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HomeMy WebLinkAboutRural Hydro Assessment-Devel Study 1997RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Prepared for: Alaska Department of Community and Regional Affairs Division of Energy Prepared by: Locher Interests LTD. Anchorage, Alaska August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT SU1¥MAtY.... This report summarizes the results of Phase 1 work for contract DOE 96-R-004, Rural Hydroelectric Assessment and Development Study. The scope of Phase 1 included development of a database of existing and potential hydroelectric projects in Alaska, screening of that database to identify potentially viable small hydroelectric projects for development to serve rural Alaskan communities receiving Power Cost Equalization assistance from the State, and selection and preliminary economic and technical evaluation of a subset of sites having a high probability of economic viability. A Microsoft AccessTm database was developed containing information on 1,144 potential sites and 52 existing hydro projects. Initial screening of the potential sites resulted in identification of 131 sites with preliminary benefit cost ratios of 1.0 or above and no obvious technical or environmental constraints to development. Further review of the information concerning these projects resulted in selection of four sites for more detailed engineering and economic evaluation. These include: Community Project Proposed Installation Atka Chuniisax Creek 80 kW - 271 kW Hoonah Gartina Creek 225 kW Old Harbor Unnamed Creek 330 kW Unalaska Pyramid Creek 100 kW - 260 kW Further analyses indicate that, except for the Gartina Creek project, all of these sites have moderate to high probabilities of producing positive net economic benefits. Gartina Creek only would be viable if capital costs could be drastically reduced, or if fuel prices should increase very dramatically. The assumptions concerning these two critical parameters required to achieve economic viability for Gartina Creek are not considered reasonable, however. The Chuniisax Creek project produces positive net economic benefits under optimistic assumptions, shows an essentially break-even result under most probable assumptions, and has negative benefits under pessimistic assumptions. Because the low -end cost estimate for this development includes some high risk assumptions on use of local labor and turn -key or force account methods, this project's economic viability may be viewed as questionable. The remaining two projects (Unnamed Creek at Old Harbor, Pyramid Creek at Unalaska) exhibit net positive benefits under almost all cases analyzed. Further evaluation of these remaining two projects is recommended. Collection of updated site -specific data on these projects is recommended. Information should be collected during site visits to verify existing conditions in the communities and identify any future development plans which could impact economic feasibility. Site visits and data collection would focus primarily on those parameters identified as critical from the economic evaluation sensitivity analyses completed during this phase of the work. Additional engineering and economic evaluations of the projects would be made following site visits and data compilation. LOCHER INTERESTS LTD. Page 1 of 30 AUgUST -its, -1vul RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT 1 Q INTR4DUGTtON This report summarizes the results of Phase 1 of the Rural Hydroelectric Assessment and Development Study, Project No. DOE 96-R-004, prepared by Locher Interests LTD. (Locher), for the Department of Community and Regional Affairs, Division of Energy (DOE). 1.1 Background Since the 1940's, numerous Federal and State agencies, as well as several utilities and other private sector organizations, have prepared reports on potential hydroelectric sites throughout Alaska. These potential developments range in size from the 5,040 megawatt (MW) Ramparts Project, envisioned by the U. S. Army Corps of Engineers in the 1950's, to developments on a micro -hydro scale of 25 kilowatts (kW) or less. A number of these projects have been developed over the past thirty years and are currently serving to provide a significant percentage of the energy needs for the citizens of Alaska. Numerous smaller sites, particularly sites that would serve the small rural communities, have never been examined in detail, or have been examined and not pursued, due to prevailing economic conditions or other limitations (i.e., land status, environmental constraints). For the most part, rural Alaskan communities rely on diesel generation for their energy needs. For many communities, the cost of this diesel power is subsidized through the State's Power Cost Equalization (PCE) program. The future of this program is uncertain, given changing fiscal conditions of the State. Moreover, as technical, economic and institutional conditions change, it is likely that