one village in deference to generation at another, but probably not enough to warrant the debt service associated with a transmission line, additional generation at the supply source, and O&M cost to maintain standby reserves at the receiving village.” Primarily due to questions on the validity of the cost data and to the poor prospects for favorable results, the study was discontinued prior to any large-scale economic screening analysis. In 1992, a consultant prepared a report for Calista Corporation on a proposal to link the following communities by intertie: Bethel, Kwethluk, Akiachak, Akiak, Tuluksak, and the Nyac (“New York Alaska Company”) gold mine. The concept was initially to connect all the communities and supply them from the Bethel diesel power plant. The line would later be extended to Nyac where a non-functioning hydro project would be rebuilt. Hydroelectric power would then be sent back to the villages and to Bethel when sufficient water was available. The consultant found the concept to be economically feasible based in part on intertie cost estimates of $10 million or less. In 1996, the Division commissioned two independent cost estimates of the proposal, each of Division of Energy Page 2 of 10 May 21, 1999 which exceeded $30 million. This higher cost far exceeded projected benefits. . In 1991 the Alaska Energy Authority considered a proposal to build an intertie from Nome to Teller and Brevig Mission. As described in the Authority's letter to Teller Power Company included in Attachment 4, the cost of the line far exceeded any identifiable benefit. ° In 1990 the Alaska Energy Authority studied the potential to connect Bethel with Atmautluak and Nunapitchuk-Kasigluk (the latter two are in close proximity to each other and are already interconnected). Once again, however, costs exceeded benefits by a significant amount. Attachment 5 includes an excerpt of the Authority's analysis. . In 1996 the Division retained a contractor to evaluate an intertie from Petersburg (which is served by the Tyee Lake hydro project) and Kake (which is served by diesel generators). The concept was to supplant diesel power with surplus hydroelectricity from the Tyee project. The intertie was estimated to cost approximately $15 million, well in excess of the savings that could be realized by shutting down the diesel generators in Kake. . Alaska Power & Telephone Co. is now constructing an intertie on Prince of Wales island connecting Thorne Bay and Kasaan with an existing grid that includes Craig, Klawock, and the Black Bear Lake hydro project. The estimated cost of the line is $2.4 million, over half of which is being paid for with State and federal grant funds. The balance is being financed with a zero-interest loan from the Division of Energy. The new line is intended to help stimulate economic development in the future but was feasible to construct only because of the high level of government subsidy. SMALL HYDROELECTRIC PROJECTS In 1997, consultants on contract to the Division published a data base on existing and proposed hydroelectric projects in rural Alaska. They also completed an economic screening analysis to determine which, if any, potential projects appeared on a preliminary basis to be cost-effective. The narrative portion of the report is included as Attachment 6. As listed on page 20 of the attachment, projects in 10 rural communities were identified as promising candidates based on the available information. Additional candidates may well be out there even though the data needed to evaluate them was not available to us. Of the 10 identified communities, hydro projects are now in varying stages of development in the following four: . Atka (Chuniisax Creek) Division of Energy Page 3 of 10 May 21, 1999 Old Harbor (unnamed stream) Unalaska (Pyramid Creek) Gustavus (Falls Creek) As for Haines and Skagway, which are also on the list, Alaska Power & Telephone Co. recently completed a hydro project at Goat Lake and a transmission line to connect the two communities. Other relevant work on small hydro during the recent past includes the following: . In 1991, a consultant on contract to the Division published a feasibility study of the $6.0 million King Cove hydroelectric project which has since been constructed with the aid of State and federal grant funds. The analysis concluded that the project would break even in economic terms, i.e. a benefit-cost ratio of 1.0 (see excerpt, Attachment 7). Government funding allowed the project to provide near-term benefit to the utility ratepayers. The Tazimina hydroelectric project serving lliamna, Newhalen, and Nondalton was recently completed at a cost of approximately $11.0 million, most of which came from State and federal grant funds. A 1991 feasibility study prepared for the utility indicated that the project would produce substantial net benefits (see excerpt, Attachment 8). Although fuel prices did not increase as anticipated and the cost estimate turned out to be low, government grant funding enabled the utility to bring the project on line without increasing local rates. The Power Creek hydroelectric project is now under construction in Cordova at an estimated cost of $15 million. Federal grants will pay approximately $5.0 million of the cost and the Division of Energy has also issued a zero interest loan for $1.0 million. Power Creek was selected by the Cordova utility following a competitive power supply solicitation process. The utility advertised for proposals from any and ali sources that could supply power for less than it cost the utility to generate from its diesel power plant. There were literally hundreds of inquiries and expressions of interest from Alaska and around the country but ultimately only 3 proposals were submitted — two hydro projects and a small-scale coal plant. Power Creek was selected as the best proposal. In 1996, the Division of Energy received loan applications for two hydro projects — one at Reynolds Creek near Hydaburg and the other at Thayer Creek near Angoon. Even with federal grant contributions, however, neither of these projects were able to demonstrate economic or financial feasibility at that time. Included as Attachment 9 are the evaluations Division of Energy Page 4 of 10 May 21, 1999 prepared by the Division of Energy and submitted to the Division's loan committee. . Alaska Power & Telephone Co. has successfully constructed hydro projects at Black Bear Lake (on Prince of Wales island) and Goat Lake (near Skagway) during the last several years. While Goat Lake did receive federal grant support, the key factor is that AP&T has been able to build these projects for considerably less cost than had been anticipated in earlier studies. Hydroelectric projects that did not appear feasible when examined in prior years may, in some cases, become feasible if private developers can build them at lower cost without sacrificing too much in terms of reliability and maintenance requirements. . Not all small hydro projects have been successful. At Akutan, a private developer installed a hydroelectric project that was intended to operate automatically in tandem with the utility's diesel plant — ramping outputs up and down depending on water availability and electrical demand. Continuing difficulties led eventually to a decision to disconnect the two plants, losing substantial benefits in the process. At Larsen Bay, a private developer vastly underestimated the project’s construction cost, which led the community into substantial debt. Operational problems with the plant over the last several years have led many to wish that the project had never been built to begin with. END-USE CONSERVATION In managing the federally-funded “Rebuild America” program, the Division focuses on conducting energy audits in non-residential buildings in rural Alaska. These typically result in a set of “no cost” recommendations (“turn off lights when you leave the room”) and other recommendations that require some investment. Fluorescent lighting retrofits are most common in this category. Although funding is not often available from the Division to implement conservation measures, lighting retrofit demonstration projects were funded in the Tanana and Akiak schools over the last two years. Limits on staff time and funding have precluded any follow-up or evaluation of these demonstration projects to date. The following considerations on end-use conservation in rural Alaska are reproduced from Attachment 1: . Because the cost to produce a kWh of energy is relatively high, electric energy conservation should be exceptionally cost-effective in this environment. Division of Energy Page 5 of 10 May 21, 1999 . Because the present level of electricity consumption in rural villages is already very low, the remaining opportunities for conservation may be limited. ° While the cost of energy for residential consumers is often considered to be the highest priority, it is most difficult to design and implement an effective energy conservation program for this segment of consumers because there are so many of them, each consuming a relatively small amount of power. ° Rural utilities are typically not supportive of energy conservation programs except for the purpose of customer relations. Because much of the utility's cost is fixed, lower power sales often means upward pressure on rates. The conserving customer may still benefit but the utility and its other customers may be left to share higher fixed costs. From the rural utility’s perspective, conservation goes in the opposite direction of the utility's effort to increase sales and thereby enhance economies of scale. WIND POWER Alaska has excellent wind resources, especially in coastal regions. Efforts to capitalize on this in the 1980s, however, were largely unsuccessful — wind machines were placed in many rural communities but most failed to operate successfully for more than a year and those that did required substantial additional investments. Given this experience, the Division has declined to recommend wind generators for small, rural communities until they are proven under Alaska conditions with respect to performance, durability, and cost. Significant advances in wind energy technology have occurred since that time and there are now two wind demonstration projects underway in northwest Alaska. . In Kotzebue, 3 new wind turbines — each rated at 50 kW — have been operating for approximately 1 year and another 7 turbines were installed this spring. The project cost is approximately $2.0 million, most of which has been funded with federal grants. A preliminary economic analysis is being prepared for the Kotzebue utility and is expected to be available for review within the next two months. The demonstration project is intended to last another two to three years in order to provide a thorough test of the equipment’s reliability and maintenance requirements. . A “high penetration” wind demonstration project, also funded primarily with federal grants, is scheduled to be underway in Wales this summer. The concept is to provide a much higher proportion of the utility's total requirements, displacing up to 50% of the utility's diesel generation with a combination of wind energy and battery storage. Division of Energy Page 6 of 10 May 21, 1999 NATURAL GAS / COAL BED METHANE Natural gas is available in some communities on the North Slope but otherwise has not been found in close proximity to communities in rural Alaska. Following are significant efforts to evaluate these possibilities: In 1997, a consultant on contract to the Division issued a report on the technical and economic potential of substituting natural gas or coal bed methane for diesel fuel in rural Alaska. The executive summary is included in Attachment 10. The consultant concludes that, given the expected costs of exploration and development, the typical size and density of rural communities, and the relative cost of diesel fuel delivered to the community, “the overall economic prospects for natural gas in rural Alaska are poor.” An aerial magnetic survey of the lower Kuskokwim basin was conducted in 1995 to determine whether subsurface conditions were promising for the discovery of hydrocarbons, especially natural gas or coal bed methane. The Department of Natural Resources analyzed the data and reached the following conclusion: “The geological and geophysical relationships in the area do not totally preclude the possibility of generation and migration of small amounts of natural gas, but the data do suggest that accumulations are very unlikely, and that they would probably be very small.” In 1988 a geological consultant on contract to Naknek Electric Association studied the potential for natural gas to replace diesel generation. The analysis concluded that, based on subsurface geology, the closest prospect for discovering commercial quantities of natural gas is at least 30 miles southwest of Naknek. Traversing this minimum distance by pipeline or transmission line would be costly, as would the exploration and drilling program needed to determine if suitable gas supplies were actually there. GEOTHERMAL ENERGY The State spent over $5 million trying to develop a geothermal power plant at Unalaska, most of which was spent in a drilling program that established the presence of an adequate geothermal resource. Fish processors at Dutch Harbor, who account for well over half of the area’s electricity demand, currently supply their own power from diesel generators. They would have been interested in buying power from the geothermal plant except for two problems: Division of Energy Page 7 of 10 May 21, 1999 de Despite proposed government subsidies of up to half the capital cost of the project, the expected cost of power was still not quite competitive with diesel. 2. Due to the unpredictable nature of the fishing industry, none of the processors were willing to sign long term commitments to purchase power even if the price were low. Without long term purchase commitments, conventional financing for any portion of the project costs would not be available. The most recent evaluation of the project was completed in 1995 by a consultant retained by AIDEA. The executive summary is included in Attachment 11. The study concludes that the project would break even compared with diesel but only if the State contributed a $45 million grant towards project construction. . In 1995 a loan application was submitted to the Division to develop a geothermal resource at Pilgrim Hot Springs, about 60 road miles from Nome. The key to the proposal was to sell power to the Nome electric utility. The problem was that it would cost in the neighborhood of $5 million to build a transmission line to Nome. The revenue projections submitted by the applicant fell considerably short of the project's overall capital requirements, including the cost of the transmission line. WASTE HEAT FROM DIESEL GENERATORS During the period 1988-90, the Alaska Energy Authority contracted for studies of waste heat potential in approximately 30 rural communities. The concept was to recapture diesel engine heat from the jacket water and supply that heat to nearby buildings. Fuel savings would then be realized by the heat recipients. Ideally, relatively large buildings with significant heating demands are located close to the diesel power plant. The smaller the heating loads and the greater the distance from the diesel plant, the less likely it is that a waste heat system will be economically feasible. The Energy Authority constructed approximately 10 of the 30 systems using State capital appropriations, focusing on those with the greatest economic potential. Although the initial concept was to finance construction of these systems with debt, none were identified that could generate enough revenue from heat sales to recover the capital cost. Local maintenance of the completed systems has been inadequate in a number of villages, leading to system failures and significant repair bills. Attachment 12 includes the executive summary from two of the studies — Kotzebue and Sand Point — where proposed waste heat projects were not built. The economics of these two appeared to be marginal. Both projects may have Division of Energy Page 8 of 10 May 21, 1999 been among the next group to be constructed, however, if additional capital funds had been appropriated. In more recent years, the Division has tried to incorporate waste heat recapture into every new and refurbished diesel power plant that we construct. Typically, this means installing relatively short pipelines to nearby buildings or other heating loads (such as the village water supply or washeteria), and foregoing the more extensive and costly district heating systems that were proposed in the earlier studies. FUEL CELLS At this stage of fuel cell technology, there are very limited fuel cell applications in rural Alaska because the fuel needed for their operation — typically natural gas or hydrogen — is not available or would have to be imported at high cost. A fuel cell demonstration project funded primarily by federal grants and, to a lesser extent, an ASTF grant, is anticipated to take place shortly in Nuiqsuit, where it will be fueled by natural gas. In the proposal to ASTF, the total capital cost is estimated at $12 million for a 300 kW fuel cell, about $40,000 per kW. By comparison, the 6,000 kW Power Creek hydro project is estimated to cost $15.0 million, or $2,500 per kW. COAL There are two different paths by which coal might grow in importance as an energy source in rural Alaska: ue Coal-water fuel. To date, coal-water fuel has typically been produced and used as a substitute for heavy oil in boiler applications. The work on subbituminous coal-water fuel now going on at the University of Alaska Fairbanks is expected to include testing the fuel in a diesel engine. If successful, and if the fuel can be produced and delivered to rural communities at a cost advantage relative to diesel fuel, then a further demonstration of its use in a village power plant would be in order. 72 Small scale coal-fired power plants. Traditionally, coal-fired power plants have not been considered competitive on a small scale because their capital and O&M costs are relatively high. For a village sized plant, these fixed costs would be especially difficult to overcome. The reason coal- fired power plants are relied upon so heavily elsewhere is because the delivered price of coal is inexpensive in more populous and accessible locations. Advances have been made in the technology, capital cost, and operating cost requirements for small-scale coal-fired power plants. A formal assessment was issued by a consultant in 1997 for a small-scale coal- Division of Energy Page 9 of 10 May 21, 1999 fired power plant in McGrath, with coal to be supplied from a proposed coal mine 90 miles away over a winter road. The executive summary is included as Attachment 13 — the project is not economically feasible. However, other utilities continue to investigate the potential for coal in their particular region. BIOMASS Biomass fuels considered by the Division have typically included wood, wood waste, and municipal solid waste. Whether the use of these fuels provides a cost advantage is very much a site-specific question and depends not only on the availability and cost of the fuel but also on the cost that may be incurred to dispose of waste fuels in some other fashion. What the Division has found is that, in a number of locations, wood or wood waste is a favorably priced fuel compared with oil but that wood is rarely cost- effective for power generation in small communities for reasons similar to coal — the capital and O&M costs of a wood-fired power plant are relatively high. The Division therefore considers space heating to be the most promising application for wood fuel in rural Alaska. A 1994 feasibility study found that a power plant fueled by municipal solid waste could be cost-effective in Thorne Bay. However, Thorne Bay has since been connected by transmission line to the Black Bear Lake hydro project and is no longer a candidate for an MSW plant. Division of Energy Page 10 of 10 ATTACHMENT 1 OPTIONS FOR REDUCING RURAL POWER COSTS WORKING PAPER — PCE BLUE RIBBON COMMITTEE FEBRUARY 1998 OPTIONS FOR REDUCING RURAL POWER COSTS WORKING PAPER - PCE BLUE RIBBON COMMITTEE FEBRUARY 1998 The primary options can be organized into three categories: 1. Reduce non-fuel operating costs. 2 Reduce fuel costs. 3. Replace diesel generation with alternative energy. Reduce non-fuel operating costs Significant measures to reduce non-fuel operating costs per kWh involve either switching to a different mode of power generation such as hydro, or enhancing economies of scale. Alternative energy strategies are discussed in a later section of this paper. Economies of scale may be sought in either of the following ways: ae Increase power sales. The problem is that this is not a realistic option in most rural villages. 2) Utility mergers. For example, a single-village utility could join a multi- village utility. Savings could be realized in administration, billing, and volume purchasing of parts, equipment, and fuel. Scale economies also allow for the employment of technical staff whose cost and expertise can be shared throughout the multi-village utility, and whose contribution can result in improved maintenance, longer equipment life, and fewer costly emergencies. As noted during our initial meeting, the multi-village utilities generally do not have a record of lower rates. For example, AVEC residential rates throughout their 50-village system exceed 40 cents/kWh. Residential rates in the 6 villages served by Tlingit-Haida Regional Electrical Authority exceed 30 cents/kWh although all 6 are located in the relatively low cost region of southeast Alaska It may be that the main effect of joining a multi-village system is not to reduce consumer rates but rather to improve reliability, safety, and environmental protection. Further, it may be that operating cost economies are realized but that the savings are then used to “purchase” a safer and more reliable system. Overall: Options for Reducing Rural Power Costs Working Paper — PCE Blue Ribbon Committee Page 2 ae Joining a multi-village utility to enhance economies of scale is not likely to produce significant rate reductions for the consumer. Joining a multi-village utility could lead to development of a power system that is more reliable, better built, and better maintained. It is a difficult strategy to implement, however, since single-village utilities typically exist where the desire for local control is relatively high. Joining a multi-village utility could lead to lower overall costs of operation and greater self-reliance even if such cost reduction is not reflected in consumer rates. Single-village utilities are more likely to seek and obtain government grants for plant replacement and emergency repairs, while multi-village utilities are more likely to finance their plant requirements and recover the associated debt service through consumer rates and PCE. Reduce fuel costs As discussed in the Committee's initial packet of materials, fuel costs are one reason for high rates in rural villages although the impact of fuel costs is less important than often assumed: 1. The average price of diesel fuel in 1995 for utilities in the Power Cost Equalization program was $1.01 per gallon, and the average efficiency of diesel generators for these same utilities was 12.9 kWh per gallon. The average fuel cost per kWh was therefore 7.8 cents. Because the price of Cook Inlet natural gas is very favorable, the fuel cost per kWh for Anchorage area utilities is approximately 2.0 cents. Therefore, the cost of fuel accounts for roughly 5.8 cents per kWh of the difference in power costs between Anchorage and the average rural Alaska community. When trying to explain power cost differentials of 20 to 30 cents or more per kWh, the fuel cost issue is important but is not a dominant factor. Options for reducing the fuel cost component can be grouped in the following categories: increase the efficiency of power generation, increase the efficiency of power distribution, and look for ways to reduce the delivered price of fuel ts Increasing the fuel efficiency of power generation is typically accomplished by purchasing new diesel units that are more efficient than the old ones, by carefully matching the size of the new units with the Options for Reducing Rural Power Costs Working Paper — PCE Blue Ribbon Committee Page 3 village demand for power, and by operating the units so that each one operates as close to maximum load as possible. a. Like the gradual substitution of more fuel efficient cars in the nation’s vehicle fleet, the widespread installation of fuel efficient diesel generators in rural Alaska has most likely been aided by government regulation but is also pushed by market forces as old equipment is periodically replaced by new. In the case of motor vehicles, the “corporate average fuel efficiency” standards imposed by the federal government appears to have hastened the move to more fuel efficient cars. Fuel efficiency standards have also been adopted in PCE regulations. If the actual efficiency of a PCE utility is less than the standard, then the PCE subsidy rate is calculated as though the efficiency standard were met. These standards, which have been in effect since 1993, range from 8 kWh sold per gallon for the smallest utilities to 12 kWh sold per - gallon for the largest. By tying the efficiency standard to kWh sold (rather than kWh generated), the regulation encompasses both generation and distribution efficiency. Somewhat different standards pertain to those few PCE utilities that do not rely entirely on diesel generation. A question that the Committee may wish to consider is whether any change is now warranted in the PCE efficiency standard. When the opportunity arises to replace a diesel generator, it is already the policy of most utilities and of the State to select a generator size that is best matched to the power requirements of the community. This makes sense because diesel generators are most efficient when operated at or near the top of their output range. An emerging development is the production of diesel generators designed to maintain a high level of fuel efficiency throughout a wide range of output levels. AVEC is one utility known to the Division that has been working with a manufacturer on these units and is continuing to purchase them. To the extent they are successful, the importance of carefully matching generator size with community load and the importance of operating units as close as possible to maximum load, will both decline. Options for Reducing Rural Power Costs Working Paper — PCE Blue Ribbon Committee Page 4 2 Increasing the efficiency of power distribution means upgrading distribution systems to reduce line losses, i.e. energy lost in transit between the power plant and the consumer. Because the useful life of a distribution system can often be extended for many years with periodic repairs and piecemeal replacements, upgrades resulting in higher efficiency are not as “automatic” as they tend to be with generator equipment. There are still substantial opportunities in rural Alaska to improve fuel efficiency by upgrading distribution systems, upgrades that might not occur for many more years in the absence of government funding. 