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HomeMy WebLinkAboutUnalaska Reconnaissance Study Of Energy Requirements & Alternatives Appendix-Unalaska 1984DRAFT pe ey RECONNAISSANCE STUDY OF ENERGY REQUIREMENTS ANG: ALTEFRINATIVES _APPENGIX: UNALASKA APRIL 1984 DRAFI PREPARED BY: Milt : 4 ALASKA POWER AUTHORITY. ISSUED TO TABLE OF CONTENTS Section A - Summary of Findings and Recommendations . . . . «© «© © © © © ew we ow B - Demographic and Economic Conditions . . . © «© © «© © © © © ew we ww C = Community Meeting Report. . 2. . «© © «© © © © © © © © © © ow ew ww D - Existing Power and Heating Facilities . ~~. 2. . «© «© © © «© © © e © E - Energy Balance. . . « «= «© «© © «© © © © © © © © © © ow ow ew ew ew ll F - Energy Requirements Forecast. . 2. « «© © © © © © © © © © © © ew ww G - Village Technology Assessment . . . «© «© © © © © © © © © © © ee we H - Energy Plan Desrciptions and Assumptions. . . . 2. 6 2 2 we we we we ee I - Energy Plan Evaluations . 2. 2. 2 2 6 © © © © ee we ee we ew ee J - Environmental and Social Impacts. . 2. 2. 2. 2 2 «© © © © ew ew we ew ew ww APPENDIX A -- Cost Estimates Developed by Republic Geothermal, Inc. For Geothermal Plant at Mt. Makushin APPENDIX B -- Alaska Power Authority Project Evaluation Guidelines Page Ze 25 29 43 A A.l SUMMARY OF FINDINGS AND RECOMMENDATIONS - General After an analysis of the information gathered on the communities of Una- laska and Dutch Harbor, the recommendations which seem to be most appropri- ate to the existing and anticipated conditions and the wishes of village residents are as follows: For the near term, and for the forseeable future, the most economical source of electricity will be diesel engines, especially when they are equipped with waste heat recovery systems. Based on available data, a large (30 MW) geothermal facility does not appear to be economically competitive with the diesel resources which were examined. A smaller (10 MW) geothermal plant is more competitive in cost, but still does not appear to be as economical as diesel. Because of the preliminary nature of this report and the small differ- ences in the costs associated with the diesel system with and without the 10 MW geothermal plant, it is recommended that further research be conducted to provide refined cost and plant operating data. Future studies should concentrate their efforts on developing feasibility level data for geothermal plants in the 5 to 10 MW range. The City should very carefully consider siting new diesel generators so that the sale of recovered waste heat may be facilitated. A number of power plants (perhaps even individual power plants for each new generat- ing unit) should be considered so that all available waste heat can be delivered to users. Piping lengths must be kept as short as possible to minimize heat losses. The sale of waste heat to seafood processors and other users could offset a substantial amount of the system's cost. The City should consider using fuels heavier than the No. 2 diesel fuel they currently burn in their diesels. These less-refined fuels can be obtained at significantly less cost than the light distallate fuels. An investigation should be made of the availability of systems which use waste heat from diesel engines to produce cold temperatures. Such sys- tems could be attractive to the seafood processors located near the gen- erator plant(s). Hydroelectric plants identified by the US Army Corps of Engineers, while not providing a substantial savings to the power system, may be worthy of further consideration. They may offer other benefits to the City, such as an enhanced water supply. Considering its present state of development, wind energy is not a viable alternative for use at Unalaska in any role except that of an experimental installation. Unalaska could be an appropriate site for a wind turbine demonstration project because of the abundant wind resource there. Because of the relatively low cost of diesel fuel at Unalaska, a wind turbine would face stiff economic competition and would likely not show any advantage over the diesel system. B_- DEMOGRAPHIC AND ECONOMIC CONDITIONS B.1 - Location Unalaska and Dutch Harbor are located on one of the Fox Islands, a group of islands in the northern part of the Aleutian Islands. The community of Dutch Harbor is on Amaknak Island, a small island separated by Unalaska Island (and the village of Unalaska itself) by a narrow channel. The sep- aration of these two communities is so small that, for the purposes of this report, they will be considered to exist on the same island. In many cases, this report will consider them as one homegeneous community. B.2 - Population Data provided by the State of Alaska's Division of Community and Regional Affairs shows the following population trends for Unalaska (including Dutch Harbor: Year: 1960 1970 1980 1983 (December) Population: 218 340 Lao22 1983) In the recent past (as recently as 1970), the majority of Unalaska's resi- dents have been Aleuts, the original inhabitants of the area. The rela- tively sudden predominance of white residents has come about as a result of Unalaska's recognition as an excellent base for commercial crabbing and fishing activities. B.3 - Economy Unalaska stands as the economic center of the Aleutian Islands and the southern part of the Alaska Peninsula. Dutch Harbor provides virtually the only deepwater in Alaska west of Kodiak. Because of the quality of its harbor, Unalaska has become a base for crabbing and bottomfishing fleets which operate throughout the North Pacific; the area's salmon industry; and the oil companies involved in exploratory activities in the southern Bering Sea and North Pacific. A significant industry has developed to support the fishing and shipping activities in the area. Dutch Harbor has a number of marine machine shops and a repair facility which boasts of being "Western Alaska's largest ship- yard." A major refiner operates a sizeable bulk fuel plant at Dutch Harbor, dispensing a wide range of fuels throughout the region. So depend- ent is the community upon the maritime industry that many businesses list their ship-to-shore channels in advertisements. The University of Alaska operates a Rural Education Center in Unalaska. There is a local television station and a radio station. Two airlines serve Unalaska, one of which recently inagurated jet service to the island. Over the past several years, especially with the decline in prices paid for Alaska salmon and the poor performance of the Aleutian crab industry, con- siderable interest has been given to the establishment of a bottomfish industry in the area. If such an industry is developed, it seems logical that Unalaska would be given prime consideration for the base of the neces- sary support industry (supplies, repair facilities, fuel, "R&R" opportuni- ties, etc). A number of studies have been done to assess the possible impact of a bot- tomfish industry on the area, some of which are mentioned in Part F and Part H of this report. In some cases, the forecasts of future population made for Unalaska and Dutch Harbor seem quite difficult to believe. One study, developed as a part of the work done to justify the expansion of the Dutch Harbor airport, suggested that under certain conditions, the year- round population of Unalaska could reach more than 22,000 by the year 2,000. This represents more than a ten-fold increase in population in the next fifteen years. The work done for this energy reconnaissance suggests that such a forecast may be unrealistically inflated. Acres expects much less growth for the community. B.4 - Government Unalaska is incorporated as a first class city (as are most other major cities throughout the state) with a mayor and city council directing the city government. The city provides infrastructure (water, sewer, electric- ity, roads, etc) services for residents of Unalaska and Dutch Harbor. B.5 - Transportation As was mentioned previously, Unalaska is served by two airlines. The "traditional" carrier, Reeve Aleutian Airways, operates Lockheed Electras (L-188's) and Japanese-built Nihon YS-11l's into Dutch Harbor from Anchorage via Cold Bay. Air-Pac, operating in cooperation with Alaska Airlines, runs direct flights between Anchorage and Dutch Harbor using Fairchild Metro II's (F-27's) and Nihon YS-ll's. It was Air-Pac which has recently intro- duced jet service to Unalaska using British Aerospace BA-146's. Unlike the similarly-sized Electras, the BA-146's are designed to take off fully laden from as little as 3500 feet of runway. The existing runway at Dutch Harbor is only about 4,300 feet long, seriously limiting the type of aircraft available to serve the community. Plans have been developed to expand the existing airport or to develop a new, larger facility. The considerable expense ($30 to $100 million depending upon the approach taken) of these options and the recent decline in oil revenue makes the near-term likelihood of improved airport facili- ties quite remote. Except for the airlines, there is no "practical" way of travelling to or from Unalaska. The Alaska Marine Highway does provide ferry service to Unalaska from Homer. A trip from Homer to Unalaska requires four days. Transportation in Unalaska and Dutch Harbor is by car or truck. The City has an extensive and (by rural Alaska standards) well-maintained system of gravel streets and roads. Two taxi services exist as does a truck rental company. Until a bridge was built across the channel between Unalaska and Dutch Harbor, traffic used a car ferry to shuttle between the two communities. References l. "City of Unalaska Electrification Study," R. W. Retherford Assoc., Anchorage, 1979; prepared for the City of Unalaska. 2. "Geothermal Potential in the Aleutians: Unalaska," Morrison-Knudsen Co. Inc., Anchorage, 1981; prepared for the Alaska Division of Energy and Power Development. 3. “Aleutian Regional Airport--Project Documentation," Dames & Moore, Anchorage, 1982, prepared for the City of Unalaska. 4. "54° North," 54 Degrees North Publishing Co., Unalaska, 1983 5. "Going Dutch--AIRPAC Brings the Jet Age to the Aleutians," Alaska Journal of Commerce and Pacific Rim Reporter, Pacific Rim Publishing Co., Anchorage, March 26, 1984. 6. "United States Government Flight Information Publication--Supplement, Alaska" US Dept of Commerce, National Oceanic and Atmospheric Admin, Nat'l Ocean Survey, Washington, DC, 1980. 7. "Jane's All the World's Aircraft," London, 1982. C_- COMMUNITY MEETING REPORT In October 1983, representatives of Acres American (Mr. James Landman) and the Alaska Power Authority (Mr. Donald Markle) paid a 3-day visit to Unalaska. The purpose of the visit was to gather data on energy use and resources and to provide an opportunity for local input to the conduct of this study. In addition to meeting individually with City officials (the City Manager; the City Planner; Director of Public Works; Director of Electrical Pro- jects; and Director of City Finance), the visitors were given the opportun- ity to address the City Council meeting which was held on the 20th of October. : The City Council meeting was well attended (about 30 people present) and after the agenda was cleared, Messrs. Landman and Markle were given an opportunity to discuss the purpose of their visit. As was expected, most of the audience's interest was focused on the Power Authority's work on the geothermal test drilling program underway on Mt. Makushin. Mr. Markle was able to give a detailed summary of the project's findings to date and work yet to be undertaken. It was apparent that some people in the audience believed that a geothermal plant, since it used no fuel per se, would pro- vide nearly free electricity. Mr. Landman spent some time explaining that while such a plant would require no fuel, there was little possibility of such a plant actually reducing the price of electricity as it is delivered to the customer. It was pointed out that, even if the City's utility required no diesel fuel, electricity would be far from free. Costs such as system maintenance and administration, debt service, and contingency funds would still have to be paid by the consumers. Data provided by the City's Director of Finance has shown that only about one quarter to one third of the price of electricity goes to pay for fuel. This was explained to the audience and the idea was introduced that the only savings which would be realized by the construction of a geothermal plant would be from the reduction of fuel use. The discussion by Messrs. Landman and Markle lasted about an hour, at which point the Council meeting adjourned and informal discussion continued. Staff from the local television station (KIW) asked the vistors to partici- pate in an interview at their studios that evening. This was agreed to, and an interview was taped for later broadcast in the community. As was the case in the City Council meeting, most of the interviewer's interest was in the Power Authority's geothermal exploration project. Prior to leaving the island on the 21st, the visitors visited APA's drill- ing sites on Mt. Makushin with the City Manager and the Director of Elec- trical Projects. D - EXISTING POWER AND HEATING FACILITIES Unalaska electric utility customers are presently served by a municipally- operated diesel generating plant located near the high school and the city offices. The City's diesels have the following ratings: l unit at 600 kW 2 units at 300 kW each As part of a pilot project, the Alaska Power Authority installed a waste heat recovery system at the City's plant. This system extracts heat from the diesels' cooling water and distributes that heat to nearby users. In the case of the Unalaska waste heat system, the energy recovered is used to heat the high school and its swimming pool; the city offices; the community center; the city clinic; and the police station. It is estimated by the APA that the waste heat system saves these users about 58,000 gallons of fuel oil each year. These City-owned generators adequately serve the present needs of the resi- dents and the small businesses in Unalaska. However, virtually all of the industrial consumers are located in Dutch Harbor and are not served by a centralized utility system. Individual consumers are responsible for pro- viding their own source of electricity. The processors and other industri- al users all have their own diesel generators. In many cases, Dutch Harbor businesses and dormitory-style housing units are owned by the processor companies. These users are provided with power by their "parents'" gener- ating facilities. A number of processors have equipped their diesel sys- tems with waste heat recovery systems to provide heat and hot water (not steam) for their own use. The City utility is in the process of building an underground power distri- bution system to provide electricity to all potential customers in both Unalaska and Dutch Harbor. In conjunction with the construction of this distribution system, they plan to build a new generation plant in Dutch Harbor to provide electricity throughout the system. Present plans call for the installation of a new 2,850 kW generator. The existing units will be moved to the new plant when it is completed. This will mean the end of the availability of waste heat for the swimming pool and city offices. However, it is expected that the new generating plant will have equipment installed to provide waste heat recovery. Careful selection of the site for the new power plant could provide nearby customers for the waste heat. Initial discussions