hydroelectric projects once found to be uneconomical or to have institutional or technical constraints precluding development may be more feasible today, or may become so in the future. Although some information on these potential projects is available in the numerous and varied reports and studies that have been done over the past fifty years, it is not always readily accessible, nor are the data easily applied to current conditions, as cost information, land status, and other key conditions all have changed somewhat since the initial analyses were completed. Thus, the DOE has identified a need for an electronic database which consolidates the information contained in the existing reports on hydroelectric potential, statewide, and facilitates evaluation of potential projects using updated assumptions concerning costs and environmental and economic feasibility. Additionally, DOE requires that an assessment of the information in the database be conducted to identify any potential projects which might provide PCE communities currently dependent on high cost, subsidized diesel power with an alternative energy source. 1.2 Scope Work under this contract is divided into two phases. This report summarizes the results of Phase 1, completion of the database, and identification and preliminary evaluation of potential hydro sites to serve PCE communities. Phase 2 will include a more detailed analysis of the potentially viable sites identified herein. More specifically, the scope of Phase 1 of this study included the: • Development of a database of known existing and potential hydroelectric sites in the State of Alaska (developed using Microsoft AccessTM software). • Preliminary screening of all potential sites to eliminate those not suitable for development as power sources for rural Alaskan communities currently participating in the PCE program. • Preliminary ranking of all remaining sites, based on environmental and economic criteria, to identify a subset of projects for more detailed evaluation as potential power sources for PCE communities. LOCHER INTERESTS LTD. Page 2 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT • Selection and evaluation of a final set of potential developments, including more detailed engineering, cost and economic evaluations, to identify those sites showing the highest probability of economic viability, to be carried forward into the Phase 2 evaluation. In addition, a paper file supplementing the information contained in the database was developed. Paper files included a printout of the complete database report for each entry, as well as photocopies of summary information from the actual reference documents (report cover, summary of pertinent project data and location map, as available) for those projects identified as potentially viable during initial screening. 1.3 Sources Utilized Phase i work was based mainly on review and analysis of existing reports and secondary data sources - Documents reviewed included those maintained at the DOE Library, the Bureau of Land Management Federal Resource Library in Anchorage, and files of the Alaska Energy Authority and the Federal Energy Regulatory Commission (preliminary permits, pending and existing license applications, existing licenses and exemptions). Additionally, DOE provided recent PCE community filings on monthly generation for incorporation into the economic evaluation of the potentially viable projects. During final screening of potentially viable projects, representatives from the PCE communities in which the developments were located were contacted. During these contacts a number of recent reports, not yet catalogued in the above libraries, were identified and obtained for review. These reports were incorporated into the database. A total of 204 technical reports and studies were reviewed and the information obtained entered into the project database. LOCHER INTERESTS LTD. Page 3 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT 2 O;:.APPR0ACH TQ*T:HE ASSIGNMEI`ii' As described below, Phase 1 of this assignment has been accomplished in two stages. Stage 1 included development of the database and screening and ranking of the projects in the database to identify a smaller subset of potentially technically, economically and environmentally viable projects. Stage 2 consisted of the evaluation of this subset of projects in more detail, including an engineering evaluation of technical reasonability, verification and revision (as required) of the cost estimates, and identification, as possible, of potential design concept modifications which might result in improved project performance or economic viability. Additionally, a Stage 2 economic evaluation was performed, based on the revised cost estimates provided by the engineering review above. This second economic evaluation utilized more community specific parameters (including historical load data) and was explicitly designed to address the range of uncertainties associated with the net benefits of each project. As detailed in subsequent sections of this report, this evaluation includes development of a probability distribution of net benefits for each project which assigns probabilities to the assumptions used in the analysis and then evaluates the results of all possible combinations of assumptions. The overall process by which this work was accomplished is described in stepwise fashion below. 