3: While the base price of fuel is largely unaffected by the actions of individual consumers, there are purchasing strategies that electric utilities can adopt to help keep the delivered price as low as possible. The key principle that operates in favor of the consumer is competition among fuel suppliers which can be encouraged as follows: a. By pooling together the fuel requirements of multiple consumers, the purchase order volume is increased. Higher purchase volumes generate greater competitive interest among fuel suppliers. b. Bids are widely and aggressively solicited for the combined purchase order. However, as noted by the AVEC representative at the initial Committee meeting, consolidated purchasing must not be taken so far as to eliminate suppliers from the market and end up reducing competition rather than enhancing it. AVEC’s approach is to package enough of its villages in combined fuel orders to gain advantage from higher volumes without driving fuel supply competitors out of the market. Fuel purchasing cooperatives can be formed among electric utilities and other fuel purchasers who presently arrange for their fuel supplies independently: a. The “Western Alaska Fuel Group” is an informal alliance of the following electric utilities: Kotzebue Electric Association Nome Joint Utilities Naknek Electric Cooperative Nushagak Electric Cooperative (Dillingham) Options for Reducing Rural Power Costs Working Paper — PCE Blue Ribbon Committee Page 5 lliamna-Newhalen-Nondalton (INN) Electric Cooperative Attached is a chart showing: 1. Average fuel prices paid by each member over the last 7 years, and 2. Average fuel prices paid by a selection of other, roughly comparable rural utilities over the same period. Within each group, coastal communities and interior communities are shown separately to provide a somewhat better comparison. Because a number of factors determine the fuel price paid by any single utility, the average price difference between the Western Alaska Fuel Group and the selected utilities in the comparison group cannot be taken as proof that cooperative buying works. Probably the best evidence in its favor is that all of the utilities in the Western Alaska Fuel Group have chosen to remain a part of it for over 10 years. In FY95 the combined fuel usage of the members of the Western Alaska Fuel Group was just over 6.0 million gallons. Assuming for illustration a savings from coordinated purchasing of $0.05 per gallon, the total savings are about $300,000 per year. Although Nunat Uquutiit Cooperative, Inc. (NUCI) presently owns only two operational tank farms, it has 42 members located in 26 villages. In 1996 NUCI bundled together the volume requirements of about half its members and purchased fuel on their behalf at $1.27 per gallon. Although the level of savings from the 1996 purchase is difficult to judge, the consolidated purchase was apparently viewed as a success by NUCI members since, in 1997, 39 of the 42 members chose to participate in the joint purchase. The average price obtained by NUCI in 1997 was $1.20 per gallon. Replace diesel generation with alternative energy Most alternative energy concepts are unproven in rural Alaska in terms of durability, reliability, and cost. For example: Options for Reducing Rural Power Costs Working Paper — PCE Blue Ribbon Committee Page 6 1. Wind energy. There were many experiments with wind generators in rural Alaska 10-15 years ago, none of which were successful on a utility scale or over a significant period of time. We are experimenting now with the latest generation of wind technology in Kotzebue and Wales, but it will be several years of testing and evaluation before the Division of Energy could recommend wind energy for rural utilities on a broad scale. Small-scale natural gas development. Economic and geophysical assessments carried out by the State on natural gas or coal bed methane development in rural Alaska have not been promising. Our information suggests that suitable deposits are not likely to be found in close proximity to rural communities, and that the cost of development for gas that is found is not likely to be competitive. While exceptions may yet be found, there is no basis to predict that natural gas will emerge as a competitive fuel source for a significant number of rural villages. The Division has evaluated power plants fueled with biomass in various forms but we have yet to identify a rural community in which this option appears to be competitive. The two main alternative energy technologies with a proven track record in rural Alaska are small hydro and electric energy conservation: a. Hydro prospects are limited in number and unevenly distributed: most are found near the arc that extends from southeast Alaska to the Aleutians. Still, undeveloped prospects remain that could serve rural Alaska communities. The Division is presently involved in the following: i Pyramid Creek in Unalaska and Old Harbor on Kodiak Island. Federal grant funds have already been appropriated to help finance the Old Harbor project. ii. Power Creek near Cordova. The Division is financing preconstruction costs of licensing and design. Federal grant funds have also been provided to help finance Power Creek It is unusual to find a rural hydro project that can support market financing and still result in rate reductions for the affected community. Most of the financial benefit of these projects is therefore tied to the amount of grant or low interest loan financing they are able to attract from the State and federal government. As an alternative for reducing rural power costs. small hydro can often fs Options for Reducing Rural Power Costs Working Paper — PCE Blue Ribbon Committee Page 7 be effective not because its actual cost is low relative to diesel energy but because it can serve as a tangible, one-time vehicle for attracting government subsidy that can then reduce consumer costs throughout the extended life of the project. Electric energy conservation is a form of alternative energy that can pay for itself when the cost to conserve a unit of energy is less than the cost to produce it. The following are among the relevant issues when considering conservation in rural Alaska: iv. Because the cost to produce a kWh of energy is relatively high, electric energy conservation should be exceptionally cost-effective in this environment. Because the present level of electricity consumption in rural villages is already very low, the remaining opportunities for conservation may be limited. While the cost of energy for residential consumers is often considered to be the highest priority, it is most difficult to design and implement an effective energy conservation program for this segment of consumers because there are so many of them, each consuming a relatively small amount of power. Rural utilities are typically not supportive of energy conservation programs except for the purpose of customer relations. Because much of the utility's cost is fixed, lower power sales often means upward pressure on rates. The conserving customer may still benefit, but the utility and its other customers may be left to share higher fixed costs From the rural utility's perspective, conservation goes in the opposite direction of the utility's effort to increase sales and thereby enhance economies of scale. AVERAGE FUEL PRICES (PCE Statistical Reports) LAS FY FY FY FY FY FY 7-Year Pop. 1991 1992 1993 1994 1995 1996 1997 Average* 2,952 Kotzebue Electric Association 0.77 0.81 0.90 0.93 0.86 0.85 0.86 0.85 4,184 Nome Joint Utilities 0.75 0.76 0.73 0.77 0.75 0.71 0.83 0.76 1,482 Naknek Electric Cooperative 0.73 0.74 0.73 0.79 0.71 0.71 0.79 0.74 2,232 | Nushagak Electric Cooperative 0.75 0.74 0.73 0.79 0.70 0.71 0.89 0.76 423 INN Electric Cooperative 1.00 1.09 1.09 1.18 int2 1.14 1.45 1.10° 1,461 Haines Light & Power 0.89 0.70 0.75 0.70 0.65 0.75 0.92 0.77 519 Yakutat, City of 1.19 0.97 1.01 1.00 0.99 0.97 0.99 1.02 2,735 Cordova Electric Cooperative 1.01 0.88 0.88 0.80 0.83 0.86 1.12 0.91 4,317 Unalaska Electric Utility 0.97 0.75 0.81 0.75 0.69 0.70 0.87 0.79 818 King Cove, City of 0.98 0.80 0.77 0.78 0.74 0.76 0.87 0.81 564 = Aniak Light & Power 1.24 1.39 1.39 1.35 Ue 1.24 1.25 1.29 524 McGrath Light & Power 1.24 1.37 1.26 1.27 1.30 1.37 1.47 1.33 Kotzebue, Nome, Naknek, Nushagak, and INN electric utilities constitute the Western Alaska Fuel Group. * 6-year average price computed for INN Electric Cooperative (FY91-96). High price in FY97 due to air delivery / low water. Group Average yn<-— W 6 So 2 3 ATTACHMENT 2 RURAL INTERTIE DATA BASE REPORT MARCH 1997 Rural Alaska Electric Utility Interties A Comprehensive Survey of Existing and Proposed Transmission Lines Serving Utilities Participating in the Alaska Power Cost Equalization Program Prepared for: Alaska Department of Community and Regional Affairs Division of Energy 333 W. 4th Avenue, Suite 220 Anchorage, AK 99501 Prepared by: Neubauer Engineering & Technical Services 8800 Glacier Highway, Suite 217 Juneau, AK 99803-2584 and Foster Wheeler Environmental Corporation 10900 NE 8th Street, Suite 1300 Bellevue, WA 98004-4405 March 1997 CONTENTS 1. INTRODUCTION 1.1 BACKGROUND 1.2 STUDY OBJECTIVE 1.3 REPORT ORGANIZATION 2. METHODOLOGY 2.1 SURVEY LETTER 2.2 TELEPHONE SURVEY 2.3 LITERATURE SEARCH 3. STUDY FINDINGS 3.1 LETTER SURVEY 3.2 TELEPHONE SURVEY 3.3 LITERATURE SEARCH 3.4 CONCLUSION 4. LITERATURE REVIEWED APPENDIX A APPENDIX B APPENDIX C APPENDIX D APPENDIX E APPENDIX F APPENDIX G Mailing List for the Letter Survey Sample Survey Letter Survey Letter Responses List of Telephone Survey Contacts Telephone Survey Records Intertie Data Sheets Annotated Bibliography of Key Documents G:\WP\1468\10395.DOC « 3/20/97 ili TABLES Table 2-1. Key Information Recorded in the Literature Search 2-4 Table 3-1. Proposed Interties Mentioned in the Letter Survey Responses 3-3 Table 3-2. Existing Interties Mentioned in the Telephone Survey Responses 3-4 Table 3-3. Proposed Interties Mentioned in the Telephone Survey Responses 3-6 Table 3-4. Conceptual Interties Mentioned in the Telephone Survey Responses 3-7 Table 3-5. Proposed Interties Identified in the Literature Search 3-12 Table 3-6. Comprehensive List of Proposed Rural Alaska Interties 3-15 G:\WP\1468\10395.DOC 3/20/97 iv 1. INTRODUCTION 1.1 BACKGROUND The delivery of electricity to residences and businesses in rural Alaska is a challenge. The state is very large and rural communities are small and isolated. Villages typically have only a few hundred residences and distances of 50 to 100 miles often separate communities. In addition, residents’ subsistence lifestyles and seasonal employment associated with the fishing or timber industry provide limited cash income to purchase electrical service from utilities. Weather conditions and geography add to the difficulties that rural utilities face. Extreme ranges of air temperature, heavy snowfall, icing, high winds, and permafrost demand special engineering and operation considerations. Mountains, braided rivers, irregular coastlines, and island geography make route selection for power lines difficult and tend to increase the length of routes. The cost of materials delivered to rural communities can be quite high, especially if communities are in remote areas accessible only by boat or plane. The transportation constraints also can restrict the delivery of fuel oil or replacement parts to particular seasons of the year. Due to these conditions, the development of a large transmission line grid to intertie rural communities has not been feasible. Electric utility service to rural communities typically consists of diesel generators or small hydropower plants and distribution power lines to service the community and its immediate environs. Historical patterns to expand electrical service in rural Alaska also have led to schools, community centers, major infrastructure facilities (e.g., airfields and harbors), mills, and seafood processing plants operating their own diesel generators. Thus. several diesel generators may be located in a single community which may not be interconnected by the electrical distribution system. Generally, customers of rural utilities in Alaska pay higher rates compared to residents in the urban areas of the state. To reduce electric rates in rural areas, the State of Alaska established the Power Cost Equalization (PCE) Program in the early 1980s. The Program pays a portion of the electric bills, up to a maximum of 700 kWh per customer per month, for all eligible consumers served by utilities participating in the program. The amount of PCE payments varies according to the rates and cost of energy generation of individual utilities. In addition, studies have been prepared that evaluate electrical source needs of rural communities. Federal and state agencies, as well as individual utilities, have published many G:\WP\1468\10395.DOC e 3/20/97 1-1 reports, especially over the past 15 to 20 years. These studies have forecast electric demand and evaluated alternative generation resources. Proposals to develop rural interties often were studied as a potential solution to lower electric rates. 1.2 STUDY OBJECTIVE The primary purpose of this study is to collect comprehensive information on electric transmission lines that have historically been proposed to intertie rural Alaska utilities. In this study, rural utilities are defined as utilities that have historically participated in the PCE Program. Literature published since 1980 was reviewed and a survey of rural electric utility managers was conducted to augment the published information. Key data on the several existing interties serving rural utilities also were compiled for comparative purposes. This study reviews interties proposed to serve at least one PCE utility. Some of the proposed interties connect two or more PCE utilities. Other proposed interties connect a PCE utility and a non-PCE utility. In addition, a few interties have been proposed to connect community utility systems to the generators of existing or planned manufacturing or mining developments. In this study, no minimum design criteria have been established to define an intertie. Voltage; phasing; pole design; and overhead, underground, or submarine configurations vary. The key selection criterion was whether or not the transmission line would interconnect to a PCE utility. Some proposed transmission lines have been excluded from this study based on their function. The extension of power lines to provide electrical service to new customers or communities has been excluded. These power lines are not true interties, rather they are extensions of distribution service lines. In addition, transmission lines interconnecting proposed generation resources and a particular community have been excluded. As these transmission lines would transport the energy generated at the power plant, they cannot be evaluated separately from the generation resource. They are an integral part of the proposed generation plant and the feasibility of the power plant must consider the engineering, environmental, and financial characteristics of the transmission line. In total, three work products were prepared as part of this study. They include: 1) this report, 2) an annotated bibliography of key documents, and 3) an electronic database of key characteristics of each proposed or existing transmission line. G:\WP\1468\10395.DOC ¢ 3/20/97 1-2 1.3 REPORT ORGANIZATION This report contains four sections and seven appendices. Section 2 describes the research methodology. Section 3 summarizes the findings of the literature search and the survey of utility managers. Section 4 contains a bibliography of literature reviewed. Appendix A is the mailing list for the PCE utilities letter survey. Appendix B contains a sample survey letter and Appendix C contains copies of the survey letter responses. A list of utilities contacted in the telephone survey and the telephone conversation records are in Appendix D and Appendix E, respectively. Appendix F contains the individual data sheets for each of the interties identified in this study. And lastly, Appendix G contains the annotated bibliography of key documents. The electronic database, included with this report on diskette, contains information about the existing and proposed interties and describes the sources of information for this study (letter and telephone survey and literature search). GWP\1468\10395.DOC « 3/20/97 1-3 2. METHODOLOGY The preparation of this report consisted of two major tasks. Task A consisted of a survey of PCE utilities. To obtain information about interties, most of the PCE utilities were contacted at least twice during the survey effort—once by written correspondence and again by telephone. In Task B, the Project Team completed an extensive literature search of interties proposed to serve one or more PCE utilities. Each of these tasks is described in more detail below. 2.1 SURVEY LETTER A survey letter was sent to each of the PCE utility managers to initiate Task A of the study. The list of PCE utilities that received a copy of the survey letter was based on the list of utilities that participated in the PCE Program during 1995. Because the number of utilities participating in the program varies slightly from year to year, staff of the Division of Energy and the “Master Directory of Utilities and Pipeline Carriers” (Alaska Public Utilities Commission 1995) also were consulted. Appendix A lists the PCE utilities that received survey letters. In total, 103 letters were mailed. The survey letter mailed to each of the utility managers explained the objectives of the study commissioned by the Alaska Division of Energy and requested general information about the utility. Questions specifically asked for information about past intertie studies and basic descriptive information concerning existing rural interties. A copy of the survey letter is contained in Appendix B. In response to this letter, 10 PCE utility managers or their representatives prepared a written response. Six utilities responded that no interties existed or were planned for their utility. These utilities included Birch Creek Village Council, City of False Pass, Manley Utility Company (Unicom), Matanuska Electric Association (Unalakleet Division), City of Ruby, and Umnak Power Company. Limited information about proposed interties was provided by the City of King Cove, Tanana Power Company, and the Thorne Bay Public Utility. Alaska Power & Telephone. which serves 13 rural utilities, provided detailed information about several interties proposed to interconnect one or more of their communities. Copies of these response letters and accompanying information are contained in Appendix C. G:\WP\1468\10395.DOC « 3/20/97 2-1 2.2 TELEPHONE SURVEY As follow-up to the survey letter, 79 PCE utilities were contacted by telephone (see Appendix D). Calls were made to each of the utility managers who had not responded to the letter survey. If not available at the time of the call, messages were left for the utility manager and/or the person conducting the surveys was referred to another utility representative. Generally, only one or two attempts were required in order to make contact with the utility manager or other knowledgeable utility worker. In some cases, however, contact with a utility representative was not made despite three telephone calls and messages. In the end, a total of 13 utilities were not surveyed, including: Aniak Light & Power Chignik, City of Coffman Cove Utilities Elfin Cove Electric Utility Far North Utilities Golovin Power Company Koliganek, Village of Koyukuk, City of Kuiggluum Ka!luguia, Inc. (Kwethluk) ee eS SS eS 10. Napaskiak Ircinraq Power Company 11. Nelson Lagoon Electric Cooperative 12. Nushagak Electric Cooperative 13. Takotna Community Association In the telephone survey, each utility representative was asked to briefly describe the distribution. transmission, and generation facilities owned by the utility as well as load growth, operation and maintenance problems, and support services received from the Alaska Division of Energy. Regarding interties, the utility managers were asked about any existing or proposed interties, description of the interties, past studies on interties, and ideas for interties to be considered in the future. A summary of each of the telephone interviews conducted for this study is included in Appendix E. G:\WP\1468\10395.DOC e 3/20/97 De Table 2-1. Key Information Recorded in the Literature Search document reference information brief summary of entire document name of community to receive energy (intertie terminus) name of intertie terminus utility name of community to supply energy (intertie source) name of intertie source utility generation resources for intertie power Fe) | a ee intertie design, length, and voltage 9. intertie construction cost, cost per mile, and cost assumptions 10. proposed or actual year of operation 11. electrical issues of the intertie 12. environmental issues of the intertie 13. financial issues of the intertie 14. public concerns about the intertie Printouts of the individual intertie data sheets are contained in this report (see Appendix F). A _ complete copy of the electronic database has been provided to the Alaska Division of Energy as part of this study. G:\WP\1468\10395.DOC e 3/20/97 2-4 3. STUDY FINDINGS As described in Section 2, this study involved a letter survey, a telephone survey, and a comprehensive literature search. In this chapter, the findings of each of these activities is summarized. 3.1 LETTER SURVEY A total of 99 letter surveys were mailed to the rural electric utilities listed in Appendix A. Only 10 of the utilities responded. These utilities are listed below and copies of their letter survey responses are contained in Appendix C. The information obtained from each letter response is also presented in the intertie data sheets in Appendix F. Alaska Power & Telephone Company Birch Creek Village Council False Pass Electric Association King Cove, City of Manley Utility Company Matanuska Electric Association/Unalakleet Division Ruby, City of Tanana Power Company Thorne Bay Public Utility SC Oe a 10. Umnak Power Company The responses of seven of these utilities were quite short and, except for one utility, did not mention any existing or proposed interties. The comments, however, are of great interest. Birch Creek Village Council expressed concern about keeping trained utility workers in the community and the need for residents to support the proposed construction and operation of an intertie. False Pass Electric Association and Umnak Power Company commented that geographic constraints would not permit the construction of an intertie to their communities. Manley Utility Company, Matanuska Electric Association/Unalakleet Division, the City of Ruby, Tanana Power Company, and Umnak Power Company all stated their interest in the study and their lack of knowledge of past studies concerning potential interties. The Tanana Power Company, however. G:\WP\1468\10395.DOC e 3/20/97 S21 mentioned the possibility of constructing an intertie to the Manley Utility Company, though the response from Manley Utility Company did not mention such an intertie. The letter survey responses from Alaska Power & Telephone Company, the City of King Cove, and Thorne Bay Public Utility were much more detailed. In particular, the Alaska Power & Telephone Company stated its commitment to construct interties, where feasible, to reduce the cost of electricity in rural Alaska. Their response outlined four specific interties the utility is actively pursuing. These interties are described below. e The Black Bear Hydro Project is now operational and the utility proposes to construct an intertie from Klawock to Thorne Bay and Kassan. To date, however, Thorne Bay Public Utility has not committed to a power supply contract. e The utility is evaluating a new technology for a proposed 35 kV submarine cable intertie between Haines and Skagway. The utility is in the process of applying for a loan from the Power Project Fund to demonstrate this new technology. e The utility is evaluating the construction of a proposed 2 MW hydro project near Hollis and an associated intertie between Klawock and Hollis. e The utility is proposing to build an intertie between Tok and Northway. This intertie would allow the diesel generator in Northway to be shut down and used only for backup power. The Alaska Power & Telephone Company also commented that one of the main difficulties in constructing an intertie is the large investment required to start a project. Because rates are based on the first year of operation, incorporation of the large up-front investment into the rate base typically causes rate shock. Alaska Power & Telephone Company submitted a proposal to the Alaska Public Utilities Commission to resolve this problem and allow utilities to levelize their rates over a longer period of time. The Alaska Public Utilities Commission rejected this request. The response from the City of King Cove highlighted the fact that in 1994 the City’s new hydro generation project was completed and had started operation. Associated with the hydro project. the utility mentioned that past studies evaluating a proposed intertie between King Cove and Cold Bay had concluded the intertie would not be feasible. The utility, however, commented that a recently proposed road between the two communities might change the economic feasibility ot this proposed intertie. G:\WP\1468\10395.DOC ¢ 3/20/97 Bo The response from the Thorne Bay Public Utility expressed strong support for the development of an intertie system on Prince of Wales Island. The utility, however, stated that it had not prepared studies of proposed interties. The utility noted the existence of numerous roads on the island, which could be used as intertie rights-of-way and avoid costly clearing of cross-country routes. In addition, the utility described the Alaska Power & Telephone Company’s Black Bear Hydro Project and efforts to develop a Klawock-Thorne Bay-Kassan intertie. Similarly, the utility mentioned Haida Corporation’s proposed hydro project near Hydaburg and an intertie linking Hydaburg with the Hollis-Klawock Intertie near the village of Hollis. In all, eight different proposed interties were mentioned in the responses to the letter survey. These proposed interties are listed in Table 3-1. For ease in comparing this list of interties with other similar lists presented in this chapter, the names of the interties have been formatted such that the names of the two terminal communities are placed in alphabetical order and the names of the interties are placed in alphabetical order. Table 3-1. Proposed Interties Mentioned in the Letter Survey Responses Cold Bay-King Cove Intertie Haines-Skagway [ntertie Hollis-Hydaburg Intertie Hollis-Klawock Intertie Kassan-Thorne Bay Intertie Klawock-Thorne Bay Intertie Manley Hot Springs-Tanana Intertie Northway-Tok Intertie 90) sy re roe | ee 3.2 TELEPHONE SURVEY For the telephone survey, a total of 99 utilities were contacted, excluding the utilities that had responded to the letter survey. The utilities and the telephone contact at each utility are listed in Appendix D. Some of the utilities were contacted more than once for follow-up conversations. Some of the communities served by the Alaska Power & Telephone Company were listed individually, but in the end they were not separately contacted. In addition, telephone contact was not made with a total of 13 utilities, despite three attempts. Notes of each of the telephone conversations are contained in Appendix E and intertie-specific information is also presented in G:\WP\1468\10395.DOC 4/18/97 3-3 the data sheets in Appendix F. Because of the large number of responses, only a general summary of the comments made by the utility representatives is discussed below. Specific interties mentioned by respondents are listed in several tables below. For the most part, the information obtained through the telephone survey was limited. Conversations were generally quite brief and the details of any proposed or existing intertie were sketchy. One problem highlighted by the survey was the frequency with which respondents said they were not aware of historical studies of potential interties. Discussion of interties typically identified the two end-points of the power line. Rarely were the voltage, phasing, or design of the intertie described. Some respondents commented that the intertie would result in the shutdown of small, inefficient generators or improve the operation efficiency of existing generators. Existing Interties The four existing interties mentioned in the telephone survey are listed in Table 3-2, followed by a brief project description of each intertie. All cost information was provided by the Alaska Department of Community and Regional Affairs, Division of Energy. Table 3-2. Existing Interties Mentioned in the Telephone Survey Responses 1. Bethel-Napakiak Intertie 2. Bethel-Oscarville Intertie 3. Dot Lake-Tok Intertie 4. Kobuk-Shungnak Intertie e The Bethel-Napakiak Intertie is an 8-mile, 14 kV, single-wire-ground-return line that started to operate in 1981. e The Bethel-Oscarville Intertie is a 5-mile, 14 kV, conventional single-phased line that was constructed in 1988 at a cost of $281,000. e The Dot Lake-Tok Line was mentioned as a constructed intertie. This 40-mile, 7,200-volt single-phase line functions more as a distribution line to supply energy to Dot Lake. G:\WP\1468\10395.DOC e 4/18/97 3-4 e The Kobuk-Shungnak Intertie is approximately 10.5 miles in length and was originally constructed in 1980 as a demonstration project from an existing telephone line using single-wire-ground-return technology. In 1991, this line was rebuilt as a conventional 14 kV, three-phase line for a cost of $1,350,000. The existing Craig-Klawock Intertie was not mentioned in the telephone survey responses. This 7-mile line was built in 1987 as a 24.9 kV line that would operate at 12.47 kV until the electric load required operation at the higher voltage. The cost to construct this line was $869,000. Proposed Interties When interviewers inquired about proposed transmission line interties, respondents to the telephone survey named many power lines, but provided varying levels of details. In part, this was due to the nature of the interview questions. Utility representatives were asked if they knew of any proposed interties and if they had any ideas for potential interties. As such, the amount of information about the proposed interties separates into a group of proposed power lines and another group of potential or conceptual interties. Table 3-3 is a list of the 34 proposed interties identified in the telephone survey and Table 3-4 is a list of the 83 conceptual interties mentioned. To facilitate review of this information, the community names of the intertie end-points were placed in alphabetical order and the resulting names of the interties were subsequently alphabetized. The majority of the proposed and conceptual interties link two PCE utilities. In some cases, however, the intertie links a PCE utility to a non-PCE utility. Lines also interconnect a community with an existing hydro project or the community served by the hydro project. In other