between the City and potential Dutch Harbor industrial customers have shown an almost uniformly enthusiastic reception of the idea of a City-operated utility in Dutch Harbor. Almost all space heat in the city is provided by fuel oil. Although the Unalaska climate is not especially cold by Alaska standards, the area is windy enough that homes and other buildings tend to use more heat than the commonly-used "heating degree days" data for the area would indicate. E - ENERGY BALANCE An energy balance for a community can be thought of in much the same way an income statement developed for a business is. The energy balance identi- fies all the sources of energy (oil, wood, coal, hydroelectric, etc.) and then lists their corresponding uses (space heating, water heating, power generation, transportation, and heat losses). As its name implies, the total energy contributed by the sources must exactly equal the energy absorbed by the uses. Such a balance statement, especially when it is developed in a graphical form, can give energy planners an idea of where most of a community's energy is coming from and how it is being used. The development of a good energy balance for Unalaska and Dutch Harbor is virtually impossible. This is largely because of the community's role as a major port for the north Pacific and the entire west coast of Alaska. The Chevron bulk plant, which is a major supplier to Dutch Harbor users, also serves the fleet which calls at Dutch Harbor and serves as a transshipment point for bulk fuel deliveries made to western cities and villages. Their recordkeeping does not break out the amount of fuel specifically sold in Unalaska and Dutch Harbor. Of the fuels that pass through the Chevron bulk plant, it is believed that only a small fraction are consumed in the city. F - ENERGY REQUIREMENTS FORECAST F.l - Capital Projects Forecast F.1l.1 - Scheduled Capital Projects New generating plant to be built by the City (1984) Ongoing development of generating facilities as load grows. F.1.2 - Potential Developments The development of Unalaska as a support base for area oil explora- tion (1985 - 20007) Increased bottomfishing activity (1984 and later) Increasing importance of Unalaska as a transshipment port for cargo bound for western Alaska (1990 and later) F.1.3 - Economic Forecast The eealstivety healthy economy now enjoyed by Unalaska and Dutch Harbor s due mainly to the crab industry. During the past few years, the crabbers have turned in increasingly poor harvests due to a decline in crab stock in the area. As a result, there has been a slowing of the City's growth. Some see the potential bottomfish industry as being able to help even out some of the feast-and-famine cycles which plague the crab industry. It should not be expected that the bottomfish industry will operate in the same manner as the crabbers have. This new industry will likely use new ships which have been outfitted as catcher/processor ships. These ships may not call at port for peri- ods measured in months. They would also not have need for the large shore-based support activities associated with processing. As a result, the City may see few economic benefits resulting from an expanded bottomfish industry. F.2 - Population Forecast The prediction of future populations of relatively "stable" communities is a difficult task. To predict the future growth of a community such as Unalaska, which is so dependent upon such volatile industries as crabbing, fishing, and petroleum is virtually impossible. This report makes an effort to put existing data to the best use to develop forecasts of popu- lations for Unalaska (including Dutch Harbor). The most recent and perhaps one of the most well thought-out planning docu- ments which provides details of future growth estimates for Unalaska was prepared in 1982 by the Anchorage office of Dames & Moore. They prepared a report to establish the community's need for a new or upgraded airport. This work provided a detailed estimate of the growth of the area's bottom- fish industry, which Dames & Moore saw as the leader of Unalaska's future economic base. Their report developed individual forecasts for the years 1980 through 2000 for low, medium, and high bottomfishing activity, and for no bottomfishery development. The population estimates for the year 2000 ranged from 2300 people (under the "no bottomfish" forecast) to almost 26,000 ("high bottomfish"). From past experience in Alaskan projects, Acres' staff have learned that far too many reports and forecasts are based on unrealistic assumptions. In the case of the Dames & Moore work, we believe that their population forecasts overestimate the amount of processing of the bottomfish catch which will be done on shore. It is our opinion that the modern bottomfish industry (especially the foreign participants in that industry) will make extensive use of self-contained catcher/processor ships. For that reason, this report ignores the Dames & Moore "high bottomfish" projections. We will use Dames & Moore's "no bottomfish" projections as our low fore- casts, with their "low bottomfish" and "best-guess bottomfish" projections being our "“best-guess" and "high-growth" projections, respectively. Table 1 on the following page gives Dames & Moore's data for the various bottomfish catch possibilities. TABLE 1 10 UNALASKA/DUTCH HARBOR POPULATION FORECAST (data taken from Dames & Moore, 1982) DAMES & MOORE DAMES & MOORE DAMES & MOORE DAMES & MOORE "NO BOTTOMFISH" "LOW BOTTOMFISH" “BEST-GUESS BOTTOMFISH" "HIGH BOTTOMFISH" (ACRES "LOW GROWTH") (ACRES "BEST GUESS") (ACRES "HIGH GROWTH") YEAR RESIDENT TRANSIENT _ TOTAL RESIDENT TRANSIENT _ TOTAL RESIDENT TRANSIENT _ TOTAL RESIDENT TRANSIENT TOTAL 1980 1,395 905 2,300 1,395 905 2,300 1,395 905 2,300 1,395 905 2,300 1981 1,420 920 2,340 1,420 980 2,400 1,473 1,040 2,513 1,520 1,070 2,590 1982 1,440 930 2,370 1,450 1,060 2,510 1,550 1,180 2,730 1,650 1,240 2,890 1983 1,460 950 2,410 1,480 1,130 2,610 1,630 1,320 2,950 1,780 1,410 3,190 1984 1,480 960 2,440 1,500 1,210 2,710 1,707 1,450 5,157 1,900 1,570 3,470 1985 1,506 978 2,484 1,530 1,285 2,815 1,785 1,590 3,375 2,030 1,740 3,770 1986 1,530 990 2,520 1,780 1,340 3,120 2,270 1,700 3,970 3,300 1,850 5,150 1987 1,550 1,010 2,560 2,020 1,400 3,420 2,760 1,800 4,560 4,570 1,970 6,540 1988 1,580 1,020 2,600 2,270 1,450 3,720 3,240 1,900 5,140 5,840 2,080 7,920 1989 1,600 1,040 2,640 2,510 1,510 4,020 3,730 2,010 5,740 7,120 2,200 9,320 1990 1,622 1,053 2,675 2,757 1,567 4,324 4,215 2,115 6,330 8,388 2,312 10,700 1991 1,660 1,077 2,737 3,360 1,630 4,990 5,260 2,200 7,460 9,740 2,560 12,300 1992 1,700 1,100 2,800 3,970 1,690 5,660 6,300 2,280 8,580 11,100 2,810 13,910 1993 1,740 1,130 2,870 4,580 1,760 6,340 7,340 2,360 9,700 12,400 3,050 15,450 1994 1,770 1,150 2,920 5,190 1,820 7,010 8,380 2,440 10,820 13,800 3,300 17,100 1995 1,812 1,175 2,987 5,799 1,883 7,682 9,425 2,921 11,946 15,151 3,547 18,698 1996 1,850 1,200 3,050 6,950 1,970 8,920 10,900 2,600 13,500 16,600 3,520 20,120 1997 1,900 1,230 3,130 8,100 2,060 10,160 12,400 2,670 15,070 18,000 3,510 21,510 1998 1,940 1,260 3,200 9,250 2,140 11,390 14,000 2,740 16,740 19,400 3,490 22,890 1999 1,980 1,280 3,260 10,400 2,230 12,630 15,500 2,820 18,320 20, 900 3,480 24,380 2000 2,023 1,515 3,336 11,550 2,317 13,867 16,972 2,894 19,866 22,287 3,459 25,746 2001 2,060 1,340 3,400 12,700 2,400 15,100 18,500 2,970 21,470 23,700 3,440 27,140 2002 2,110 1,370 3,480 13,800 2,450 16,250 20,000 3,040 23,040 25,100 3,420 28,520 2003 2,150 1,400 3,550 15,000 2,580 17,580 21,500 3,120 24,620 26,600 3,410 30,010 2004 2,190 1,420 3,610 16,200 2,660 18,860 23,000 3,190 26,190 28,000 3,390 31,390 Notes: Population data for 1980, 1985, 1990, 1995, and 2000 were taken direcly from Dames & Moore's 1982 report "Aleutian Regional Airport, Project Documentation." Data for other years were estimated using linear interpolation. 1l F.3 - Electrical Energy Forecast Beginning in this section, and continuing through the remainder of the report, we present "Low," "Best-Guess," and "High" forecasts of economic activity and electric energy use growth. References to bottomfish catch levels will generally be omitted. Unalaska residential customers have had access to both a centralized utili- ty system and a source of income long enough to have attained a relatively high level of consumption for rural Alaska communities. City officials note that a "normal" level of residential electricity use is about 600 kWh per month. The State subsidy program (Power Cost Assistance Program) has set its cutoff at 600 kWh/month. Beyond that level, the customers must pay "full price" for electricity. In Unalaska, that would be about $0.17 per kWh, which is relatively inexpensive for diesel-generated electricity in a rural community. The consumption levels of many of the non-residential users have been care- fully estimated by City utility staff members, even though they are not yet customers of the City system. These users and their consumption levels are given in Table 2, below: TABLE 2 EXISTING LOADS (From Unalaska Loan Application Documents) Customer Demand (kW) Consumption (MWh) Standard Oil Company 200 834 Standard Oil Hill (residential) 200 876 American President Lines 870 493 Strawberry Hill 30 144 Whitney Fidalgo (closed) 0 0 East Point Seafoods 860 841 Universal Seafoods 2,450 10,074 Panama Marine 1,400 3,000 Pan Alaska Seafoods 1,750 3,942 Pacific Pearl 570 LoL City Airport (including expansion) 75 328 Sea Alaska 1,750 3,942 City Dock 200 175 City Boat Harbor 250 zo City of Unalaska Sales 1,140 2,500 TOTALS 11,745 28,682 Note: 1 MWh = 1,000 kWh TABLE 3 UNALASKA/DUTCH HARBOR HOUSING AND RESIDENTIAL ELECTRICITY USE FORECAST FROM ACRES' LOW-GROWTH POPULATION FORECAST (assuming no bottomfish development) 12 HOUSES APARTMENTS POPULATION NUMBER OF ENERGY POWER NUMBER OF ENERGY POWER ENERGY POWER YEAR RESIDENT TRANSIENT _ TOTAL HOUSES USE (kWh) DEMAND (kW) | APARTMENTS USE (kWh) DEMAND (kW) | USE (kWh) DEMAND (kW) 1980 1,395 905 2,300 349 2,932 524 627 2,257 314 5,189 838 1981 1,420 920 2,340 355 2,982 533 638 2,297 319 5,279 852 1982 1,440 930 2,370 360 3,024 540 645 2,322 323 5,346 863 1983 1,460 950 2,410 365 3,066 548 658 2,369 329 5,435 877 1984 1,480 960 2,440 370 3,108 555 665 2,394 333 5,502 888 1985 1,506 978 2,484 377 3,167 566 677 2,437 339 5,604 905 1986 1,530 990 2,520 383 3,217 575 686 2,470 343 5,687 918 1987 1,550 1,010 2,560 388 3,259 582 699 2,516 350 5,775 932 1988 1,580 1,020 2,600 395 3,318 593 708 2,549 354 5,867 947 1989 1,600 1,040 2,640 400 3,360 600 720 2,592 360 5,952 960 1990 1,622 1,053 2,675 406 3,410 609 729 2,624 365 6,034 974 1991 1,660 1,077 2,737 415 3,486 623 746 2,686 373 6,172 996 1992 1,700 1,100 2,800 425 3,570 638 763 2,747 382 6,317 1,020 1993 1,740 1,130 2,870 435 3,654 653 783 2,819 392 6,473 1,045 1994 1,770 1,150 2,920 443 3,721 665 796 2,866 398 6,587 1,063 1995 1,812 1,175 2,987 453 3,805 680 814 2,930 407 6,735 1,087 1996 1,850 1,200 3,050 463 3,889 695 831 2,992 416 6,881 1,111 1997 1,900 1,230 3,130 475 3,990 713 853 3,071 427 7,061 1,140 1998 1,940 1,260 3,200 485 4,074 728 873 3,143 437 7,217 1,165 1999 1,980 1,280 3,260 495 4,158 743 888 3,197 444 7,355 1,187 2000 2,023 1,313 3,336 506 4,250 759 909 3,272 455 7,522 1,214 2001 2,060 1,340 3,400 515 4,326 773 928 3,341 464 7,667 1,237 2002 2,110 1,370 3,480 528 4,435 792 949 3,416 475 7,851 1,267 2003 2,150 1,400 3,550 538 4,519 807 969 3,488 485 8,007 1,292 2004 2,190 1,420 3,610 548 4,603 822 984 3,542 492 8,145 1,314 Assumptions: 1. 75 percent of "Resident" population is assumed to live in single-family homes at 3 people per house; 25 percent in apartment-type dwellings at 2 people per unit. type dwellings at 2 people per unit. 100 percent of "Transient" population is assumed to live in apartment- 2. Houses will be assumed to consume 700 kWh/month, with a peak demand (coincident) of about 1.5 kW; apartment-type dwellings will be assumed to consume 350 kWh/month, with a peak demand (coincident) of about 0.5 kW. TABLE 4 UNALASKA/DUTCH HARBOR HOUSING AND RESIDENTIAL ELECTRICITY USE FORECAST FROM ACRES' BEST-GUESS POPULATION FORECAST (assuming a low-growth bottomfish industry) 13 HOUSES APARTMENTS TOTALS POPULATION NUMBER OF ENERGY POWER NUMBER OF ENERGY POWER ENERGY POWER YEAR RESIDENT TRANSIENT _ TOTAL HOUSES USE (kWh) DEMAND (kW) | APARTMENTS USE (kWh) DEMAND (kW) | USE (kWh) DEMAND (kW) 1980 1,395 905 2,300 349 2,932 524 627 2,257 314 5,189 838 1981 1,420 980 2,400 355 2,982 533 668 2,405 334 5,387 867 1982 1,450 1,060 2,510 363 3,049 545 711 2,560 356 5,609 901 1983 1,480 1,130 2,610 370 3,108 555 750 2,700 375 5,808 930 1984 1,500 1,210 2,710 375 3,150 563 793 2,855 397 6,005 960 1985 1,530 1,285 2,815 383 3,217 575 834 3,002 417 6,219 992 1986 1,780 1,340 3,120 445 3,738 668 893 3,215 447 6,953 1,115 1987 2,020 1,400 3,420 505 4,242 758 953 3,431 477 7,673 1,235 1988 2,270 1,450 3,720 568 4,771 852 1,009 3,632 505 8, 403 1,357 1989 2,510 1,510 4,020 628 5,275 942 1,069 3,848 535 9,123 1,477 1990 2,757 1,567 4,324 689 5,788 1,034 1,128 4,061 564 9,849 1,598 1991 3,360 1,630 4,990 840 7,056 1,260 1,235 4,446 618 11,502 1,878 1992 3,970 1,690 5,660 993 8,341 1,490 1,341 4,828 671 13,169 2,161 1993 4,580 1,760 6,340 1,145 9,618 1,718 1,453 5,231 727 14,849 2,445 1994 5,190 1,820 7,010 1,298 10, 903 1,947 1,559 5,612 780 16,515 2,727 1995 5,799 1,883 7,682 1,450 12,180 2,175 1,666 5,998 833 18,178 3,008 1996 6,950 1,970 8,920 1,738 14,599 2,607 1,854 6,674 927 21,273 3,534 1997 8,100 2,060 10,160 2,025 17,010 3,038 2,043 7,399 1,022 24,365 4,060 1998 9,250 2,140 11,390 2,215 19,429 3,470 2,226 8,014 1,113 27,443 4, 583 1999 10,400 2,230 12,630 2,600 21,840 3,900 2,415 8,694 1,208 30,534 5,108 2000 11,550 2,317 13,867 2,888 24,259 4,332 2,602 9,367 1,301 33,626 5,633 2001 12,700 2,400 15,100 3,175 26,670 4,763 2,788 10,037 1,394 36, 707 6,157 2002 13,800 2,450 16,250 3,450 28,980 5,175 2,950 10,620 1,475 39,600 6,650 2003 15,000 2,580 17,580 3,750 31,500 5,625 3,165 11,394 1,583 42,894 7,208 2004 16,200 2,660 18, 860 4,050 34,020 6,075 3,355 12,078 1,678 46,098 7,753 Assumptions: 1. 75 percent of "Resident" population is assumed to live in single-family homes at 3 people per house; 25 percent in apartment-type dwellings at 2 people per unit. type dwellings at 2 people per unit. 100 percent of "Transient" population is assumed to live in apartment- . Houses will be assumed to consume 700 kWh/month, with a peak demand (coincident) of about 1.5 kW; apartment-type dwellings will be assumed to consume 350 kWh/month, with a peak demand (coincident) of about 0.5 kW. TABLE 5 UNALASKA/DUTCH HARBOR HOUSING AND RESIDENTIAL ELECTRICITY USE FORECAST FROM ACRES' HIGH-GROWTH POPULATION FORECAST (using the best-guess bottomfish estimates) 14 HOUSES APARTMENTS TOTALS POPULATION NUMBER OF ENERGY POWER NUMBER OF ENERGY POWER ENERGY POWER YEAR RESIDENT TRANSIENT _ TOTAL HOUSES USE (kWh) DEMAND (kW) | APARTMENTS USE (kWh) DEMAND (kW) | USE (kWh) DEMAND (kW) 1980 1,395 905 2,300 349 2,932 524 627 2,257 314 5,189 838 1981 1,473 1,040 2,513 368 3,091 552 704 2,534 352 5,625 904 1982 1,550 1,180 2,730 388 3,259 582 784 2,822 392 6,081 974 1983 1,630 1,320 2,950 408 3,427 612 864 3,110 432 6,537 1,044 1984 1,707 1,450 3,157 427 3,587 641 938 3,377 469 6,964 1,110 1985 1,785 1,590 3,375 446 3,746 669 1,018 3,665 509 7,411 1,178 1986 2,270 1,700 3,970 568 4,771 852 1,134 4,082 567 8,853 1,419 1987 2,760 1,800 4,560 690 5,796 1,035 1,245 4,482 623 10,278 1,658 1988 3,240 1,900 5,140 810 6,804 1,215 1,355 4,878 678 11, 682 1,893 1989 3,730 2,010 5,740 933 7,837 1,400 1,471 5,296 736 13,133 2,136 1990 4,215 2,115 6,330 1,054 8,854 1,581 1,584 5,702 792 14,556 2,373 1991 5,260 2,200 7,460 1,315 11,046 1,973 1,758 6,329 879 17,375 2,852 1992 6,300 2,280 8,580 1,575 13,230 2,363 1,928 6,941 964 20,171 3,327 1993 7,340 2,360 9,700 1,835 15,414 2,753 2,098 7,553 1,049 22,967 3,802 1994 8,380 2,440 10,820 2,095 17,598 3,143 2,268 8,165 1,134 25,763 4,277 1995 9,425 2,521 11,946 2,356 19,790 3,534 2,439 8,780 1,220 28,570 4,754 1996 10,900 2,600 13,500 2,725 22,890 4,088 2,663 9,587 1,332 32,477 5,420 1997 12,400 2,670 15,070 3,100 26,040 4,650 2,885 10,386 1,443 36,426 6,093 1998 14,000 2,740 16,740 3,500 29,400 5,250 3,120 11,232 1,560 40,632 6,810 1999 15,500 2,820 18,320 3,875 32,550 5,813 3,348 12,053 1,674 44,603 7,487 2000 16,972 2,894 19,866 4,243 35,641 6,365 3,569 12,848 1,785 48,489 8,150 2001 18,500 2,970 21,470 4,625 38,850 6,938 3,798 13,673 1,899 52,523 8,837 2002 20,000 3,040 23,040 5,000 42,000 7,500 4,020 14,472 2,010 56,472 9,510 2003 21,500 3,120 24,620 5,375 45,150 8,063 4,248 15,293 2,124 60, 443 10,187 2004 23,000 3,190 26,190 5,750 48,300 8,625 4,470 16,092 2,235 64,392 10,860 Assumptions: 1. 