2.1 Development of the Database The first step in Phase 1 of this assignment was development of the project database. As detailed in Section 3, on page 8 of this report, a Microsoft Access'"' database, consisting of 53 information fields for each database entry, was developed. Information on both existing and potential hydroelectric projects, obtained from review of the reports listed in Attachment A, was entered into this database. This ultimately resulted in the identification of 1,144 unique projects, including 52 existing projects and 1,093 potential projects, located statewide. Information on potential project developments included, as available, project location, communities potentially served, potential capacity and energy, and estimated costs for development, as well as information on land ownership and possible environmental constraints. The database also included a field assigning each site to the appropriate statistical area, as defined by the State for collecting power production statistics, (Southeast, Southwest, Southcentral, Arctic/Northwest and Yukon). Results of the screening and analysis procedures described below, as well as the project's paper files, are organized on the basis of these statistical areas. 2.2 Stage 1 Screeninq and Rankinq Following completion of the database, the projects identified were subjected to a preliminary screening to eliminate those which were obviously not suitable for consideration as an energy source for PCE communities. Prior to screening, the costs for all projects were adjusted to 1996 dollars using the Handy - Whitman Index of Public Utility Construction Costs. Initial screening included elimination of: Existing Projects (see Tables 4.1-4.3, on pages 11 and 12 in Section 4 of this report, for listings of existing projects), Projects currently being actively developed by others (that is, where FERC preliminary permits were known to have been issued or license applications were in preparation; see Table 4.4, on page 13 in Section 4), = Sites for which no construction cost data had been developed (database entries with null records in the construction cost field), LOCHER INTERESTS LTD. Page 4 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT • Projects considered to be too large or too small for development by PCE communities (i.e., installed capacity greater than 5,000 kW or less than 25 kW as denoted in the database installed capacity field), • Projects clearly identified by previous investigators as being inappropriate for development (i.e., lacking adequate flow or head, as described in the database field labeled non -viable), • Projects having obvious land or environmental constraints which could preclude or substantially increase the cost of development (Le., sites located in national parks, wildlife refuges or preserves, and sites on major salmon streams, and described in the non -viable database field). This screening procedure resulted in the elimination of all but 131 potential projects, distributed throughout the State as follows: Statistical Area Southeast Southcentral Southwest Yukon Arctic/Northwest Number of Sites 16 41 22 35 17 A listing of these 131 sites is presented as Table 5.3, on pages 15-17 in Section 5 of this report. Following initial screening, the remaining 131 projects were subjected to preliminary economic ranking, utilizing the approach detailed in Attachment B. As discussed therein, the goal of this screening and ranking process was to eliminate those projects which are clearly uneconomical while retaining those which may have some potential for development. This ranking process was designed to provide a coarse screen, somewhat biased in favor of hydro development, so as to avoid elimination of potentially viable projects, where the available information was likely to be sparse and of limited accuracy. This ranking procedure resulted in identification of 31 potential projects with a preliminary benefit cost (BC) ratio equal to or greater than 1.0. These 31 projects, by statistical area, were distributed as follows: Statistical Area Southeast Southcentral Southwest Yukon Arctic/Northwest Number of Sites 16 6 8 0 1 Table 5.4, on page 18 in Section 5 of this report provides additional detail on these projects. LOCHER INTERESTS LTD. Page 5 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1REPORT 2.3 Project Team Review The 31 projects identified during the Stage 1 economic screening and ranking procedure were reviewed by the project team (cost engineer, economist, environmental