cases, the transmission line links rural communities and the generation source for a proposed mine. Specific details about the proposed interties mentioned in the telephone survey interviews are found in Appendix E. Additional Comments The utility representatives also provided comments on a wide variety of other topics. Some comments were related to utility operation problems, while others voiced utility concerns. As most comments were specific to the concerns of the particular utility, the comments were rarely repeated by other utilities. The themes of the comments, however, were repeated. The following paragraphs briefly discuss these themes. G:\WP\1468\10395.DOC « 4/18/97 5 Table 3-3. Proposed Interties Mentioned in the Telephone Survey Responses Akiachak-Tuluksak Intertie Angoon-Kootznawoo Village Intertie Aniak-Chauthbaluk Intertie Atmautluak-Bethel Intertie Atmautluak-New Kasigluk Intertie Atmautluak-Nunapitchuk Intertie Atmautluak-Old Kasigluk Intertie Bethel-Nyac Mine (proposed) Intertie Bethel-Tuluksak Intertie Bethel-Tuntatuliak Intertie Brevig Mission-Teller Intertie Cold Bay-King Cove Intertie Cordova-Valdez/Silver Lake Intertie Chilkat Valley-Haines Intertie Gustavus-Hoonah Intertie Haines-Kensington Mine (proposed)-Juneau Intertie Haines-Skagway Intertie Hollis-Klawock Intertie Hoonah-Tanakee Springs Intertie Hydaburg-Thorne Bay Intertie Johnny Mountain-Tyee Lake Intertie Kake-Petersburg Intertie Kake-Sitka-Greens Creek Mine-Juneau Intertie Karluk-Larsen Bay Intertie Kassan-Thorne Bay Intertie Klawock-Thorne Bay Intertie Kodiak-Ouzinkie Intertie McGrath-Fairwell Mine (proposed) Intertie Nome-Teller Intertie Northway-Tok Intertie Ouzinkie-Terror Lake Hydro Intertie Red Devil-Sleetmute Intertie St. Michael-Stebbins Intertie Tatitlek- Valdez/Silver Lake Hydro Intertie G:\WP\1468\10395.DOC « 3/21/97 3-6 Table 3-4. Conceptual Interties Mentioned in the Telephone Survey Responses Akhiok-Kodiak Intertie Akhiok-Old Harbor Intertie Akiachak-Akiak Intertie Akiak-Kwethluk Intertie Akutan-Fish Processor Intertie Alaskanuk-Sheldon Point Intertie Allakaket-Hughes Intertie Arctic Village-Fort Yukon Intertie Arctic Village-Venetie Intertie Atqasuk-Barrow Intertie Barrow- Wainwright Intertie Beaver-Fort Yukon Intertie Beaver-Stevens Village Intertie Brevig Mission-Wales Intertie Brevig Mission-Teller Intertie Buckland-Candle Intertie Buckland-Deering Intertie Buckland-OTZ Intertie Buckland-Selewik Intertie Chalkyitsik-Fort Yukon Intertie Chefornak-Kipnuk Intertie Chefornak-Nightmute Intertie Chenega Bay-Tatilek Intertie Chenega Bay-Whittier Intertie Chicken-Eagle Intertie Chignik-Chignik Lake Intertie Chignik-Perryville Intertie Chignik-Port Heiden Intertie Chignik Lake-Chignik Lagoon Intertie Chitina-CVEA Intertie Circle-Central Intertie Clarks Point-Ekuk/Cannery Intertie Cold Bay-False Pass Intertie Cold Bay-Sand Point Intertie Cordova-Katella Mine (proposed) Intertie Council-Nome Intertie Dillingham-Manokotak Intertie Dillingham-Naknek Intertie Diomede-Russia Intertie Egegik-Fish Processor(s) Intertie Egegik-Naknek Intertie Egegik-Pilot Point Intertie Ekwok-Klignick Intertie \\BECALVIN\VOL2\WP\1468\10395T.DOC « 3/20/97 Ekwok-New Stuyakhok Intertie Elfin Cove-Pelican Intertie Emonak-Kotlik Intertie Fort Yukon-Venetie Intertie Galena-Koyukuk Intertie Galena-Ruby Intertie Golovin-White Mountain Intertie Good News-Platinum Intertie Haines-THREA Intertie Igiugig-Fishing Lodges Intertie Igiugig-INN Intertie Iliamna-Pedro Bay Intertie Iliamna-Port Alsworth Intertie Karluk-Larsen Bay Intertie Keys Point-Port Alsworth Intertie Kipnuk-Kwig Intertie Kodiak-Old Harbor Intertie Kongiganak-Kwigillingok Intertie Kotzebue-Russia Intertie Levelock-Naknek Intertie Levelock-New Stuyahok Intertie Manley-Rampart Intertie Manley-Tanana Intertie McGrath-Crooked Creek Mine (proposed) Intertie McGrath-Nikolai Intertie McGrath-Vinasale Valley Mine (proposed) Intertie Minto-Rampart Intertie Newtok-Toksook Bay Intertie Nightmute-Toksook Bay Intertie Nikolai-Nixon Fork Mine (proposed) Intertie Nikolai-Telida Intertie Nome-Teller Intertie Pilot Point-Ugashik Intertie Red Devil-Crooked Creek Mine (proposed) Intertie St. Michael-Stebbins Intertie Shaktoolik-Unalakleet Intertie Stevens Village-Pump Station Intertie Telida-Lake Minchumina Intertie Togiak-Twin Hills Intertie Unalaska-Fish Processor(s) Intertie 3-7 Most utility representatives expressed interest in this study. They were generally unaware of past studies for interties to their community and spoke of the need to expand their diesel generation capacity. The majority of respondents also expressed concern about the cost of energy production. Regarding the cost of energy, utility representatives expressed their concerns over the high cost of utility rates and future funding of the PCE Program. The majority commented on the tremendous cost of diesel, both the large amount of fuel required as well as the cost of transportation. For others, the obstacles to diesel delivery were a constant concern. Examples mentioned include the lack of road access, seasonal land delivery dependent on snow cover, seasonal shipping dependent upon spring and fall flooding, and air delivery. Recognizing that the construction of interties could reduce the cost of energy in the community, a number of utility responses expressed support for the development of interties. Respondents, however, were generally aware of the challenges of constructing power lines in rural Alaska. Specifically, they mentioned the long distances between communities, the lack of road access along proposed intertie routes, the limited load likely to be transported by interties, extreme weather conditions, and the many environmental obstacles to siting a transmission line (e.g, = __ wetlands, muskegs, rivers, lakes, floating moss, permafrost, and mountains). Understanding these constraints and the potential benefits of multiple generation resources, utility representatives also spoke of interties between existing utility generation resources and other local generators operated by the school, community center, major infrastructure facilities, or perhaps local industrial plants. In fact, four PCE utility representatives spoke of potential interties with existing seafood processing plants. These utilities were Akutan Electric Utility, the City of Clarks Point (a cannery in nearby Ekuk), Egegik Light & Power, and Unalaska Electric Utility. Utility representatives viewed the seafood processing plant generators as potential generation resources that could be used to meet community electric demand, especially considering the seasonal use of these local industry generators. They also wondered if the seafood processing plants required all of the capacity of plant generators. In general, the utility representatives spoke of increased efficiency if all community generators were interconnected. G:\WP\1468\10395.DOC 3/20/97 3-8 On the other hand, several utility representatives described their efforts or desires to investigate alternative energy generation resources to reduce electric rates in their communities. This continued interest in the development of alternative generation resources is described below. e Hydropower. A number of utilities are initiating or re-evaluating potential hydropower projects, particularly small run-of-river units. Specific hydropower projects mentioned included those proposed for Goat Lake, Chilkoot Lake, Silver Lake, Chilkat Valley, Indian River, as well as projects to serve Atka and Unalaska. Furthermore, Chitina Electric expressed interest in reconstructing a small hydro project that was abandoned due to collapse of the tunnel. e Thermal. The development of thermal resources (coal or natural gas) is currently under investigation by four utilities: Ipnatchiaq Electric Company, Gwitchyaa Zhee Utility Company, McGrath Light & Power, and Barrow Utilities & Electric Cooperative. e Wind. Two utilities commented that they had recently installed wind generation units. Unfortunately, the plant in White Mountain was shut down due to a lack of wind and the plant in Sheldon Point has closed (because of lack of maintenance at the facility). Other utilities expressed interest in developing wind generation in their communities including Kokhanok Electric, Pelican Utility Company, Kipnuk Light Plant, Tatitlek Electric Utility, Ipnatchiaq Electric Company, Unalaska Electric, and Ungusraq Power Company The representatives of utilities serving the communities of Chilkyitsik, Port Heiden. and Arctic Village all mentioned plans to install wind generation units during 1997. e Mining Generators. Interties to planned generation plants for supplying power to proposed mining projects were mentioned a number of times by utility representatives These generation resources included those associated with the following proposed mines Kensington, Fairwell, Katella, Nyac, Crooked Creek, Nixon Fork, and Vinasale Valley No details were provided to indicate if any of these proposed interties would be feasible Utility generation problems were another major concern. Contacts described their concerms tor the precarious reliability of their electrical system. Many are dependent upon a single diesel generator with no backup generation capacity. For others, the diesel generators need to be shut down during maintenance work, leaving customers without power during an oil change or some similar task. For utilities with run-of-river hydro projects, the lack of water storage results 1n minimal or no generation capacity during cold winter months when electric demand peaks G:\WP\1468\10395.DOC ¢ 4/18/97 3-9 Several utility representatives also commented on operation difficulties. Respondents mentioned a lack of community residents committed to help operate and maintain the electrical system and a lack of community residents willing to contribute their time and skills to repair power lines and other facilities. Voltage fluctuation, line loss, and intermittent ground shorts were problems mentioned, with hopes the State of Alaska could help finance solutions to these problems. In support of state services, several utility representatives praised the Circuit Rider Program. Some representatives also commented on their utility’s inability to adequately serve existing or near-future electric load. Specifically, one utility is unable to meet existing peak loads. For others, the existing generation capacity will not be able to accommodate the increase in electric demand from the ongoing construction of new houses, including Housing and Urban Development (HUD) houses, or a new sewer and water system. To serve these new electric customers, these utilities have an emergency need to purchase additional diesel generation capacity. Environmental regulation was another topic of concern. Comments addressed the burdensome nature of the regulations, the potential inability to comply with the new Environmental Protection Agency (EPA) guidelines for fuel storage, known problems with existing tank farms and waste _ - oil, and the required compliance documentation for regulated activities. One utility representative expressed a need to replace old hazardous transformers and another requested information on the prevention of electrocution of birds by power lines. Summary As stated earlier, the purpose of the letter and telephone surveys was to involve the utilities in the development of a list of existing and potential rural Alaska interties. To this end, the utility responses demonstrate a keen interest in interties, especially if electric rates could be reduced as a result of constructing an intertie. Responses that describe particular intertie proposals also indicate which historical intertie proposals have continued to interest utilities over time. The survey findings indicate that the staff of these rural utilities are primarily occupied by operation problems. As such, it appears that rural electric utilities have difficulty sustaining the long-term planning effort needed to develop an intertie proposal, to conduct environmental and economic evaluations, and to acquire the sums of money required to construct such projects. Thus, the numerous studies funded by the Department of Community and Regional Affairs, Division of Energy and its predecessors have been key to ongoing efforts to develop interties in rural Alaska. G:\WP\1468\10395.DOC « 3/20/97 3-10 3.3 LITERATURE SEARCH In this study, key descriptive information was recorded for each proposed transmission line intertie to PCE utilities identified in the literature search. This information included the two end- points of the intertie plus any intermediary utilities, the names of the two terminal utilities, the preferred engineering design, length, voltage, estimated construction cost, and cost assumptions. General comments were also recorded regarding electrical, environmental, and financial issues, and any known public concerns pertaining to the line. Table 3-5 lists the names of all of the proposed interties identified in the literature search. In total, there are 79 distinct interties listed. Surprisingly, a large number of the interties were not identified in the letter and telephone surveys. This confirms that many utilities are unaware of past studies, as discovered in the utility managers’ survey. A one-page data sheet was prepared for each intertie identified in the documents reviewed. The data sheets are found in Appendix F, where they are arranged in alphabetical order by the name of the intertie. In Appendix F, the names of the interties are defined first by the name of the source utility and then by the name of the terminal utility. At the top of each data sheet, the names of the proposed intertied utilities that have participated in the PCE Program are identified. ~ Some data sheets may lack significant descriptive information because the literature did not describe these intertie characteristics. The varying detail of information on the proposed interties is due to the variety of documents reviewed in the literature search. The five major types of documents were alternative energy generation resources, regional intertie planning documents, reconnaissance or conceptual studies. feasibility studies, and studies evaluating specific project alternatives. Depending upon the purpose and scope of the source document, a particular intertie could be described as a simple intertie between two utilities or the same intertie could be described as a portion of a larger transmission line intertie system. For example, in southwestern Alaska, studies of proposed interties include the Akiachak-Akiak Intertie as well as the Bethel-Nyac Intertie. In fact, the proposed Bethel-Nyac Intertie also would supply energy to the communities G:\WP\1468\10395.DOC e 3/20/97 3-11 Table 3-5. Proposed Interties Identified in the Literature Search Akiachak-Akiak Intertie Akiachak-Bethel Intertie Akiachak-Junction Intertie Akiachak-Kwethluk Intertie Akiak-Bethel Intertie Akiak Tuluksak Intertie Akolmuit-Atmautluak Intertie Akutan-Akutan Trident Seafoods Intertie Akutan-Hydro Project Intertie Alatna-Allakaket Intertie Ambler-Shungnak Intertie Atmautluak Junction-Nunapitchuk Intertie Atmautluak-Bethel Intertie Atqasuk-Barrow Intertie Barrow- Wainwright Intertie Bering River Coal Field-Cordova Intertie Bethel-Junction Intertie Bethel-Kwethluk Intertie Bethel-Napaskiak Intertie Bethel-Nyac Intertie Bethel-Oscarville Intertie Brevig Mission-Teller Intertie Brevig Mission- Wales Intertie Chignik-Chignik Lagoon Intertie Chignik Lagoon-Chignik Lake Intertie Chitina-CVEA Intertie Cold Bay-King Cove Intertie Cordova-Solomon Gulch Hydro Intertie Cordova-Valdez Intertie Cordova- Whittier Intertie Craig-Klawock Intertie Dillingham-Manokotak Intertie Eek-Napaskiak Intertie Elim-Golovin Intertie Elim-Koyuk Intertie Fairbanks-Tanana Intertie Haines-Klukwan Intertie Haines-Skagway Intertie Hoonah-Juneau Intertie Humpy Creek Hydro Project-Larsen Bay Intertie Hydro Project-Dillingham Intertie \\BECALVIN\VOL2\WP\1468\10395T.DOC e 3/20/97 Iliamna-Pedro Bay Intertie Junction-Kwethluk Junction Intertie Juneau-Skagway Intertie Juneau- Whitehorse, Y.T. Intertie Kanahanak-Manokotak Heights Intertie Kassan-Thorne Bay Intertie Kake-Petersburg Intertie Kake-Sitka Intertie Kake-Snettisham Hydro Project Intertie Ketchikan-Hollis Intertie Ketchikan-Metlakatla Intertie Ketchikan-Thorne Bay Intertie Keyes Point-Nondalton Intertie Kiana-Noorvik Intertie Klawock-Thorne Bay Intertie Kokhanok-Newhalen Intertie Koyuk-Shaktoolik Intertie Kwethluk-Kwethluk Junction Intertie Kwethluk Juntion-Napaskiak Intertie Napakiak-Oscarville Intertie Napakiak-Tuntutuliak Intertie Napaskiak-Oscarville Intertie Nunapichuk-Oscarville Intertie Petersburg-Thorne Bay Intertie Port Lions-Terror Lake Hydro Project Intertie St. George-St. George Intertie St. Mary’s-Mountain Village Intertie St. Mary’s-Pilot Point Intertie St. Michael-Stebbins Intertie St. Michael-Unalakleet Intertie Skagway- White Pass Intertie Skagway-Whitehorse, Y.T. Intertie Shaktoolik-Unalakleet Intertie Togiak-Togiak Fisheries Ltd. Intertie Togiak-Twin Hills Intertie Toksook-Tununak Intertie West Creek Hydro Project-Skagway Intertie White Pass, AK-Whitehorse, Y.T. Intertie 3-12 of Akiachak, Akiak, and Tuluksak. The descriptive information for the Bethel-Nyac Intertie is discussed in terms of the longer power line, not its individual segments. Thus, information on the longer interties proposed to serve multiple communities was more general than the information available on a particular segment of the intertie. In addition, this naming convention can account for multiple names for the same intertie segment. Since the literature searched spanned a period of over 15 years, more than one report may have been published during this period on a particular proposed intertie. For example, a line could be described only briefly as a project alternative in one report or described in great detail in a project-specific feasibility report. Side by side, the information from each of the reports presents a planning history of the refinement of the proposed intertie. For this reason, individual intertie data sheets have been prepared for each source document (see Appendix F). With the publication of more detailed studies of proposed interties, the design of the transmission line often would change. For example, in one study a line might be described as a long submarine cable. Later it might be described as a shorter submarine cable with overhead wood pole segments at either end. Similarly, a proposed line might be evaluated initially as a 69 kV line and later as a 34 kV line. Or, the intertie might originally be described as a single-wire- ground-return power line and later studies might evaluate the line based on an assumed three- phase conventional power line. The effect of this evolving design process tends to increase the accuracy of construction cost estimates. Examination of the construction cost estimates for the proposed interties revealed a wide range of variables comprising conceptual-level and feasibility-level estimates. A primary difference between cost estimates was the actual materials and equipment included in the estimate. For example, the transmission line costs may have been included in the estimate, but the cost of substation equipment or transition stations perhaps were omitted. Often the conceptual-level estimates were based on generalized cost-per-mile estimates as opposed to anticipated design requirements assumed in feasibility-level estimates. The costs for administration, project management, overhead fees, contingency fees, and project loan interest during the construction of the project may or may not have been included in cost estimates. In addition, the year of the cost estimate was often not defined, so the date of the publication must be used to define an approximate year. For these reasons, defined cost assumptions for a specific intertie are recorded on each of the intertie data sheets (see Appendix F). G:\WP\1468\10395.DOC ¢ 3/20/97 3-13 3.4 CONCLUSION With the completion of this study, many more proposed interties were identified than were originally anticipated at the start of work. The primary reason was the lack of significant overlap between the several lists of proposed interties (see Tables 3-3, 3-4, and 3-5). In the letter survey, eight proposed interties were described. The telephone survey identified 34 proposed and 83 conceptual interties. In contrast, 79 interties were defined in the documents reviewed in the literature search. The sum of these numbers is 204, but elimination of the duplicate listings reduces the list to 174 interties. Table 3-6 is a comprehensive list of these interties proposed to link rural Alaska utilities. The feasibility of constructing any one of these proposed interties in the near future, however, can only be determined by reviewing all historical studies, conducting more detailed engineering and environmental analyses, and systematically developing comprehensive cost estimates. G:\WP\1468\10395.DOC e 3/20/97 3-14 Table 3-6. Comprehensive List of Proposed Rural Alaska Interties Akhiok-Kodiak Intertie Akhiok-Old Harbor Intertie Akiachak-Akiak Intertie Akiachak-Bethel Intertie Akiachak-Junction Intertie Akiachak-Kwethluk Intertie Akiachak-Tuluksak Intertie Akiak-Bethel Intertie Akiak-Kwethluk Intertie Akiak-Tuluksak Intertie Akolmuit-Atmautluak Intertie Akutan-Akutan Trident Seafoods Intertie Akutan-Fish Processor Intertie Akutan-Hydro Project Intertie Alaskanuk-Sheldon Point Intertie Alatna-Allakaket Intertie Allakaket-Hughes Intertie Ambler-Shungnak Intertie Angoon-Kootznawoo Village Intertie Aniak-Chauthbaluk Intertie Arctic Village-Fort Yukon Intertie Arctic Village-Venetie Intertie Atmautluak-Bethel Intertie Atmautluak-New Kasigluk Intertie Atmautluak-Nunapitchuk Intertie Atmautluak-Old Kasigluk Intertie Atmautluak Junction-Nunapitchuk Intertie Atqasuk-Barrow Intertie Atqasuk-Barrow Intertie Barrow- Wainwright Intertie Beaver-Fort Yukon Intertie Beaver-Stevens Village Intertie Bering River Coal Field-Cordova Intertie Bethel-Junction Intertie Bethel-Kwethluk Intertie Bethel-Napaskiak Intertie Bethel-Nyac Mine (proposed) Intertie Bethel-Oscarville Intertie Bethel-Tuluksak Intertie \\BECALVIN\VOL2\WP\1468\10395T.DOC ¢ 3/21/97 3-15 Page 1 of 3 Bethel-Tuntatuliak Intertie Brevig Mission-Teller Intertie Brevig Mission-Wales Intertie Buckland-Candle Intertie Buckland-Deering Intertie Buckland-OTZ Intertie Buckland-Selewik Intertie Chalkyitsik-Fort Yukon Intertie Chefornak-Kipnuk Intertie Chefornak-Nightmute Intertie Chenega Bay-Tatilek Intertie Chenega Bay- Whittier Intertie Chicken-Eagle Intertie Chignik-Chignik Lagoon Intertie Chignik-Chignik Lake Intertie Chignik-Perryville Intertie Chignik-Port Heiden Intertie Chignik Lagoon-Chignik Lake Intertie Chilkat Valley-Haines Intertie Chitina-CVEA Intertie Circle-Central Intertie Clarks Point-Ekuk/Cannery Intertie Cold Bay-False Pass Intertie Cold Bay-King Cove Intertie Cordova-Katella Mine (proposed) Intertie Cordova-Solomon Gulch Hydro Intertie Cordova-Valdez/Silver Lake Intertie Cordova- Whittier Intertie Council-Nome Intertie Craig-Klawock Intertie Dillingham-Manokotak Intertie Dillingham-Naknek Intertie Diomede-Russia Intertie Eek-Napaskiak Intertie Egegik-Fish Processor(s) Intertie Egegik-Naknek Intertie Egegik-Pilot Point Intertie Ekwok-Klignick Intertie Ekwok-New Stuyakhok Intertie Table 3-6. Comprehensive List of Proposed Rural Alaska Interties Elfin Cove-Pelican Intertie Elim-Golovin Intertie Elim-Koyuk Intertie Emonak-Kotlik Intertie Fairbanks-Tanana Intertie Fort Yukon-Venetie Intertie Galena-Koyukuk Intertie Galena-Ruby Intertie Golovin-White Mountain Intertie Good News-Platinum Intertie Gustavus-Hoonah Intertie Haines-Kensington Mine (proposed)-Juneau Intertie Haines-Klukwan Intertie Haines-Skagway Intertie Haines-THREA Intertie Hollis-Hydaburg Intertie Hollis-Klawock Intertie Hoonah-Juneau Intertie Hoonah-Tanakee Springs Intertie Humpy Creek Hydro Project-Larsen Bay Intertie Hydaburg-Thome Bay Intertie Igiugig-Fishing Lodges Intertie Igiugig-INN Intertie Iliamna-Pedro Bay Intertie Iliamna-Port Alsworth Intertie Johnny Mountain-Tyee Lake Intertie Junction-Kwethluk Junction Intertie Juneau-Skagway Intertie Juneau- Whitehorse, Y.T. Intertie Kake-Petersburg Intertie Kake-Sitka-Greens Creek Mine-Juneau Intertie Kake-Snettisham Hydro Project Intertie Kanahanak-Manokotak Heights Intertie Karluk-Larsen Bay Intertie Kassan-Thorne Bay Intertie Kake-Sitka Intertie Ketchikan-Hollis Intertie Ketchikan-Metlakatla Intertie \\BECALVIN\VOL2\WP\1468\10395T.DOC 3/21/97 3-16 Page 2 of 3 Ketchikan-Thorne Bay Intertie Keyes Point-Nondalton Intertie Keyes Point-Port Alsworth Intertie Kiana-Noorvik Intertie Kipnuk-Kwig Intertie Klawock-Thorne Bay Intertie Kodiak-Old Harbor Intertie Kodiak-Ouzinkie Intertie Kokhanok-Newhalen Intertie Kongiganak-Kwigillingok Intertie Kotzebue-Russia Intertie Koyuk-Shaktoolik Intertie Kwethluk-Kwethluk Junction Intertie Kwethluk Junction-Napaskiak Intertie Levelock-Naknek Intertie Levelock-New Stuyahok Intertie Manley-Rampart Intertie Manley-Tanana Intertie McGrath-Crooked Creek Mine (proposed) Intertie McGrath-Fairwell Mine (proposed) Intertie McGrath-Nikolai Intertie McGrath-Vinasale Valley Mine (proposed) Intertie Minto-Rampart Intertie Napakiak-Tuntutuliak Intertie Napakiak-Oscarville Intertie Napaskiak-Oscarville Intertie Newtok-Toksook Bay Intertie Nightmute-Toksook Bay Intertie Nikolai-Nixon Fork Mine (proposed) Intertie Nikolai-Telida Intertie Nome-Teller Intertie Northway-Tok Intertie Nunapichuk-Oscarville Intertie Ouzinkie-Terror Lake Hydro Intertie Petersburg-Thorne Bay Intertie Pilot Point-Ugashik Intertie Port Lions-Terror Lake Hydro Project Intertie Table 3-6. Comprehensive List of Proposed Rural Alaska Interties Page 3 of 3 Red Devil-Crooked Creek Mine (proposed) Stevens Village-Pump Station Intertie Intertie Tatitlek-Valdez/Silver Lake Hydro Intertie Red Devil-Sleetmute Intertie Telida-Lake Minchumina Intertie Shaktoolik-Unalakleet Intertie Togiak-Togiak Fisheries Ltd. Intertie Skagway- White Pass Intertie Togiak-Twin Hills Intertie Skagway-Whitehorse, Y.T. Intertie Toksook-Tununak Intertie St. George-St. George Harbor/Air Field Intertie Unalaska-Fish Processor(s) Intertie St. Mary’s-Mountain Village Intertie West Creek Hydro Project-Skagway Intertie St. Mary’s-Pilot Point Intertie White Pass, AK-Whitehorse, Y.T. Intertie St. Michael-Stebbins Intertie St. Michael-Unalakleet Intertie \\BECALVIN\VOL2\WP\1468\10395T.DOC ¢ 3/21/97 3-17 4. LITERATURE REVIEWED Alaska Department of Community and Regional Affairs, Division of Energy. 1994. Economic Comparison of Power Generation Alternatives for Thorne Bay, Alaska (Draft). Steve Colt Institute of Social and Economic Research, University of Alaska, Anchorage in collaboration with Mark A. Foster and Associates. Anchorage, Alaska. June 1, 1994. Alaska Energy Authority. 1990. Akutan Hydroelectric Feasibility Assessment. Ott Engineering, Inc. in association with Dryden and LaRue, Inc. Anchorage, Alaska. June 1990. Alaska Energy Authority. 1990. Status Sheet for Kodiak Island Village Utility Council. October 5, 1990. Alaska Energy Authority. 1991-1996. Annual Reports, 1990-1995. Anchorage, Alaska. 1991, 1992, 1993, 1994, 1995, 1996. Alaska Office of the Governor. Regional Electric Utilities in Rural Alaska. Office of the Governor, Division of Policy. Juneau, Alaska. July 1989. Alaska Power Administration. 1981. Juneau-Hoonah Transmission Line: Reconnaissance Evaluation. Anchorage, Alaska. December 1981. Alaska Power Authority. 1980. Akutan Corps of Engineers Site No. 4. Robert W. Retherto rd Associates and International Engineering Co., Inc. Anchorage, Alaska. March 1980. Alaska Power Authority. 1980. Reconnaissance Assessment of Energy Alternatives, Chilkat River Basin Region. CH2M HILL. Anchorage, Alaska. February 1980. Alaska Power Authority. 1980. Reconnaissance Study of Lake Elva and Alternate Hydroelectric Power Potentials in the Dillingham Area. Robert W. Retherford Associates. Anchorage. Alaska. February 1980. Alaska Power Authority. 1980. Reconnaissance Study of the Kisaralik River Hydroelectric Power Potential and Alternate Electric Energy Resources in the Bethel Area. Robert W Retherford Associates and Arctic District of International Engineering Company. Inc Anchorage, Alaska. March 1980. Alaska Power Authority. 1981. Addendum to Reconnaissance Report on Alternatives for the Haines-Skagway Region. R.W. Beck and Associates, Inc. Anchorage, Alaska. April 1981. Alaska Power Authority. 1981. Black Bear Lake Project: Feasibility Report. Harza Engineering Company and CH2M HILL Northwest, Inc. Anchorage, Alaska. October 1981. G:\WP\1468\10395.DOC 3/20/97 4-1 —_ Alaska Power Authority. 1981. Reconnaissance Study of Energy Requirements and Alternatives for Takotna. International Engineering Company, Inc. Robert W. Retherford Associates, Arctic Division of International Engineering Company, Inc. Anchorage, Alaska. May 1981. Alaska Power Authority. 1981. Transmission Intertie Kake-Petersburg, Alaska: A Reconnaissance Report. Robert W. Retherford Associates. Anchorage, Alaska. January 1981. Alaska Power Authority. 1982. Bristol Bay Regional Power Plan Detailed Feasibility Analysis, Interim Feasibility Assessment, Volume 1—Report. Stone & Webster Engineering Corporation. Anchorage, Alaska. July 1982. Alaska Power Authority. 