75 percent of "Resident" population is assumed to live in single-family homes at 3 people per house; 25 percent in apartment-type dwellings at 2 people per unit. type dwellings at 2 people per unit. 100 percent of "Transient" population is assumed to live in apartment- 2. Houses will be assumed to consume 700 kWh/month, with a peak demand (coincident) of about 1.5 kW; apartment-type dwellings will be assumed to consume 350 kWh/month, with a peak demand (coincident) of about 0.5 kW. 15 Acknowledging that some fraction of the bottomfish catch harvested in Unalaska's service area will be brought to shore for processing, we now calculate the amount of energy used for this operation. Since bottomfish are generally frozen (instead of being canned), the great- est use of energy in their processing is consumed in the freezing operation. Once the fish are frozen, relatively little energy is required to keep them frozen. We do not believe that any more than 40 percent of the area catch will be processed at Unalaska. This proportion could be as low as 25 percent of the catch. The energy used to freeze the fish caught under Acres' "Best-Guess" and "High-Growth" forecasts are shown on Tables 6 and 7 on the following pages. TABLE 6 UNALASKA/DUTCH HARBOR BOTTOMFISH PROCESSING ENERGY ESTIMATES TO BE USED WITH ACRES' BEST-GUESS FORECAST DAMES & MOORE LOW BOTTOMFISH PORTION OF AREA CATCH PROCESSED IN UNALASKA/DUTCH HARBOR CATCH ESTIMATE 40 PERCENT 30 PERCENT 25 PERCENT YEAR (106 1b) ENERGY (MWh) POWER (MW) ENERGY (MWh) POWER (MW) ENERGY (MWh) POWER (MW) 1980 0 0 0 0 0 0 0 1981 0 0 0 0 0 0 0 1982 0 oO 0 oO 0 0 0 1983 0 0 0 0 0 0 0 1984 10 268 0 201 0 168 0 1985 55 1,474 1 1,106 0 921 0 1986 90 2,412 1 1,809 1 1,508 1 1987 120 3,216 1 2,412 1 2,010 1 1988 150 4,020 2 3,015 1 2,513 1 1989 190 5,092 2 3,819 2 3,183 1 1990 220 5,896 3 4,422 2 3,685 2 1991 260 6,968 3 5,226 2 4,355 2 1992 310 8,308 4 6,231 3 5,193 2 1993 350 9,380 4 7,035 3 5,863 3 1994 400 10,720 5 8,040 4 6,700 3 1995 440 11,792 5 8,844 4 7,370 3 1996 550 14,740 7 11,055 5 9,213 4 1997 660 17,688 8 13,266 6 11,055 5 1998 770 20, 636 9 15,477 7 12,898 6 1999 880 23,584 ll 17,688 8 14,740 7 2000 990 26,532 12 19,899 9 16,583 7 2001 1,100 29,480 13 22,110 10 18,425 8 2002 1,200 32,160 14 24,120 ll 20, 100 9 2003 1,300 34,840 16 26,130 12 21,775 10 2004 1,400 37,520 17 28,140 13 23,450 ll TABLE 7 UNALASKA/DUTCH HARBOR BOTTOMFISH PROCESSING ENERGY ESTIMATES TO BE USED WITH ACRES' HIGH-GROWTH FORECAST DAMES & MOORE BEST-GUESS BOTTOMFISH PORTION OF AREA CATCH PROCESSED IN UNALASKA/DUTCH HARBOR CATCH ESTIMATE 40 PERCENT 30 PERCENT 25 PERCENT YEAR (108 1b) ENERGY (MWh) POWER (MW) ENERGY (MWh) POWER (MW) ENERGY (MWh) POWER (MN) 1980 0 0 0 0 0 0 0 1981 0 0 0 0 0 Oo 0 1982 0 0 0 9 0 0 0 1983 oO oO 0 oO oO oO 0 1984 30 804 0 603 0 503 0 1985 110 2,948 1 2,211 1 1,843 it 1986 180 4,824 2 3,618 2 3,015 1 1987 240 6,432 3 4,824 2 4,020 2 1988 310 8,308 4 6,231 3 5,193 2 1989 370 9,916 4 7,437 3 6,198 3 1990 440 11,792 5 8, 844 4 7,370 3 1991 530 14,204 6 10,653 5 8,878 4 1992 620 16,616 7 12, 462 6 10, 385 5 1993 700 18,760 8 14,070 6 11,725 5 1994 790 21,172 9 15,879 7 13,233 6 1995 880 23,584 ll 17,688 8 14,740 7 1996 1,000 26,800 12 20, 100 9 16,750 8 1997 1,200 32,160 14 24,120 ll 20,100 9 1998 1,300 34,840 16 26,130 12 21,775 10 1999 1,500 40,200 18 30,150 14 25,125 ll 2000 1,650 44, 220 20 33,165 15 27,638 12 2001 1,800 48,240 22 36,180 16 30,150 14 2002 2,000 53,600 24 40, 200 18 33,500 15 2003 2,100 56,280 25 42,210 19 35,175 16 2004 2,300 61,640 28 46,230 21 38,525 7 NON-BOTTOMFISH RESIDENTIAL INDUSTRIAL LOADS ENERGY POWER ENERGY POWER YEAR USE (MWh) DEMAND (MW) USE (MWh) DEMAND (MW) 1980 5,189 0.84 28, 700 12 1981 5,279 0.85 28,700 12 1982 5,346 0.86 28, 700 12 1983 5,435 0.88 28,700 12 1984 5,502 0.89 28, 700 12 1985 5,604 0.90 28,700 12 1986 5,687 0.92 28, 700 12 1987 5,775 0.93 28,700 12 1988 5,867 0.95 28, 700 12 1989 5,952 0.96 28,700 12 1990 6,034 0.97 28, 700 12 1991 6,172 1.00 28,700 12 1992 6,317 1.02 28, 700 12 1993 6,473 1.14 28,700 12 1994 6,587 1.06 28, 700 12 1995 6,735 1.09 28,700 12 1996 6,881 lll 28,700 12 1997 7,061 1.14 28,700 12 1998 7,217 1.16 28, 700 12 1999 7,355 1.19 28,700 12 2000 7,522 1.21 28, 700 12 2001 7,667 1.24 28,700 12 2002 7,851 1.27 28, 700 12 2003 8,007 1.19 28,700 12 2004 8,145 1.31 28, 700 12 TABLE 8 18 TOTAL ENERGY USE--ACRES' LOW-GROWTH FORECAST BOTTOMFISH PROCESSING LOADS MISCELLANEOUS LOADS TOTALS ENERGY POWER ENERGY POWER ENERGY POWER USE (MWh) DEMAND (MW) USE (MWh) DEMAND (MW) USE (MWh) DEMAND (MW) 0 0 0 0 33,889 13 0 0 0 0 33,979 13 0 Q 0 0 34,046 13 0 0 20 0.008 34,155 13 0 0 20 0.008 34,222 13 0 0 20 0.008 34,324 13 0 0 40 0.015 34,427 13 0 0 40 0.015 34,515 13 0 0 60 0.022 34,627 13 0 0 60 0.022 34,712 13 0 0 60 0.022 34,794 13 0 0 80 0.030 34,952 13 0 0 100 0.038 35,117 13 0 0 100 0.038 35,273 13 0 0 120 0.045 35,407 13 0 0 120 0.045 35,555 13 0 0 140 0.052 35,721 13 0 0 160 0.060 35,921 13 0 0 180 0.068 36,097 13 0 0 180 0.068 36,235 13 0 0 200 0.075 36,422 13 0 0 220 0.082 36,587 13 0 0 220 0.082 36,771 13 0 0 240 0.090 36,947 13 0 0 260 0.098 37,105 13 TABLE 9 TOTAL ELECTRICITY USE--ACRES' BEST-GUESS FORECAST NON-BOTTOMF ISH BOTTOMFISH RESIDENTIAL INDUSTRIAL LOADS PROCESSING LOADS MISCELLANEOUS LOADS ENERGY POWER ENERGY POWER ENERGY POWER ENERGY POWER YEAR USE (MWh) DEMAND (MW) USE (MWh) DEMAND (MW) USE (MWh) DEMAND (MW) USE (MWh) DEMAND (MH) 1980 5,189 0.85 28,700 12 0 0 0 0 1981 5,387 0.87 28,700 12 0 0 20 0.008 1982 5,609 0.90 28, 700 12 0 0 40 0.015 1983 5,808 0.93 28,700 12 0 0 60 0.022 1984 6,005 0.96 28,700 12 201 0 80 0.030 1985 6,219 0.99 28,700 12 1,106 0 100 0.038 1986 6,953 Tet 28, 700 12 1,809 1 160 0.060 1987 7,673 1223 28,700 12 2,412 1 220 0.105 1988 8, 403 1.36 28, 700 12 3,015 1 280 0.128 1989 9,123 1.48 28,700 12 3,819 2 340 0.150 1990 9,849 1.60 28, 700 12 4,422 2 400 0.172 1991 11,502 1.88 28,700 12 5,226 2 520 0.218 1992 13,169 2.16 28, 700 12 6,231 3 660 0.270 1993 14,849 2.44 28,700 12 7,035 3 800 0.322 1994 16,515 2.73 28, 700 12 8,040 4 940 0.375 1995 18,178 3.00 28,700 12 8,844 4 1,060 0.420 1996 21,273 3.53 28,700 12 11,055 5 1,320 0.518 1997 24,365 4.06 28,700 12 13,266 6 1,560 0.608 1998 27,443 4.58 28,700 12 15,477 7 1,800 0.697 1999 30,534 5.11 28,700 12 17,688 8 2,060 0.758 2000 33,626 5.63 28, 700 12 19,899 9 2,300 0.848 2001 36,707 6.16 28,700 12 22,110 10 2,560 0.945 2002 39, 600 6.66 28, 700 12 24,120 ll 2,780 1.028 2003 42,894 7.21 28,700 12 26,130 12 3,040 1.125 2004 46,098 7.75 28, 700 12 28, 140 13 3,300 1.223 TOTALS ENERGY USE (MWh) DEMAND (MW) 33,889 34,107 34,349 34,568 34, 986 36,125 37,622 39,005 40, 398 41,982 43,371 45,948 48, 760 51,384 54,195 56,782 62, 348 67,891 73,420 78,982 84,525 90,077 95, 200 100,764 106,238 POWER 13 13 13 13 13 13 14 14 14 16 16 16 17 18 19 19 21 23 24 26 27 29 31 32 34 19 TABLE 10 20 TOTAL ENERGY USE--ACRES' HIGH-GROWTH FORECAST NON-BOTTOMF ISH BOTTOMF ISH RESIDENTIAL INDUSTRIAL LOADS PROCESSING LOADS MISCELLANEOUS LOADS TOTALS ENERGY POWER ENERGY POWER ENERGY POWER ENERGY POWER ENERGY POWER YEAR USE (MWh) DEMAND (MW) USE (MWh) DEMAND (MW) USE (MWh) DEMAND (MW) USE (MWh) DEMAND (MW) USE (MWh) DEMAND (MW) 1980 5,189 0.84 28,700 12 0 0 0 0 33,889 13 1981 5,625 0.90 28,700 12 0 0 40 0.015 34,365 13 1982 6,081 0.97 28,700 uy 0 0 80 0.030 34, 861 13 1983 6,537 1.04 28,700 12 0 0 120 0.045 35,357 13 1984 6,964 1.11 28,700 12 603 0 160 0.060 36,427 13 1985 7,411 1.18 28,700 12 2,211 1 200 0.075 38,522 14 1986 8,853 1.42 28,700 32 3,618 2 320 0.120 41,491 16 1987 10,278 1.66 28,700 12 4,824 2 440 0.165 44,242 16 1988 11,682 1.89 28,700 IZ 6,231 3 560 0.210 47,173 7 1989 13,133 2.14 28,700 12 7,437 3 680 0.255 49,950 17 1990 14,556 2.37 28,700 12 8,844 4 800 0.300 52,900 19 1991 17,375 2.85 28,700 12 10,653 5 940 0.353 57,668 20 1992 20,171 3.33 28,700 12 12,462 6 1,160 0.435 62,493 22 1993 22,967 3.80 28,700 12 14,070 6 1,400 0.525 67,137 22 1994 25,763 4.28 28,700 12 15,879 7 1,620 0.608 71,962 24 1995 28,570 4.75 28,700 12 17,688 8 1,840 0.690 76,798 25 1996 32,477 5.42 28,700 12 20, 100 9 2,160 0.810 83,437 27 1997 36,426 6.09 28,700 12 24,120 ll 2,460 0.922 91,706 30 1998 40,632 6.81 28,700 12 26, 130 12 2,800 1.050 98, 262 32 1999 44,603 7.48 28,700 12 30,150 14 3,120 1.170 106,573 35 2000 48,489 8.15 28,700 12 33,165 15 3,420 1,282 113,774 36 2001 52,523 8.84 28,700 12 36,180 16 3,740 1.402 121,143 38 2002 56,472 9.51 28,700 12 40, 200 18 4,060 1,522 129,432 41 2003 60,443 10.19 28,700 12 42,210 19 4,340 1.635 135,693 43 2004 64, 392 10.86 28,700 12 46,230 21 4,640 1.755 143,962 46 POWER DEMAND (MW) UNALASKA LOAD FORECAST 50+] --------- +--------- t--------- +--------- t$--------- +------- H 45-4 - H H 40+ --------- $--------- +--------- +--------- +--------- +------- H H 35-4 - H B H B B 30-] --------- +--------- +--------- +---H----- $--------- +------- B H B B 25-4 - H H B B HH B 20- --------- +--------- +-H------- +o-------- $oee------ ey H BB B HH B HH BBB 15-4 - HB BB Se eee ot oOoee ee oer ee cere 10- --------- +o-------- +--------- +o-------- Hoenn nee -- +------- LEGEND: = ACRES' LOW-GROWTH FORECAST = * BEST-GUESS = HIGH-GROWTH s = YEARS OF FORECAST OVERLAP 21 coco | 1980 1985 1990 1995 2000 2005 ENERGY USE (MWh) UNALASKA ENERGY USE FORECAST 150,000-| --------- fons ssesew pw ee oer wees pare ans eS +--------- toeseaas, | H 140, 000-| - | H 130,000-| - | H 120, 000-| - H | H 110, 000-| - B | H B 100,000-| --------- teo------- to-------- +----- H---+--------- +------- B 90,000-| - H B | H B 80,000-| - B | H B 70,000-| - H B | H 60, 000-| - HH B | H BB 50,000-| --------- teon---- H-+---B-B---+--------- to-------- to------ | HH B 40,000-| - HHBBBB ee eee eeLE EE EEE EEE ELELELELELL 30, 000-| - | LEGEND: L = ACRES' LOW-GROWTH FORECAST 20,000-| - B= " BEST-GUESS " | H= " HIGH-GROWTH =" 10,000-| - * = YEARS OF FORECAST OVERLAP | o-| | | | | | | | | | | | 1980 1985 1990 1995 2000 2005 22 a el ress ll en ele la sti er eno aenrellepress oiserms lan mint acelin 23 G - VILLAGE TECHNOLOGY ASSESSMENT The purpose of this part of the report is to briefly discuss the various technologies which have been used to generate electricity as they may be used in Unalaska. Because of the area's fishing and crabbing industry and the on-shore personnel required to provide maintenance, Unalaska has available to it a relatively skilled work pool. In the operation of a utility system, access to such a high grade of labor can be quite important. In this regard, Unalaska enjoys a considerable advantage over most other rural communities when the application of relatively sophisticated generation equipment is considered. 1. Coal. There are no known coal deposits in the Unalaska area. Any application of coal for the generation of power would require that it be shipped in (likely from the Healy area). The city may be large enough to support a small coal-fired power plant, but it is believed that the importation of coal may make this alternative so expensive as to be uncomptetitive. 2. Conservation. This is a "resource" available to virtually all energy users anywhere in the state. Sometimes even the simplest steps taken can save appreciable amounts of energy. Based on conversations with City officials, Acres' staff believe that Unalaska residents actively practice conservation in their electricity use when they make an effort to hold stay below the 600 kWh limit of the State subsidy. Individual efforts to conserve are likely to be the most effective. As energy becomes more and more expensive more people (not just those in Unalaska) will take this option more seriously. 3. Geothermal. Unalaska is one of the few Alaska cities located near enough a geothermal resource that they could possible take advantage of ditis The Alaska Power Authority has been actively exploring the geo- thermal potential of Mt. Makushin, about 12 miles to the east of the city. Their work done to date has shown that the mountain has a large geothermal resource. The economics of utilizing the area's geothermal energy are explored in later sections of this report. 4. Hydroelectric. The US Army Corps of Engineers have carried out studies on Unalaska Island to determine the costs associated with available hydropower sites. They have uncovered at least two sites which may be worthy of further consideration. These are considered in later sections of this report. 5. Petroleum. Fuel oil is the principal source of heat and electricity for Unalaska. This situation will likely continue far into the future. The city's generators are run on diesel fuel. The use of diesel engines is the predominant means of providing electricity throughout rural Alaska. With the large (by Alaskan standards) load on the 24 Unalaska system, larger, more fuel-efficient diesel engines can be used. Technologies are available which can be used with diesel engines to make them more efficient sources of energy. Called “waste heat recovery," energy that would otherwise be given up to the atmosphere can be captured and put to use. A common form of waste heat recovery is now operating at the Unalaska power plant, where heat normally given up by the diesels' radiators is captured to heat the surrounding buildings. Another possible use is to route hot exhaust gasses through a heat exchanger to generate steam or, in some cases, to turn relatively cool liquid organic fluids (such as freon) to hot gasses, so they can be used to run ae_e turbine. The turbine is then used to generate electricity. Such a process is known as an "Organic Rankine Cycle." In conversations with a major manufacturer of this type of equipment, Acres' staff learned that systems smaller than about 25,000 should not be considered for the use of this technology. They said that, as a rule, about 10 percent of a power plant's "nameplate" rating can be recovered in this manner. Organic Rankine Cycle equipment has seen very little application in this country. It may be considered to be too experimental for use at Unalaska. In addition to the waste heat technologies used to provide (a) heat for other users and (2) more electricity, there is a system available from Japan's Hitachi Corporation which can use waste heat to produce cold. Instead of piping hot water to users near a generating plant, this sys- tem would flow very cold ammonia or freon to nearby users. In a com- munity such as Unalaska, where there are tremendous amounts of energy is used for chilling and freezing, the investigation of this type of equipment may be quite worthwhile. Photovoltaic. This alternative is presently too expensive to consider for utility application in Alaska. Wind. The Aleutian Islands are all exposed to very windy conditions. Although wind turbines, for the most part, considered to be too unreli- able for serious consideration for utility use, they have attracted a fair amount of attention from the US Department of Energy and other research agencies. The State of Alaska has funded the installation of a number of small wind turbines in locations from Skagway to Kotzebue. None of these units have yet contributed enough energy to the utility systems to which they are connected that customers have had their rates reduced. Wood. While in use throughout much of Alaska as a heating fuel, wood is not widely available at Unalaska. Its use as an energy source was not given serious consideration in this report. 