specialist, and project advisor. These sites are listed in Table 5.4, page 18 of this report. The purpose of the team review was to verify that the information contained in the database concerning these selected projects, and utilized in the screening and ranking procedure, was reasonable. Project cost estimates, communities served, system loads, and other features were reviewed and adjusted as appropriate, based upon the project team's judgment or on additional information identified as a result of the review process. This review found that the information in the database was generally reasonable, although some adjustment of transmission line costs was required for projects which had originally been studied as one of a larger group of developments with shared transmission line costs. In a few cases, transmission line costs were missing from the original study estimate. Costs were adjusted appropriately to account for these problems. Following this review and adjustment, the economic screening process was repeated, and a revised list of the top ranked economically viable projects was developed. Table 5.5, on page 20 in Section 5, presents this second list of 15 projects. 2.4 DOE Review The list of 15 projects developed during the Project Team Review described above was provided to DOE for their review and concurrence. At their request, the original list of the 131 projects (Table 5.3 on pages 15-17) which resulted from the Stage 1 screening process and the shorter list of projects with appropriate BC ratios (Table 5.4 on page 18) were also provided for DOE consideration. After review of these lists, DOE met with Locher to discuss the addition of some projects being studied by others to the final list (these projects had been screened out during Stage 1 screening above). Based on these additions and a second economic screening and ranking of the remaining projects, a list of four projects to be carried forward for further consideration was developed. PCE Community Served Project Name Atka Chuniisax Creek Hoonah Gartina Creek Old Harbor Unnamed Creek Unalaska Pyramid Creek 2.5 Stage 2 Engineering Evaluation The four projects listed above were subjected to an engineering review to ascertain that the overall technical assumptions used were reasonable and to identify, as possible, any design concept or construction approach changes which might affect project viability. Additionally, the cost estimates for the four developments were evaluated in more detail and a.high and low cost estimate developed for use in the Stage 2 economic evaluation. High and low costs are related either to possible design or construction procedures modifications or to project size. Generally, this review confirmed the technical design concepts for these developments. In some cases possible design modifications such as use of a rubber dam or wooden flashboards, in place of a LOCHER INTERESTS LTD. Page 6 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT conventional concrete structure, use of different sizes or types of penstock materials, elimination of certain project features such as potable water and sanitary facilities, were identified as possible means to reduce costs. The major area of uncertainty identified for the cost estimates for these projects is related to assumptions concerning the use of local labor and/or force account methods in their construction. Assuming such non- traditional approaches, costs are significantly lower than if traditional methods of contracting and construction are used. Conversely, risks of problems during and after construction may be higher for projects constructed by non-traditional means. Attachment C presents the engineering review performed for these four projects, along with the final cost estimates utilized in the Stage 2 economic evaluation. 2.6 Stage 2 Economic Evaluation Using the costs and installed capacities provided from the engineering evaluation above, an economic evaluation of the four projects was performed using a model developed for this assignment. The evaluation procedure, described in detail in Attachment D, rely on community specific parameters and compares the cost of electric power with and without hydroelectric power development over a 35-year planning period, extending through the year 2032. The model addresses uncertainty by including multiple assumptions about the following critical parameters comparing the percentage of cases resulting in net positive benefits with those producing negative results provides an estimate of the economic viability of the development: • future price of diesel fuel • capital cost of hydro project • annual hydro maintenance cost • real discount rate • load growth of community served The multiple assumptions used for each of the above parameters are assigned probabilities and all possible combinations of assumptions, with their associated probabilities, are analyzed, producing a probability distribution of net benefits for each