1982. Cordova-Valdez DC Transmission Tie Line Feasibility Report. Alcat Engineering. Anchorage, Alaska. May 1, 1982. Alaska Power Authority. 1982. Haines-Skagway Region Feasibility Study, Volume 1—Report. R.W. Beck and Associates, Inc. Anchorage, Alaska. June 1982. Alaska Power Authority. 1982. Haines-Skagway Region Feasibility Study, Volume 3— Addendum. R.W. Beck and Associates, Inc. Anchorage, Alaska. December 1982. Alaska Power Authority. 1982. Kake-Petersburg Intertie Interim Report. Ebasco Services, Inc. with Alaska Economics, Inc. and Polarconsult, Inc. Anchorage, Alaska. October 1982. - Alaska Power Authority. 1982. Reconnaissance Study of Energy Requirements and Alternatives: Main Report. Northern Technical Services and Van Gulik and Associates. Anchorage, Alaska. July 1982. Alaska Power Authority. 1982. Reconnaissance Study of Energy Requirements and Alternatives for Tanunak. Northern Technical Services and Van Gulik and Associates. Anchorage. Alaska. July 1982. Alaska Power Authority. 1982. Reconnaissance Study of Energy Requirements and Alternatives for Toksook Bay. Northern Technical Services and Van Gulik and Associates. Anchorage, Alaska. July 1982. Alaska Power Authority. 1983. Bristol Bay-Bethel Interregional Power Plan, Preliminary Assessment. Stone and Webster Engineering Corporation. Anchorage, Alaska. April 1983. Alaska Power Authority. 1983. Haines-Skagway Region Feasibility Study, Volume 4— Supplemental Investigations. R.W. Beck and Associates, Inc. Anchorage, Alaska. December 1983. Alaska Power Authority. 1983. Kake-Petersburg Intertie Mixed Overhead/Underground Transmission Line Reconnaissance Report. Ebasco Services, Inc. Anchorage, Alaska November 1983. G:\WP\1468\10395.DOC @ 3/20/97 4-2 Alaska Power Authority. 1983. Kake-Petersburg Intertie Project Underground Transmission Line Alternative: Phase I-Preliminary Technical Analysis Report. Ebasco Services, Inc. Anchorage, Alaska. July 29, 1983. Alaska Power Authority. 1983. Kodiak Island Borough Electrification Planning Assessment, Final Report—Summary. Northern Technical Services and Fryer Pressley Engineering. Anchorage, Alaska. May 1983. Alaska Power Authority. 1983. Kodiak Island Borough Electrification Planning Assessment, Final Report. Northern Technical Services and Fryer Pressley Engineers. Anchorage, Alaska. May 1983. Alaska Power Authority. 1983-1990. Annual Reports, 1982-1989. Anchorage, Alaska. 1983, 1984, 1985, 1986, 1987, 1988, 1989, 1990. Alaska Power Authority. 1984. Bethel Area Power Plan Feasibility Assessment, Regional Report. Harza Engineering Company. Anchorage, Alaska. April 1984. Alaska Power Authority. 1984. Findings and Recommendations: Angoon Hydropower. Anchorage, Alaska. December 1984. Alaska Power Authority. 1984. Kake-Petersburg Intertie Draft Feasibility Report Supplement. Ebasco Services, Inc. with R and M Consultants, Inc. and Alaska Economics, Inc. Anchorage, Alaska. January 1984. Alaska Power Authority. 1984. Reconnaissance Study of Energy Requirements and Alternatives, Elfin Cove. ACRES. Anchorage, Alaska. February 1984. Alaska Power Authority. 1984. Tyee-Kake Intertie Project: Detailed Feasibility Analysis, Final Report. Ebasco Services, Inc. Anchorage, Alaska. March 1984. Alaska Power Authority. 1985. Akutan Hydroelectric Power Project. Polarconsult Alaska, Inc. Anchorage, Alaska. November 1985. Alaska Power Authority. 1985. Findings and Recommendations: Bethel Area Power Plan. Anchorage, Alaska. December 1985. Alaska Power Authority. 1985. Metlakatla Power Alternatives: Findings and Recommendations. Anchorage, Alaska. May 1985. Alaska Power Authority. 1986. Cordova Power Plan: Findings and Recommendations. Anchorage, Alaska. October 1, 1986. Alaska Power Authority. 1986. Description of the Proposed Craig-Klawock Transmission Intertie on Prince of Wales Island, Alaska. Harza Engineering Company. Anchorage, Alaska. March 1986. Alaska Power Authority. 1986. Findings and Recommendations: Bethel Area Power Plan. Anchorage, Alaska. February 3, 1986. G:\WP\1468\10395.DOC ¢ 3/20/97 4-3 Alaska Power Authority. 1986. Findings and Recommendations: Grant Lake Hydroelectric Project and Dave’s Creek-Seward Transmission Line. Anchorage, Alaska. September 1986. Alaska Power Authority. 1986. Manokotak Transmission Line Study. Polar Consult, Consulting Engineers and Planners. Anchorage, Alaska. June 26, 1986. Alaska Power Authority. 1986. Metlakatla Power Alternatives: Findings and Recommendations. Anchorage, Alaska. May 1986. Alaska Power Authority. 1987. Black Bear Lake Hydroelectric Project: Feasibility Report Update. Harza Engineering Company. Anchorage, Alaska. February 1987. Alaska Power Authority. 1988. Dillingham-Manokotak Electrical Study (Final). Fryer/Pressley Engineering, Inc. Anchorage, Alaska. November 1, 1988. Alaska Power Authority. 1988. Klukwan Proposed Walker Lake Hydroelectric Project: Reconnaissance Findings and Recommendations. Anchorage, Alaska. July 1988. Alaska Power Authority. 1989. St. George Electrical System Study. Polarconsult Alaska, Inc. Anchorage, Alaska. April 1, 1989. Alaska Power Authority. 1996. Findings and Recommendations: Bristol Bay Power Plan. Anchorage, Alaska. February 3, 1996. Alaska Systems Coordinating Council and the State of Alaska Department of Community and Regional Affairs, Division of Energy. 1995. Selected Alaskan Electric Utilities at a Glance. Anchorage, Alaska. August 1995. Bering Strait REAA School District. 1980. Bering Strait Energy Reconnaissance. Holden and Associates Planning Consultants. Nome, Alaska. June 1980. City of Akutan. 1980. Akutan Hydropower: Preliminary Design Report. Ott Water Engineers Inc. and Thomas D. Humphrey, P.E., Co. Akutan, Alaska. September 1980. Department of Community and Regional Affairs. 1986. Feasibility Study: Kake-Petersburg Intertie. R.W. Beck and Associates, Inc. Anchorage, Alaska. June 1986. Department of Community and Regional Affairs. 1995. Utility Improvements Grant Application. City of Chignik. Anchorage, Alaska. September 24, 1995. Department of Community and Regional Affairs. 1996. Power Intertie Analysis. Haight and McLaughlin Consulting Engineers. Anchorage, Alaska. January 1, 1996. Ebasco. 1984. Juneau 20-Year Power Supply Plan. Prepared for the Alaska Electric Light and Power Company, Glacier Highway Electric Association, Alaska Power Administration. and the Alaska Power Authority. Bellevue, Washington. December 1984. G:\WP\1468\10395.DOC ¢ 3/20/97 4-4 Kodiak Island Borough. 1980. Reconnaissance of Micro-Hydroelectric Potential: Akhiok Village, Kodiak. Jack West Associates and Fryer, Pressley, Elliott Consulting Engineers. Kodiak, Alaska. September 26, 1980. Kokhanok Village Council. 1985. Feasibility Study: Kokhanok to Newhalen Electrical Tie Line. Dryden and LaRue Consulting Engineers, Inc. Kokhanok, Alaska. October 1985. Letter. April 13, 1988. Edwin T. Gonin of Bering Strait School District to Mr. Bob LeResche of Alaska Power Authority. Subject: Teller-Brevig Mission Transmission Line. Letter. September 6, 1991. Nome Joint Utility System to Alaska Power Authority. Subject: Teller-Nome Transmission Line. Letter. June 17, 1992. Alaska Village Electric Cooperative, Inc. Mark and Teitzel to Alaska Energy Authority, Tim Peters. Subject: Regional Planning: St. Mary’s 69 kV Grid. Letter Report. January 31, 1983. Robert E. Dryden of Dryden and LaRue Consulting Engineers, Inc. to Iliamna-Newhalen Electric Cooperative. Subject: Initial Feasibility- Interconnection of Pedro Bay and Kokhanok with Iliamna-Newhalen Electric Cooperative. Memo. 1988. Eric Marchegiani to Brent Petrie, both of Alaska Power Authority. April 1988. North Slope Borough. 1980. North Slope Regional Energy Use and Resource Assessment Study. Battelle Pacific Northwest Laboratories. Barrow, Alaska. April 1980. North Slope Borough. 1981. Long Range Utility Master Plan for Anaktuvuk Pass, Atkasook. Barrow, Kaktovik, Nuiqsut, Point Hope, Point Lay, and Wainwright (Draft). Robert W. Retherford Associates and Arctic District of International Engineering Company, Inc. Barrow, Alaska. March 1981. North Slope Borough. 1981. Right-of-Way Application and Environmental Analysis for Proposed Barrow-Atqasuk- Wainwright Powerline. Howard Grey & Associates, Inc. Barrow, Alaska. May 1981. North Slope Borough. 1981. Transmission Line Barrow-Atqasuk-Wainwright: Project Planning Report. Jack West Associates, Robert W. Retherford Associates, and Howard Grey Associates. Barrow, Alaska. September 1981. Northern Canada Power Commission. 1983. Whitehorse-Skagway Transmission Line Feasibility Study. FMS Engineers. Whitehorse, Yukon Territory, Canada. September 1983. Reeve Engineers. 1983. King Cove and Cold Bay Tie-Line “First Look” Feasibility Study. Anchorage, Alaska. June 30, 1983. G:\WP\1468\10395.DOC 3/20/97 4-5 U.S. Army Corps of Engineers, Alaska District. 1984. Chignik, Alaska Draft Small Hydro- Power Interim Feasibility Report and Draft Environmental Impact Statement. Anchorage, Alaska. July 1, 1984. U.S. Army Corps of Engineers, Alaska District. 1984. Small-Scale Hydropower for Anaktuvuk Pass, Alaska-Letter Report. Anchorage, Alaska. September 1984. U.S. Department of Energy, Alaska Power Administration. 1981. Preliminary Evaluation of Hydropower Alternatives for Chitina, Alaska. Anchorage, Alaska. February 1981. U.S. Department of Energy, Alaska Power Administration. 1981. Juneau-Hoonah Transmission Line: Reconnaissance Evaluation. Anchorage, Alaska. December 1981. U.S. Department of Energy, Alaska Power Administration. 1982. Southeast Alaska Intertie DC Transmission System. Teshmont Consultants, Inc. Anchorage, Alaska. 1982. G:\WP\1468\10395.DOC 3/20/97 4-6 ATTACHMENT 3 RURAL INTERTIE STUDY EXCERPT FROM CONSULTANT COMMENTS MAY 1996 2 oe AR onaneons omen n na mennne Page 3, Rural Intertie Study Status, Richard Emerman, May 4, 1996 . “Intertie studies that have been conducted on your behalf or by your utility staff for your village.” ° “Basic descriptive information on all existing rural interties (if any) between [your community] and adjacent villages, including location, construction cost, length, voltage, and design.” Approximately 25 percent of the communities responded in writing or by telephone to the request for information. We have, however, initiated telephone calls to all of the villages to further pursue this information. More importantly, we have communicated with the utility managers who have the greatest likelihood of pursuing or planning for such interconnections in the future. These utilities include Alaska Village Electric Cooperative Association (AVEC), Tlingit-Haida Regional Electric Authority, Alaska Power and Telephone Company, and INN Electric Cooperative. The telephone follow-up to those villages that did not respond to the questionnaire should be completed by May 17, 1996. Information obtained from the utilities is being recorded by Memorandum to File when by telephone, or by separate file for information sent by mail or extracted from their utility files. i ati a. A. The majority of the studies are very dated, most having been accomplished prior to | 1985. Furthermore, there are very few studies that specifically address interconnections of YY villages. Instead the studies were conducted for the purpose of evaluating energy alternatives for a single village or group of villages, and the interconnection is more of an incidental element of the overall study. In addition, because the transmission line costs are generally only a fraction of the total cost of the energy project being studied, the cost estimate for the transmission line portion of the total estimate is rarely more then a single line item with little backup. B. There are very few existing interconnected villages in rural Alaska from which to obtain transmission line cost information. There are a few long distribution (in the 10 mile range) lines but their costs are hardly indicative of what true transmission line costs would be in the bush. Many of the larger utilities have good transmission line cost information, but they are usually of a higher capacity then what would be needed in rural Alaska and are in locations more conducive to economical construction then is usually the case in rural Alaska. C. There is a large disparity in the range of transmission line cost estimates depending on which engineering firm was conducting the estimate. D. Very few of the rural utilities are planning interconnections and hence the utility managers survey has not turned up much new information. The most aggressive utilities are those which have a surplus hydropower energy available to displace existing diesel Page 4, Rural Intertie Study Status, Richard Emerman, May 4, 1996 ~ generation. Most utility managers perceive little advantage in interconnecting to villages that are already being served by central station diesel generation. The large majority of the villages throughout Alaska are presently being supplied by diesel power with little variable cost from one village to the next. There may be some economy of scale by eliminating generation at one village in deference to generation at another, but probably not enough to warrant the debt service associated with a transmission line, additional generation at the supply source, and O & M cost to maintain standby reserves at the receiving village. E. Use of waste heat from diesel generation for district heating is often incompatible with the economic advantage that comes from interconnection. As an example, fifteen of the 46 villages presently in the AVEC system have waste recapture systems that are used for station heating and for district heating of major facilities within the villages. It is desirable to utilize waste heat at all of the villages, but the transmission line alternative would preclude the use of waste heat at those villages with no generation. Furthermore, if there were not a full utilization of waste heat at the generation source, then the overall efficience of energy utilization within the participating communities would diminish. A transmission line to a village where there is presently a waste heat recapture program would result in the preclusion of the waste heat capital expenditure, and the acquisition of new heating and fuel to replace the lost heat. I hope that the above status report addresses your needs. If you have any additional questions on the program please call me at 786-5728. In the mean time it would be beneficial to meet with you at your earliest convenience to discuss the ongoing study in light of my accepting a new job. I suggest a meeting on May 8, 1996 as both Betsy Minden and Mike Carson will be available in Anchorage on that date. Please let me know if you feel such a meeting would be beneficial or if you would rather have a conference call at your convenience. Sincerely, s_-P YH Eric P. Yould Manager, Alaska Operations cc Betsy Minden Mike Carson ATTACHMENT 4 ENERGY AUTHORITY REVIEW OF PROPOSED INTERTIE NOME TO TELLER AND BREVIG MISSION JULY 1991 State of A-:as«a N Waiters F:cKel Scverccr Alaska Energy Authority A Public Corporation July 9, 1991 Mr. Richard Blodgett Teller Power Company Teller, Alaska 99778 Subject: Intertie from Nome to Teller and Brevig Mission Dear Mr. Blodgett: Your letter to Governor Hickel of March 27, 1991 regarding the proposed intertie from Nome to Teller and Brevig Mission was referred to me for consideration. The long term benefits that could result from the project appear to be: 1) The cost of power in Teller and Brevig Mission could be reduced because power production costs in Nome are lower. This cost — - advantage is due to lower delivered fuel costs and better economies of scale. 2) Lower power costs in the region would favor economic development, especially mining. Your letter refers to the immense mineral potential in the Lost River area. To get an initial feel for the project, I asked the Authority staff for a rough estimate of the costs and benefits that would probably come out if a feasibility study were undertaken. Following is an outline of the initial staff review. Project Definition and Cost There are two ways of looking at the project: one is to build the line with enough capacity to allow Nome to provide a significant share of the power requirements of future mining operations; the other is to build a much smaller line that would provide power to Teller and Brevig Mission, but would not have the capacity to serve future mining loads. To meet only the expected loads in Teller and Brevig Mission, the minimum voltage would be 25 kV/14.4 kV. This is estimated to be sufficient until combined loads exceed 500 kW. (The combined peak load is presently estimated at 200 kW.) An order of magnitude estimate for new overhead line constructed at this voltage is $100,000 per mile (assuming Davis-Bacon wages were not required), which implies that the minimum cost from Nome to Teller would be in the neighborhood of $7 million. For the connection between Teller and Brevig Mission, armored © PO.BoxAM Juneau, Alaska 99811 (907) 465-3575 MH PO Raw 40NR4O =—-704 East Tudor Road Anchorage, Alaska 99519-0869 (907) 561-7877 submarine cable is estimated to cost at least $40 per foot, or roughly $1 million altogether. A line with enough capacity to serve significant mining loads would have to be constructed for a fairly high voltage level, possibly 138 kV. Our most recent cost estimate for a new 138 kV overhead line between Healy and Fairbanks is roughly $500,000 per mile (in 1991 dollars, and including provision for Davis-Bacon wages). A 138 kV line between Nome and Teller, excluding extension to Brevig Mission and beyond, would therefore be likely to cost in the neighborhood of $35 million. Minimum Benefit Needed for Project Feasibility Regarding the smaller, $7 million line from Nome to Teller, an annual capital cost expressed in 1991 dollars can be estimated assuming a 35 year life and a 3% real interest rate (i.e. interest over and above inflation). The annual capital cost derived in this way is about $325,000. The average annual energy requirement in Teller today is roughly 700,000 kWh. Assuming the average energy requirement in Teller over the next 35 years is twice the level today, then savings of about $.23 per kWh (in 1991 dollars) would be needed to offset the intertie capital cost. If annual operations and maintenance cost of the intertie amounted to 1% of the capital cost (i.e. $70,000 per year), then an additional $.05 per kWh of savings would be needed to reach breakeven. It is difficult to see how the numbers can come together for the project defined in this way. A fuel price differential as high as $.80 per gallon (based on Nome and Teller reported prices in FY 89) will only produce a savings of $.08 per kWh, and other long-run savings in capital and O&M cannot raise the total up to the $.28 per kWh range. If loads grew much beyond the 1.4 million kWh used in the example, a more expensive line with greater capacity would be needed to carry the additional power. The $1 million cable from Teller to Brevig Mission could be considered as an extension of the $7 million Nome-Teller line, or by itself as a stand-alone project. If considered an extension of the proposed Nome- Teller line, then the estimated total project cost would be $8 million, and the annual capital cost derived as above (3% real interest, 35 years) would be roughly $375,000. $80,000 per year is added if annual O&M costs are 1% of the capital cost. The average annual energy requirement today in Teller and Brevig Mission combined is about 900,000 kWh. Again, assuming the average energy requirement over the next 35 years were double today's level, then savings of about $.25 per kWh (in 1991 dollars) would be needed to offset the combined capital and 0&M costs of the project. While this is a little better than the $.28 per kWh estimated benefit needed for the Nome-Teller line alone, it is still out of reach. Considering the Teller-Brevig Mission cable as a stand-alone project, the annual capital and 0&M cost defined as above would be about $55,000. The annual energy requirement in Brevig Mission today is about 170,000 kWh. Assuming average demand will be twice today's level, savings of $.16 per kWh (again in 1991 dollars) would be needed to reach breakeven. While the required savings are lower than estimated for the Nome-Teller or Nome-Teller-Brevig Mission proposals, the stand-alone project cannot take advantage of the lower fuel costs and substantial economies of scale available in Nome. We have no basis at this time for projecting that power production costs in Teller could be that much lower than power production costs in Brevig Mission. Regarding a larger capacity line that would cost substantially more, the State is likely to consider an investment of that magnitude only if an identified load exists, or if the line would provide a powerful inducement for economic development to occur. In this case, it is not clear that a mining operation of significant size would gain much benefit from the line because self-generated power for a large-scale operation could cost roughly the same as power purchased from the Nome utility. If this is so, then there should be more effective ways to use State funds to encourage mining development on the Seward Peninsula. Conclusion Based on the numbers produced in this initial scoping exercise, it is very unlikely that a feasibility study of the intertie proposal would produce a favorable result. If you have reason to believe that the intertie could be built for substantially less than we have assumed, please let me know so that we can reconsider our order of magnitude cost assumptions. Also, if our simple assessment of benefit based on differences in diesel production cost leaves out something that could potentially change the feasibility outcome, please send me your comments about that as well. Si ly, ) Charlie Bussell Executive Director ATTACHMENT 5 ENERGY AUTHORITY REVIEW OF PROPOSED INTERTIE BETHEL TO ATMAUTLUAK AND NUNAPITCHUK MARCH 1990 ay y ' BETHEL-ATMAUTLUAK-NUNAPITCHUK INTERTIE ECONOMIC ANALYSIS INTRODUCTION AND EXECUTIVE SUMMARY Introduction In a July 1975 report titled "A Regional Electric Power System for the Lower Kuskokwim Vicinity, A Preliminary Feasibility Assessment", prepared for the United States Department of the Interior, Alaska Power Administration, Robert W. Retherford Associates stated that "A regional electric power system of lines interconnecting the ten villages within a 40 mile radius of Bethel is a feasible project." Retherford also found that "A transmission interconnection using a Single Wire Ground Return (SWGR) line promises the lowest costs of all by virtue of its substantially lower investment," and suggested that a line from Bethel to Napakiak would be an excellent demonstration project. The Bethel to Napakiak line was constructed in May 1980 as a ten-year demonstration project using the proposes SWGR goncase and conioring "free- floating" "A"-frame gravity-stabilized tower structures. The design has proven to be a relatively low maintenance design. Documented maintenance and repair costs have been approximately $1,500/mile/year. Line failures have occurred twice since 1980. The first occurred when several "A"-frame structures "walked" (twisted) in high winds causing several towers to topple. The second occurred when one of the insulators was shot-out, creating a short and a resulting fire that parted the conductor and caused several towers to fall. Two minor design modifications have been incorporated to improve the structural strength of the intertie and reduce the possibility of towers toppling. First, additional y-wires were added to prevent multiple towers from toppling when one tower falls. condly, long rebar stakes were driven through the feet of the "A"-frames to prevent the towers from twisting and toppling in high wind. Overall, the onaiinn intertie has proven reliable, demonstrated low line loss, and has incurred relatively low maintenance and repair costs. Although the SWGR Seen ee eS has proven a success, the concept continues to fall outside accepted safety code (NESC) standards and no additional SWGR lines have been proposed. The Energy Authority has been unsuccessful in convincing either Napakiak or Bethel Utilities Corporation (BUC) to assume ownership of the intertie. A Memorandum of nt (MOA) was drafted between and Napakiak Ircinrag Power pany in October 1985 for the NIPC to assume ownership of the line. However, although the design and construction modifications stated in the MOA were apparently completed, transfer of ownership at this time has not occurred. In addition, BUC stated in a letter to the Energy Authority dated November 7, 1989 that they would not be interested in owning a SWGR system. NOTE: The Ri 4nd f for 1 Agreement for the Intertie is due to expire April 29, days to effect the removal of the eT : 1990, and provi Within the last few years, Retherford’s concept of a "regional electric power system" has been expanded through the construction of the Bethel-Oscarville, and Oscarville- Napaskiak Interties (both of these interties are single-phase lines incorporating conventional pole construction). The next step in the expansion of the regional er system is the proposed Bethel-Atmautluak-Nunapitchuk Intertie. This intertie has been proposed due to the close proximity of these communities to each other and to Bethel, and to their high electric consumption relative to other isolated villages in the vicinity. The following report and economic analysis was performed to determine the cost effectiveness of providing re to the villages of Atmautiuak and Nunapitchuk- Kasigluk from Bethel, using a 34.5 kV, 3-phase transmission line. Executive Summary The life-cycle cost of the proposed intertie is $4.47 million. The net benefit (or savings) over a 30 year expected useful life is $3.24 million. This corresponds to a Benefit/Cost ratio of .72. The life-cycle cost includes the estimated construction cost of $3.5 million (approximately $100,000/mile) in today’s dollars, and an estimated intertie O&M cost of $1,500/mile/year. The net benefit is equal to the avoided cost of $7.51 million minus the incurred cost of $4.27 million. The maximum construction cost at which the Benefit/Cost ratio equals 1.0 is $2.27 million (approximately $68,800/mile). The avoided cost includes the estimated capital, fuel, and non-fuel costs avoided by providing electricity over the intertie. The incurred cost includes the fuel cost incurred by Bethel Utilities to produce the electricity, and the O&M cost for maintaining the generation equipment in Atmautluak and Nunapitchuk for emergency and stand-by power. A real interest rate of 3% is used to discount cash- flows over the expected 30 year useful life of the Intertie. Input data for fuel efficiency, kWh generated, and kWh sold are based on FY89 PCE data. Non-fuel and —— costs for Atmautluak and Nunapitchuk-Kasigluk are based on information from Atmautluak’s Consultant, Kinetic Energy Systems, and AVEC’s Engineering department, respectively. Fuel is valued at $1.25/gallon for all sites. All costs are held constant in today’s dollars. Given the fuel price equivalence at all locations, the primary factor that leads to a Benefit/Cost ratio of less than 1.0 is the seeigs increase in fuel efficiency with the Intertie, as a result of Nunapitchuk’s existing high fuel efficiency. Atmautluak and Nunapitchuk-Kasigiuk consumed 172,948 gailons of fuel to ee 2,029,343 KWh in FYR9 this is approximately a 7% improvement in fuel efficiency compared to FY88). ing a 6% line loss, Bethel Utilities would have to transfer 2,158,876 kWh onto the Intertie to achieve the same 2,029,343 kWh. At 12.7 kWh/gallon, Bethel Utilities would consume 169,990 gallons of fuel. This is a net fuel savings of less than 2%. Without an appreciable increase in fuel efficiency achieved with the Intertie (i.e., a greater fuel savings), the avoided capital and non-fuel costs are not great enough to offset the construction and O&M costs of the intertie. TECHNICAL DESCRIPTION The proposed intertie route (as shown in fi 1) is approximately 35 miles long, 26.1 miles from Atmautluak to Bethel and ST tniles ore the Nunapitchuk-Kasigluk junction to the Atmautluak junction, 5.2 miles outside of Atmautluak. The proposed ATTACHMENT 6 RURAL HYDROELECTRIC DATA BASE NARRATIVE REPORT AUGUST 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Prepared for: Alaska Department of Community and Regional Affairs Division of Energy Prepared by: Locher Interests LTD. Anchorage, Alaska August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT SUMMARY — This report summarizes the results of Phase 1 work for contract DOE 96-R-004, Rural Hydroelectric Assessment and Development Study. The scope of Phase 1 included development of a database of existing and potential hydroelectric projects in Alaska, screening of that database to identify potentially viable small hydroelectric projects for development to serve rural Alaskan communities receiving Power Cost Equalization assistance from the State, and selection and preliminary economic and technical evaluation of a subset of sites having a high probability of economic viability. A Microsoft Access™ database was developed containing information on 1,144 potential sites and 52 existing hydro projects. Initial screening of the potential sites resulted in identification of 131 sites with preliminary benefit cost ratios of 1.0 or above and no obvious technical or environmental constraints to development. Further review of the information concerning these projects resulted in selection of four sites for more detailed engineering and economic evaluation. These include: Community Project Proposed Installation Atka Chuniisax Creek 80 kW - 271 kW Hoonah Gartina Creek 225 kW Old Harbor Unnamed Creek 330 kW Unalaska Pyramid Creek 100 kW - 260 kW Further analyses indicate that, except for the Gartina Creek project, all of these sites have moderate to high probabilities of producing positive net economic benefits. Gartina Creek only would be viable if capital costs could be drastically reduced, or if fuel prices should increase very dramatically. The assumptions concerning these two critical parameters required to achieve economic viability for Gartina Creek are not considered reasonable, however. The Chuniisax Creek project produces positive net economic benefits under optimistic assumptions, shows an essentially break-even result under most probable assumptions, and has negative benefits under pessimistic assumptions. Because the low-end cost estimate for this development includes some high risk assumptions on use of local labor and turn-key or force account methods, this project's economic viability may be viewed as questionable. The remaining two projects (Unnamed Creek at Old Harbor, Pyramid Creek at Unalaska) exhibit net positive benefits under almost all cases analyzed. Further evaluation of these remaining two projects is recommended. Collection of updated site-specific data on these projects is recommended. Information should be collected during site visits to verify existing conditions in the communities and identify any future development plans which could impact economic feasibility. Site visits and data collection would focus primarily on those parameters identified as critical from the economic evaluation sensitivity analyses completed during this phase of the work. Additional engineering and economic evaluations of the projects would be made following site visits and data compilation. LOCHER INTERESTS LTD. Page 1 of 30 August 18, 1997 ~ RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT 4.0 INTRODUCTION — _ This report summarizes the results of Phase 1 of the Rural Hydroelectric Assessment and Development Study, Project No. DOE 96-R-004, prepared by Locher Interests LTD. (Locher), for the Department of Community and Regional Affairs, Division of Energy (DOE). 