4) H_ - ENERGY PLAN DESCRIPTIONS AND ASSUMPTIONS H.1 - Base Case The base case plan will assume that the City of Unalaska will continue to develop its centralized electric utility system. They will use diesel engines to generate electricity and will recover and sell waste heat. We will use a number of assumptions to simplify the calculations in this report. It is believed that the recommendations which are based upon our economic analysis will not be compromised by the use of these assumptions, especially if they are applied uniformly from one alternative to another. With regard to the base case plan, the following assumptions will be made: ® Beginning in 1984, the City will begin to increase generation capacity to the point where they can supply all electricity needed in the commun- ity. In 1984, they will bring two new 2,500 kW machines on-line. Each year thereafter, they will add two more of these units until the load capacity is met. As the load increases (as is the case under the best- guess and high-growth forecasts), they will add more units as needed. ® The diesel generating units will have capital costs of $300 per kW and they will have a lifetime of 20 years. Installation of the units will run another $300/kW, for a total installed cost of $600/kW. ® The diesel units will require a major overhaul every 10 years. These overhauls will cost the City about 1/3 the original price of the machines or $100/kW. *® The diesels will be equipped with waste heat recovery systems which will cost, complete with piping and heat exchangers at the user locations, $150/kW. The waste heat systems will have lifetimes of 15 years. * The diesels will be expected to produce 12 kWh of electrical energy for each gallon of diesel fuel used. They will also be able to produce 10 kWh (34,000 Btu) of waste heat (recovered from the cooling water) for this same gallon of fuel. * Normal operation and maintenance of the diesels and their waste heat systems. This will require a minimum crew of three people for the initial machines, with one more added for every three additional machines. The payroll costs of each of these workers is estimated at $130,000 per year, including overtime, and all fringe benefits and over- head expenses. General O&M parts and supplies will be assumed to be about $20,000 per machine. ® Fuel is estimated to cost $0.98/per gallon when the new plant is built in 1984. The plant will have a direct pipeline from the Chevron bulk plant on Amakanak Island. Fuel costs will escallate at 2.5 percent annually through 2003 and remain constant thereafter. 26 Waste heat will be assumed to be sold to customers at a price which is 10 percent less than what they could have produced it themselves from The fuel oil price to these customers will be assumed burning fuel oil. to be the same as that purchased by the City to run the generators. The economic calculations associated with the base case are given in section I. an H.2 - Alternative Plan "A" This alternative plan will examine the economics of a geothermal energy plant on Mt. Makushin when operated in conjunction with the diesel system described in the base case plan. The addition of diesel units to meet sys- tem load will continue as before, but they will only be used to provide the energy which cannot be provided by the geothermal plant. In this type of arrangement, the only savings realized by the construction of a geothermal plant will be due to the reduced consumption of diesel fuel. Most of the data used to evaluate this alternative have been provided by Republic Geothermal, Inc, the company under contract to the Alaska Power Authority to conduct the Mt. Makushin exploration. It should be noted that while Acres' staff may not agree totally with some items in Republic's cost estimates, these estimates are believed to be quite satisfactory for the level of detail required for a reconnaissance study. Their cost esti- mates were used without change to develop the following assumptions regard- ing the geothermal plant: : For Acres' low-growth forecast, two 5,000 kW units will be installed to be operational by 1993. This report will refer to such a configuration as "the 10 MW plant." After all in-plant load was taken care of, 6,700 kW would be available to the City. Republic estimates that this plant would cost $68.3 million in 1983 dollars. - Republic estimates that the 10 MW plant would cost $1.8 million each year (1983 dollars) in operation, maintenance, and administrative costs. = For higher growth levels, Republic proposes that a 30 MW plant be built (which will be able to provide 20,000 kW of power to the City). They have suggested at least two options for a construction schedule for such a plant. The first option (and the less expensive option by a slight margin) is to initially drill enough geothermal wells to supply the entire plant when it is buit to its full capacity. Generating units would be added in increments as they are required to meet the increasing load at Unalaska. Republic estimates that such a plant would cost $202 million in 1983 dollars. The second option available is to build the geothermal plant in incre- ments of both geothermal wells and generating units. Republic has estimated that such a plant would cost $220 million. OC The operation, maintenance, and administration of the 30 MW plant has been estimated to cost $2.8 million per year. 28 H.3 - Alternative Plan "B" This alternative plan assumes the existence of the Unalaska diesel system, as in the case of the two previously described cases. However, in this case, data provided by the US Army Corps of Engineers in their report "Unalaska, Alaska, Small Hydropower Interim Feasibility Study and Environ- mental Impact Statement" is used to examine the economics of constructing one or more small hydro projects near Unalaska. The assumptions used for this part of the report (in addition to those pre- sented for the base case plan) were, for the most part, directly from the Corps report. They are as follows: * A hydropower project constructed on the Shaishnikof River could have a capacity of 700 kW. The Corps estimates construction costs of such a project to be about $6.0 million (in 1983 dollars). Such a project would have a lifetime of 50 years. The project is estimated to be cap- able of producing about 3,100,000 kWh each year. This level of energy production could save the City about 260,000 gallons of fuel each year. ® The Shaishnikof project would cost about $30,000 per year for operation, maintenance, and administrative expenses. * A hydropower project constructed on Pyramid Creek could have a capacity of 260 kW. The Corps estimates that this project would cost about $845,000 (in 1983 dollars) and have a lifetime of 50 years. The Pyramid Creek plant would produce about 2,200,000 kWh each year, thus saving the City about 180,000 gallons of fuel * The Pyramid Creek project would cost about $20,000 per year to maintain. 29 I_- ECONOMIC EVALUATIONS OF ENERGY PLAN ALTERNATIVES I.1 - General In this section of the report, we will examine in some detail the relative economics of the alternatives as they were described in Section H. The method followed was developed by the Alaska Power Authority to provide a uniform analysis of diverse project types. At the request of the Alaska Power Authority, our economic analysis of the Mt. Makushin geothermal project (Alternative "A") assumes an economic life of 35 years and a financing term of 25 years. Power Authority guidelines suggest that a 15-year life and financing term be assumed for geothermal projects. These guidelines are directed at low-temperature geothermal resources and are not appropriate for projects such as the proposed Mt. Makushin plant. Geothermal systems of this type use steam turbines having economic lives and financing terms similar to those used by coal- or wood- fired boilers. Several firms contacted by the Power Authority who are experienced in the development of geothermal facilities similar to those proposed for Unalaska have confirmed that a 35-year economic life and a 25-year financing term are realistic paramaters for this analysis. To clearly identify the economic advantages of one project over another, Power Authority guidelines suggest that anlyses take into account expenses which are unique to a particular alternative. In this case, Acres assumes that the City will pursue the development of a full-capacity diesel plant regardless of the existence of a Mt. Makushin geothermal plant or the hydro plants identified by the Corps of Engineers. This approach is taken because, in the opinion of Acres' staff, the reliability of the Mt. Makushin plant and its power transmission line is not sufficiently assured. The reliability of a single transmission circuit or a single right-of-way does not provide the assurance that power would be available from the geo- thermal project with a small probability of extended outages. The redun- dancy of the extra diesel capacity is relatively cheap insurance against the failure of geothermal plant equipment or its transmission line. Thus the only savings which can be attributed to any of the projects to be evaluated is derived from the reduced quantity of fuel which must be burned by the City's diesels to produce electricity. The following pages present tables of calculations used to determine the relative economics of the various alternatives studied. Following these tables is a brief section which presents a discussion of decision theory and its application to this study. TABLE 11 ECONOMIC ANALYSIS OF BASE CASE PLAN (LOW-GROWTH FORECAST) 30 POWER ENERGY FUEL FUEL FUEL WASTE HEAT SALES PRICE — REVENUE FROM PRESENT VALUE DEMAND USE USE PRICE costs PRODUCED OF WASTE HEAT WASTE HEAT SOLD TOTAL COSTS OF TOTAL COSTS YEAR __ (MW) (MWh) (1,000 g) _($/gal)_ _($1,000) (MBtu) — ($1000/MBtu) ($1,000) ($1,000) ($1,000) 1984 13 34, 222 2,852 0.980 2,795 97,253 0084 817 1,978.0 1,911.1 1985 13 34,324 2,860 1.004 2,872 97,526 0084 819 2,053.0 1,916.5 1986 13 34,427 2,869 1.029 2,952 97,833 .0086 841 2,111.0 1,903.9 1987 3 34,515 2,876 1.055 3,034 98,072 0090 883 2,151.0 1,874.4 1988 13 34,627 2,886 1.082 3,122 98,413 .0092 905 2,217.0 1,866.7 1989 13 34,712 2,893 1.109 3,208 98,651 0094 927 2,281.0 1,855.6 1990 13 34,794 2,900 1.136 3,294 98,890 .0097 959 2,335.0 1,835.3 1991 13 34,952 2,913 1.165 3,393 99,333 0099 983 2,410.0 1,830.2 1992 13 35,117 2,926 1.194 3,494 99,777 0101 1,008 2,486.0 1,824.0 1993 13 35,273 2,939 1.224 3,598 100,220 0104 1,042 2,556.0 1,811.9 1994 13 35,407 2,951 1.254 3,700 100,629 0107 1,077 2,623.0 1,796.5 1995 13 35,555 2,963 1.286 3,810 101,038 -0110 1,111 2,699.0 1,786.2 1996 13 35,721 2,977 1.318 3,923 101,516 0112 1, 137 2,786.0 1,781.4 1997 13 35,921 2,993 1.351 4,044 102,061 -0115 1,174 2,870.0 1,773.1 1998 13 36,097 3,008 1.385 4,166 102,573 0118 1,210 2,956.0 1,764.4 1999 13 36,235 3,020 1.419 4,285 102,982 -0121 1,246 3,039.0 1,752.6 2000 13 36,422 3,035 1.455 4,416 103,494 0124 1, 283 3,133.0 1,745.7 2001 13 36,587 3,049 1.491 4,546 103,971 .0127 1,320 3,226.0 1,736.9 2002 13 36,771 3,064 1.528 4,682 104,482 0130 1,358 3,324.0 1,729.1 2003 13 36,947 3,079 1.567 4,825 104,994 0134 1,407 3,418.0 1,717.9 2004-2038 13 37,105 3,092 1.567 4,845 105,437 0134 1,413 3,432.0 33, 331.6 NOTE: ALL COSTS IN 1983 DOLLARS TOTAL: 69,545.0 TABLE 12 31 ECONOMIC ANALYSIS OF BASE CASE PLAN (BEST-GUESS FORECAST) POWER ENERGY FUEL FUEL FUEL WASTE HEAT SALES PRICE — REVENUE FROM PRESENT VALUE DEMAND USE USE PRICE costs PRODUCED OF WASTE HEAT WASTE HEAT SOLD TOTAL COSTS OF TOTAL COSTS YEAR __ (MW) (MWh) (1,000 g) _($/gal) ($1,000) (Btu) ($1000/MBtu) ($1,000) ($1,000) ($1, 000) 1984 13 34,986 2,916 0.980 2,857 99,436 0084 835 2,022.0 1,953.7 1985 13 36,125 3,010 1.004 3,022 102,641 0084 862 2,160.0 2,016.4 1986 14 37,622 3,135 1.029 3,226 106,904 0086 919 2,307.0 2,080.7 1987 14 39,005 3,250 1.055 3,429 110,825 -0090 997 2,432.0 2,119.2 1988 14 40, 398 3,367 1.082 3,643 114,815 0092 1,056 2,587.0 2,178.3 1989 16 41,982 3,499 1.109 3,880 119,316 0094 1,122 2,758.0 2,243.6 1990 16 43,371 3,614 1.136 4,106 123,237 -0097 1,195 2,911.0 2,288.0 1991 16 45,948 3,829 1.165 4,461 130,569 0099 1,293 3,168.0 2,405.8 1992 17 48,760 4,063 1.194 4,852 138,548 0101 1,399 3,453.0 2,533.5 1993 18 51,384 4,282 1.224 5,241 146,016 0104 1,519 3,722.0 2,638.5 1994 19 54,195 4,516 1.254 5,663 153,996 +0107 1,648 4,015.0 2,749.9 1995 19 56,782 4,732 1.286 6,085 161,361 -0110 1,775 4,310.0 2,852.4 1996 21 62, 348 5,196 1.318 6,848 177,184 0112 1,984 4,864.0 3,110.0 1997 23 67,891 5,658 1.351 7,643 192,938 -0115 2,219 5,424.0 3,350.9 1998 24 73,420 6,118 1.385 8,474 208,624 0118 2,462 6,012.0 3,588.6 1999 26 78,982 6,582 1.419 9,340 224,446 -0121 2,716 6,624.0 3,820.1 2000 27 84,525 7,044 1.455 10,249 240,200 +0124 2,978 7,271.0 4,051.4 2001 29 90,077 7,506 1.491 11,192 255,955 -0127 3,251 7,941.0 4,275.4 2002 31 95,200 7,933 1.528 12,122 270,515 0130 3,517 8,605.0 4,476.3 2003 32 100,764 8,397 1.567 13,158 286,338 +0134 3,837 9,321.0 4,684.7 2004-2034 34 106, 238 8,853 1.567 13,873 301,887 0134 4,045 9,828.0 95,449.5 NOTE: ALL COSTS IN 1983 DOLLARS TOTAL: 154,866.9 TABLE 13 32 ECONOMIC ANALYSIS OF BASE CASE PLAN (HIGH-GROWTH FORECAST) POWER ENERGY FUEL FUEL FUEL WASTE HEAT SALES PRICE — REVENUE FROM PRESENT VALUE DEMAND USE USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD TOTAL COSTS OF TOTAL COSTS YEAR __ (MW) (MWh) (1,000 g) _($/gal)_ _($1,000) (MBtu) _ ($1000/MBtu) ($1,000) ($1,000) ($1,000) 198413 36,427 3,036 «0.980 2,975 103,528 .0084 870 2,105.0 2,033.9 1985 14 38,522 3,210 1.004 3,223 109,461 -0084 919 2,304.0 2,150.8 1986 16, 41,491 3,458 =—-1,029 3,558 117,918 - 0086 1,014 2,544.0 2,294.4 1987 16 44,242 3,687 ~—-:1.055 3,890 125,727 .0090 1,132 2,758.0 2,403.3 198817 47,173 3,931 ~—-:1.082 4,253 134,047 .0092 1,233 3,020.0 2,542.8 198917 49,950 4,163 1,109 4,616 141,958 .0094 1,334 3,282.0 2,669.9 1990 = «19 52,900 4,408 1.136 5,008 150,313 .0097 1,458 3,550.0 2,790.3 1991 20 57,668 4,806 1.165 5,599 163,885 -0099 1,622 3,977.0 3,020.1 1992.22 62,493 5,208 1,194 6,218 177,593 -0101 1,794 4,424.0 3,245.9 199322 67,137 5,595 1.224 6,848 190,790 -0104 1,984 4,864.0 3,448.1 1994 24 71,962 5,997 1.254 7,520 204,498 -0107 2,188 5,332.0 3,651.9 1995 25 76,798 6,400 1.286 8,230 218,240 -0110 2,401 5,829.0 3,857.6 1996 = 27 83,437 6,953 1.318 9,164 237,097 -0112 2,655 6,509.0 4,161.9 1997-30 91,706 7,642 1.351 10,325 260,592 +0115 2,997 7,328.0 4,527.2 1998 = 32 98,262 8,189 1.385 11,341 279,245 -0118 3,295 8,046.0 4, 802.7 1999-35 106,573 8, 881 1.419 12,602 302,842 .0121 3,664 8,938.0 5,154.5 2000 (36, 113,774 9,481 =—-1.455 13,795 323,302 -0124 4,009 9,786.0 5,452.8 2001 +38 121,143 10,095 1.491 15,052 344,240 -0127 4,372 10,680.0 5,750.1 20024 129,432 10,786 =1.528 16,481 367,803 -0130 4,781 11, 700.0 6,086.3 200343 135,693 11,308 =—-1.567 17,719 385,603 -0134 5,167 12,552.0 6,308.6 2004-2038 46 143,962 11,997 1.567 18,799 409,098 +0134 5,482 13,317.0 129, 334.7 NOTE: ALL COSTS IN 1983 DOLLARS TOTAL: 205,687.8 TABLE 14 33 ECONOMIC ANALYSIS OF ALTERNATIVE "A" (WITH 10 MW PLANT) LOW-GROWTH Fi A ENERGY GEOTHERMAL DIESEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM GEOTHERMAL PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR _ (MWh) (MWh) (MWh) (1000 g) ($/gal) ($1000) __(MBtu) _ ($1000/MBtu) ($1,000) ($1000) ($1,000) ($1,000) 1984 34, 222 O 34,222 2,852 0.980 2,795 97,253 0084 817 0 1,978.0 1,911.1 1985 = 34,324 O 34,324 2,860 1.004 2,872 97,526 0084 819 0 2,053.0 1,916.5 1986 = 34, 427 O 34,427 2,869 1.029 2,952 97,833 0086 841 0 2,111.0 1,903.9 1987 34,515 O 34,515 2,876 1.055 3,034 98,072 -0090 883 0 2,151.0 1,874.4 1988 = 34,627 O 34,627 2,886 1.082 3,122 98,413 0092 905 0 2,217.0 1,866.7 1989 34,712 O 34,712 2,893 1.109 3,208 98,651 0094 927 0 2,281.0 1,855.6 1990 = 34,794 0 34,794 2,900 1.136 3,294 98,890 -0097 959 0 2,335.0 1,835.3 1991 34,952 O 34,952 2,913 1.165 3,393 99,333 -0099 983 0 2,410.0 1,830.2 1992 35,117 QO 35,117 2,926 1.194 3,494 99,777 -0101 1,008 oO 2,486.0 1,824.0 1993 35,273 24,700 +=:10,573 9 8B81_~=—S «1.224 =, 078 30,042 +0104 312 5,900 6,666.0 4,725.5 1994 35,407 24,800 10,607 884 1.254 1,108 30,144 -0107 323 5,900 6,685.0 4,578.6 1995 35,555 24,900 10,655 888 1.286 1,142 30,281 -0110 333 5,900 6,709.0 4,440.0 1996 35,721 25,000 10,721 893 1.318 1,178 30,451 +0112 341 5,900 6,737.0 4,307.6 1997 35,921 25,100 10,821 + 902 1.351 1,218 30,758 0115 354 5,900 6,764.0 4,178.8 1998 36,097 25,200 10,897 908 1.385 1,258 30,963 +0118 365 5,900 6,793.0 4,054.7 1999 36,235 25,400 §=:10,835 = 903S:1.419 1,281 30,792 +0121 373 5,900 6,808.0 3,926.2 2000 36,422 25,500 10,922 910 1.455 1,324 31,031 0124 385 5,900 6,839.0 3,810.7 2001 36,587 25,600 10,987 916 1.491 1,365 31,236 -0127 397 5,900 6,868.0 3,697.7 2002 = 36,771 «25,700 911,071 +9 923Ss«1.528 =, 410 31,474 -0130 409 5,900 6,901.0 3,589.9 2003 36,947 25,900 11,047 921 1.567 1,443 31,406 0134 421 5,900 6,922.0 3,479.0 2004-2017 37,105 26,000 11,105 925 1.567 1,450 31,543 +0134 423 5,900 6,927.0 36, 733.9 2018-2027 37,105 26,000 11,105 925 1.567 1,450 31,543 +0134 423 1,400 2,427.0 6,055.4 2028-2037 37,105 26,000 11,105 925 1.567 1,450 31,543 0134 423 5,900 6,927.0 12, 253.9 2038 37,105 26,000 11,105 925 1.567 1,450 31,543 +0134 423 (44,100) (43,073.0) (7,714.4) NOTE: ALL COSTS IN 1983 DOLLARS TOTAL: 108, 935.2 TABLE 15 34 ECONOMIC ANALYSIS OF ALTERNATIVE "A" (WITH 10 MW PLANT) ENERGY GEOTHERMAL DIESEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM GEOTHERMAL PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR _(Mih) (MWh) (MWh) (1000 g) ($/gal) ($1000) __(MBtu) _ ($1000/MBtu) ($1,000) ($1000) ($1,000) ($1,000) 1984 34, 986 0 34,986 2,916 0.980 2,857 99,436 0084 835 0 2,022.0 1,953.7 1985 36,125 O 36,125 3,010 1.004 3,022 102,641 0084 862 0 2,160.0 2,016.4 1986 37,622 O 37,622 3,135 1.029 3,226 106,904 . 0086 919 0 2, 307.0 2,080.7 1987 39,005 0 39,005 3,250 1.055 3,429 110,825 -0090 997 0 2,432.0 2,119.2 1988 = 40,398 0 40,398 3,367 1.082 3,643 114,815 0092 1,056 0 2,587.0 2,178.3 1989 41,982 O 41,982 3,499 1.109 3,880 119,316 0094 1,122 0 2,758.0 2,243.6 1990 = 43,371 O 43,371 3,614 1.136 4,106 123,237 .0097 1,195 0 2,911.0 2,288.0 1991 45,948 0 45,948 3,829 1.165 4,461 130,569 .0099 1,293 0 3,168.0 2,405.8 1992 48,760 0 48,760 4,063 1.194 4,852 138,548 -0101 1,399 0 3,453.0 2,533.5 1993 51,384 36,000 15,384 1,282 1.224 1,569 43,716 +0104 455 5,900 7,014.0 4,972.2 1994 54,195 37,900 16,295 1,358 1.254 1,703 46, 308 .0107 495 5,900 7,108.0 4, 868.3 1995 56,782 39,700 17,082 1,424 1.286 1,831 48,558 -0110 534 5,900 7,197.0 4,763.0 1996 62,348 43,400 18,948 1,579 1.318 2,081 53, 844 .0112 603 5,900 7,378.0 4,717.5 1997 67,891 47,000 20,891 1,741 1.351 2,352 59,368 +0115 683 5,900 7,569.0 4,676.1 1998 73,420 47,000 26,420 2,202 1.385 3,049 75,088 -0118 886 5,900 8,063.0 4,812.8 1999 78,982 47,000 31,982 2,665 1.419 3,782 90,877 -0121 1,100 5,900 8,582.0 4,949.2 2000 84,525 47,000 37,525 3,127 1.455 4,550 106,631 0124 1,322 5,900 9,128.0 5,086.1 2001 90,077 47,000 43,077 3,590 1.491 5,352 122,419 .0127 1,555 5,900 9,697.0 5,220.9 2002 95,200 47,000 48,200 4,017 1.528 6,137 136,980 -0130 1,781 5,900 10, 256.0 5,335.2 2003 100,764 47,000 53,764 4,480 1.567 7,021 152,768 0134 2,047 5,900 10,874.0 5,465.3 2004-2017 106,238 47,000 59,238 4,937 1.567 7,735 168,352 0134 2,256 5,900 11,379.0 60, 342.8 2018-2027 106,238 47,000 59,238 4,937 1.567 7,735 168,352 -0134 2,256 1,400 6,879.0 17,163.1 2028-2037 106,238 47,000 59,238 4,937 1.567 7,735 168,352 0134 2,256 5,900 11,379.0 20, 129.5 2038 106,238 47,000 59,238 4,937 1.567 7,735 168,352 -0134 2,256 (44,100) (38,621.0) (6,917.0) NOTE: ALL COSTS IN 1983 DOLLARS TOTAL: 165, 404.2 TABLE 16 35 ECONOMIC ANALYSIS OF ALTERNATIVE "A" (WITH 10 MW PLANT) ENERGY GEOTHERMAL DIESEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM GEOTHERMAL PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR (MWh) (MWh) (MWh) (1000 g) ($/gal) ($1000) __(MBtu) _ ($1000/MBtu) ($1,000) ($1000) ($1,000) ($1,000) 1984 36,427 O 36,427 3,036 0.980 2,975 103,528 -0084 870 0 2,105.0 2,033.9 1985 38,522 O 38,522 3,210 1.004 3,223 109,461 0084 919 0 2,304.0 2,150.8 1986 = 41, 491 O 41,491 3,458 1.029 3,558 117,918 -0086 1,014 0 2,544.0 2,294.4 1987 = 44,242 O 44,242 3,687 1.055 3,890 125,727 -0090 1,132 0 2,758.0 2,403.3 1988 = 47,173 O 47,173 3,931 1.082 4,253 134,047 -0092 1,233 0 3,020.0 2,542.8 1989 49,950 0 49,950 4,163 1.109 4,616 141,958 -0094 1,334 0 3,282.0 2,669.9 1990 52,900 OQ 52,900 4,408 1.136 5,008 150,313 -0097 1,458 0 3,550.0 2,790.3 1991 57,668 0 57,668 4,806 1.165 5,599 163,885 -0099 1,622 0 3,977.0 3,020.1 1992 62,493 O 62,493 5,208 1.194 6,218 177,593 -0101 1,794 0 4,424.0 3,245.9 1993 67,137 47,000 20,137 1,678 1.224 2,054 57,220 -0104 595 5,900 7,359.0 5,216.8 1994 71,962 47,000 24,962 2,080 1.254 2,609 70,928 -0107 759 5,900 7,750.0 5,308.0 1995 76,798 47,000 29,798 2,483 1.286 3,193 84,670 -0110 931 5,900 8,162.0 5,401.6 1996 83,437 47,000 36,437 3,036 1.318 4,002 103,528 -0112 1,160 5,900 8,742.0 5,589.6 1997 91,706 47,000 44,706 3,726 1.351 5,033 127,057 -O115 1,461 5,900 9,472.0 5,851.8 1998 98,262 47,000 51,262 4,272 1.385 5,916 145,675 -0118 1,719 5,900 10,097.0 6,026.9 1999 106,573 47,000 59,573 4,964 1.419 7,045 169,272 -0121 2,048 5,900 10,897.0 6,284.3 2000 113,774 47,000 66,774 5,565 1.455 8,096 189,767 -0124 2,353 5,900 11,643.0 6,487.5 2001 121,143 47,000 74,143 6,179 1.491 9,212 210,704 -0127 2,676 5,900 12,436.0 6,695.5 2002 129,432 47,000 82,432 6,869 1.528 10,496 234,233 -0130 3,045 5,900 13,351.0 6,945.2 2003 135,693 47,000 988,693 7,391 1.567 11,582 252,033 0134 3,377 5,900 14,105.0 7,089.2 2004-2017 143,962 47,000 96,962 8,080 1.567 12,662 275,528 -0134 3,692 5,900 14,870.0 78, 855.6 2018-2027 143,962 47,000 96,962 8,080 1.567 12,662 275,528 0134 3,692 1,400 10,370.0 25,873.2 2028-2037 143,962 47,000 96,962 8,080 1.567 12,662 275,528 -0134 3,692 5,900 14,870.0 26, 305.0 2038 143,962 47,000 96,962 8,080 1.567 12,662 275,528 -0134 3,692 (44,100) (35,130.0) (6,291.8) NOTE: ALL COSTS IN 1983 DOLLARS TOTAL: 214,789.8 TABLE 17 36 ECONOMIC ANALYSIS OF ALTERNATIVE "A" (WITH 30 MW PLANT) TOW-GROW i ENERGY GEOTHERMAL DIESEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM GEOTHERMAL PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR _ (MWh) (MWh) (MWh) (1000 g) ($/gal) ($1000) _ (MBtu) __ ($1000/MBtu) ($1,000) ($1000) ($1,000) ($1,000) 1984 34,222 O 34,222 2,852 0.980 2,795 97, 253 0084 817 0 1,978.0 1,911.1 1985 34,324 O 34,324 2,860 1.004 2,872 97,526 0084 819 0 2,053.0 1,916.5 1986 34,427 0 34,427 2,869 1.029 2,952 97,833 0086 841 0 2,111.0 1,903.9 1987 34,515 O 34,515 2,876 1.055 3,034 98,072 -0090 883 0 2,151.0 1,874.4 1988 = 34,627 O 34,627 2,886 1.082 3,122 98,413 0092 905 0 2,217.0 1,866.7 1989 34,712 0 34,712 2,893 1.109 3,208 98,651 0094 927 0 2,281.0 1,855.6 1990 34,794 0 34,794 2,900 1.136 3,294 98,890 .0097 959 0 2,335.0 1,835.3 1991 34,952 O 34,952 2,913 1.165 3,393 99,333 0099 983 0 2,410.0 1,830.2 1992 35,117 O 35,117 2,926 1.194 3,494 99,777 0101 1,008 0 2,486.0 1,824.0 1993 35,273 24,700 10,573 881 1.224 1,078 30,042 -0104 312 15,100 15,866.0 11,247.4 1994 35,407 24,800 10,607 884 1.254 1,108 30,144 -0107 323 15,100 15, 885.0 10, 879.6 1995 35,555 24,900 10,655 888 1.286 1,142 30,281 -0110 333 15,100 15,909.0 10,528.6 1996 35,721 25,000 10,721 893 1.318 1,178 30,451 0112 341 15,100 15,937.0 10,190.1 1997 35,921 25,100 +10,821 + 902 1.351 1,218 30,758 0115 354 15,100 15,964.0 9,862.6 1998 36,097 25,300 10,797 900 1.385 1,246 30,690 0118 362 15,100 15, 984.0 9,540.8 1999 36,235 25,400 10,835 903 1.419 1,281 30,792 0121 373 15,100 16,008.0 9,231.8 2000 36,422 «25,500 +=:10,922, 910s «1.455 1,324 31,031 +0124 385 15,100 16,039.0 8,936.9 2001 36,587 25,600 10,987 916 1.491 1,365 31,236 0127 397 15,100 16,068.0 8,651.0 2002 36,771 25,700 11,071 923 1.528 1,410 31,474 0130 409 15,100 16,101.0 8,375.7 2003 36,947 25,800 11,147 929 1.567 1,456 31,679 0134 424 15,100 = 16,132.0 8,107.9 2004-2017 37,105 26,000 11,105 925 1.567 1,450 31,543 0134 423 15,100 16,127.0 85,521.5 2018-2027 37,105 26,000 11,105 925 1.567 1,450 31,543 0134 423 2,800 3,827.0 9,548.4 2028-2037 37,105 26,000 11,105 925 1.567 1,450 31,543 0134 423 15,100 6,127.0 28, 528.7 2038 37,105 26,000 11,105 925 1.567 1,450 31,543 0134 423 (132,100) (131,073.0) — (23,475.2) NOTE: ALL COSTS IN 1983 DOLLARS TOTAL: 222,493.5 TABLE 18 37 ECONOMIC ANALYSIS OF ALTERNATIVE "A" (WITH 30 MW PLANT) ENERGY GEOTHERMAL DIESEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM GEOTHERMAL PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR _ (MWh) (Mth) (MWh) (1000 g) ($/gal) ($1000) __(MBtu) _ ($1000/MBtu) ($1,000) ($1000) ($1,000) ($1,000) 1984 34,986 0 34,986 2,916 0.980 2,857 99,436 0084 835 0 2,022.0 1,953.7 1985 36,125 0 36,125 3,010 1.004 3,022 102,641 0084 862 0 2,160.0 2,016.4 1986 37,622 0 37,622 3,135 1.029 3,226 106,904 0086 919 0 2,307.0 2,080.7 1987 39,005 0 39,005 3,250 1.055 3,429 110,825 .0090 997 0 2,432.0 2,119.2 1988 = 40, 398 0 40,398 3,367 1.082 3,643 114,815 0092 1,056 0 2,587.0 2,178.3 1989 = 41, 982 O 41,982 3,499 1.109 3,880 119,316 0094 1,122 0 2,758.0 2,243.6 1990 = 43,371 O 43,371 3,614 1.136 4,106 123,237 .0097 1,195 0 2,911.0 2,288.0 1991 45,948 O 45,948 3,829 1.165 4,461 130,569 0099 1,293 0 3,168.0 2,405.8 1992 48,760 O 48,760 4,063 1.194 4,852 138,548 0101 1,399 0 3,453.0 2,533.5 1993 51,384 36,000 15,384 1,282 1.224 1,569 43,716 0104 455 15,100 16,214.0 11,494. 1994 54,195 37,900 16,295 1,358 1.254 1,703 46, 308 0107 495 15,100 16,308.0 11, 169.3 1995 56,782 39,700 17,082 1,424 1.286 1,831 48,558 -0110 534 15,100 16,397.0 10,851.5 1996 62,348 43,600 18,748 1,562 1.318 2,059 53, 264 0112 597 15,100 6,562.0 10, 589.7 1997 67,891 47,500 20,391 1,699 1.351 2,296 57,936 0115 666 15,100 16,730.0 10,335.8 1998 73,420 51,400 22,020 1,835 1.385 2,541 62,574 0118 738 15,100 16,903.0 10,089.4 1999 78,982 55,300 23,682 1,974 1.419 2,800 67,313 .0121 814 15,100 17,086.0 9,853.5 2000 84,525 59,200 25,325 2,110 1.455 3,071 71,951 0124 892 15,100 = 17,279.0 9,627.9 2001 90,077 63,000 27,077 2,256 1.491 3,364 76,930 .0127 977 15,100 17,487.0 9,415.0 2002 95,200 66,600 28,600 2,383 1.528 3,642 81,260 0130 1,056 15,100 17,686.0 9,200.3 2003 100,764 70,500 30,264 2,522 1.567 3,952 86,000 0134 1,152 15,100 17,900.0 8,996.5 2004-2017 106,238 74,400 31,838 2,653 1.567 4,158 90, 467 0134 1,212 15,100 18,046.0 95,697.9 2018-2027 106,238 74,400 31,838 2,653 1.567 4,158 90,467 0134 1,212 2,800 5,746.0 14,336.3 2028-2037 106,238 74,400 31,838 2,653 1.567 4,158 90, 467 0134 1,212 15,100 18,046.0 31,923.4 2038 106,238 74,400 31,838 2,653 1.567 4,158 90,467 -0134 1,212 (132,100) (129,154.0) — (23,131.5) NOTE: ALL COSTS IN 1983 DOLLARS TOTAL: 250, 268.3 TABLE 19 ECONOMIC ANALYSIS OF ALTERNATIVE "A" (WITH 30 MW PLANT) 38 ENERGY GEOTHERMAL DIESEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM GEOTHERMAL PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR _(Mih) (MWh) (MWh) (1000 g) ($/gal) ($1000) __(MBtu) _ ($1000/MBtu) ($1,000) ($1000) ($1,000) ($1,000) 1984 36,427 0 36,427 3,036 0.980 2,975 103,528 0084 870 0 2,105.0 2,033.9 1985 38,522 O 38,522 3,210 1.004 3,223 109,461 0084 919 0 2,304.0 2,150.8 1986 41,491 O 41,491 3,458 1.029 3,558 117,918 .0086 1,014 0 2,544.0 2,294.4 1987 44,242 O 44,242 3,687 1.055 3,890 125,727 -0090 1,132 0 2,758.0 2,403.3 1988 = 47,173 O 47,173 3,931 1.082 4,253 134,047 0092 1,233 0 3,020.0 2,542.8 1989 49,950 0 49,950 4,163 1.109 4,616 141,958 0094 1,334 0 3,282.0 2,669.9 1990 52, 900 0 52,900 4,408 1.136 5,008 150,313 0097 1,458 0 3,550.0 2,790.3 1991 57,668 0 57,668 4,806 1.165 5,599 163,885 0099 1,622 0 3,977.0 3,020.1 1992 62,493 0 62,493 5,208 1.194 6,218 177,593 0101 1,794 0 4,424.0 3,245.9 1993 67,137 47,000 20,137 1,678 1.224 2,054 57,220 0104 595 15,100 = 16,559.0 11,738.7 1994 71,962 50,400 21,562 1,797 1.254 2,253 61,278 0107 656 15,100 16,697.0 11,435.8 1995 76,798 53,800 22,998 1,917 1.286 2,465 65,370 -0110 719 15,100 16,846.0 11,148.7 1996 83,437 58,400 25,037 2,086 1.318 2,750 71, 133 0112 797 15,100 = 17,053.0 10, 903.7 1997 91,706 64,200 27,506 2,292 1.351 3,097 78,157 -0115 899 15,100 17,298.0 10,686.7 1998 98,262 68,800 29,462 2,455 1.385 3,400 83,716 0118 988 15,100 17,512.0 10,452.9 1999 106,573 74,600 31,973 2,664 1.419 3,781 90,842 -0121 1,099 15,100 17,782.0 10,254.9 2000 113,774 79,600 34,174 2,848 1.455 4,144 97,117 0124 1,204 15,100 18,040.0 10,051.9 2001 121,143 84,800 36,343 3,029 1.491 4,516 103,289 .0127 1,312 15,100 18,304.0 9,854.9 2002 129,432 90,600 38,832 3,236 1.528 4,945 110,348 0130 1,435 15,100 18,610.0 9,680.9 2003 135,693 95,000 40,693 3,391 1.567 5,314 115,633 0134 1,549 15,100 18,865.0 9,481.5 2004-2017 143,962 100,800 43,162 3,597 1.567 5,636 122,658 0134 1,644 15,100 19,092.0 101, 244.9 2018-2027 143,962 100,800 43,162 3,597 1.567 5,636 122,658 -0134 1,644 2,800 6,792.0 16,946.0 2028-2037 143,962 100,800 43,162 3,597 1.567 5,636 122,658 0134 1,644 15,100 9,092.0 33,773.7 2038 143,962 100,800 43,162 3,597 1.567 5,636 122,658 -0134 1,644 (132,100) (128,108.0) (22,944.1) NOTE: ALL COSTS IN 1983 DOLLARS TOTAL: 267,862.5 TABLE 20 39 ECONOMIC ANALYSIS OF ALTERNATIVE "B" (WITH BOTH HYDRO PLANTS) (LOW-GROWTH FORECAST) ENERGY HYDRO DIESEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM HYDRO PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR _ (MWh) (MWh) (MWh) (1000 g) ($/gal) ($1000) __(MBtu) _ ($1000/MBtu) ($1,000) ($1000) ($1,000) ($1,000) 1984 34,222 O 34,222 2,852 0.980 2,795 97, 253 0084 817 0 1,978.0 1,911.1 1985 34,324 O 34,324 2,860 1.004 2,872 97,526 .0084 819 0 2,053.0 1,916.5 1986 34,427 0 34,427 2,869 1.029 2,952 97,833 0086 841 0 2,111.0 1,903.9 1987 34,515 O 34,515 2,876 1.055 3,034 98,072 -0090 883 0 2,151.0 1,874.4 1988 34,627 0 34,627 2,886 1.082 3,122 98,413 0092 905 0 2,217.0 1,866.7 1989 34,712 5,400 29,312 2,443 1.109 2,709 83,306 0094 783 460 2,386.0 1,941.0 1990 34,794 5,400 29,394 2,450 1.136 2,783 83,545 0097 810 460 2,433.0 1,912.3 1991 34,952 5,400 29,552 2,463 1.165 2,869 83,988 0099 831 460 2,498.0 1,897.0 1992 35,117 5,400 29,717 2,476 1.194 2,957 84,432 0101 853 460 2,564.0 1,881.2 1993 35,273 5,400 29,873 2,489 1.224 3,047 84,875 0104 883 