project. In addition. break-even analyses were performed. Break-even analyses were accomplished by beginning with very pessimistic assumptions and then determining how much critical parameters had to be changed in order to bring net benefits up to zero. LOCHER INTERESTS LTD. Page 7 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT 3 0 7H'E DATASAS1E Master.mdb is a Microsoft AccessTm database file (2.2 Mb) with 1,978 entries representing a compilation of both existing and potential hydroelectric developments in Alaska. Information sources used to obtain information for the database include 204 reports found in various libraries, including the Department of Community and Regional Affairs, Division of Energy (DOE) Library, the Bureau of Land Management Federal Resource Library, Alaska Energy Authority project files, and Federal Energy Regulatory Commission (FERC) reports on preliminary permits and license applications. A complete bibliography, indicating report name, author, year of publication, and report is provided (Attachment A). Of file 1,978 database entries, there are 1, 144 unique projects or development sites. Multiple entries for a given project indicate multiple reports for the same site. When more than one site was investigated for a project, each site was given a unique database entry. The number of sites per statistical area are given below: Table 3.1 - Alaska rural hydroelectric projects by region. Statistical area* Total Database Total Unique Existing Proposed Entries Projects projects" Projects Southeast (SE) 719 342 35 309 Southcentral (SC) 489 327 14 313 Southwest (SW) 345 224 2 222 Northwest/Arctic (NW/A) 204 88 0 88 Yukon(Y) 221 163 1 161 Totals: 1978 1144 52 1093 * See explanation below. ** Includes projects that have been abandoned or which are no longer utilized to generate power. Following initial data compilation, certain sites were eliminated from further investigations based upon prescribed screening factors, such as excessive distance from intended load center, obvious land use or environmental restrictions, inappropriate project size, unavailable construction costs, and community participation in the Power Cost Equalization (PCE) program. The sub -set of viable projects passing the preliminary screening processes contains 131 projects determined to be appropriate for rural Alaskan communities, as determined from the information available in previous reports. These projects were copied to another database named working.mdb (295 kb). The i bete of pole I_+;_11" . .. L. L... ..i.. ;. - ..L. .. ♦..Lte.ii�...l ..L........ i.. 'r_L.I_ O 7 � �G 1-1 u1 � IUG1 VI f/vlcl orally V IQu1C PI VieI..LJ IVI call) JLa LIOW,01 1 egIUI I are DI IUYVI I III I aUIC J.L. Table 3.2 - Number of viable hydroelectric project sites by statistical area. StatisticalArea Number of Viable Projects Southeast (SE) 16 Southcentral (SC) 41 Southwest (SW) 22 Northwest/Arctic (NW/A) 35 Yukon (Y) 17 Totals: 131 Each database contains 53 fields of information for each project. Field names are attached in Microsoft AccessTM table format, with units and field descriptions. Blank fields in the database correspond with information not found in the reports. Most fields are self-explanatory, those fields that merit further definition are explained below. A complete listing of the fields and sample database report printouts on individual projects is provided as Attachment E. LOCHER INTERESTS LTD. Page 8 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT File Name: This alpha -numeric field corresponds with the paper file (hard copy) folder for each project site and represents the project statistical area and an entry. For example, SC 28 would correspond with the twenty-eighth folder within Southcentral statistical area files. When this field is blank in the database, the project report has been combined with another database report which better represents the site (see Project Count). ID: The ID numeric field is set up as a counter providing a unique identification number for each database entry. No two ID entries should be alike within the database, and all new entries should be assigned a new number. The highest ID number and the total number of records are not necessarily equal, since records may have been entered into the database (which increases the counter) and then later deleted. To add new records, this field should be sorted in ascending order first, with new records inserted at the end of the field to ensure a unique number. Project Name: The project name is a text field displaying the community name of the load center, plus the stream/lake name. Duplicate project names would indicate multiple studies or reports of the same site, or multiple sites along a single stream or river. Project Count: This numeric field provides a means to distinguish multiple studies for the same site. The field is "l" where the entry was judged to be the most complete and/or representative report for a project; the