1.1 Background Since the 1940's, numerous Federal and State agencies, as well as several utilities and other private sector organizations, have prepared reports on potential hydroelectric sites throughout Alaska. These potential developments range in size from the 5,040 megawatt (MW) Ramparts Project, envisioned by the U. S. Army Corps of Engineers in the 1950's, to developments on a micro-hydro scale of 25 kilowatts (kW) or less. A number of these projects have been developed over the past thirty years and are currently serving to provide a significant percentage of the energy needs for the citizens of Alaska. Numerous smaller sites, particularly sites that would serve the small rural communities, have never been examined in detail, or have been examined and not pursued, due to prevailing economic conditions or other limitations (i.e., land status, environmental constraints). For the most part, rural Alaskan communities rely on diesel generation for their energy needs. For many communities, the cost of this diesel power is subsidized through the State’s Power Cost Equalization (PCE) program. The future of this program is uncertain, given changing fiscal conditions of the State. Moreover, as technical, economic and institutional conditions change, it is likely that hydroelectric projects once found to be uneconomical or to have institutional or technical constraints precluding development may be more feasible today, or may become so in the future. Although some information on these potential projects is available in the numerous and varied reports and studies that have been done over the past fifty years, it is not always readily accessible, nor are the data easily applied to current conditions, as cost information, land status, and other key conditions all have changed somewhat since the initial analyses were completed. Thus, the DOE has identified a need for an electronic database which consolidates the information contained in the existing reports on hydroelectric potential, statewide, and facilitates evaluation of potential projects using updated assumptions concerning costs and environmental and economic feasibility. Additionally, DOE requires that an assessment of the information in the database be conducted to identify any potential projects which might provide PCE communities currently dependent on high cost, subsidized diesel power with an alternative energy source. 1.2 Scope Work under this contract is divided into two phases. This report summarizes the results of Phase 1, completion of the database, and identification and preliminary evaluation of potential hydro sites to serve PCE communities. Phase 2 will include a more detailed analysis of the potentially viable sites identified herein. More specifically, the scope of Phase 1 of this study included the: e Development of a database of known existing and potential hydroelectric sites in the State of Alaska (developed using Microsoft Access™ software). e Preliminary screening of all potential sites to eliminate those not suitable for development as power sources for rural Alaskan communities currently participating in the PCE program. e Preliminary ranking of all remaining sites, based on environmental and economic criteria, to identify a subset of projects for more detailed evaluation as potential power sources for PCE communities. LOCHER INTERESTS LTD. Page 2 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT e Selection and evaluation of a final set of potential developments, including more detailed engineering, cost and economic evaluations, to identify those sites showing the highest probability of economic viability, to be carried forward into the Phase 2 evaluation. In addition, a paper file supplementing the information contained in the database was developed. Paper files included a printout of the complete database report for each entry, as well as photocopies of summary information from the actual reference documents (report cover, summary of pertinent project data and location map, as available) for those projects identified as potentially viable during initial screening. 1.3 Sources Utilized Phase 1 work was based mainly on review and analysis of existing reports and secondary data sources. Documents reviewed included those maintained at the DOE Library, the Bureau of Land Management Federal Resource Library in Anchorage, and files of the Alaska Energy Authority and the Federal Energy Regulatory Commission (preliminary permits, pending and existing license applications, existing licenses and exemptions). Additionally, DOE provided recent PCE community filings on monthly generation for incorporation into the economic evaluation of the potentially viable projects. During final screening of potentially viable projects, representatives from the PCE communities in which the developments were located were contacted. During these contacts a number of recent reports, not yet catalogued in the above libraries, were identified and obtained for review. These reports were incorporated into the database. A total of 204 technical reports and studies were reviewed and the information obtained entered into the project database. LOCHER INTERESTS LTD. Page 3 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT 2.0 APPROACH TO THE ASSIGNMENT As described below, Phase 1 of this assignment has been accomplished in two stages. Stage 1 included development of the database and screening and ranking of the projects in the database to identify a smaller subset of potentially technically, economically and environmentally viable projects. Stage 2 consisted of the evaluation of this subset of projects in more detail, including an engineering evaluation of technical reasonability, verification and revision (as required) of the cost estimates, and identification, as possible, of potential design concept modifications which might result in improved project performance or economic viability. Additionally, a Stage 2 economic evaluation was performed, based on the revised cost estimates provided by the engineering review above. This second economic evaluation utilized more community specific parameters (including historical load data) and was explicitly designed to address the range of uncertainties associated with the net benefits of each project. As detailed in subsequent sections of this report, this evaluation includes development of a probability distribution of net benefits for each project which assigns probabilities to the assumptions used in the analysis and then evaluates the results of all possible combinations of assumptions. The overall process by which this work was accomplished is described in stepwise fashion below. 2.1 Development of the Database The first step in Phase 1 of this assignment was development of the project database. As detailed in Section 3, on page 8 of this report, a Microsoft Access™ database, consisting of 53 information fields for each database entry, was developed. Information on both existing and potential hydroelectric projects, obtained from review of the reports listed in Attachment A, was entered into this database. This ultimately resulted in the identification of 1,144 unique projects, including 52 existing projects and 1,093 potential projects, located statewide. Information on potential project developments included, as available, project location, communities potentially served, potential capacity and energy, and estimated costs for development, as well as information on land ownership and possible environmental constraints. The database also included a field assigning each site to the appropriate statistical area, as defined by the State for collecting power production statistics, (Southeast, Southwest, Southcentral, Arctic/Northwest and Yukon). Results of the screening and analysis procedures described below, as well as the project's paper files, are organized on the basis of these statistical areas. 2.2 Stage 1 Screening and Ranking Following completion of the database, the projects identified were subjected to a preliminary screening to eliminate those which were obviously not suitable for consideration as an energy source for PCE communities. Prior to screening, the costs for all projects were adjusted to 1996 dollars using the Handy- Whitman Index of Public Utility Construction Costs. Initial screening included elimination of: e Existing Projects (see Tables 4.1-4.3, on pages 11 and 12 in Section 4 of this report, for listings of existing projects), e Projects currently being actively developed by others (that is, where FERC preliminary permits were known to have been issued or license applications were in preparation; see Table 4.4, on page 13 in Section 4), e Sites for which no construction cost data had been developed (database entries with null records in the construction cost field), LOCHER INTERESTS LTD. Page 4 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT e Projects considered to be too large or too small for development by PCE communities (i.e., installed capacity greater than 5,000 kW or less than 25 kW as denoted in the database installed capacity field), e Projects clearly identified by previous investigators as being inappropriate for development (i.e., lacking adequate flow or head, as described in the database field labeled non-viable), e Projects having obvious land or environmental constraints which could preclude or substantially increase the cost of development (i.e., sites located in national parks, wildlife refuges or preserves, and sites on major salmon streams, and described in the non-viable database field). This screening procedure resulted in the elimination of all but 131 potential projects, distributed throughout the State as follows: Statistical A . Southeast 16 Southcentral 41 Southwest 22 Yukon 35 Arctic/Northwest 17 A listing of these 131 sites is presented as Table 5.3, on pages 15-17 in Section 5 of this report. Following initial screening, the remaining 131 projects were subjected to preliminary economic ranking, utilizing the approach detailed in Attachment B. As discussed therein, the goal of this screening and ranking process was to eliminate those projects which are clearly uneconomical while retaining those which may have some potential for development. This ranking process was designed to provide a coarse screen, somewhat biased in favor of hydro development, so as to avoid elimination of potentially viable projects, where the available information was likely to be sparse and of limited accuracy. This ranking procedure resulted in identification of 31 potential projects with a preliminary benefit cost (BC) ratio equal to or greater than 1.0. These 31 projects, by statistical area, were distributed as follows: Statistical A Numt f Sit Southeast 16 Southcentral 6 Southwest 8 Yukon 0 Arctic/Northwest 1 Table 5.4, on page 18 in Section 5 of this report provides additional detail on these projects. LOCHER INTERESTS LTD. Page 5 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT 2.3 Project Team Review The 31 projects identified during the Stage 1 economic screening and ranking procedure were reviewed by the project team (cost engineer, economist, environmental specialist, and project advisor. These sites are listed in Table 5.4, page 18 of this report. The purpose of the team review was to verify that the information contained in the database concerning these selected projects, and utilized in the screening and ranking procedure, was reasonable. Project cost estimates, communities served, system loads, and other features were reviewed and adjusted as appropriate, based upon the project team’s judgment or on additional information identified as a result of the review process. This review found that the information in the database was generally reasonable, although some adjustment of transmission line costs was required for projects which had originally been studied as one of a larger group of developments with shared transmission line costs. In a few cases, transmission line costs were missing from the original study estimate. Costs were adjusted appropriately to account for these problems. Following this review and adjustment, the economic screening process was repeated, and a revised list of the top ranked economically viable projects was developed. Table 5.5, on page 20 in Section 5, presents this second list of 15 projects. 2.4 DOE Review The list of 15 projects developed during the Project Team Review described above was provided to DOE for their review and concurrence. At their request, the original list of the 131 projects (Table 5.3 on pages 15-17) which resulted from the Stage 1 screening process and the shorter list of projects with appropriate BC ratios (Table 5.4 on page 18) were also provided for DOE consideration. After review of these lists, DOE met with Locher to discuss the addition of some projects being studied by others to the final list (these projects had been screened out during Stage 1 screening above). Based on these additions and a second economic screening and ranking of the remaining projects, a list of four Projects to be carried forward for further consideration was developed. PCE Community Served Project Name Atka Chuniisax Creek Hoonah Gartina Creek Old Harbor Unnamed Creek Unalaska Pyramid Creek 2.5 Stage 2 Engineering Evaluation The four projects listed above were subjected to an engineering review to ascertain that the overall technical assumptions used were reasonable and to identify, as possible, any design concept or construction approach changes which might affect project viability. Additionally, the cost estimates for the four developments were evaluated in more detail and a high and low cost estimate developed for use in the Stage 2 economic evaluation. High and low costs are related either to possible design or construction procedures modifications or to project size. Generally, this review confirmed the technical design concepts for these developments. In some cases possible design modifications such as use of a rubber dam or wooden flashboards, in place of a LOCHER INTERESTS LTD. Page 6 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT conventional concrete structure, use of different sizes or types of penstock materials, elimination of certain project features such as potable water and sanitary facilities, were identified as possible means to reduce costs. ; The major area of uncertainty identified for the cost estimates for these projects is related to assumptions concerning the use of local labor and/or force account methods in their construction. Assuming such non- traditional approaches, costs are significantly lower than if traditional methods of contracting and construction are used. Conversely, risks of problems during and after construction may be higher for projects constructed by non-traditional means. Attachment C presents the engineering review performed for these four projects, along with the final cost estimates utilized in the Stage 2 economic evaluation. 2.6 Stage 2 Economic Evaluation Using the costs and installed capacities provided from the engineering evaluation above, an economic evaluation of the four projects was performed using a model developed for this assignment. The evaluation procedure, described in detail in Attachment D, rely on community specific parameters and compares the cost of electric power with and without hydroelectric power development over a 35-year planning period, extending through the year 2032. The model addresses uncertainty by including multiple assumptions about the following critical parameters comparing the percentage of cases resulting in net positive benefits with those producing negative results provides an estimate of the economic viability of the development: e future price of diesel fuel e capital cost of hydro project e annual hydro maintenance cost e real discount rate e load growth of community served The multiple assumptions used for each of the above parameters are assigned probabilities and all possible combinations of assumptions, with their associated probabilities, are analyzed, producing a probability distribution of net benefits for each project. In addition, break-even analyses were performed. Break-even analyses were accomplished by beginning with very pessimistic assumptions and then determining how much critical parameters had to be changed in order to bring net benefits up to zero. LOCHER INTERESTS LTD. Page 7 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT 3.0 THE DATABASE Master.mdb is a Microsoft Access™ database file (2.2 Mb) with 1,978 entries representing a compilation of both existing and potential hydroelectric developments in Alaska. Information sources used to obtain information for the database include 204 reports found in various libraries, including the Department of Community and Regional Affairs, Division of Energy (DOE) Library, the Bureau of Land Management Federal Resource Library, Alaska Energy Authority project files, and Federal Energy Regulatory Commission (FERC) reports on preliminary permits and license applications. A complete bibliography, indicating report name, author, year of publication, and report is provided (Attachment A). Of the 1,978 database entries, there are 1,144 unique projects or development sites. Multiple entries for a given project indicate multiple reports for the same site. When more than one site was investigated for a project, each site was given a unique database entry. The number of sites per statistical area are given below: Table 3.1 - Alaska rural hydroelectric projects by region. Statistical area* Total Database Total Unique Existing Proposed Entries Projects projects** Projects Southeast (SE) 719 342 35 309 Southcentral (SC) 489 327 14 313 Southwest (SW) 345 224 2 222 Northwest/Arctic (NW/A) 204 88 0 88 Yukon (Y) 22 Teo tet OB totes otis Nettie Lieto Totals: 1978 1144 52 1093 > See explanation below. ** Includes projects that have been abandoned or which are no longer utilized to generate power. Following initial data compilation, certain sites were eliminated from further investigations based upon prescribed screening factors, such as excessive distance from intended load center, obvious land use or environmental restrictions, inappropriate project size, unavailable construction costs, and community participation in the Power Cost Equalization (PCE) program. The sub-set of viable projects passing the preliminary screening processes contains 131 projects determined to be appropriate for rural Alaskan communities, as determined from the information available in previous reports. These projects were copied to another database named working.mdb (295 kb). The number of potentially viable projects for each statistical region are shown in Table 3.2. Table 3.2 - Number of viable hydroelectric project sites by statistical area. Statistical Area Number of Viable Projects Southeast (SE) 16 Southcentral (SC) 41 Southwest (SW) 22 Northwest/Arctic (NVW/A) 35 Yukon (Y) cl Tite lizchneinadln eters Totals: 131 Each database contains 53 fields of information for each project. Field names are attached in Microsoft Access™ table format, with units and field descriptions. Blank fields in the database correspond with information not found in the reports. Most fields are self-explanatory; those fields that merit further definition are explained below. A complete listing of the fields and sample database report printouts on individual projects is provided as Attachment E. LOCHER INTERESTS LTD. Page 8 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT File Name: This alpha-numeric field corresponds with the paper file (hard copy) folder for each project site and represents the project statistical area and an entry. For example, SC 28 would correspond with the twenty-eighth folder within Southcentral statistical area files. When this field is blank in the database, the project report has been combined with another database report which better represents the site (see Project Count). ID: The ID numeric field is set up as a counter providing a unique identification number for each database entry. No two ID entries should be alike within the database, and all new entries should be assigned a new number. The highest ID number and the total number of records are not necessarily equal, since records may have been entered into the database (which increases the counter) and then later deleted. To add new records, this field should be sorted in ascending order first, with new records inserted at the end of the field to ensure a unique number. Project Name: The project name is a text field displaying the community name of the load center, plus the stream/lake name. Duplicate project names would indicate multiple studies or reports of the same site, or multiple sites along a single stream or river. Project Count: This numeric field provides a means to distinguish multiple studies for the same site. The field is “1” where the entry was judged to be the most complete and/or representative report for a project; the field is “O” if the entry is a duplicate entry for a project or a secondary reference to a site containing limited information. When the project count is “0,” the File Name is also blank. Project Location: Latitude and longitude have been given to define a project location, when available. Locations may also be represented as township, range, and section or by river-mile. In some cases, location must be inferred by stream or lake name and other geographic information (i.e. community served). - Statistical area: All entries have been organized by the five areas for which Alaska power statistics are maintained, defined by DOE to include: Southeast Alaska (SE) Southcentral Alaska (SC) Southwest Alaska (SW) Yukon (Y) Northwest and Arctic (NW/A). Information Source: This text field provides bibliographic information of the data source, organized in a standard format: Title; by Author; for Agency; Date; Library reference/call number; physical location of report. Level of Effort: The level of investigative effort of the information source is shown as either a letter report, a reconnaissance study, a preliminary investigation, a feasibility study, or a final report. Data Input By: Initials of person entering the record into the database @ organization, and date. Construction Cost: Shown as dollars in the study year, unless another year is indicated. Costs include direct costs, contingencies, engineering, and administration when provided in the report. Costs do not include interest accrued during construction. Non-viable: This text field provides information indicating a serious impediment to development identified during preliminary screening. A blank or null record for this field in a query indicates a potentially viable project. LOCHER INTERESTS LTD. Page 9 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT 4.0 EXISTING PROJECTS ~ There are 52 projects identified in the database as existing projects. These include 20 projects licensed by the Federal Energy Regulatory Commission (FERC) along with three FERC exempted projects. Additionally there are two projects (Eklutna and Snettisham) currently owned by the Federal Alaska Power Administration (APA). Eklutna is scheduled to be purchased by a group of railbelt utilities, and Snettisham is slated for transfer to the State of Alaska in the near future. Finally, there are approximately 27 non- regulated projects, many developed by individuals or private companies (mainly canneries), some of which have been abandoned or are not operating. Table 4.1, on page 11, lists the existing FERC licensed, FERC exempted, and federally owned projects identified in the database and provides information, as available, on their status. Table 4.2, on page 12, lists those projects identified as existing in the literature, but not currently regulated. Information on the non-regulated projects often is sparse and difficult to obtain, so these entries should be viewed with caution. As shown, of the approximately 357,202 kW of installed capacity (combined totals from Tables 4.1 and 4.2 on pages 11 and 12) represented by the existing projects identified in the database, approximately 66.7% (238,295 kW) is associated with the 20 FERC licensed and three FERC exempted projects. Twenty-five percent (90,000 kW) is associated with one project, Bradley Lake, currently the largest hydropower project in the State. Additionally, 30.3% (108,200 kW) of the total installed capacity is associated with the two federally owned projects, Snettisham and Eklutna. Projects associated exclusively with small rural Alaskan communities are listed in Table 4.3 on page 12. These projects represent only about 0.04% (14,380 kW) of the total installed capacity of the State’s hydroelectric projects. In addition to the 52 existing projects discussed above, there are currently 17 sites with active preliminary permit or license applications on file with FERC. If these sites were to be developed, they would provide an additional 140 MW to the statewide hydroelectric project capacity. Table 4.4 on page 13 lists these sites, currently under investigation for development. Of the existing small projects developed for rural Alaskan communities, three are reported to have had serious problems associated with them. The first, the Chitina Project at Town Lake, has been abandoned as a result of problems. As reported, the project penstock includes a siphon to deliver water to the turbine. This siphon was constructed using high density PVC and was buried in or along a roadway, apparently without the use of sand or other material to properly bed the pipe. Shortly after the project went into operation, problems attributed to the entrainment of air into the siphon began, causing periodic shut down of the project. It is reported that the pipeline is thought to have deformed at the joints, possibly where the road crosses over the buried line, allowing air to enter and destroy the siphon action. The frequency of these events gradually increased over time, and for the past two to three years, the project has been abandoned, as the effort involved in continually restarting the siphon became too great to justify continued operation. The second project with past problems, Larsen Bay, has been recently modified to address its major problems and is currently operating successfully. However, as in the case of the Chitina Project, Larsen Bay had problems with deformation of the penstock attributed to inadequate use of bedding material where it is buried. In this case, the deformation resulted in leakage. Additionally, the joint between the larger, low-pressure PVC section of the penstock and the smaller, high-pressure steel section failed and had to be repaired. This failure is thought to be due to poor installation. Additionally, there were substantial delays in the construction of the Larsen Bay Project, related in part to the need to revise the original project design and to deal with associated increases in construction cost. During this period, the project mechanical equipment was stored on the dock at Larsen Bay. Some corrosion occurred during storage and the generator bearings failed within a very short period after the project went on line. Finally, the project has had continual problems with debris, causing frequent outages. Recently, however, the LOCHER INTERESTS LTD. Page 10 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT operators have initiated a program of periodic clearing of debris from the reservoir, and this problem has been resolved. A third existing project, a small facility constructed in Seward, has had problems severe enough to result in its abandonment. Reasons that this project is no longer utilized are not clear; however, difficulty of fitting generation into the city’s diesel operation and lack of familiarity/interest in operation and maintenance of a hydro system appear to have played some role. TABLE 4.1 - Existing FERC licensed hydro projects, projects with Alaska issued FERC exemptions, and Federally owned projects. FERC Existing Project Name Location Owner License Generation Number (kW) Non-Federally Owned Armstrong Keta Port Armstrong na EXEMPT 80 Black Bear Lake Klawock Black Bear Lake Hydro, Inc. 10440 4500 Blind Slough Petersburg Petersburg Mun. Light and Power 201 2000 Blue Lake Sitka Sitka Electric Department 2230 9600 Bradley Lake Homer Alaska Energy Authority 8221 90000 Burnett River Project Burnett River Burnett River Hatchery 10773 80 Chignik Chignik Alaska Packers Assoc. 