460 2,624.0 1,860.2 1994 35,407 5,400 30,007 2,501 1.254 3,136 85, 284 0107 913 460 2,683.0 1,837.6 1995 35,555 5,400 30,155 2,513 1.286 3,232 85,693 -0110 943 460 2,749.0 1,819.3 1996 35,721 5,400 30,321 2,527 1.318 3,330 86,171 0112 965 460 2,825.0 1,806.3 1997 35,921 5,400 30,521 2,543 1.351 3,436 86,716 .0115 997 460 2,899.0 1,791.0 1998 36,097 5,400 30,697 2,558 1.385 3,543 87,228 0118 1,029 460 2,974.0 1,775.2 1999 36,235 5,400 30,835 2,570 1.419 3,646 87,637 -0121 1,060 460 3,046.0 1,756.6 2000 36,422 5,400 31,022 2,585 1.455 3,761 88,149 0124 1,093 460 3,128.0 1,742.9 2001 36,587 5,400 31,187 2,599 1.491 3,875 88,626 .0127 1,126 460 3,209.0 1,727.7 2002 36,771 5,400 31,371 2,614 1.528 3,995 89,137 -0130 1,159 460 3,296.0 1,714.6 2003 36,947 5,400 31,547 2,629 1.567 4,120 89,649 0134 1,201 460 3,379.0 1,698.3 2004-2023 37,105 5,400 31,705 2,642 1.567 4,140 90,092 0134 1,207 460 3,393.0 23,415.1 2024-2038 37,105 5,400 31,705 2,642 1.567 4,140 90,092 0134 1,207 50 2,983.0 10, 306.3 NOTE: ALL COSTS IN 1983 DOLLARS TOTAL: 70, 355.2 ECONOMIC ANALYSIS OF ALTERNATIVE "B"™ (ITH BOTH HYDRO PLANTS) TABLE 21 40 ENERGY HYDRO DIESEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM HYDRO PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR _(MWh) (Muh) (MWh) (1000 g) ($/gal) ($1000) __(MBtu) __ ($1000/t8tu) ($1,000) ($1000) ($1,000) ($1,000) 1984 34, 986 0 34,986 2,916 0.980 2,857 99,436 0084 835 0 2,022.0 1,953.7 1985 36,125 0 36,125 3,010 1.004 3,022 102,641 +0084 862 0 2,160.0 2,016.4 1986 37,622 0 37,622 3,135 1.029 3,226 106,904 0086 919 0 2,307.0 2,080.7 1987 39,005 0 39,005 3,250 1.055 3,429 110,825 0090 997 0 2,432.0 2,119.2 1988 © 40, 398 0 40,398 3,367 1.082 3,643 114,815 0092 1,056 0 2,587.0 2,178.3 1989 41,982 5,400 36,582 3,049 1.109 3,381 103,971 -0094 977 460 2,864.0 2,329.9 1990 43,371 += 5,400 »=— 37,971 3,164 1.136 3,595 107,892 .0097 1,047 460 3,008.0 2, 364.3 1991 45,948 5,400 40,548 3,379 1.165 3,937 115,224 .0099 1,141 460 3,256.0 2,472.6 1992 48,760 5,400 43,360 3,613 1.194 4,314 123,203 0101 1, 244 460 3,530.0 2,590.0 1993 51,384 5,400 45,984 3,832 1.224 4,690 130,671 +0104 1,359 460 3,791.0 2,687.4 1994 54,195 5,400 48,795 4,066 1.254 5,099 138,651 .0107 1,484 460 4,075.0 2,791.0 1995 56,782 5,400 51,382 4,282 1.286 5,506 146,016 +0110 1,606 460 4,360.0 2,885.4 1996 62,348 5,400 56,948 4,746 1.318 6,255 161,839 0112 1,813 460 4,902.0 3,134.3 1997 67,891 5,400 62,491 5,208 1.351 7,035 177,593 +0115 2,042 460 5,453.0 3,368.9 1998 73,420 5,400 68,020 5,668 1.385 7,851 193,279 .0118 2, 281 460 6,030.0 3,599.3 1999 78,982 5,400 73,582 6,132 1.419 8,701 209,101 -0121 2,530 460 6,631.0 3,824.1 2000 84,525 5,400 79,125 6,594 1.455 9,594 224,855 0124 2, 788 460 7, 266.0 4,048.6 2001 90,077 5,400 84,677 7,056 1.491 10,521 240,610 .0127 3,056 460 7,925.0 4,266.8 2002 95,200 5,400 89,800 7,483 1.528 11,435 255,170 .0130 3,317 460 8,578.0 4,462.3 2003 100,764 5,400 95,364 7,947 1.567 12,453 270,993 +0134 3,631 460 9,282.0 4,665.1 2004-2023 106,238 5,400 100,838 8,403 1.567 13,168 286,542 0134 3,840 460 9,788.0 67, 547.0 2024-2038 106,238 5,400 100,838 8,403 1.567 13,168 286,542 -0134 3,840 50 9,378.0 32,401.0 NOTE: ALL COSTS IN 1983 DOLLARS TOTAL: 159, 786.3 TABLE 22 41 ECONOMIC ANALYSIS OF ALTERNATIVE "B" (WITH BOTH HYDRO PLANTS) ENERGY HYDRO DIESEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM HYDRO PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR (MWh) (MWh) (MWh) (1000 g) ($/gal) ($1000) _ (MBtu) — ($1000/MBtu) ($1,000) ($1000) ($1,000) ($1,000) 1984 36,427 0 36,427 3,036 0.980 2,975 103,528 0084 870 0 2,105.0 2,033.9 1985 38,522 O 38,522 3,210 1.004 3,223 109,461 0084 919 0 2,304.0 2,150.8 1986 = 41, 491 O 41,491 3,458 1.029 3,558 117,918 +0086 1,014 0 2,544.0 2,294.4 1987 44,242 O 44,242 3,687 1.055 3,890 125,727 0090 1,132 0 2,758.0 2,403.3 1988 = 47,173 O 47,173 3,931 1.082 4,253 134,047 -0092 1,233 0 3,020.0 2,542.8 1989 49,950 5,400 = 44,550 3,713 + =:1.109 4,117 126,613 0094 1,190 460 3,387.0 2,755.3 1990 §=©52,900 5,400 »= 47,500 3,958 1.136 4,497 134,968 0097 1,309 460 3,648.0 2,867.3 1991 57,668 5,400 52,268 4,356 1.165 5,074 148,540 0099 1,471 460 4,063.0 3,085.4 1992 62,493 5,400 57,093 4,758 1.194 5,681 162,248 -0101 1,639 460 4,502.0 3,303.1 1993 67,137. = 5,400 61,737 5,145 1.224 6,297 175,445 +0104 1,825 460 4,932.0 3,496.3 1994 71,962 5,400 66,562 5,547 1.254 6,956 189,153 0107 2,024 460 5,392.0 3,693.0 1995 76,798 5,400 71,398 5,950 1.286 7,651 202,895 -0110 2,232 460 5,879.0 3,890.7 1996 83,437 5,400 78,037 6,503 1.318 8,571 221,752 +0112 2,484 460 6,547.0 4,186.2 1997 91,706 5,400 86,306 7,192 1.351 9,717 245,247 +0115 2,820 460 7,357.0 4,545.2 1998 98,262 5,400 92,862 7,739 1.385 10,718 263,900 0118 3,114 460 8,064.0 4,813.4 1999 106,573 5,400 101,173 8,431 1.419 11,964 287,497 0121 3,479 460 8,945.0 5,158.6 2000 113,774 5,400 108,374 9,031 1.455 13,140 307,957 0124 3,819 460 9,781.0 5,450.0 2001 121,143 5,400 115,743 9,645 1.491 14,381 328,895 0127 4,177 460 =10,664.0 5,741.5 2002 129,432 5,400 124,032 10,336 1.528 15,793 352,458 -0130 4,582 460 11, 671.0 6,071.3 2003 135,693 5,400 130,293 10,858 1.567 17,014 370,258 0134 4,961 460 12,513.0 6,289.0 2004-2023 143,962 5,400 138,562 11,547 1.567 18,094 393,753 0134 5,276 460 13,278.0 91,631.5 2024-2038 143,962 5,400 138,562 11,547 1.567 18,094 393,753 -0134 5,276 50 12,868.0 44,458.9 NOTE: ALL COSTS IN 1983 DOLLARS TOTAL: 212,861.9 42 1.2 - Decision Analysis Tables 11 through 22 have provided net present worth estimates for all four of the energy-supply alternatives considered for Unalaska. These estimates are summarized in Table 23, below: TABLE 23 TOTAL PRESENT WORTH OF ALTERNATIVES AT EACH GROWTH RATE STUDIED (Costs shown are in millions of 1983 dollars) FUTURE GROWTH RATES ALTERNATIVE Low BEST GUESS HIGH 1. Base Case (Diesels) 6925 154.9 205.07 2. Alternative A (Diesels plus 10 MW geothermal) 108.9 165.4 214.8 3. Alternative A (Diesels plus 30 MW geothermal) 222.5 250.3 267.9 4. Alternative B (Diesels plus small hydro) 70.3 159.8 21209 At each level of load growth studied, it may be seen that the least expensive alternative is the continued (and expanded) use of the diesel units. In a case such as this, the conclusion to be drawn is quite obvious. Had the outcome not been so clear-cut, with the ranking of the alternat- ives' costs differing from one growth rate to the next, there are widely accepted methods for selecting the one alternative to be pursued to min- imize cost or to minimize risk of loss. These techniques were not need- ed in the study of this set of alternatives. 43 J_- ENVIRONMENTAL AND SOCIAL IMPACTS It is expected that none of the alternatives examined by this report would have any negative impacts upon the environment in and around Unalaska nor upon the social structure of the community. The diesel engines which would exist in any event give off exhaust and noise. The nearly constant wind at Unalaska will disperse exhaust emissions quickly. Noise can be controlled when adequate consideration is given to engine enclosures and muffler systems. The danger of fuel spills associated with the installation of diesel engines must be acknowleged. The danger of such spills may be minimiz- ed with proper design. A well-developed spill management plan can help to avoid unnecessary damages if a spill should occur. Salmon spawning areas may be adversely affected by the development of a hydro project on Shaishnikof River. In their draft report on the pro- ject, the Corps of Engineers described measures available to mitigate the damages to such habitat. The construction of a geothermal plat on Mt. Makushin could have sig- nificant environmental impacts, especially upon the surrounding land. With carefully planned construction activities, these damages can be minimized. Areas worth special consideration are the construction of the access road and the disposal of down-hole material and drilling mud. Any one of these projects could provide significant employment possi- bilities to the residents of the area. APPENDIX A COST ESTIMATES DEVELOPED BY REPUBLIC GEOTHERMAL, INC. FOR A GEOTHERMAL PLANT AT MT. MAKUSHIN MAR - 8 1984 REPUBLIC GEOTHERMAL, INC. 11623 EAST SLAUSON AVENUE SANTA FE SPRINGS, CALIFORNIA 90670 TWX . 910.586.1696 (213) 945.3661 March 5, 1984 RECEIVED Mr. David Denig-Chakroff Alaska Power Authority MAR 07 1984 334 W. 5th Ave. Anchorage, AK 99501 ALASKA POWER AUTHORITY, Subject: Electrical Power Generation Economic Analysis Contract CC08-2334, Amendment No. 6 ANCHORAGE ACRES AMERICAN Dear Dave; As requested in your February 2, 1984 letter, please find enclosed a draft of the economic feasibility section of the subject report. This section addresses the estimated capital and operation and maintenance (O&M) costs required for the two cases of a 10 MW gross (6.7 MW net) geothermal power plant and for a 30 MW gross (20 MW net) geothermal power plant on the Island of Unalaska. The two power plant sizes are derived by superimposing the installed capacity of all units over the estimated power demand as shown on the attached figures. To ensure that power will be available during both normal and emergency operations, the power generation capacity of all available units is always kept above the peak load demand. Normal operation is defined as all installed units available for power generation. Emer- gency operation is defined as the largest installed unit down for maintenance and the second largest installed unit down on emergency trip. Determination of power plant sizing, unit sizing, and phasing schedule will be described in detail ina separate section of the report. Based on the above criteria, The 10 MW gross plant will satisfy the electrical load demand estimated by Acres American, Inc. for the “no-bottomfishing case" well into the future. The 30 MW gross plant will satisfy the electrical load demand estimated by Acres American, Inc. for the “low- bottomfish catch case" well past the year 2000. Due to the uncertainties in the electrical load forecasts, it is recommended that the geothermal power plant be developed in phases that are timed to the growth in demand. The first Phase of development would consist of two identical 5 MW gross REPUBLIC GEOTHERMAL, INC. Mr. D. Denig-Chakroff March 5, 1984 Page 2 binary units capable of generating a total of 6.7 MW net of electrical power. Should bottomfishing take place and elec- trical load demand increase, than a second and third phase would be added as required. If the load demand follows the low-bottomfish catch projection, the second and third phases would each consist of two 5 MW gross binary units, duplicating the initial phase. They would become commercial in early 1993 and 2000, respectively. We also have analyzed the effects of drilling all wells required for the 30 MW gross plant upon construction of the initial phase, instead of drilling the wells as each increment is constructed. If all wells are drilled in the initial phase, the total development costs are $202,316,000. This requires a total equity investment of $101,158,000 having a 1983 present value of $45,984,000 if discounted back at a factor of 10.5% per year. If the wells are drilled as each increment is constructed, the total development costs are $220,334,000. This requires a total equity investment of $110,172,000 having a 1983 present value of $46,201,000 if discounted back at 10.5% per year. Assuming that amortization of the debt starts upon com- pletion of each phase of construction, a high penalty will be paid if all wells are drilled up front, as the debt service will be substantially higher. Based on the this, and because of the uncertainties in electrical demand growth, it is recom- mended that the wells be drilled as each increment is con- structed to minimize the risk to the existing consumer base. In order to finalize the draft report by the end of March as scheduled, we would appreciate your comments to the attached at your earliest convenience. If you have any questions, please let us know. Sincerely, J. Bi ce Sr. Power Plant Engineer JB/lc ECONOMIC FEASIBILITY The economic feasibility of developing the Makushin geothermal resource for electrical power generation will be assessed by ACRES American, Inc. as requested by the Alaska Power Authority. To permit this assessment, Republic Geothermal, Inc. has prepared the following tables showing the capital cost estimate and the operation and maintenance cost estimate for each alternative studied: Vs 2. Table I - Capital cost estimate for the development of a 10 MW gross (6.7. MW net) geothermal power plant. Table II - Capital cost estimate for the development of a 30 MW gross (20 MW net) geothermal power plant with all the wells drilled during the first phase of plant development. Table III - Capital cost estimate for the development of a 30 MW gross (20 MW net) geothermal power plant with the wells drilled as needed in each phase of plant development. Table IV - Operation and maintenance cost estimate for a 10 MW gross (6.7 MW net) geothermal plant development. Table V - Operation and maintenance cost estimate for a 30 MW gross (20 MW net) geothermal plant development. The cost estimates are based on using the recommended binary cycle for power generation. es Capital Costs Capital cost estimates show the field development costs, power plant construction costs, and other necessary costs in 1983 dollars for each alternative. Addition of these costs gives a total development cost in 1983 dollars. To this total, escalation and interest during construction are added to give a total capital cost required for the development of each alternative. dle Field Development Costs The field development costs include production well drilling and completion, injection well drilling and completion, well testing Necessary to prove productivity and injectivity, direct field operation and maintenance during development, home office support and services, and field operation and maintenance during power plant start-up. Ten MW gross field development includes two production wells and one injection well. This provides for almost a full spare production well when the plant is operated at full capacity and ensure adequate power generation in the unlikely event of the catastrophic failure of a production well. The injection well provides approximately 40 percent more capacity than necessary to reinject the total fluid required to run the power plant at full capacity. In the very unlikely event of a catastrophic failure, it is assumed that temporary disposal of the spent brine on the ground would be permissible. Thirty MW gross field development includes five production wells and three injection wells, which provides for one spare production well and one spare injection well. Power Plant Costs Power plant costs include engineering and construction of the binary units, engineering and construction of the production pipeline, engineering and construction of the injection pipeline, spare parts, consulting services and coordination support, start-up including operator training, and fire and casualty insurance during construction. 