field is "0" if the entry is a duplicate entry for a project or a secondary reference to a site containing limited information. When the project count is "0," the File Name is also blank. Project Location: Latitude and longitude have been given to define a project location, when available. Locations may also be represented as township, range, and section or by river -mile. In some cases, location must be inferred by stream or lake name and other geographic information (i.e. community served). Statistical area: All entries have been organized by the five areas for which Alaska power statistics are maintained, defined by DOE to include: Southeast Alaska (SE) Southcentral Alaska (SC) Southwest Alaska (SW) Yukon (Y) Northwest and Arctic (NW/A). Information Source: This text field provides bibliographic information of the data source, organized in a standard format: Title; by Author; for Agency; Date; Library reference/call number; physical location of report. Level of Effort: The level of investigative effort of the information source is shown as either a letter report, a reconnaissance study, a preliminary investigation, a feasibility study, or a final report. Data Input By: Initials of person entering the record into the database @ organization, and date. Construction Cost: Shown as dollars in the study year, unless another year is indicated. Costs include direct costs, contingencies, engineering, and administration when provided in the report. Costs do not include interest accrued during construction. Non -viable: This text field provides information indicating a serious impediment to development identified during preliminary screening. A blank or null record for this field in a query indicates a potentially viable project. LOCHER INTERESTS LTD. Page 9 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT ................................................................ 4 0 .E* XISTI O PROJECTS There are 52 projects identified in the database as existing projects. These include 20 projects licensed by the Federal Energy Regulatory Commission (FERC) along with three FERC exempted projects. Additionally there are two projects (Eklutna and Snettisham) currently owned by the Federal Alaska Power Administration (APA). Eklutna is scheduled to be purchased by a group of railbelt utilities, and Snettisham is slated for transfer to the State of Alaska in the near future. Finally, there are approximately 27 non - regulated projects, many developed by individuals or private companies (mainly canneries), some of which have been abandoned or are not operating. Table 4.1, on page 11, lists the existing FERC licensed, FERC exempted, and federally owned projects identified in the database and provides information, as available, on their status. Table 4.2, on page 12, lists those projects identified as existing in the literature, but not currently regulated. Information on the non -regulated projects often is sparse and difficult to obtain, so these entries should be viewed with caution. As shown, of the approximately 357,202 kW of installed capacity (combined totals from Tables 4.1 and 4.2 on pages 11 and 12) represented by the existing projects identified in the database, approximately 66.7% (238,295 kW) is associated with the 20 FERC licensed and three FERC exempted projects. Twenty-five percent (90,000 kW) is associated with one project, Bradley Lake, currently the largest hydropower project in the State. Additionally, 30.3% (108,200 kW) of the total installed capacity is associated with the two federally owned projects, Snettisham and Eklutna. Projects associated exclusively with small rural Alaskan communities are listed in Table 4.3 on page 12. These projects represent only about 0.04% (14,380 kW) of the total installed capacity of the State's hydroelectric projects. In addition to the 52 existing projects discussed above, there are currently 17 sites with active preliminary permit or license applications on file with FERC. If these sites were to be developed, they would provide an additional 140 MW to the statewide hydroelectric project capacity. Table 4.4 on page 13 lists these sites, currently under investigation for development. Of the existing small projects developed for rural Alaskan communities, three are reported to have had serious problems associated with them. The first, the Chitina Project at Town Lake, has been abandoned as a result of problems. As reported, the project penstock includes a siphon to deliver water to the turbine. This siphon was constructed using high density PVC and was buried in or along a roadway, apparently without the use of sand or other material to properly bed the pipe. Shortly after the project went into operation, problems attributed to the entrainment of air into the siphon began, causing periodic shut down of the project. It is reported that the pipeline is thouaht to have deformed at the ioints_ nossihly where the road crosses over the buried line. allowina air to