620 60 Cooper Lake Cooper Landing Chugach Electric Co. 2170 17200 Dry Spruce Bay Kodiak na 1432 75 Eklutna Recovery Eklutna Anchorage Water and Wastewater EXEMPT 750 Project Utility - = Green Lake Sitka Sitka Electric Department 2818 18500 Humpback Creek Cordova Cordova Electric Cooperative 8889 na Jetty Lake Port Alexander na 3017 2000 Ketchikan Lakes Ketchikan Ketchikan Public Utilities 420 4200 Pelican Pelican Pelican Utility Co. 10198 700 Salmon Creek Juneau Alaska Electric Light and Power 2307 7000 Silvis/Beaver Falls Ketchikan Ketchikan Public Utilities 1922 5400 Skagway Haines/Skagway Alaska Power and Telephone 1051 950 Solomon Gulch Valdez Alaska Energy Authority 2742 12000 Swan Lake Ketchikan Alaska Energy Authority 2911 22500 Tazimina lliamna lliamna Newhalen Nondalton Electric EXEMPT 700 Cooperative Terror Lake Kodiak Alaska Energy Authority 2743 20000 Tyee Creek Wrangell/Petersburg Alaska Energy Authority 3015 20000 Subtotal 238295 Federally Owned Eklutna Project Eklutna Alaska Power Administration EXEMPT 30000 Snettisham Project Juneau Alaska Power Administration EXEMPT 78200 Subtotal 108200 TOTAL 346495 LOCHER INTERESTS LTD. Page 11 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Table 4.2 - Projects identified as existing, but not currently Federally owned or regulated by FERC. Existing Project Name Location Owner Generation (kW) Akutan Akutan na na Annex Creek Juneau Alaska Electric Light and Power 3200 Bahovec Warm Springs Bay Mr. Fred Bahovec 3 Bear Cove Bear Cove na 15 Bear Creek Juneau na 10 Chester Lake Metlakatla Metlakatla Power and Light 1000 Chichagof-Superior Chichagof Island Superior Packing Co. 10 Chichagof-Swanson Chichagof Island Mr. Earnest Swanson UL Chitina Chitina Chitina Electric na College Sitka Sheldon-Jackson Jr. College 50 Dayville Project Valdez-Allison Ck Mrs. O.B. Day 200 Gold Creek Juneau Alaska Electric Light and Power 1600 Keku Kupreanof Island Keku Canning Co. 30 Larsen Bay Larsen Bay Alaska Energy Authority 475 Linkum Creek Kasaan Pacific American Fisheries 17 Medvetcha River Medvetcha River Alaska Lumber Pulp Co. na Nugget Creek Juneau na na One Mile Creek Kodiak Island New England Fish Co. 8 Parks Canning Kodiak Island Parks Canning Co. 8 Pillars Baranof Island Stofold and Grondahl Packing Co. 15 Pitkas Point Pitkas Point na Aa - Purple Lake Metlakatla Metlakatla Power and Light 3900 San Juan Lake San Juan Lake San Juan Fishing and Packing Co. 105 Sheep Creek Thane na na Short Project Baranof River Mr. Bill D. Short 3 Skeckley Creek Port Armstrong Buchan and Heinen Packing Co. 14 Uganik Kodiak Island Uganik Fisheries Inc. 30 Walsh Creek Revillagigedo Island Wards Cove Packing 7 TOTAL 10707 TABLE 4.3 - Hydro projects associated exclusively with small rural Alaskan communities. Existing Project Name Community Owner Generation (kW) Armstrong Keta Port Armstrong na 80 Black Bear Lake Klawock Black Bear Lake Hydro, Inc. 4500 Chester Lake Metlakatla Metlakatla Power and Light 1000 Chitina Chitina Chitina Electric na Dry Spruce Bay Kodiak na 15 Humpback Creek Cordova Cordova Electric Cooperative na Jetty Lake Port Alexander na 2000 Larsen Bay Larsen Bay Alaska Energy Authority 475 Pelican Pelican Pelican Utility Co. 700 Purple Lake Metlakatla Metlakatla Power and Light 3900 Skagway Haines/Skagway Alaska Power and Telephone 950 Tazimina Project lliamna lliamna Newhalen Nondalton Elect. Coop. 700 TOTAL 14380 LOCHER INTERESTS LTD. Page 12 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Table 4.4 - Active FERC Preliminary Permits and License Applications in Alaska as of 06/30/97". Project Name FERC Expiration Licensee/Permitee Capacity Number Date (MW) Upper Chilkoot 11319 3/31/99 Haines Light and Power Co., Inc. 6.2 Upper Reynolds Creek 11480 11/30/97 Haida 1.5 LeAnne Lake 11497 11/30/97 Kodiak Electric Association, Inc. 2.8 Wolf Lake 11508 3/31/98 Alaska Power and Telephone Co. na Allison Lake 11510 4/30/98 ABIDC 8 Grant Lake 11528 6/30/98 ABIDC 7 Silver Lake 11548 10/31/98 Silver Lake Hydro, Inc. 15 Lace River 11553 11/30/98 Lace River Hydro, Inc. 62 Lake Dorothy 11556 12/31/98 Lake Dorothy Hydro, Inc. 17 Old Harbor 11561 2/28/99 Alaska Village Electric Coop., Inc. 0.33 Icy Gulch 11562 2/28/99 Alaska Gastineau Dev. Corp. 0.26 Power Creek 11584 3/30/99 Whitewater Engr. 5 Otter Creek 11588 10/31/99 Alaska Power and Telephone 4.5 Sunrise Lake 11591 12/31/00 Wrangell 1.5 Whitman Lake 11597 12/23/97 Ketchikan Public Utilities 4.5 Carlanna Lake 11598 6/2/00 Ketchikan Public Utilities 0.8 Connell Lake 11599 6/2/00 Ketchikan Public Utilities 1.7 Does not include projects with license applications which have been submitted (Goat Lake, Mahoney Lake). LOCHER INTERESTS LTD. Page 13 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT 5. POTENTIAL PROJECTS Table 5.1 presents the total number of statewide potential hydro sites which have been investigated in the past, by statistical area and installed capacity. As shown, there are 1,144 potential sites identified in the database, of which 602 are estimated to be in the size range appropriate for smaller rural communities (< 5,000 kW). Table 5.1 - Potential Hydroelectric Sites in Alaska, by Statistical Area. | Installed Capacity Installed Capacity | Statistical Area < 5,000 kW | > 5,000 kW Not Specified Total Southeast 183 75 84 342 Southcentral 161 133 33 327 Southwest 120 31 73 224 Arctic/Northwest 52 L 26 10 88 Yukon 86 54 23 163 Totals 602 319 223 1144 It should be noted that a number of these sites are non-viable. either for technical reasons (i.e., lack of water, lack of head), or due to environmental or land use constraints. In other cases, multiple sites have been identified in an area and development of one would preclude (or in some cases has precluded) future development of the remaining sites. 5.1 First Screening Results Stage 1 screening of these potential sites, according to the criteria listed in Section 2 (page 4) of this report, reduced the number of potentially viable projects to a total of 131. As previously discussed, these potential sites are distributed throughout the State as shown in Table 5.2. Table 5.2. - Hydroelectric projects potentially suitable for serving rural communities in Alaska, by statistical area. Statistical Area Number of Potential Projects Southeast 16 Southcentral 41 i Southwest 22 i Yukon 17 Arctic/Northwest 35 Totals 131 Table 5.3, on pages 15-17, presents a complete listing of these potential sites, including project name, project location, proposed installed capacity, and estimated construction cost (adjusted to 1996 dollars). The 131 potential projects listed in Table 5.3 were subjected to Stage 1 economic screening and ranking, utilizing the method presented in Attachment B. The intent of this first screening and ranking was to eliminate only those projects that are clearly uneconomical. Thus, screening was designed to be coarse, so as to not eliminate any potentially viable projects, even if their viability appeared marginal at this stage of the evaluation. The list of projects selected by first stage economic screening process is presented in Table 5.4 on page 18. As shown, this procedure produced a list of 31 potentially economically viable sites with BC ratios equal to 1.0 and above. LOCHER INTERESTS LTD. Page 14 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Table 5.3 - List of potential hydro sites passing preliminary screenings for project viability. Project Name Statistical Installed 1996 Cost Area Capacity ($1000) (kW) Ambler (East Fork Jade Creek) NW/A 106 5,976.88 Ambler (Jade Creek) NW/A 1,225 7,660.10 Bettles (Jane Creek) NW/A 276 8,532.79 Brevig Mission (Teller, Don River) NW/A 119 14,796.56 Brevig Mission (Teller, Main Stem Bluestone River) NWA 276 9,077.31 Buckland (Hunter Creek) NW/A 238 19,614.40 Elim (Creek at Elim) NW/A 28 4,328.21 Golovin (Eagle Creek) NW/A 200 8,540.65 Golovin (East Tributary and Upper Cheenik Creek) NW/A 164 11,749.30 Golovin (East Tributary Cheenik Creek) NW/A 99 6,637.49 Golovin (Kwiniuk River) NW/A 204 8,572.11 Kiana (Canyon Creek) NW/A 460 8,977.37 Kobuk (Dahl Creek) NW/A 140 4,639.95 Koyukuk (East Tributary Nulato River) NW/A 157 12,252.61 Nome (Numerous Creeks) NW/A 724 19,613.62 Nome (Osborn Creek) NW/A 479 8,540.65 Nome (Penny River) NW/A 219 6,668.94 Point Hope (Akalolik Creek) NW/A 454 17,726.18 Shungnak (Cosmos Creek) NW/A 1,235 9,653.38 Teller (Brevig Mission, Right Fork Bluestone River) NW/A 240 7,439.65 Wales (Kanauguk River) NW/A 36 9,437.19 Barabara Creek sc 3,000 15,377.23 Cape Chiniak (Myrtle Creek) sc 238 4,529.85 Cape Chiniak (West Fork Twin Creek) sc 84 2,563.77 Ceres Lake sc 2,000 8,175.37 Chitina (Fivemile Creek) sc 100 1,168.64 Chitina (Haley Creek) Sc 100 1,689.26 Chitina (Liberty Creek) Sc 100 1,698.69 Chitina (O'Brien/Fox Creek) sc 100 1,189.09 Chitina (Town Lake Penstock Repair) sc n/a 300.00 Copper Center (Klawasi River) sc 2,782 37,647.11 Cordova (Crater Lake) sc 1,200 16,162.70 Cordova (Hartney Creek, Lower) sc 216 4,669.06 Cordova (Hartney Creek, Upper) sc 306 5,360.77 Cordova (Heney Creek, Lower) sc 130 2,766.85 Cordova (Heney Creek, Upper) sc 260 3,458.56 Cordova (Lake 1488) sc 4,300 46,968.41 Cordova (Lake 1975 Elevation - Dead Creek tributary) sc 2,200 16,240.57 Cordova (No Name Lake sc 5,000 8,435.46 Cordova (Sheep River Lake middle, Lake 1022) sc 1,200 8,858.49 Cordova (Sheep River Lakes, Lake 649) sc 3,000 46,612.92 Cordova (Sheep River upper Lake, Lake 2026) sc 1,200 8,858.49 Cordova (Unnamed Falls) sc 190 4,841.99 Gakona, Gulkana (Copper River Tributary) sc 1,075 5,752.11 Halibut Cove (Halibut Creek) sc 4,117 9,264.51 Harrison Lagoon (Lagoon Creek) sc 120 n/a Hope (Bear Creek) sc 626 2,518.76 Kachemak (Swift Creek) sc 674 3,398.71 Kodiak (Virginia Creek) Sc 120 2,610.95 LOCHER INTERESTS LTD. Page 15 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Project Name Larsen Bay (Humpy Creek) Meakerville, Eyak (Robinson Falls Creek) New Chenega (Crab Bay, Chenega Bay) New Chenega (San Juan fish hatchery, Sawmill Bay) Intertie Ouzinkie (unnamed stream, site #1) Ouzinkie (unnamed stream, site #2) Port Graham - English Bay (Dangerous Cape Creek) Port Lions (Crescent Lake, Port Lions River) Port Lions (Mennonite Creek, Port Lions River) Seldovia Lake Suntrana (Moody Creek) Talkeetna (Middle Fork Montana Creek) Whittier (Placer River) Anita Lake Chatham (Chatham Creek; 57.31’, 134.57’) City Creek (Petersburg) Elfin Cove (Margaret Creek; 58.07’, 136.20') Excursion Inlet (N Excursion Inlet; 58.25’, 135.24’) Excursion Inlet (S Excursion Inlet; 58.25', 135.24') Gunnuk Creek Haines (Dayebas Creek) Haines (Lake Project; 59.25', 135.40') Hassler Lake Hoonah (Gartina Creek) Lake Josephine (Portage Creek) Reid Falls Rowan Bay (6415 Road) Rowan Bay (Big Lake) Rowan Bay (Small Lake/ Erode Creek) Rowan Bay (Stink Creek/ Erode Creek) Rowan Bay (Unnamed Creeks) Skagway Project (Dewey Lakes, Icy and Snyder Creeks) Triangle Lake (Annette Island) Whale Pass Work Center (Neck Creek) Adak (unnamed stream, site #1) Adak (unnamed stream, site #2) Adak (unnamed stream, site #3) Akutan (Loud Creek) Akutan (North Creek) Akutan (unnamed stream, site #1) Akutan (unnamed stream, site #2) Akutan (unnamed stream, site #3) Akutan (unnamed stream, site #4) Atka (Chuniisax Creek) Attu (unnamed stream, site #1) Chignik (Indian Creek) Chignik Bay (Indian Creek) Chignik Bay (Negro Creek) Contact Creek Statistical Area sc sc sc sc sc sc sc sc sc sc sc sc Sc SE SE SE SE SE SE SE SE SE SE SE SE SE SE SE SE SE SE SE SE SE SW SW SW SW SW SW SW SW SW SW SW SW SW SW SW. Installed Capacity (kW) 300 905 16 105 990 220 985 180 200 1,500 4,843 1,009 3,917 4,000 175 700 780 920 1,700 1,800 4,490 5,180 4,000 450 2,000 3,040 250 700 250 280 200 520 3,000 125 200 303 192 150 126 1,500 69 112 117 271 101 1,100 550 360 3,000 1996 Cost ($1000) 11,055.40 8,421.47 956.00 432.80 4,761.06 2,123.37 10,627.24 3,534.27 1,611.76 14,200.39 11,690.26 3,705.80 11,294.58 13,032.79 2,766.85 1,769.47 3,458.56 9,338.12 10,375.69 7,407.67 9,409.02 15,736.46 19,878.83 8,473.48 23,917.92 9,653.38 2,540.37 5,505.03 4,718.59 4,718.59, 245075115 6,413.91 32,149.77 565.01 2,359.30 3,098.54 2,783.97 1,955.37 1,817.04 10,302.26 1,108.87 1,516.24 1,667.24 722.79 2,170.55 11,909.30 4,035.97 3,899.13 n/a LOCHER INTERESTS LTD. Page 16 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Project Name Statistical Installed 1996 Cost Area Capacity ($1000) (kW) Copper River, Meadow Lake SW. 1,500 8,534.01 Creek (sic) SW 900 9,320.83 Dillingham (Grant Lake) SW 2,700 37,034.30 Goodnews Bay (stream S of Chawekat Mtn.) SW 85 2,864.71 lvanoff Bay (unnamed stream) SW 650 5,964.30 King Cove (Delta Creek) SW 700 6,568.38 King Salmon River SW 800 8,698.29 Kokhanok River SW 1,500 9,251.66 Nikolski (Sheep Creek) SW 120 1,596.46 Nikolski (unnamed stream, site #2) SW 1,000 7,664.57 Nikolski (unnamed stream, site #3) SW 130 3,208.64, Nyac (Tuluksak River, Slate Creek) SW 1,800 20,036.33 Pilot Point (unnamed stream, site #1) SW 47 2,894.07 Reindeer Creek SW 400 8,853.92 Sand Point (unnamed stream, site #2) SW 39 1,240.99 Squaw Harbor (unnamed stream, site #1) SW 104 1,997.54 Togiak (Kartluk River) SW 30 2,273.07 Unalaska (Pyramid Creek) SW 260 1,091.49 Unalaska (Shaishnikof River) SW 700 8,063.09 Unalaska (unnamed stream, site #2) SW 399 5,064.62 Allakaket (unnamed stream NW) Yukon 105 5,981.60 Allakaket (unnamed stream South) Yukon 82 5,589.96 Cantwell-Broad Pass (Carlo Creek) Yukon 1,710 8,115.85 Cronin Lake Yukon 2,500 9,329.12 Galena (Kala Creek) Yukon 761 24,941.22 Grayling (N. Fork Grayling Creek) Yukon 230 6,422.23 Hughes Yukon 45 5,023.95 Hughes (Creek Northwest) Yukon 45 5,389.26 Hughes (Two Creeks West) Yukon 45 5,347.74 Kaltag (North Tributary Kaltag River) Yukon 127 7,561.07 Kaltag (South Tributary Kaltag River) Yukon 115 7,537.48 Kaltag (stream 4 mi W of) Yukon 155 3,736.92 Manley Hot Springs (McCloud Ranch Creek) Yukon 37 2,081.53 Nulato (East and West Tributaries Nulato River) Yukon 381 23,561.98 Nulato (West Tributary Nulato River) Yukon 166 10,349.13 Tanana (Bear Creek) Yukon 185 8,031.67 Tanana (Jackson Creek) Yukon 174 6,390.55 LOCHER INTERESTS LTD. Page 17 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Table 5.3 - Top ranked projects from Stage 1 economic screening and ranking. Project Name Port Lions (Mennonite Creek, Port Lions River) Meakerville, Eyak (Robinson Falls Creek) Atka (Chuniisax Creek) Rowan Bay (6415 Road) Rowan Bay (Stink Creek/ Erode Creek) Port Lions Meakerville, Eyak (Cordova) Community Output BC (kWh/year Ratio 1,785,000 3.79 5,074,000 3.70 Haines (Dayebas Creek) Port Graham - English Bay (Dangerous Cape Creek) Hassler Lake Creek (Petersburg Reid Falls Rowan Bay (Small Lake/ Erode Creek) Rowan Bay (Unnamed Creeks) Nyac (Tuluksak River, Slate Creek) Rowan Bay (Big Lake) Haines (Lake Project; 59.25’, 135.40') Triangle Lake (Annette Island) lvanoff Bay (unnamed stream) Chignik Bay (indian Creek) Shungnak (Cosmos Creek) ‘Anita Lake Port Lions (Crescent Lake, Port Lions River) Chignik Bay (Negro Creek) Unalaska (Pyramid Creek) Hoonah (Gartina Creek) Akutan (Loud Creek) Metlakatla 520,000 Kake 1,095,750 3.22 Kake 1,227,240 3.08 Haines 18,190,000 3.06 Port Graham - English Bay (Seldovia) 4,488,000 3.05 16,980,000 2,830,000 11,335,000 1,095,750 2.89 2.83 Cordova (Sheep River upper Lake, Lake 2026) Cordova (Lake 1975 Elevation - Dead Creek tributary) Cordova (Sheep River Lake middie, Lake 1022) Akutan (North Creek) Whale Pass Work Center (Neck Creek) Skagway River Kake 876,600 2.67 Nyac (Bethel) 6,700,000 2.61 Kake 3,068,100 2.22 Haines (possible Skagway intertie) 44,200,000 2.09 1.88 Sand Point 2,848,950 1.78 Chignik Bay (Port Heiden) 2,410,650 1.73 3,245,580 1.70 1.66 1,581,000 1.58 1,577,880 1.53 1.50 [Hoonah 2,970,000 1.36 Unalaska/Dutch Harbor 1,292,000 1.32 Cordova 5,260,000 1.25 Cordova 9,420,000 1.22 Cordova 5,000,000 1.19 | 1,088,000 141 Wrangell 547,875 1.09 Kake 25,230,000 1.05 ‘Key Assumptions: Real discount rate: 2.0% LOCHER INTERESTS LTD. Real diesel price escalation: 1.0% Fraction of diesel O&M saved: 50.0% Page 18 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Second Screening and Ranking As anticipated, the results of the first stage screening and ranking procedure, done in an essentially mechanical manner and utilizing the information in the database “as is,” produced a list of potential projects with some problems, requiring review and revision from the project team. For example, the top ranked site listed in Table 5.4 on page 18 (Port Lyons, Mennonite Creek) is located near a community that receives power from the existing Terror Lake Hydroelectric Project, at extremely favorable rates. Thus, model assumptions concerning avoided costs do not apply to this project, and its actual economic viability is much different than that calculated by the model. Another common problem with the first screening results was the inclusion of multiple sites from the same study area. Five Rowan Bay, four Cordova, three Unalaska and two Port Lyons sites were included among the 31 sites having first stage BC ratios of 1.0 or above. This grouping of sites can be an artifact of the accuracy of the cost assumptions used in a particular study, for example. Alternatively, costs for some projects may be incomplete as the original study may have looked at a cluster of developments, and certain costs (transmission line for example) may have been allocated among all projects. Consideration of only a single development would be based on an artificially low cost. Finally, in some cases, the projects identified proved to be alternative developments considered for an area where another project actually has been developed. The Akutan Bay site, for example, is an alternative to a project that has since been developed. Accordingly, second stage screening of the sites identified as potentially viable began with a detailed review by the project team (economist, cost engineer, environmental scientist, and project consultant/advisor). This review included consideration of the following critical parameters: e Project Cost Estimate (completeness, reasonableness), e Location of project in relation to nearby PCE communities, e Proposed installed capacity, projected output, e Recent development or plans for future development by others which might affect project viability/desirability. This Project Team review eliminated a number of the projects included in Table 5.4 on page 18. In addition, some projects which were not originally in the database and/or which had a BC ratio slightly below 1.0, but appeared to be promising based on other factors, were added back into the list. Corrected information was input into the database as appropriate. A final list of potentially viable projects was developed from this review. This final list includes 15 projects, potentially serving ten communities, as shown in Table 5.5 on page 20. This list of projects was provided to DOE for their review and final selection of sites to be carried forward to Stage 2 evaluation. LOCHER INTERESTS LTD. Page 19 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Table 5.5 - Projects determined to be potentially economically viable following project team review of the results of first stage economic screening. | Community Project BC Ratio Cost ($1,000;1996) | | Ambler/Shungnak/Kobuk Jade Creek 0.91 7660.10 Cosmos Creek 1.71 9653.40 1 Atka Chuniisax Creek 3.47 722.80 i Chitina Town Lake na* 300.00 Gustavus [ Falls 2 na* 1859.40 Haines/Skagway Reid Falls | 2.86 6939.60 Dayebas Creek 3.06 9409.00 Lake Project 2.09 15736.5 tT | Hoonah Gartina Creek 1.50 8473.50 f —r Kake Rowan Bay (un-named) 2.67 2507.10 Rowan Bay (6415 Road) 3.22 2540.40 Rowan Bay (Big Lake) 2.22 5505.00 | Kiana ! Canyon Creek 0.95 8977.40 Old Harbor Old Harbor na* 5278.50 Unalaska Pyramid Creek 1.50 1091.50 * Project added to list by review team, no preliminary economic evaluation available. In addition to this list, supplementary information on the projects listed above along with data on the 131 projects identified as potentially viable from Stage 1 screening and ranking was provided to DOE for review and selection of a final group of projects to be carried forward to the next stage of the study. Following completion of DOE's review of this information, the following four projects were selected for final evaluation: PCE Community Atka Hoonah Old Harbor Unalaska LOCHER INTERESTS LTD. Page 20 of Project Chuniisax Creek Gartina Creek Unnamed Stream Pyramid Creek 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT 6.0 PROJECTS SELECTED FOR DETAILEDEVALUATION —_w The four projects identified above were subjected to an engineering review (limited to review of the available reports concerning these projects), to confirm that the design concepts and project costs appear reasonable, and to identify possible design concept modifications which might improve operation of the projects as envisioned or, reduce project costs. Results of this review are presented in detail as Attachment C. Following this review, and based in part on the findings of the engineering review report, a set of final costs, including both high and low cost, were provided to the project economist for completion of the Stage 2 economic evaluation. Detailed results of this second economic evaluation are presented in Attachment D. The general findings of both the engineering and economic evaluations are summarized below by community. As discussed, all projects except the Gartina Creek (Hoonah) development appear to be potentially viable developments. The Chuniisax Creek development at Atka, however, is viable only when the most optimistic assumptions are utilized, and given the uncertainty associated with the proposed non- traditional approach to construction, should be viewed with caution. Atka: Atka is a community of approximately 100 people, located on Atka Island, in the Aleutians. Based on data from Fiscal Years 1992 through 1997, Atka generates an average of 281,170 kWh per year (23,341 kWh per month), as shown in Table 6.1, below. The system peaks slightly in summer, due to fish processing loads. The fish processors have begun to largely provide their own power, however, and as a result, the | utility served load declined at an average rate of 4.4% per year over the period 1992 through 1996. Currently, Atka provides power with two diesel generators, rated at 125 kW and 75 kW. Table 6.1. Atka average monthly generation, in kWh, from data for Fiscal Years 1992 -1997. Month Average Generation; kWh January 24133 | February 23736 i March 22385 | April 22730 May 23854 | June 26252 July 24722 August | _ 25832 September 21417 October 22120 | November 22601 December 21390 Average Annual 23431 As detailed in Attachment C, a timber flashboard type dam anchored to a concrete foundation on Chuniisax Creek has been proposed. Water from this diversion would be carried via one 1,160 foot (ft) long, 28-inch diameter HDPE pipe to a 271 kW unit, rated at a gross head of 116 ft and a flow of 36 cubic feet per second (cfs). It is estimated that this plant could produce 1,760,000 kWh per year, some six times the energy currently generated by the utility. Alternatively, an 80 kW unit, capable of providing some 520,000 kWh of energy annually has been proposed. Such a smaller single unit could be installed during initial development, leaving space for a second unit, to be installed in the future, as demand requires. LOCHER INTERESTS LTD. Page 21 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Engineering review has indicated that minimal cost savings might be realized by consideration of an overhead transmission line in place of a buried line, as proposed. However, such a choice could increase project Operation and Maintenance (O&M) costs, so that no real savings would be realized. Moreover, even though the most recent and detailed report on this project has a cost estimate of $766,000, this cost is based on a non-traditional approach to construction (use of local labor with turnkey or force account | methods). Such methods should be viewed as a relatively high risk approach. Use of more traditional construction methods could escalate project costs to around $1,200,000. Thus, costs of $766,000 and $1,200,000 provide adequate bracketing for the purposes of Stage 2 economic evaluation. As presented in Attachment D, net present benefit for an 80 kW project producing 540,000 kWh of energy per year is a negative $5,914, under mid-range assumptions. Thus, the project essentially breaks even under the mid-range case. Under the most pessimistic and most optimistic cases, the net present benefits are negative (- $534,090) and positive ($1,856,748), respectively. Figure 6.1 below summarizes the results of the probability of net benefits analysis for the Atka project. Considering all possible combinations of critical assumptions for this case, with their assigned probabilities, a largely positive probability distribution of net benefits results. Only twenty-eight of the 108 possible combinations evaluated are negative. The cumulative probability of these negative combinations is just 25%, so that if the assumptions used are accurate, there is a 75% chance that the project, as analyzed, will produce positive benefits. However, given the uncertainty of the low-end cost estimate used and the fact that the project only provides positive net present benefits under the most optimistic assumptions, the economic viability of this project may be viewed as questionable. Figure 6.1 Atka Probability Distribution of Net Benefits 0.12 0.1 0.08 probability [o} 8 Net Benefits (million 1996$) Break-even analysis (see Attachment D) shows that the best ways to achieve a positive net benefit for this project would be to reduce capital costs to the low end of the range estimated and/or to secure financing in the 2% to 3% (real) range. That is, this development is most sensitive to these two critical parameters and is less readily affected by fuel costs, annual maintenance costs, or load growth. LOCHER INTERESTS LTD. Page 22 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Hoonah: Hoonah is a community of some 900 people, located on Chichagof Island in Southeast Alaska. Data from the past five years indicates that Hoonah has generated an average of 4,377,531 kWh of energy annually. Average monthly generation over this period is 364,794 kWh. As shown in Table 6.2 below, the system peaks slightly in winter but remains fairly constant throughout the year. Hoonah’s current system consists of three diesel units rated at 1,000, 855, and 610 kWh. As reported in Attachment D, the system grew at a rate of 4.1% between 1992 and 1996. Table 6.2. Hoonah average monthly generation, in kWh, from data for Fiscal Years 1992 -1997. | Month Average Generation; kWh January 382082 February 399233 March 344961 April 373645 May ail 339549 | June 366274 July 315670 August 345431 September 373759 October 363652 November 386859 December 386417 Average Annual 364794 The proposed project consists of a low concrete gravity dam located on Gartina Creek, immediately upstream of a set of waterfalls, which form a natural barrier to salmon. An above ground 57-inch diameter penstock 210 ft long, would provide water to two vertical shaft turbines, rated at 225 kW, at a flow of 50 cfs and a net head of 65 ft. The penstock is sized to accommodate an additional 450 kW of installed capacity, to be added at a later date. Based on the equipment and site hydrology, the average annual energy output from this project would be some 2,170,000 kWh, equivalent to about 50% of the current annual energy generated by the diesel units in Hoonah Engineering review of the proposed project has identified a number of features which might be altered to reduce costs and/or improve project operations. An inflatable rubber dam with a concrete slab foundation, instead of the