10 MW gross power plant construction is assumed to take place during spring and summer months (April to October) of the first year of construction and continuously from April to end of construction of second year of construction. First phase of 30 MW gross power plant construction (20 MW ‘gross) is assumed to take place as described above. Second and third phases will take place continuously, starting in April of the first year until completion at the end of the second year. Power plant engineering and construction costs are based on a turnkey type proposal offered by the Ben Holt Co. for a binary plant similar to one being built in the Sierra Nevada of California. Construction costs are multiplied by a factor of four to reflect the high construction cost expected on Unalaska. Construction field costs include manual labor, Nonmanual labor, indirect field costs and construction management . Other Costs Other costs include the construction of a road from Driftwood Bay to the power plant site and the construction of a 34.5 kv transmission line from the power plant site to a substation in Dutch Harbor. The road construction estimate is based on a Dames and Moore study prepared for Republic Geothermal, Inc. and Alaska Power Authority in February 1, 1983. It includes existing road grading, repair and gravel surfacing; new road construction including culverts and major canyon crossing; and mobilization and demobilization. To ensure that the road is ready to receive major equipment as it 1s unloaded from the barge, road construction is scheduled for the summer months of the year prior to actual field construction of the first 10 MW gross power plant. The transmission line estimate is based on burying the cable approximately 30" underground from the power plant site to Broad Bay and then going underwater to Dutch Harbor. The estimate includes a substation to be located in Dutch Harbor that will tie the power plant to the distribution system. It also includes a 30 percent contingency to account for the uncertainties about the underwater portion of the line which has to be buried in the ocean floor. Escalation Escalation is based on an annual inflation rate of seven percent. Interest Expenses Interest expenses represent the interest to be paid during construction based in a debt to equity ration of one and on an interest rate of 12 percent per year. Operation and Maintenance Costs Operation and maintenance (0&M) costs estimates show the total annual cost in 1983 dollars to operate and maintain the overall geothermal development. O&M costs assume that operation and maintenance labor as well as administration personnel are shared by both power plant and field. O&M costs do not include any royalty payment on the resource utilized during commercial operation or any taxes on the power plant or field. TABLE I NO-BOTTOMF ISHING DEVELOPMENT CASE UNALASKA 10 MW GROSS (6.7 MW NET) BINARY POWER PLANT DEVELOPMENT COSTS IN THOUSANDS OF DOLLARS Field Development Costs (1983) Production Wells (2) Injection Wel] (1) Well Testing Direct Operation & Maintenance Home Office Start-Up Subtotal Field Costs Power Plant Costs (1983) Power Plant Eng. & Const. Production Pipeline Injection Pipeline Spare Parts Consulting & Coordination Start-Up Insurance Subtotal Power Plant Costs Other Costs (1983) Road Construction Transmission Line Subtotal Other Costs TOTAL COSTS (1983) Escalation TOTAL ESCALATED COSTS Interest Expenses TOTAL DEVELOPMENT COSTS Equity Debt TOTAL USE OF FUNDS 3,747 2,352 0 0 6,099 1,600 0 0 0 1,600 521 236 0 0 757 513 526 426 734 2,199 475 600 400 525 2,000 0 0 0 210 210 6,856 3,714 826 1,469 12,865 0 2,504 10,516 7,010 20,030 0 0 963 0 963 0 0 0 453 453 0 0 0 200 200 162 200 200 238 800 0 0 0 400 400 0 0 130 130 260 0 5,146 0 0 5,146 0 0 0 6,405 6,405 0) 5,146 0 6,405 11,551 7,018 11,564 12,635 16,305 47,522 Field Development Costs (1983) Production Wells (5) Injection Wells (3) Well Testing Direct Operation & Maint. Home Office Start-Up Subtotal Field Costs Power Plant Costs (1983) Power Plant Eng. & Const. Production Pipeline Injection Pipeline Spare Parts Consulting & Coordination Start-Up Insurance Subtotal Power Plant Costs Other Costs (1983) Road Construction Transmission Line Subtotal Other Costs TOTAL COSTS (1983) Escalation TOTAL ESCALATED COSTS Interest Expenses TOTAL DEVELOPMENT COSTS Equity Debt TOTAL USE OF FUNDS TABLE [1 LOW-BOTTOMFISH CATCH CASE UNALASKA 30 MW GROSS (20 MW NET) BINARY POWER PLANT DEVELOPMENT COSTS IN THOUSANDS OF DOLLARS ALL WELLS DRILLED IN FIRST PHASE OF POWER PLANT DEVELOPMENT Total Costs Total Costs Total Costs Total Costs 1985 1986 1987 1988 First Phase 1991 1992 Second Phase 1998 1999 Third Phase All Phases 3,747 4,404 4,404 0 12,555 0 0 0 0 0 0 12,555 1,600 1,600 1,600 0 4,800 0 0 0 0 0 0 4,800 521 354 354 0 1,229 0 0 0 0 0 0 1,229 513 526 526 734 2,299 426 734 1,160 426 734 1,160 4,619 475 600 600 525 2,200 400 525 925 400 525 925 4,050 0 0 0 210 210 0 150 150 0 100 100 460 6,856 7,484 7,484 1,469 23,293 826 1,409 2,235 826 1,359 2,185 27,713 O 2,504 10,516 7,010 20,030 10,015 10,015 20,030 10,015 10,015 20,030 60,090 0 0 963 0 963 963 0 963 325 0 325 2,251 0 0 0 453 453 0 453 453 0 453 453 15359) 0 0 0 200 200 0 200 200 0 200 200 600 162 200 200 238 800 200 200 400 200 200 400 1,600 0 0 0 400 400 0 200 200 0 150 150 750 0 0 130 130 260 0 130 130 0 130 130 520 162 2,704 11,809 8,431 23,106 11,178 11,198 22,376 10,540 11,148 21,688 67,170 0 5,146 0 0 5,146 i} 0 0 0 0 0 5,146 0 0 0 6,405 6,405 0 0 0 0 0 0 6,405 0 5,146 0 6,405 11,551 0 0 0 0 0 0 14,551 7,018 15,334 19,293 16,305 57,950 12,004 12,607 24,611 11,366 12,507 28 873 106 ,434 1,017 3,451 5,997 6,564 17,029 8,621 10,570 19,191 19,993 24,416 44,409 80,629 8,035 18,785 25,290 22,869 74,979 20,625 23,177 43,802 31,359 36,923 68,282 187 ,063 259° 1,125 2,598 4,295 8,277 655 2,091 2,746 997 3,233 4,230 155203 8,294 19,910 27,888 27,164 83,256 21,280 25,268 46,548 32,356 40,156 75,512 202,316 4,147 9,955 13,944 13,582 41,628 10,640 12,634 23,274 16,178 20,078 36,256 101,158 4,147 9,955 13,944 13,582 41,628 10,640 12,634 23,274 16,178 20,078 36,256 101,158 8,294 19,910 27,888 27,164 83,256 21,280 25,268 46,548 32,356 40,156 72,512 202,316 Field Development Costs (1983) Production Wells (5) Injection Wells (3) Well Testing Direct Operation & Maint. Home Office Start-Up Subtotal Field Costs Power Plant Costs (1983) Power Plant Eng. & Const. Production Pipeline Injection Pipeline Spare Parts Consulting & Coordination Start-Up Insurance Subtotal Power Plant Costs Other Costs (1983) Road Construction Transmission Line Subtotal Other Costs TOTAL COSTS (1983) Escalation TOTAL ESCALATED COSTS Interest Expenses TOTAL DEVELOPMENT COSTS Equity Debt TOTAL USE OF FUNDS TABLE IIT LOW-BOTTOMF ISH CATCH CASE UNALASKA 30 MW GROSS (20 MW NET) BINARY POWER PLANT DEVELOPMENT COSTS IN THOUSANDS OF DOLLARS WELLS DRILLED AS NEEDED IN EACH PHASE OF POWER PLANT DEVELOPMENT Total Costs Total Costs Total Costs Total Costs 1985 1986 1987 1988 First Phase 1991 1992 Second Phase 1998 1999 Third Phase All Phases 3,747 = 2,352 0 0 6,099 5,799 0 5,799 3,747 0 3,747 15,645 1,600 0 0 0 1,600 1,600 0 1,600 1,600 0 1,600 4,800 $21 236 0 0 757 354 0 354 236 0 236 1,347 513 526 426 734 2,199 526 734 1,260 526 734 1,260 4,719 475 600 400 525 2,000 600 525 1,125 600 525 1,125 4,250 0 0 0 210 210 0 150 150 0 100 100 460 6,856 3,714 826 1,469 12,865 8,879 1,409 10,288 6,709 1,359 8,068 31,221 0 2,504 10,516 7,010 20,030 10,015 10,015 20,030 10,015 10,015 20,030 60,090 0 0 963 0 963 963 0 963 325 0 325 E25) 0 0 0 453 453 0 453 453 0 453 453 1,359 0 0 0 200 200 0 200 200 0 200 200 600 162 200 200 238 800 200 200 400 200 200 400 1,600 0 0 0 400 400 0 200 200 0 150 150 750 0 0 130 130 260 0 130 130 0 130 130 520 162 «2,704 11,809 8,431 23,106 11,178 11,198 22,376 10,540 11,148 21,688 67,170 0 5,146 0 0 5,146 0 0 0 0 0 0 5,146 0 0 0 _6,405 6,405 0 0 0 0 0 0 6,405 O 5,146 0 6,405 11,551 0 0 0 0 0 0 11,551 7,018 11,564 12,635 16,305 47 522 20,057 12,607 32,664 17,249 12,507 29,756 109 ,942 1,017 2,602 3,927 6,564 14,110 14,405 10,570 24,975 30,342 24,416 54,758 93,843 8,035 14,166 16,562 22,869 61,632 34,462 23,177 57,639 47,591 36,923 84,514 203,785 259 978 2,018 3,399 6,654 1,096 2,999 4,095 1,513 4,297 5,810 16,559 8,294 15,144 18,580 26,268 68, 286 35,558 26,176 61,734 49,104 41,220 90,324 220,344 4,147 7,572 9,290 13,134 34,143 17,779 13,088 30 867 24,552 20,610 45,162 110,172 4,147 7,572 9,290 13,134 34,143 17,779 13,088 30,867 24,552 20,610 45,162 110,172 8,294 15,144 18,580 26,268 68,286 35,558 26,176 61,734 49,104 41,220 90,324 220,344 TABLE IV NO-BOTTOMFISHING DEVELOPMENT CASE UNALASKA 10 MW GROSS (6.7 MW NET) BINARY POWER PLANT COMBINED PLANT AND FIELD OPERATION AND MAINTENANCE COSTS (Thousands of 1983 Dollars) Administration 85 Operation and Maintenance Labor 580 Contract Maintenance 350 Well Reconditioning 73 Outside Consulting 150 Power Plant Insurance 100 Miscellaneous 460 TOTAL ANNUAL COST 1,800 TABLE V LOW-BOTTOMFISH CATCH CASE UNALASKA 30 MW GROSS (20 MW NET) BINARY POWER PLANT COMBINED PLANT AND FIELD OPERATION AND MAINTENANCE COSTS (Thousands of 1983 Dollars) Administration 170 Operating and Maintenance Labor 790 Contract Maintenance 650 Well Reconditioning 225 Outside Consulting 150 Power Plant Insurance 300 Miscellaneous 550 TOTAL ANNUAL COST 2,835 ELECTRICAL POWER DEMAND — MW 1984 1986 NO BOTTOMFISH DEVELOPMENT CASE ELECTRICAL GRID LOAD FORECASTS PEAK LOAD DEMAND BASE LOAD DEMAND 1988 1990 1992 1994 1996 1998 2000 YEARS 2002 AGI E1834 NO BOTTOMFISH DEVELOPMENT CASE POWER PLANT DEVELOPMENT SCHEDULE 4 £ 5 18 al < 17 ee <q<z 2a 16 é “ ° 15 =a aw 23 14 zs ug ee ee ee ee ee ee ee ee ee . S " a aS 12 2 z <5 2tn ae 3/3 =z <= = 10 fl, 2a a Gg 2 é = i 5 3 é S| ee en ne ee = hs 5 7 PEAK LOAD DEMAND & - wa S = = w & as 6 an wx aoe 5 <<. © ee © cue © cme 6 cee 6 ee 6 ee © eee ee ee es eee es — ! BASE LOAD DEMAND 3 2 a -- 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS AGI £1529 NO BOTTOMFISH DEVELOPMENT CASE POWER GENERATION-NORMAL OPERATION ALL UNITS AVAILABLE ELECTRICAL POWER DEMAND — MW BASE LOAD DEMAND 0 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS AGi £1528 NO BOTTOMFISH DEVELOPMENT CASE POWER GENERATION-~EMERGENCY OPERATION LARGEST UNIT DOWN AND SECOND LARGEST UNIT TRIPPED ELECTRICAL POWER DEMAND — MW 0 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS RGi £1527 ELECTRICAL POWER DEMAND — MW 1984 1986 LOW BOTTOMFISH CATCH CASE ELECTRICAL GRID LOAD FORECASTS 1988 1990 1992 1994 1996 1998 2000 YEARS 2002 2004 Gt E1633 LOW BOTTOMFISH CATCH CASE POWER PLANT DEVELOPMENT SCHEDULE ELECTRICAL POWER DEMAND 3 X 6.7 MW (NET) PLANTS EACH INCLUDING 2 IDENTICAL UNITS BINARY GEOTHERMAL POWER PLANTS a e 2 <|5 2 35 wu 3 = 0 ga wx oe 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS RG! 21531 LOW BOTTOMFISH CATCH CASE POWER GENERATION-NORMAL OPERATION ALL UNITS AVAILABLE ELECTRICAL POWER DEMAND 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS AGI E1829 LOW BOTTOMFISH CATCH CASE POWER GENERATION-EMERGENCY OPERATION LARGEST UNIT DOWN FOR MAINTENANCE AND ELECTRICAL POWER DEMAND SECOND LARGEST UNIT TRIPPED 4 36 34 32 30 28 26 24 20 18 16 14 12 10 Qa 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS RGi =1530 APPENDIX B ALASKA POWER AUTHORITY PROJECT EVALUATION GUIDELINES MAR 2 & 1984 ALASKA POWER AUTHORITY 334 WEST 5th AVENUE - ANCHORAGE, ALASKA 99501 Phone: (907) 277-7641 (907) 276-0001 ANCHORAGE March 28, 1984 Mr. Jim Landman Acres American, Inc. 1577 C Street, Suite 305 Anchorage, Alaska 99501 Dear we eRe The Alaska Power Authority's economic analysis guidelines appear to be unrealistic with respect to the economic life and term of financing of geothermal power facilities. Several outside sources experienced in geothermal development have confirmed that ae) geothermal systems can be expected to have a 30-year economic life i and that 25-year financing is generally accepted. For your econom- |——~} ic analysis of the geothermal alternative for the Unalaska recon- \—- naissance study, please use these figures in place of the 15-year Ae economic life/15-year financing recommended in past Power Authority Dave Denig-Chakroff Project Manager DDC/ms 544/173/D1/F1 ! Jucy $e Lacrent 2/Ib /: ALASKA POWER AUTHORITY PROJECT EVALUATION PROCEDURE The Power Authority's project evaluation procedure reflects the organization's purpose and philosophy. The Power Authority was established as an instrument of the State to intervene for the purpose of bringing to. fruition worthy projects that would otherwise be excluded from development by the constraints of financial markets. Most, if not all, Alaskan capital intensive power projects would be precluded from conventional financing due to the perception of added risk inherent in building projects in small, isolated Alaska communities. Thus, the Authority's approach to project evaluation does not consist, as some have recommended, of using market financial parameters to determine the ability of the project to generate sufficient sales to cover revenue requirements. Instead, the approach entails first assessing a project's “worthiness" apart from the constraints of financial markets, and, second, determining if there is the ability and political will to intervene to establish financing arrangements and terms that permit the project to be financed. To reiterate, the Authority's purpose is to intervene in financial markets to permit worthy projects to be developed. A project evaluation procedure that requires a project to pass a financing test using market conditions would preclude the Authority from acting in keeping with its purpose. The means that the Authority has adopted to assess a project's worthiness are consistent with traditional federal evaluation methods for. public water resource projects. The goal is to maximize net economic benefits from the state's perspective, tempered by environmental, socioeconomic and public preference constraints. The method attempts to identify the real economic resource costs of all options under study; the magnitude of these costs are independent of the entity that finances and implements the options. The Authority's project evaluation procedure has evolved since 1979 and continues to undergo refinement. Some desired characteristics of the procedures are: 1. Consistency from one study and market area to another. 2. Equity in the treatment of alternatives. 3. Practicality, given data limitations. 4. Responsiveness to statutory direction. In general terms, the procedure entails (1) forecasting end use requirements on the basis of assumptions regarding economic activity and energy cost trends; (2) formulating various alternative plans to satisfy the forecasted requirements; (3) estimating the capital, operation, maintenance and fuel costs of each plan over its life cycle; (4) discounting the cost of each plan to a common point in time; (5) comparing the total discounted costs of each plan and determining Project Evaluation Procedure Page 2 the preferred plan; (6) evaluating the preferred plan's cost of power under a variety of financing arrangements in relation to anticipated power costs without the plan; and (7) identifying those financing arrangements which result in acceptable power costs. Forecasting Future Requirements. A planning period is first adopted to define the period of time over which forecasts are developed and energy plans are formulated. The length of the planning period is limited by the practical difficulties of forecasting far into the future. A period of 20 years from the present is normally adopted. End use requirements (space heating, water heating, lights and appliances, and industrial processes) are forecast over the planning period for each of three sectors (residential, commercial/government, and manufacturing). The end use requirement forecasts are initially developed irrespective of the form of energy being used to energize the end use. The forecast for each end use reflects a range of economic activity/population forecasts and a range of overall energy prices. With respect to the former, economic base analysis founded on discreet developmental events is used as the basis of forecasting rather than simple trend projections, whenever possible. With regard to the latter, the end use forecasts reflect situations both where energy prices, overall, rise faster than general prices and where energy prices, overall, rise at a rate in keeping with general price levels. (It can be expected that the actual energy costs of the preferred plan will eventually be shown to fall within that range.) An intermediate forecast is used as the basis for the initial planning steps. - For each end use where more than one energy form is available to energize that end use, a mode split analysis is performed. This is accomplished in the course. of the following initial screening of alternatives: 1. All reasonable alternative means of providing each end use are identified. 