enter and destroy the siphon action. The frequency of these events gradually increased over time, and for the past two to three years, the project has been abandoned, as the effort involved in continually restarting the siphon became too great to justify continued operation. The second project with past problems, Larsen Bay, has been recently modified to address its major problems and is currently operating successfully. However, as in the case of the Chitina Project, Larsen Bay had problems with deformation of the penstock attributed to inadequate use of bedding material where it is buried. In this case, the deformation resulted in leakage. Additionally, the joint between the larger, low-pressure PVC section of the penstock and the smaller, high-pressure steel section failed and had to be repaired. This failure is thought to be due to poor installation. Additionally, there were substantial delays in the construction of the Larsen Bay •Project, related in part to the need to revise the original project design and to deal with associated increases in construction cost. During this period, the project mechanical equipment was stored on the dock at Larsen Bay. Some corrosion occurred during storage and the generator bearings failed within a very short period after the project went on line. Finally, the project has had continual problems with debris, causing frequent outages. Recently, however, the LOCHER INTERESTS LTD. Page 10 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT operators have initiated a program of periodic clearing of debris from the reservoir, and this problem has been resolved. A third existing project, a small facility constructed in Seward, has had problems severe enough to result in its abandonment. Reasons that this project is no longer utilized are not clear; however, difficulty of fitting generation into the city's diesel operation and lack of familiarity/interest in operation and maintenance of a hydro system appear to have played some role. TABLE 4.1 - Existing FERC licensed hydro projects, projects with Alaska issued FERC exemptions, and Federally owned projects. FERC Existing Project Name Location Owner License Generation Number (kW) -- Non -Federally Owned Armstrong Keta Port Armstrong na EXEMPT 80 Black Bear Lake Klawock Black Bear Lake Hydro, Inc. 10440 4500 Blind Slough Petersburg Petersburg Mun. Light and Power 201 2000 Blue Lake Sitka Sitka Electric Department 2230 9600 Bradley Lake Homer Alaska Energy Authority 8221 90000 Burnett River Project Burnett River Burnett River Hatchery 10773 80 Chignik Chignik Alaska Packers Assoc. 620 60 Cooper Lake Cooper Landing Chugach Electric Co. 2170 17200 Dry Spruce Bay Kodiak na 1432 75 Eklutna Recovery Eklutna Anchorage Water and Wastewater EXEMPT 750 Project Utility Green Lake Sitka Sitka Electric Department 2818 18500 Humpback Creek Cordova Cordova Electric Cooperative 8889 na Jetty Lake Port Alexander na 3017 2000 Ketchikan Lakes Ketchikan Ketchikan Public Utilities 420 4200 Pelican Pelican Pelican Utility Co. 10198 700 Salmon Creek Juneau Alaska Electric Light and Power 2307 7000 Silvis/Beaver Falls Ketchikan Ketchikan Public Utilities 1922 5400 Skagway Haines/Skagway Alaska Power and Telephone 1051 950 Solomon Gulch Valdez Alaska Energy Authority 2742 12000 Swan Lake Ketchikan Alaska Energy Authority 2911 22500 Tazimina Iliamna Iliamna Newhalen Nondalton Electric EXEMPT 700 Cooperative Terror Lake Kodiak Alaska Energy Authority 2743 20000 TN/pa r.raak \A/rnnnall/Patarchi irn Alacka Fnprnv Ai ithnrity ;n15 20000 Subtotal 238295 Federally; Owned Eklutna Project Eklutna Alaska Power Administration EXEMPT 30000 Snettisham Project Juneau Alaska Power Administration EXEMPT 78200 Subtotal 108200 TOTAL 346495 LOCHER INTERESTS LTD. Page 11 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Table 4.2 - Projects identified as existing, but not currently Federally owned or regulated by FERC Existing Project Name Location Owner Generation (kW) Akutan Akutan na na Annex Creek Juneau Alaska Electric Light and Power 3200 Bahovec Warm Springs Bay Mr. Fred Bahovec 3 Bear Cove Bear Cove na 15 Bear Creek Juneau na 10 Chester Lake Metlakatla Metlakatla Power and Light 1000 Chichagof-Superior Chichagof Island Superior Packing Co. 10 Chichagof-Swanson Chichagof Island Mr. Earnest Swanson 7 Chitina Chitina Chitina Electric na College Sitka Sheldon -Jackson Jr. College 50 Dayville Project Valdez -Allison Ck Mrs. O.B. Day 200 Gold Creek Juneau Alaska Electric Light and Power 1600 Keku Kupreanof Island Keku Canning Co. 30 Larsen Bay Larsen Bay Alaska Energy Authority 475 Linkum Creek Kasaan Pacific American Fisheries 17 Medvetcha River Medvetcha River Alaska Lumber Pulp Co. na Nugget Creek Juneau na na One Mile Creek Kodiak Island New England Fish Co. 8 Parks Canning Kodiak Island Parks Canning Co. 8 Pillars Baranof Island Stofold and Grondahl Packing Co. 15 Pitkas Point Pitkas Point na na Purple Lake Metlakatla Metlakatla Power and Light 3900 