concrete structure proposed, could result in cost reductions on the order of $300,000. In addition, a rubber dam might provide an environmental benefit as it could be operated to allow gravel to pass downstream, helping to maintain fish spawning habitat. Alternatively, a timber flashboard dam also might be utilized, with comparable cost reductions. Additional savings are possible by substituting use of a mobile crane, both during installation and for future maintenance, for the bridge crane as proposed in the original study. Penstock costs may be reduced by some $300,000 by reducing the size and omitting the continuous concrete support of the pipe originally envisioned. Additional savings might be possible by substituting HDPE pipe, with wooden supports, for the steel penstock as proposed. Finally however, the costs estimated for mechanical equipment may be low, and based on recent experience costs, could increase by some $175,000 to account for this discrepancy. LOCHER INTERESTS LTD. Page 23 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Old Harbor: Old harbor is a community with a population of approximately 310, located on Kodiak Island some 40 miles southwest of the City of Kodiak. Average annual generation in Old Harbor over the 1992 - 1997 period was about 727,904 kWh, with average monthly energy production of about 60,660 kWh. As shown in Table 6.3 below, the system peaks slightly in winter, but is fairly constant. Old Harbor’s load grew at an average rate of 2.1% per year between 1992 and 1996. Energy needs in Old Harbor are currently supplied by three diesel generators with a total capacity of 536 kW (two units rated at 197 kW and one at 142 kW). Table 6.3. Old Harbor average monthly generation, in kWh, from data for Fiscal Years 1992 -1997. Month Average Generation; kWh |___ January 70167 February 62875 March 66470 April 62156 May 58960 June 46858 July 48236 August 52196 September 60703 October 63828 November 65705 December 69751 Average Annual 60659 Past reports have considered a range of potential hydro developments for Old Harbor. Projects varying in size from 2,280 kW to 330 kW have been evaluated. Given the size of the load, projects at the lower end of this range have been selected for evaluation for this study. A cast-in-place concrete diversion, with stoplogs, would provide water to a 16-inch diameter combination HDPE and steel penstock, supplying a 330 kW turbine, rated for 7.5 cfs at 747 ft of head. This installation would be capable of providing some 2,665,000 kWh of energy annually, a surplus of about 1,900,000 kWh over the current load. Engineering review of this project concept indicates that costs for excavation and backfill for the penstock could be some $270,000 low. Some cost savings might be possible by substituting an overhead transmission line for the buried line as proposed, but this could lead to increases in project O&M costs. The major cost issue for this development relates to the assumptions made concerning the construction method. The most recent cost estimate developed assumed use of local labor via turnkey or force account methods, as well as an approach which uses “loose” engineering design with modification of design in the field to suit field conditions. Should this high risk approach not be suitable, costs could increase by nearly 50%, from $1,369,000 to $2,000,000. These two values are used in this evaluation to bracket possible project construction costs. Economic evaluation of the Old Harbor project, as detailed in Attachment D, indicates that the project has positive net benefits under most combinations of assumptions used. Net benefits range from a negative $1,000,000 under the most pessimistic case to a positive $440,000 for the mid-range case, and as high as a positive $5,300,000 for the most optimistic case. LOCHER INTERESTS LTD. Page 25 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT As shown in Figure 6.3 below, the probability distribution of net benefits falls almost entirely in the positive region. Net benefits are negative in only about 20 out of 108 combinations of assumptions and the indication is that there is an 85% chance of net positive benefits for this project, assuming the probabilities assigned are accurate. Figure 6.3 probability Probability Distribution of Net Benefits: Old Harbor 0.14 0.12 0.1 0.08 mw prob 0.06 0.04 0.02 o N 2 8 FF ocUCUCU rll ON OT 4.3 5.0 c= =A o 9 Net Benefits (million 1996$) Break-even analysis of the Old Harbor project indicates that low capital costs and load growth are both important to its economic viability. Given the project's ability to produce substantial amounts of excess energy at zero marginal cost, an increase in load such as off-peak heating or fish processing would greatly improve the economics of this project. LOCHER INTERESTS LTD. Page 26 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Unalaska: Unalaska, located on Unalaska Island in the Aleutian Islands has a population of around 4,090. Average annual energy generated by Unalaska, over the FY 1992 - 1997 period, was 25,194,869 kWh. Average monthly generation over this period was 2,099,572 kWh. The system peaks slightly in winter but is relatively constant year round. Currently, Unalaska is served by three diesel units providing approximately 8.0 megawatts of installed capacity (two units rated at 2,000 kW and one at 4,000 kW). Table 6.4. Unalaska average monthly generation, in kWh, from data for Fiscal Years 1992 -1997. Month Average Generation; kWh January 2118404 February 2583722 March 2556576 April 2088508 May 2044527 June 1897441 July 1831638 August 2080769 September 1940942 October 2046122 November 2025393 December 1980829 Average Annual 2099572 Past reports have identified a number of options for supplying hydropower to Unalaska. Developments ranging in size from 1,430: kW to 90 kW have been studied. The most economical options appear to be projects that would: 1) support an installation sized at about 100 kW, designed to tie into the City’s existing water supply line and use only the City’s water supply demand or, 2) a slightly larger development, of about 260 kW, also utilizing the City water supply with additional water diversions. Both of these options have been evaluated in this study. Various options are possible to provide water to this project, over and above simply tying in to the existing water supply line. Increasing the height of the existing water supply diversion dam, and the addition of a second diversion dam downstream are possible options. A small concrete dam, sheet piling in a concrete strip which is anchored to bedrock, a small rubber dam, or a timber dam bolted to bedrock are all possibilities which have been proposed. Further analysis will be required to identify the best solution. Similarly, use of the existing water supply pipeline and partial or complete replacement of the pipeline with steel or HDPE pipe are options. For the 260 kW installation, a horizontal Francis turbine, rated for 22 cfs and 170-ft of net head is assumed. For the option utilizing only the available City water supply, a 100 kW Francis turbine is assumed. Because the possible range of options for this development is so wide, two alternative have been evaluated. These are the small (100 kW) development and the 260 kW alternative. Given the range of options possible for a development at this site, it is not surprising that a wide range of costs also exist. For this analysis, costs are bracketed using a high estimate of $1,283,000 and a low estimate of $400,000. As in the case of previous costs, the low range estimate assumes use of local labor and turnkey methods which have a higher risk associated with them. Economic evaluation of a smaller (100 kW) project, using the low-end cost estimate, indicate that the project has net positive benefits under all combinations of assumptions used. These range from $329,376 for the most pessimistic case to $830,356 for the mid-case, and $1,693.529 for the most optimistic assumptions. LOCHER INTERESTS LTD. Page 27 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY. PHASE 1 REPORT Figure 6.4 below presents the probability distribution of results for this development. As shown, all combinations of critical assumptions produce positive results for this case. , Figure 6.4 Probability Distribution of Net Benefits: Unalaska 100 kW Power Recovery 0.25 ° i) ° a a probability ° Net Benefits (million 1996$) For the 260 kW development, economic evaluation indicates that the project produces positive net economic benefits of $3,900,000 for the most optimistic case, a negative $165,000 for the mid-case (essentially break-even), and a negative $707,000 under the most pessimistic case. Probability distribution of net benefits shows that in two-thirds of the combinations of assumptions the project produces net benefits in the positive range (Figure 6.5 on page 29). LOCHER INTERESTS LTD. Page 28 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Figure 6.5 Probability Distribution of Net Benefits: Unalaska 260kW 0.18 0.16 0.14 0.12 0.1 0.08 0.06 0.04 0.02 mw prob probability So So <= Q ba 2 2 oS So So - = N N 3.2 3.7 Net Benefits (million 1996$) Break-even analysis indicates that low discount rates and/or low hydro O&M costs are critical to the / economic viability of this project. LOCHER INTERESTS LTD. Page 29 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT 7.0 RECOMMENDATIONS FOR PHASE 2 Based on the results of Phase 1 analysis, it is recommended that the two potential projects found to have generally positive net benefits under the economic evaluation be investigated further to better define their economic and financial viability. Community Project Old Harbor Unnamed Creek Unalaska Pyramid Creek Further review should include a site visit by members of the project team to meet with local utility managers and community officials, verify existing conditions, more detailed review of the proposed plan vis a vis site conditions, existing and anticipated loads, development of updated costs, and a final economic evaluation utilizing the same methods as those employed herein. LOCHER INTERESTS LTD. Page 30 of 30 August 18, 1997 ATTACHMENT 7 KING COVE HYDROELECTRIC PROJECT EXCERPT — FEASIBILITY STUDY FEBRUARY 1991 KING COVE HYDROELECTRIC PROJECT FEASIBILITY STUDY Prepared for: Alaska Energy Authority 701 East Tudor Road Anchorage, Alaska 99519 HDR Engineering, Inc. 4446 Business Park Boulevard Building B Anchorage, Alaska 99503 February 1991 For this analysis, costs for all years are computed in inflation free 1990 dollars. The model does not increase costs by inflation but calculates present value of future costs by using a discount rate equal to the nominal interest minus inflation. This is the same method that was used by,AEA.in 1988 (3). . : The base year of economic analysis is 1990 as actual City generation data was available for that year. The electric load and generation data of Peter Pan collected and used by AEA in 1985 (3) are used for this analysis. This data represents the most recent data collected for the seafood processor. Peter Pan was contacted to discuss their generation system and any changes to that system since 1985. These changes have been incorporated into this analysis. Table 10 presents the economic analysis for a two 350 kW unit hydroelectric project serving only the City of King Cove. The project is assumed to be delivering power by 1994. The base case analysis assumes increasing the 800 kW present firm capacity through generation replacements to 1,000 kW for capacity in 1992 and increasing capacity to 1,300 kW in 2002. Firm capacity represents the required generation capacity to meet electric demand including generator down time for repairs. Firm capacity is maintained through replacement of existing generators in the years noted. The two existing old 300 kW City units would be replaced in 1992 with a single 500 kW unit under both cases. Other generation equipment replacements and additions are shown. Some diesel generation will be required during each year because of low creek flows. This is reflected as minimum diesel generation requirement in line 16. The minimum was derived as noted in the previous assumptions. Electricity generated in excess of the City needs and generator waste heat was assumed to have no value. No costs were included for construction of new generator buildings. Table 11 presents a similar analysis of the Delta Creek hydroelectric project with the assumption of one 700 kW hydroelectric generation unit installed to serve the City and Peter Pan by 1994. Again replacement and increases in diesel generation capacity were developed from the conversations with Peter Pan and as previously noted for Table 10. Electricity generated in excess of the City and Peter Pan needs and generator waste heat was assumed to have no value. It was assumed that Peter Pan and the City represent an infinite load and all hydroelectric generation can be used. This assumption may not be valid because peak hydroelectric generation may not correspond to peak electrical demands. Because this is a run-of-the-river project and generation depends on flow in Delta Creek, a daily generation capacity should be estimated prior to sale of electricity negotiations. Table 10 shows the base case present value to be $15,372,000 and the hydroelectric meen \L- value to be $15,137,000, with the 34 year cost-to-cost ratio 1.02. The project is defined as feasible. Table 11 shows the base case present value to be $35,442,000 and the hydroelectric present value to be $35,431,000 with 34 year cost-to-cost ratio 1.00. The project is defined as feasible. 07073.003:N:8:D10 51 ATTACHMENT 8 TAZIMINA HYDROELECTRIC PROJECT EXCERPT — FEASIBILITY STUDY MAY 1991 TAZIMINA RIVER HYDROELECTRIC PROJECT FEASIBILITY STUDY Prepared for: Tliamna-Newhalen-Nondalton Electrical Co-Op (INNEC) Box 206 lliamna, Alaska 99606 Prepared by: HDR Engineering, Inc. 4446 Business Park Boulevard Building B Anchorage. Alaska 99503 May 1991 additional capacity requires capital expenditure beyond the basic O&M budget. ° If the hydroelectric project is built and is on line in 1995, then the 320 kW diesel unit would not need to be bought in 1995, and the existing diesel generators would provide sufficient peaking capacity until 2009. Other generation equipment replacements and additions are shown. A minimum diesel generation of 5 percent annual system load (line 15, Table 5) has been assigned to account for diesel generation required during hydroelectric downtime and to meet daily peaks. ¢ Electricity generated in excess of the utility needs was assumed to have no value. Table 5 shows the diesel net present value to be $32,218,000 and the hydroelectric net present value to be $24,332,000 for the 30 year comparative analysis period. The present worth cost-to- cost ratio for this analysis is 1.32. The project is defined as feasible. A sensitivity analysis was completed to determine the effect of varying six of the economic parameters that affect the cost to cost ratio. Construction cost, initial fuel price, load growth, fuel escalation rate, interest rate, and inflation rate were each varied one at a time within a reasonable range and the present worth cost-to-cost ratio tabulated. This is shown in Figure 3. None of the six assumptions, when varied independently by plus or minus 50 percent, caused the cost-to-cost ratio to drop below 1.0. A combination of factors, however, such as a large cost et overrun accompanied by a drop in oil prices, could conceivably cause the project cost-to-cost Tatio to drop below 1.0, and therefore, define the project as not feasible. Calculations using a variation of the economic analysis period were also performed. They showed that the project has a cost-to-cost ratio of 1.08 for an analysis period of 20 years and 1.40 for an analysis period of 50 years. The addition of 30 percent of the Cominco workforce to be served by INNEC increased the cost- to-cost ratio to 1.36. The hydroelectric project is undersized even for the expected increases of the community without the additional Cominco growth. With increased growth the turbine capacity is exceeded sooner and increased fuel costs are incurred to provide for demand. If the project were upsized (analysis of project size was not in the scope of this study), the cost-to-cost ratio for a high load growth scenario could increase. N:07250.001:1:D8 12 ATTACHMENT 9 REYNOLDS CREEK AND THAYER CREEK HYDROELECTRIC PROJECTS DIVISION OF ENERGY LOAN ANALYSIS OCTOBER 1996 Power Project Fund — Haida Corporation A. Information Item A. $2,000,000 loan application from Haida Corporation, the village corporation for the community of Hydaburg, to finance in part the proposed Reynolds Creek hydroelectric project on Prince of Wales Island. The applicant submitted an alternative loan application for $1.0 million to be considered if $2.0 million is not available. Background Electric utility service in Hydaburg is provided by Alaska Power and Telephone Co. (AP&T). Our most recent statistical reports provide the following basic data: Hydaburg/ AP&T Population 415 Annual kWh sales 1.5 million kWh Peak demand 0.4 MW Diesel fuel price $0.93 per gal kWh sold per gallon 13.0 Annual fuel cost $107,052 Average residential rate 15.8 cents per kWh Effective rate after PCE 10.4 cents per kWh Construction of a hydroelectric project at Reynolds Creek has been considered over a number of years. Significant previous studies available in the Division of Energy library include the following: 1. Black Bear Lake Project Feasibility Report. Harza Engineering Co. and CH2M Hill Northwest. October 1981. A reconnaissance review of Reynolds Creek was conducted as a possible alternative to the Black Bear Lake project. Referred to as the “Lake Mellen” project, a 6.0 MW project was defined with an estimated cost of $34.2 million (1981 dollars), including transmission to Craig/Klawock as well as Hydaburg. Prepared By: Division of Energy / DCRA October 1996 Power Page 2 Project Fund — Haida Corporation 2. Hydaburg Hydro Investigation. HDR Engineering, Inc. November 1991. A 750 kW project was defined, with provision for expansion to 1.5 MW, at an estimated cost of $7.7 million (1992 dollars). Over half of the project cost was attributable to the transmission line to Hydaburg. Haida Corporation has been working for several years with its consultant, Mountain Energy, Inc., to define, license, and finance a hydro project at Reynolds Creek that will provide economic benefits in the region. Supported by federal grant funds administered by the U.S. Department of Energy (USDOE), Haida Corporation and its contractors have been conducting design and environmental studies under the terms of a preliminary permit issued by the Federal Energy Regulatory Commission (FERC) in December 1994. They intend to submit an application for a FERC license by the end of 1996 or early 1997. Project Information ie According to the loan application, the estimated capital cost of the project is $7.6 million. The application does not make clear whether this estimate is expressed in 1996 dollars or includes future inflation. Project financing was anticipated as follows: A. _ At the time of the loan application, federal grant funds in the amount of $2.0 million had been appropriated for the project. This is in addition to the federal funds that are presently supporting the FERC license application and environmental studies. B. ‘The loan application states that Haida Corporation has committed $2.0 million of its own funds as an equity investment in the project although no documentation of this commitment was provided. The PPF loan application instructions direct the applicant to document the availability of other funds needed to complete the project. Cs Of the remaining $3.6 million financing requirement (assuming the $7.6 million estimate includes inflation), the Power Page 3 D. Project Fund — Haida Corporation applicant seeks either $1.0 million or $2.0 million from the Power Project Fund, and states that the remainder will be sought in the form of additional loans or grants from the State and/or federal governments. Ds After the loan application was submitted, an additional $1.0 million in federal grant funds was appropriated for the project. Adjusting the the loan application to account for this, project financing could now be proposed as follows: Federal grants $3.0 million Haida Corp. equity 2.0 million PPF loan 2.0 million Other .6 million Total $7.6 million Bh The project configuration as proposed would initially yield the following: A. 1.5 MW installed capacity. B. 13.1 million kWh average annual energy. For an additional cost not specified in the loan application, the applicant proposes to expand the project to 5.0 MW and 27.0 million kWh when justified in the future by increased demand. The $7.6 million cost estimate includes transmission only to Hydaburg which presently consumes about 1.5 million kWh per year — about 10% of the project’s initial energy capability. Technical Feasibility Sufficient information is provided in the application and in other materials previously submitted to the Division to confirm the project’s technical feasibility. Division engineering staff recommends an independent review of the project cost estimate before considering financial participation in the project. Financial Feasibility Power Page 4 Project Fund — Haida Corporation With respect to project financing, the loan application assumes the following: 1. a maximum debt component of $3.0 million at 6.2%, 2. Haida Corp. equity of $2.0 million, 3. $2.6 million balance funded from federal and State grants. Although $3.0 million in federal grants has already been appropriated, the financing structure defined above provides a useful starting scenario in view of the Division’s uncertainty on the overall project cost estimate. Annual revenue requirements in this scenario are as follows: 1. Debt service on $3.0 million at 6.2% over 30 years is $222,631 per year. 2: The applicant estimates annual O&M costs for the hydro project at $140,000 although no breakdown of this estimate is provided. 3. The application does not discuss the expected timing and amount of return on equity. While the applicant may settle for no revenue in one or more early years of the project, substantial revenue must be anticipated later on. Leaving aside for now the question of return on equity for Haida Corporation, the annual revenue requirement in the early years of project operation would be $362,631 for the financing scenario outlined above. The loan application does not discuss the avoided cost of diesel generation for comparison with projected hydro costs. From our statistical reports we know that the annual cost of diesel fuel for the electric utility in Hydaburg is presently $107,052. Assuming for illustration that $0.05 per kWh would also be avoided for diesel O&M and capital costs, savings would be increased by about $75,000 per year yielding a total of $182,052 in avoided diesel generation costs. This is about half of the initial year hydro cost estimated above for the initial financing scenario. Clearly, some combination of increased savings and reduced costs would be necessary for the project to meet financial feasibility criteria. Power Project Fund — Haida Corporation Page 5 An alternative scenario is therefore considered below that assumes government grants totalling $3.6 million, a zero interest PPF loan of $2.0 million, and deferral of Haida Corporation’s initial return on $2.0 million of equity until year 6 of project operation. This alternative scenario is examined with respect to a base load forecast and a high growth forecast as presented by the applicant: Le The base load forecast is defined by the applicant as 2.84% per year, representing the average annual growth over the last 10 years. Assuming the first year of project operation is 2000, energy demand is projected as follows: a. 1.7 million kWh in year 1 of project operation, and b. 2.0 million kWh in year 6 of project operation. The high forecast defined by the applicant is as follows: a. 4.0 million kWh in year 1 of project operation (assumed herein to be the year 2000), and b. 17.0 million kWh in year 6 of project operation (assumed herein to be 2005). The applicant supports the high load forecast with a number of assumptions but does not provide a breakdown of the quantitative impact of each assumption. These assumptions include: a. Construction of new residences averaging 30 per year following issuance of 500 new residential lots in 1996 to Haida Corporation shareholders. Our statistical reports indicate that, presently, there are 142 total residential customers in Hydaburg. b. Conversion of existing residences to electric space heat as preferential space heating rates become available. Although the application provides no further detail on this assumption, it has been discussed somewhat more by others in previous Power Project Fund — Haida Corporation Page 6 consideration of the project. A retail electricity price of $.03 to $.04 per kWh is equivalent to $1.00 per gallon fuel oil. To provide an incentive for residential customers to incur the cost of heating system conversions, the space heating rate must be substantially below the equivalent fuel oil rate — probably no higher than $.02 per kWh. cs Industrial development “in the form of fish processing and storage and secondary wood processing” that will occur when project power becomes available, as well as other commercial developments. d. Other unspecified growth. The applicant observes that growth is continuing throughout Prince of Wales Island. Because total energy available from the project is limited to 13.1 million kWh as initially constructed, and since the cost of expanding the project is not addressed in the loan application, the following example assumes for the high case that energy sales in 2005 are limited to 13.1 million kWh. The example also assumes that project output can be timed to meet the entire load requirement in 2005. although information to support this assumption is not presented in the loan application. Alternative Scenario Major assumptions: ie Zero interest loan over 30 years from Power Project Fund for $2.0) million. Haida Corporation equity investment of $2.0 million. Revenue to Haida Corporation is: a. Zero in year | of project operation. b. $200,000 in year 6 of project operation. Note that revenue must escalate above this level in later years for Haida Corporation to achieve a reasonable return on equity given the Power Page 7 Project Fund — Haida Corporation assumption that any return is deferred in the early years of project operation. 3. Government grants totalling $3.6 million (of which $3.0 million has been appropriated to date by the federal government). The revenue requirement in the first year of project operation would be $206,666 as follows: 1. $66,666 debt service on zero interest, $2.0 million PPF loan, plus 2. $140,000 hydro O&M. The revenue requirement in year 6 of project operation would be $406,666, adding in the $200,000 of revenue to Haida Corporation. Although the applicant did not estimate avoided diesel generation costs, the assumptions used for illustration in this example are: 1. $0.07 per kWh diesel fuel cost, plus 2 $0.05 per kWh diesel O&M and capital cost — for an overall avoided cost of $0.12 per kWh. The results of this scenario are as follows: 1. Given the base load forecast, costs and savings are as follows in year 1 of project operation: a. Hydro cost is $206,666. b. Avoided diesel cost is $204,000 (i.e. $0.12 X 1.7 million kWh). 2. Given the base load forecast, costs and savings in year 6 of project operation are as follows: a. Hydro cost is $406,666. b. Avoided diesel cost is $240,000. Power Page 8 Project Fund — Haida Corporation Conclusion #1: Given the base load forecast, the project does not meet financial feasibility criteria given a zero interest State loan for $2.0 million, State and federal grants of $3.6 million, and equity investment by Haida Corporation of $2.0 million. In this scenario, the major factor that leads to this result is the revenue needed for Haida Corporation to recover its equity investment. 