2. The per unit cost of energy is determined for each alternative using the Power Authority's economic evaluation parameters. 3. The amount of energy (or the amount of energy savings) that can be provided by each alternative is estimated. 4. For each end use, cost curves are developed showing relative cost, over time, of providing the end use by each of the reasonable alternatives. 5. The lowest cost means, or combination of means of providing each end use is identified. This determines the mode split after due consideration of the existing mode split and lag time for substitution of energy forms. The results also serve as a tool for formulating energy plans, which is the next step in the analysis. Project Evaluation Procedure Page 3 The forecasts address both energy and peak load requirements. Plan Formulation. The first step in formulating energy plans is identifying and screening all reasonable energy supply and conservation options. These include structural and non-structural alternatives and alternatives that provide intermittent as well as firm energy. This is accomplished in the course of the previous step in the analysis. Existing energy generation facilities and conservation practices are also evaluated for their performance, operation and maintenance costs, condition and remaining economic life. Given the menu of options available, the relative cost and mode split information developed in the course of forecasting energy requirements, and any additional comparative analysis of the options, two or more energy plans are formulated. Each plan must, with a consistent level of reliability, meet the forecasted energy and peak load requirements over the planning period. Whether plans are formulated to meet electrical energy requirements only, or both electrical and thermal requirements, depends upon the results of the mode split analysis. If it is shown that thermal needs should be met to a significant extent by electrical energy, then plans are formulated to meet both thermal and electrical requirements. If it is shown, on the other hand, that electricity should not play a significant part in providing thermal needs, then the bounds of the study are_limited to electrical energy requirements only. One plan is termed the “base case plan"; this plan is developed assuming a continuation of existing practice in the study area and is used as a common yard stick for comparison of the other plans. If opportunities exist, a plan is formulated to improve the base case plan by increasing its efficiency or by other means. One or more additional plans are formulated incorporating various combinations of options with the objective of identifying the lowest cost plan that is environmentally and socially acceptable. The sequence and timing of plan components are optimized as an integral part of plan formulation. This is accomplished by a systematic testing of different sequences and project timing in search of the sequence and timing that results in the lowest present value of plan costs. Project Evaluation Procedure Page 4 Discussion: 1. The Authority initially confined the forecasting to electrical energy requirements only. There are two problems with this approach. First, electrical energy supply plans often have associated with them certain amounts of waste heat suitable for space, water or process heating. In such cases, a forecast of thermal energy requirements is needed to determine the possibility of effectively utilizing this heat. Second, in forecasting electrical energy alone, the analyst is either explicitly or implicitly assuming a certain mode split in those end uses where more than just electrical energy can provide that end use. It is necessary to make the analysis of mode split explicit, and to do so requires a forecast of end use requirements rather than simply electrical energy needs. Ze In amplification of the procedure for mode split determination, the goal is to determine, based on full economic cost of alternatives and rational economic behavior, the lowest cost way of providing the end use. Estimating Project Costs. AlT costs for all projects are estimated with reference to a base year and -in terms of the base year price levels. Costs incurred in future years reflect relative price changes only. Capital cost estimates are “overnight" estimates. Capital costs (in the year they are incurred) are added to annual operation and maintenance costs and any fuel costs to give the total yearly cost of a plan. The series of yearly costs is discounted to a common point in time, typically the first year of the planning period. Discussion: 1. <A constant dollar approach has been adopted in the economic analysis to keep from having to forecast a long term inflation rate that would always serve as source of dispute, and to ease the computational burden. As reported by the Water and Energy Task Force of the U.S. Water Resources Council in their December 1981 report entitled “Evaluating Hydropower Benefits,“ the critical element in an analytical approach is the “use of consistent assumptions about interest rates and future prices." The Task Force endorses either “life-cycle analysis" (which includes inflation) or “inflation free analysis". The Power Authority's approach is specifically cited by the Task Force as an example of the latter. Project Evaluation Procedure Page 5 2. Life cycle analysis dictates, state statute requires, and the long term planning horizon of a state government suggests that the relative plan costs be compared over the economic life of the projects under consideration. When hydroelectric and steam plant projects are being addressed, the economic evaluation period exceeds the 20 (or sometimes 30) year planning horizon. Yet, it is inappropriate to forecast load growth or escalation trends beyond the limits of the planning period. Also, project economic lives differ for varying types of facilities. These problems are handled by addressing costs throughout the economic evaluation period, but by assuming no load growth or cost escalation beyond the planning period. Facilities are replaced throughout the economic analysis period as dictated by their economic lives. Salvage values are included in the final year of the period as necessary. The economic evaluation period extends to the year that the longest lived project (that is added during the planning period) reaches the end of its economic life. For instance, if a hydroelectric project with a 50-year economic life is added in the tenth year of the planning period, the economic evaluation period would be 60 years in duration. Plan Comparison. Plans are compared in terms of total net benefits. Net benefits are equal to the gross benefits associated with a plan, less plan cost. The benefits are defined as the discounted total cost of the base case plan, supplemented by any subsidiary benefits of a particular plan (see discussion). The plan offering the greatest net benefits is the preferred plan from an economic perspective. A benefit/cost ratio can also be used as an indicator of a plan's cost effectiveness. Discussion: 1. In the event a plan provides a beneficial output other than that specifically being addressed in the study, incremental costs required to realize that benefit are subtracted from the benefit in each year, and these annual subsidiary net benefits are discounted to the common base date. 2. Consider the following hypothetical example: All cost and benefit figures are the sum of annual amounts discounted to the base date. Project Evaluation Procedure Page 6 Plan Base Plan Plan Base Plan Plan Cost Case 100 A 120 B 90 Case Evaluation - benefits: 100 cost: 100 net benefits: 0 benefit/cost ratio: 1 A Evaluation - benefits: 100 + 10 = 110 cost: 120 net benefits: 110 - 120 = -10 benefit/cost ratio: 110/120 = 0.92 B Evaluation - benefits: 100 + 15 = 115 cost: 90 net benefits: 115 - 90 = 25 benefit/cost ratio: 115/90 = 1.28 Subsidiary Net Benefit 10 15 SUMMARY OF RECOMMENDATIONS Analysis Parameters for the 1983 Fiscal Year Economic Analysis Inflation Rate - 0% Real Discount Rate - 3.5% Real Oil Distillate Escalation Rate 2.5% - First 20 years 0% - Thereafter Cost of Power AnaTtysis Inflation Rate -7.0% Project Debt to Equity Ratio - 1:0 Cost of Debt - 12.0% Economic Life and Term of Financing Gasification Equipment Waste Heat Recapture Equipment. Under 5 MW Over 5 MW Solar, Wind Turbines, Geothermal and Organic Rankine Cycle Turbines Diesel Generation* Units under 300 KW Units over 300 KW Gas Turbines Combined Cycle Turbines Steam Turbines (Including Coal and Wood-fired Boilers) Under 10 MW Over 10 MW Hydroelectric Projects Economic Life Term of Financing Transmission Systems Transmission Lines w/ Wood Poles Transmission Lines w/ Steel Towers Submarine Cables Oil Filled Solid Dielectric *Diesel Reserve Units will have longer life depending on use. 10 years 10 years 20 years 15 years 10 years 20 years 20 years 30 years . 20 years 30 years 50 years 35 years 30 years 40 years 30 years 20 years economic life is by unit and not total plant capacity. -¢- Lstel}E Also this Inflation Rate For the purpose of the economic analysis there is assumed to be no inflation. Recommendation: The inflation rate should therefore remain at 0%. Discount Rate As previously indicated in the Analysis Parameters of FY 82 the historic inflation free cost of money to the utility industry appears to be approximately 3.0%. Currently national and local economists and financial experts estimate the overall real discount rate to be in the range of 3% to 4% with a likelihood that the real cost of money for utilities is increasing slightly due to the increasing size and cost of electric generation projects currently being undertaken. It is also acknowledged that historically the real cost of money in Alaska contains an “Alaska factor" and is therefore somewhat higher than in the rest of the nation. However, the discount rate is also intended reflect the state opportunity cost of money and reflect long term trends. Recommendation: In regards to the above analysis and review, the Discount Rate should be set at 3.5%. Escalation Rate Based upon”a composite research of Energy Consulting Companies, national and local economists, and Investment Brokerage Firms, the forecast of distillate fuels (diesel and fuel oil) are expected to increase at an average real rate of 2.5% per annum for the period from 1982 to 2001. Beyond the year 2001 further increases in fuel are assumed to be zero. This assumption is based upon the belief that although additional increases are expected they are too speculative to quantify. . Recommendation: The escalation rate for diesel and fuel oil be set at 2.5% per annum for the first 20 years of the economic analysis. Thereafter, further increases in the rate are assumed to be zero. Inflation Rate For the 1983 Fiscal Year, national and local economists along with Financial Institutions and Energy consulting Firms forecast the National inflation rate between 6 and 8 percent. Recommendation: The inflation rate should be set at 7% per year. Debt to Equity Ratio At the present time and under legislation currently in effect it is difficult to estimate the extent of debt financing for future Power Authority projects. It is also common utility practice to debt finance capital intensive projects. Recommendation: In spite of the Power Authority's legislation, the debt to equity ratio for power project financing should remain at 1:0. Cost of Debt Cost of Debt is largely determined by the interest rate identified by statute for loans from the Power Project Loan fund. That interest rate is equal to the average weekly yield of municipal revenue bonds for the previous 12 month period as determined from the Weekly Bond Buyers 30 year index of revenue bonds. This average is currently approximately 13%. It is anticipated that the average will decrease only slowly during the 1983 fiscal year. Recommendation: Because of the anticipated slow decrease in the weekly revenue bond index it is recommended that the cost of debt be set at 12% to reflect current long term tax exempt rates with a decreasing participation of the Rural Electrification Administration in providing federal low interest financing. Economic Life and Term of Loan Although in certain instances economic lives of up to 100 years may be warranted for hydroelectric projects, both the State Division of Budget and Management and F.E.R.C. recommend the use of 50 year economic lives As a result the economic life of a new hydroelectric project is set at 50 years and the term of financing at 35 years. For all other alternative generation sources, the economic life and the term for which financing can be obtained is assumed to be the for new hydroelectric projects. same even though they vary for each alternative. lives and loan terms should be used for various power project alternatives. Economic Life and Term of Financing Gasification” Equipment 10 Waste Heat Recapture Equipment Under 5 MW 10 Over 5 MW 20 Solar, Wind Turbines, Geothermal and Organic Rankine Cycle Turbines 15) Diesel Generation* Units under 300 KW 10 Units over 300 KW 20 Gas Turbines 20 Combined Cycle Turbines 30 Steam Turbines (Including Coal * and-Wood-fired Boilers) Onder 10 MW 20 Qver 10 MW 30 Hydroelectric Projects Economic Life 50 Term of Financing 35) Transmission Systems Transmission Lines w/ Wood Poles 30 Transmission Lines w/ Steel Towers 40 Submarine Cables Oil Filled 30 Solid Dielectric 20 *Diesel Reserve Units will have longer life depending on use. economic life is by unit and not total plant capacity. years years years years years years years years years years years years years . years years years The following economic Also this REFERENCE Inflation Rate Discount Rate Fuel Escalation Rate Or. Scott Goldsmith [SSG Re 6.0% 3.0% Cee Or. David Reaume Economic Consultant 7.0% 3.0% 2.6% Lehman Brothers, Kohn Loeb 5.0 - 6.0% . 3.0 - 3.5% J 2.8% Or. Bradford Tuck . University of Alaska 6.0% soe 2.65% Donald MacFayden Salomon Brothers 6 - 8% 4.0% 3.0 - 4.0% Peter W. Sugg URS/Cloverdale & Colpitts- 6.0 - 7.0% 4.04% 4.0% Gary Anderson, Stanford Research Institute 7.0% 4.0 - 4.042 3.0% Or. Mike Scott Battelle Pacific N.W. Lab. 5.0 - 7.0% 3.0% 2.7% Mr. Thomas Thurber Data Resources, Inc. 625% 3.0% 2.0% Victor A. Perry III Bechtel Corp. 5.0% 3.0% 2.9% William L. Randall The First Boston Corp. 7.0 - 8.0% 319% ISOS ).1516 Wm. Micheal McHugh Applied Economics Associates 7.0 - 8.0% 3.5% Se R= e354) Fredric J. Prager Smith, Barney, Harris Upnam & Company 5.0 - 6.0% 4.0% 2.5% John Delrocali Wharten Econometric Fotcasting Asso. 7.0% 3.5% 2.3% Michael G. Moroney Peat, Marwick & Mitchell, Inc. 6.5% 3.0% 2.5% ee a ne ane: 2 ne