3. Given the high load forecast, costs and savings are as follows in year 1 of project operation: a. Hydro cost is $206,666. b. Avoided diesel cost is $480,000 (i.e. $0.12 X 4.0 million kWh). While this example calls out for closer scrutiny of the $0.12 per kWh avoided diesel cost assumption, substantial savings would be realized even if avoided costs were limited to $0.07 per kWh in fuel savings: $0.07 X 4.0 million kWh yields $280,000, well above the initial year hydro cost. 4. Given the high load forecast, costs and savings in year 6 of project operation are as follows: a. Hydro cost is $406,666. b. Avoided diesel cost for fuel alone would be $917,000 (i.e. $0.07 X 13.1 million kWh), and would be substantially higher with the inclusion of avoided capital and O&M costs. Conclusion #2: Based on the high load forecast, the project meets financial feasibility criteria given a zero interest State loan for $2.0 million, State and federal grants of $3.6 million, and equity investment by Haida Corporation of $2.0 million. The major factor leading to this result is the assumption that loads will increase dramatically in the near future. The high load forecast does not have to be quite so high for financial feasibility criteria to be met. The following is a modified case based on less aggressive assumptions: Power Project Fund — Haida Corporation Page 9 Conclusion #3: The project can meet financial feasibility criteria under a combination of favorable assumptions, one possible set of which are Avoided diesel cost is estimated at $0.09 per kWh. Load requirements are: a. 2.5 million kWh in year 1 of project operation. b. 4.5 million kWh in year 6 of project operation. Given these assumptions, year | costs and savings are as follows: a. hydro costs are $206,666. b. avoided diesel costs are $225,000. Given these assumptions, year 6 costs and savings are as follows: a. hydro costs are $406,666. b. avoided diesel costs are $405,000. as follows: ile An additional $600,000 in grant funding is obtained, bringing total government grants to $3.6 million. A zero interest, $2.0 million loan is approved from the Power Project Fund. (Additional grant funds would be needed if the zero interest loan were limited to $1.0 million.) A $2.0 million equity investment is made by Haida Corporation, which agrees to defer any substantial return during the early years of the project. Electric energy requirements in Hydaburg increase from today’s level of 1.5 million kWh per year to 2.5 million kWh in the year 2000 and 4.5 million kWh in 2005. Power Project Fund — Haida Corporation Page 10 As previously noted, Alaska Power & Telephone (AP&T) presently serves as the electric utility in Hydaburg. In a letter dated June 7, 1996, addressed to the agent for Haida Corporation, AP&T states its belief that “the load in Hydaburg and the estimated cost of diesel generated electric power does not appear to support the [Reynolds Creek hydro project] on an economic or financial basis.” The letter takes the developer to task for not supplying appropriate economic and financial analyses in the context of its licensing studies to date. F. Conclusions The proposed Reynolds Creek hydro project is technically feasible. With respect to financial feasibility, however, the application submitted by Haida Corporation does not provide the information needed to support a $1.0 or $2.0 million loan in connection with a $7.6 million project: i No information is provided on the expected timing and amount of revenue to Haida Corporation in connection with its $2.0 million equity investment. No documentation with respect to the equity investment is included with the application — e.g. a resolution adopted by the corporation’s board of directors. 2s The electric utility that serves Hydaburg, AP&T, opposes the project and no power sales agreement — conceptual or otherwise — has been reached. 3! While the Division can estimate the avoided diesel fuel costs by referring to our own statistical reports, the loan application provides no breakdown or discussion of other avoided diesel generation costs. 4. While the Division can define some assumptions and conduct its own rudimentary financial analysis, the loan application provides no systematic analysis of costs, savings, cash flow and rate impacts from which the Division can assess financial feasibility. ay The project is critically dependent on major, sustained growth in electricity demand. To the extent such growth depends on identified developments, signed power purchase agreements may be needed to provide security for the requested loan. The application provides Power Project Fund — Haida Corporation \ Page 11 very little information on the sources of load growth and provides no information from which the Division could assess its likelihood. Because $3.0 million has already been appropriated by the federal government for project construction, the Division concludes that the additional grant funding needed for the project may be achievable. If sufficient grant funding is made available, it is possible that a financial package could be put together which, in combination with sufficient load growth, could provide benefits to Hydaburg ratepayers. The Division does not propose to approve the loan application as submitted for this solicitation. As discussed above, there are too many uncertainties about the project at this time including issues that are critical to project financing. The applicant can reapply in response to any future solicitation of loan applications under the Power Project Fund program. Power Project Fund -- Kootznoowoo Inc. A. B. Information Item A $1,000,000 loan application from Kootznoowoo Inc., the village corporation for the community of Angoon, to finance in part the proposed Thayer Creek hydroelectric project on Admiralty Island. Background Electric utility service in Angoon is provided by Tlingit-Haida Regional Electrical Authority (THREA). Our most recent statistical reports provide the following basic data: Angoon / THREA Population q25 Annual kWh sales 1,840,150 Peak demand 0.4 MW Diesel fuel price $0.79 per gal kWh sold per gallon 11.9 Annual fuel cost $121,067 Average residential rate 33.4 cents per kWh Effective rate after PCE 14.3 cents per kWh Construction of a hydroelectric project at Thayer Creek has been considered over a number of years. Significant previous studies available in the Division of Energy library include the following: iF Thayer Creek Project: A Reconnaissance Report. Harza Engineering Company. October 1979. Construction cost of 400 kW project, including a 56 foot dam, estimated at $9.4 million. 2. Angoon Hydro Study. Polarconsult Alaska, Inc. August 1989. Construction cost of a 400 kW project, based on a tunnel scheme instead of a dam, estimated at $3.3 million. Prepared By: Division of Energy / DCRA October 1996 Power Page 2 D. Project Fund — Kootznoowoo Inc. Provision was made within the Alaska National Interest Lands Conservation Act (ANILCA) for possible future construction of the project by Kootznoowoo Inc. A relevant excerpt from ANILCA included in Kootznoowoo’s loan application is attached. Project Information The following project information is taken from the loan application: 1. The estimated construction cost is $8.5 million (1996 dollars). Project financing is anticipated as follows: A. Kootznoowoo expects to receive $7.5 million (plus inflation) in federal grants for the project. However, the loan application provides no documentation or further information on the source of these funds. B. _ The $1.0 million balance is requested from the Power Project Fund. 2a The project configuration as proposed would yield the following: A. 1.0 MW installed capacity. B. 0.8 MW “firm capacity.” Cc 9,000,000 kWh per year available energy. Technical Feasibility The application states that “Kootznoowoo has recently completed the feasibility study stage of the Project.” However, the loan application did not include a copy of a feasibility study. Elsewhere, the application states that the project is at a “preliminary engineering feasibility stage” and that detailed site specific information is not yet available. Because very little information about the project is provided in the loan application, it is not possible at this time for Division staff to form any opinion about the technical feasibility of the project concept or the adequacy of the cost estimate. The earlier studies noted above do conclude Power Page 3 Project Fund — Kootznoowoo Inc. that some form of hydroelectric development is technically feasible at the site. Financial Feasibility In addition to the capital cost estimate of $8.5 million, the loan application indicates that annual O&M cost for the project will be $80,000 per year. No back-up is presented in connection with the O&M estimate. The loan application addresses financial feasibility only under the assumption that $7.5 million in federal grants will be obtained for the project. The financial feasibility calculations included in the loan application are confusing* but it appears that avoided diesel generation cost is assumed to be $180,000 per year. Since recent fuel cost is known to be $121,067 per year, this leaves roughly $60,000 per year for other avoided diesel costs. No detail is provided that would allow the Division to evaluate this estimate. If $7.5 million in federal grants were obtained, the loan application suggests that the requested $1.0 million loan would be financially feasible at the assumed tax exempt interest rate of 6.2%: i Annual debt service on $1.0 million over 30 years at 6.2% is $74,210. Ds Adding $80,000 per year in hydro plant O&M yields a total annual hydro production cost of $154,210, somewhat less than the avoided diesel generation cost estimate of $180,000. Clearly, these numbers also suggest that the project would be financially infeasible in the absence of sizeable grant contributions. For example, if the entire $8.5 million project cost were financed at 0% interest over 30 years, the annual debt service alone would be $283,000. Adding $80,000 per year in hydro O&M would bring the annual cost to $363,000, roughly twice the amount suggested as the avoided diesel cost. * It is stated in the application narrative that the hydro project would reduce diesel O&M and fuel costs by $346,000 per year. This is based on a value for “operating expenses” of 17.3 cents per kWh (as shown in the FY 95 PCE statistical report) times 2.0 million kWh per year. However, the 17.3 cents found in the PCE statistical report actually represents all costs of the utility except for fuel and debt service. In the financial feasibility tables prepared by the applicant, it appears that about $180,000 of this amount is actually assumed to be avoidable diesel costs while the other $160,000 is assumed to be unavoidable. as -> Power Project Fund — Kootznoowoo Inc. Page 4 Although the views of THREA - the utility serving Angoon — are not discussed in the loan application, THREA management has previously indicated that it would be receptive to buying power from the Thayer Creek project if the price were favorable compared with avoided diesel generation costs. F. Conclusions The application submitted by Kootznoowoo Inc. does not provide the information needed to support a $1.0 million loan in connection with an $8.5 million project: 1. There is no design information, conceptual or otherwise, from which the Division could determine if the project concept is technically feasible. 25 There is no information from which the Division could determine if the capital and O&M cost estimates for the project are reasonable. 3: There is no documentation or other information regarding the likelihood, timing, or source of the $7.5 million in federal grants sought by the applicant. To our knowledge, none of this funding has been obtained to date. 4. While the Division can estimate the avoided diesel fuel costs by referring to our own statistical reports, the loan application provides no breakdown or discussion of other avoided diesel generation costs. 55 No load forecast is provided nor any discussion of contacts with the electrical utility serving Angoon. The Division does not propose to approve the loan application as submitted for this solicitation. As discussed above, there are too many uncertainties about the project at this time including issues that are critical to project financing. If sufficient grant funding is made available in the future, it is possible that a financial package could be put together which could provide benefits to ratepayers in Angoon. The applicant can reapply in response to any future solicitation of loan applications under the Power Project Fund program. ATTACHMENT 10 RURAL NATURAL GAS STUDY EXECUTIVE SUMMARY FEBRUARY 1997 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 rura/ 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/Soldoma, 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 “Exploration is becoming, quite for /ocal entrepreneurial independents does not have to meet decisively, a _ technologically traditional payback analysis to be undertaken.’ Often, the sophisticated and systematic independent is attracted to prospects with a relatively low research and development activity probability of success and what appears to be a big payoff. rather than the far more romantic The basic ingredients for an entrepreneurial exploration but decidedly more uncertain program are equipment, material, sweat equity, and luck. “intuitive geology” that was Under this model, exploration for natural gas aimed at serving characteristic of natural gas domestic Alaskan markets may occur if exploration equipment exploration until the late 1980s.” is available to local entrepreneurs at a significant discount. 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 modem exploration program for coalbed methane 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: ¢ — larger 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 Jong 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. 6 “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 ATTACHMENT 11 UNALASKA (MAKUSHIN) GEOTHERMAL PROJECT EXECUTIVE SUMMARY -— FEASIBILITY STUDY FEBRUARY 1995 Final Report Comparative Power Cost Analysis of the Makushin Geothermal Project - “Alaska Industrial Development ~~ and Export Authority February 28, 1995 EXECUTIVE SUMMARY INTRODUCTION Over the past two decades, the economy of the Unalaska/Dutch Harbor area has grown considerably, primarily due to growth in the local seafood processing and shipping industry. In response to the need to locate processing facilities near the fishing grounds, several large international companies have established operations in the Unalaska/Dutch Harbor area. The resulting growth has created certain problems, including the logistical and air quality problems associated with providing electric power to area residents and businesses. Electric power is currently provided entirely from diesel generators located at the local load centers. As the economy has grown in recent years, so has the installed diesel capacity and the generation of electrical energy. In order to lessen the area's dependence on oil as the sole fuel source, alternative resources have been investigated for a number of years. These — investigations have recently developed a new urgency as energy requirements have caused some existing generating sites on the island to approach or surpass currently permitted emissions limits. One of the potential generating options is a geothermal-fueled generator, which would take hot fluids from the Makushin Volcano area, use the fluid to produce electrical energy, re-inject the fluid into the ground, and transmit the electrical energy to the load centers in the Unalaska/Dutch Harbor area. PURPOSE The purpose of this report is to provide the Alaska Industrial Development & Export Authority (“AIDEA”) with projections of life-cycle costs of electric energy over a 30-year period, allowing AIDEA to evaluate the Makushin Geothermal Project ("Makushin" or the "Project") against other power generation options. This study includes a review of a diverse set of resource options, including combustion turbines, internal combustion diesels, coal, wind, and hydroelectric generation. —— EXECUTIVE SUMMARY STUDY RESULTS After an environmental and economic screening of the available power supply options, two alternative power supply plans were developed to compare to the Status Quo Alternative (continuation of current operations). These were the Integrated Diesel Alternative, (addition of baseload diesel generation at a new site), and the Makushin Alternative for which it was to be assumed that some level of grant funds would be made available. Based upon a preliminary economic analysis, AIDEA directed that the grant amount be set at $45 million. The three alternatives were examined in a detailed production cost and financial analysis over a 30-year period. The total 30-year “life-cycle” costs of power were also aggregated to an equivalent cost in 1998 on a present value basis, for ease of comparison. The following table shows the results of the study of the three alternatives under several possible load growth and fuel price escalation scenarios. f-\wp2156.aa5\rpt2.doe ‘ Page [-2 No Load Growth 3% Load Growth Loss of Load No Load Growth 3% Load Growth Loss of Load fAwp2156.aa5\rpt2.doc Alternative” Table ES-1 SUMMARY OF RESULTS 30 Year Life-Cycle Costs Base Fuel Price Escalation Status Quo Integrated Diesel Alternative EXECUTIVE SUMMARY Makushin Alternative” $182,400,000 $177,700,000 Best Case $234,500,000 Best Case” $185,700,000 $179,400,000 Best Case “1 High Fuel Price Escalation $192,200,000 Best Case” $197,800,000 $261,200,000 $195,700,000 5% above Makushin 4% above Makushin (1) Violates current air quality related generation limits. (2) Assumes grants totaling $45 million. (3) Results are within 2% and judged to be equal for purposes of this study. $192,800,000 8% above Integrated Diesel $239,500,000 Best Case”) $186,700,000 4% above Integrated Diesel $194,300,000 Best Case” $249,400,000 Best Case $187,900,000 Best Case Payee 1-3 EXECUTIVE SUMMARY PRIMARY CONCLUSIONS The following primary conclusions were developed based on the assumptions and analyses presented in this study. Other general conclusions are included in Section 5 of this report. i The Status Quo Alternative violates current air quality related generation limits, a situation which will be exacerbated by any future load growth. Both the Integrated Diesel Alternative and Makushin Alternative would bring the Unalaska/Dutch Harbor area into environmental compliance and allow for future load growth. Present environmental problems cannot be adequately addressed without island-wide interconnection and coordinated dispatch. The Integrated Diesel Alternative is the least-cost alternative under the following assumptions: = No load growth/Base fuel price escalation » Loss of load/Base fuel price escalation The Makushin Alternative is the least-cost alternative under the following assumptions: « 3% load growth/High fuel price escalation « Loss of load/High fuel price escalation 6. The Integrated Diesel and Makushin Alternatives are approximately equal under the following assumptions: » No load growth/High fuel price escalation = 3% load growth/Base fuel price escalation f\wp2156.aa5\rpt2.doc Page 1+ ATTACHMENT 12 KOTZEBUE AND SAND POINT WASTE HEAT STUDIES EXECUTIVE SUMMARIES 1990 KOTZEBUE WASTE HEAT RECOVERY REPORT AND CONCEPT DESIGN MARCH 30, 1990 TABLE OF CONTENTS 1.0 EXECUTIVE SUMMARY 1 2.0 INTRODUCTION 2 3.0 DESCRIPTION OF SITE VISIT 4 40 POWER PLANT DESCRIPTION 5 5.0 POTENTIAL WASTE HEAT USER BUILDING DESCRIPTIONS 12 6.0 RIGHT-OF-WAY/EASEMENT 43 7.0 CONCEPT DESIGN 44 8.0 ECONOMIC DATA 81 9.0 FAILURE ANALYSIS 84 10.0 CONCLUSIONS AND RECOMMENDATIONS 94 APPENDICES 1. Calculations 2. Contact Names 3. Cost Estimates 4, Raw Data 1.0 KOTZEBUE WASTE HEAT RECOVERY REPORT AND CONCEPT DESIGN MARCH 30, 1990 EXECUTIVE SUMMARY A potential for waste heat recovery exists in the community of Kotzebue. Kotzebue |s lo- cated on the northwest shore of the Baldwin Peninsula in Kotzebue Sound. The com- munity is located 560 air miles northwest of Anchorage. The heat energy could be recovered from the diesel engine-generator sets operated by Kotzebue Electric As- sociation and circulated to user buildings in the community. Twelve possible waste heat user buildings have been identified: the major potential users include the future hospital, the water treatment plant, and the three school buildings (the elementary, middie, and high schoo). , tt appears as if the most advantageous system will provide heat to new hospital, the A.C. Co. Store, the KIC Apartments, the Public Works building, and the Water Treatment building. A summary of the construction cost estimates along with design and SIA costs ls Included In the Cost Estimate Appendix. if the system is installed connecting the above mentioned buildings, the following are the estimated results: : Estimated Project Cost $2,101,900 Total Fuel Oil Savings 214,200 gallons Total Annual Dollar Savings $282.700 SAND POINT WASTE HEAT RECOVERY REPORT AND CONCEPT DESIGN JANUARY 15, 1989 TABLE OF CONTENTS 1.0 EXECUTIVE SUMMARY 1 2.0 INTRODUCTION 2 3.0 DESCRIPTION OF SITE VISIT 4 4.0 POWER PLANT DESCRIPTION 5 5.0 POTENTIAL WASTE HEAT USER BUILDING DESCRIPTIONS 9 6.0 —RIGHT-OF-WAY/EASEMENT 23 7.0 CONCEPT DESIGN 24 8.0 ECONOMIC DATA 4 9.0 FAILURE ANALYSIS 48 10.0 CONCLUSIONS AND RECOMMENDATIONS 58 APPENDICES 1 Calculations 2, Contact Names 3. Cost Estimates 4 Raw Data 1.0 SAND POINT WASTE HEAT RECOVERY REPORT AND CONCEPT DESIGN JANUARY 26, 1990 EXECUTIVE SUMMARY A potential for waste heat recovery exists in the community of Sand Point. Sand Point Is located at Humboldt Harbor on the northwestem coast of Popof Island in the Shumagin Island Group. The community |s located 571 air miles southeast of Anchorage. The heat energy could be recovered from the diesel engine-generator sets operated by Sand Point Electric and circulated to user buildings in the community. Five possible waste heat user buildings have been identified: the Sand Point Electric Administration Building, the U.S. Post Office, a gas station, a retail store, and the School. It appears as If the most economical system will provide heat to SPE Administration bulid- Ing, the Post Office, the Gas Station, the Store, and the school. A summary of the con- struction cost estimates along with design and SIA costs Is included in the Cost Estimate Appendix. If the system Is installed connecting the above mentioned bulidings. the fol- lowing are the estimated results: Estimated Project Cost $673,765 Total Fuel Oil Savings 56,575 gallons Total Annual Dollar Savings $69,327 Page 1 ATTACHMENT 13 MCGRATH COAL-FIRED POWER PLANT EXECUTIVE SUMMARY -— FEASIBILITY STUDY MARCH 1997 MAY-21-99 FRI 09:52 AM P, 05 A Feasibility Analysis of a Proposed Coal Fired Thermal Power Station at McGrath, Alaska for MTNT, Limited and McGrath Light and Power P.O. Box 309 McGrath, Alaska 99627 FINAL DRAFT - May 3, 1997 by J.S. Strandberg Consulting Engineers, Inc. Anchorage, Alaska in association with Parsons Power Group, Inc. ; Reading, PA | Northern Economics, Inc. Anchorage, Alaska 99501 March, 1997 MAY-21-99 FRI 09:52 AM / P, 06 McGrath Coal Fired Power Plant Feasibility Project - FINAL DRAFT - 5/3/97 1 1.0 EXECUTIVE SUMMARY A regional energy project that will make use of an Alaskan low rank coal deposit to create power and heat for the City of McGrath Alaska, has been analyzed for feasibility. McGrath is a rural Alaskan community of 500 people situated on the Kuskokwim River in the southwestern Alaska interior This project consists of 1) a coal fired cogeneration power plant in McGrath, Alaska, 2) the development of the Little Tonzona River coal deposit into a producing open pit mine, and 3) development of a winter haul route to transport this coal to the McGrath power plant. The feasibility considered two options for the McGrath Light and Power as follows: Option 1. Diesel. Continue with present operation of internal combustion diesel engine gemerator sets. Option 2. Coal/Diesel, Construct the new coal fired power plant and a district heating system for McGrath. Option 3. Coal/Stand-alone. Evaluate the construction of a new coal fired power plant, without the ongoing debt burden that would be a part of Option 2. - This third option was evaluated to provide a site-nonspecific analysis for the coal fired power plant concept for those wishing to consider the plant for other locations. Feasibility criteria for the successful option require that a net present value of all future costs, when added together must be a positive number, and larger than any competing option. As an integral part of the analysis, it is assumed that all but $1.0 Million of first cost of construction would be granted, and the $1.0 Million would be provided by McGrath Light and Power (ML&P). All downstream operating costs would be borne by ML&P. The project develops one approach for employing an Alaskan low rank coal deposit in a long term energy solution for rural Alaska. The project employs a proven coal combustion technology for energy conversion, and applies this to support a critical need of McGrath, that of regional energy self sufficiency, linking community energy solutions to local employment. The project develops a regional coal resource at Little Tonzona River, which is about 90 miles from McGrath, to yield a producing surface coal mine. A winter haul route is envisioned to transport 20,000 tons of mined coal to McGrath every other year. The winter haul operation will be accomplished by contractors who specialize in winter transport over snow roads. In McGrath, Alaska, a coal fired power plant will be constructed that produces both electricity and heat energy. These two commodities will be sold to the customers of McGrath Light and Power, the utility that will own and operate the power plant. Electricity will be delivered through existing transmission and J. S. Strandberg Consulting Engineers, Inc. MAY-21-99 FRI 09:52 aM P07 McGrath Coal Fired Power Plant Feasibility Project - FINAL DRAFT - 5/3/97 2 distribution wires, while the heat will be conveyed to customers via a hot water medium in a buried two pipe heating distribution system that would be constructed in conjunction with the power plant. This community energy svstem would provide a large portion of McGrath’s energy needs over a project lifetime of 30 years, and would greatly reduce the amounts of heating fuels that are presently purchased outside of and brought into the community at great expense. The system employs a steam rankine cycle comprised of a small steam turbine/electrical generator set with one megawatt gross power output and a stearmn/hot water heat exchanger to transfer heat from the exhaust steam coming out of the back end of the turbine set into a pumped hot water heating medium. Clean burning fluidized bed combustion. technology is used in the coal combustor, where the coal is burned under conditions that minimize the formation and emission of environmental pollutants. This concept of clean, reliable combustion, in a system that has an acceptable overall thermal efficiency and which allows a community to make beneficial use of an indigenous energy resource is the kernel concept of the McGrath project. Earlier project description work established a design and construction cost estimate for the project of $5,562,805. A more detailed cost estimate has been formulated for this feasibility report by the same team of engineers, and the cost estimate has increased to $10,887,680. Major changes are in increased - costs for site work and building, the combustor, and the district heating system (through increasing capacity from 5 to 10 Million BTU/hr}. A total project development budget has also been calculated, which would include all mine, haul route and power plant/district heating system expenses and this estimate is, with a 10% contingency, $13,822,882. Coal Resource and Winter Haul Route: Work accomplished by Doyon, Ltd., establishes the presence of adequate coal reserves at Little Tonzona River. Also, evaluation of the winter haul route in previous studies and on-the-ground reconnaissance of the route in December 1996 established the feasibility of winter haul of coal. While there is concern that costs in some years could be high due to freak weather it should also be noted that other times costs could be lower because unusually good weather creates excellent haul conditions. Feasibility of the Project for McGrath - The Option 2 Coal/Diesel alternative Proposes the construction of the coal fired power plant, development of the What is the next step for McGrath’s energy system development? One primary issue noted in the analysis is the very high parasitic power the circulating fluidized bed combustor requires. This raises fuel consumption of J, S. Strandberg Consulting Engineers, Inc. c. MAY-21-99 FRI 09:53 AM P, 08 McGrath Coal Fired Power Plant Feasibility Project - FINAL DRAFT - 5/3/97 3 the plant dramatically, lowers the overall efficiency, and causes difficulties in designing for system black start. Consideration should be given to finding other types of combustion equipment to lower requirements for parasitic power, and in finding alternate fuel resources in the region to supplant the coal supply. The project configuration examined in this feasibility report is only one of a number of energy system configurations fueled by local energy resources that are possible for rural Alaska. Other small scale fluidized bed combustion systems which have lower parasitic power are to be considered as a replacement for the combustor used in this study, and the use of other indigenous fuels, specifically biomass and peat are being included for consideration, all to reduce costs of operation. Also, there is new data just now becoming available on small scale coal fired power plants operated unattended in the lower 48 states, which might be applicable to this project. It is important to keep the results of this analysis in correct context. Costs tend to be high for coal based power projects, and the McGrath coal fired power plant is no exception. But these coal and alternate fuel projects promise Jong term operation at stable fuel prices, with systems that are enduring and long lived; this alone is a good reason to continue the search for alternative fuels based rural] community energy systems. J. S. Strandberg Consulting Engineers, Inc,