San Juan Lake San Juan Lake San Juan Fishing and Packing Co. 105 Sheep Creek Thane na na Short Project Baranof River Mr. Bill D. Short 3 Skeckley Creek Port Armstrong Buchan and Heinen Packing Co. 14 Uganik Kodiak Island Uganik Fisheries Inc. 30 Walsh Creek Revillagigedo Island Wards Cove Packing 7 TOTAL 10707 TABLE 4.3 - Hydro projects associated exclusively with small rural Alaskan communities. Project Name Community Owner Existing Generation (kW) Armstrong Keta Port Armstrong na 80 Black Bear Lake Klawock Black Bear Lake Hydro, Inc. 4500 Chester Lake Metlakatla Metlakatla Power and Light 1000 Chitina Chitina Chitina Electric na Dry Spruce Bay Kodiak na 75 Humpback Creek Cordova Cordova Electric Cooperative na Jetty Lake Port Alexander na 2000 Larsen Bay Larsen Bay Alaska Energy Authority 475 Pelican Pelican Pelican Utility Co. 700 Purple Lake Metlakatla Metlakatla Power and Light 3900 Skagway Haines/Skagway Alaska Power and Telephone 950 Tazimina Project Iliamna Iliamna Newhalen Nondalton Elect. Coop. 700 TOTAL 14380 LOCHER INTERESTS LTD. Page 12 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Table 4.4 - Active FERC Preliminary Permits and License Applications in Alaska as of 06/30/971. Project Name FERC Expiration Licensee/Permitee Capacity Number Date (MW) Upper Chilkoot 11319 3/31/99 Haines Light and Power Co., Inc. 6.2 Upper Reynolds Creek 11480 11/30/97 Haida 1.5 LeAnne Lake 11497 11/30/97 Kodiak Electric Association, Inc. 2.8 Wolf Lake 11508 3/31/98 Alaska Power and Telephone Co. na Allison Lake 11510 4/30/98 ABIDC 8 Grant Lake 11528 6/30/98 ABIDC 7 Silver Lake 11548 10/31/98 Silver Lake Hydro, Inc. 15 Lace River 11553 11/30/98 Lace River Hydro, Inc. 62 Lake Dorothy 11556 12/31/98 Lake Dorothy Hydro, Inc. 17 Old Harbor 11561 2/28/99 Alaska Village Electric Coop., Inc. 0.33 Icy Gulch 11562 2/28/99 Alaska Gastineau Dev. Corp. 0.26 Power Creek 11584 3/30/99 Whitewater Engr. 5 Otter Creek 11588 10/31/99 Alaska Power and Telephone 4.5 Sunrise Lake 11591 12/31/00 Wrangell 1.5 Whitman Lake 11597 12/23/97 Ketchikan Public Utilities 4.5 Carlanna Lake 11598 6/2/00 Ketchikan Public Utilities 0.8 Connell Lake 11599 6/2/00 Ketchikan Public Utilities 1.7 'Does not include projects with license applications which have been submitted (Goat Lake, Mahoney Lake). LOCHER INTERESTS LTD. Page 13 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT 5 POTENTIAL P.k 3 CTS Table 5.1 presents the total number of statewide potential hydro sites which have been investigated in the past, by statistical area and installed capacity. As shown, there are 1,144 potential sites identified in the database, of which 602 are estimated to be in the size range appropriate for smaller rural communities (< 5,000 kW). Table 5.1 - Potential Hvdroelectric Sites in Alaska, by Statistical Area. Statistical Area Installed Capacity < 5000 kW Installed Capacity > 5,000'kW Not Specified I Total Southeast 183 75 84 342 Southcentral 161 133 33 327 Southwest 120 31 73 224 Arctic/Northwest 52 26 10 88 Yukon 86 54 23 163 Totals 602 319 223 1144 It should be noted that a number of these sites are non -viable, either for technical reasons (i.e., lack of water, lack of head), or due to environmental or land use constraints. In other cases, multiple sites have been identified in an area and development of one would preclude (or in some cases has precluded) future development of the remaining sites. 5.1 First Screening Results Stage 1 screening of these potential sites, according to the criteria listed in Section 2 (page 4) of this report, reduced the number of potentially viable projects to a total of 131. As previously discussed, these potential sites are distributed throughout the State as shown in Table 5.2. Table 5.2. - Hydroelectric projects potentially suitable for serving rural communities in Alaska, by statistical area. Statistical' Area Number of Potential Projects Southeast 16 Southcentral 41 Southwest 22 Yukon 17 Arctic/Northwest 35 Totals 131 Table 5.3, on pages 15-17, presents a complete listing of these potential sites, including project name, project location, proposed installed capacity, and estimated construction cost (adjusted to 1996 dollars). The 131 potential projects listed in Table 5.3 were subjected to Stage 1 economic screening and ranking, utilizing the method presented in Attachment B. The intent of this first screening and ranking was to eliminate only those projects that are clearly uneconomical. Thus, screening was designed to be coarse, so as to not eliminate any potentially viable projects, even if their viability appeared marginal at this stage of the evaluation. The list of projects selected by first stage economic screening process is presented in Table 5.4 on page 18. As shown, this procedure produced a list of 31 potentially economically viable sites with BC ratios equal to 1.0 and above. LOCHER INTERESTS LTD. Page 14 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Table 5.3 - List of potential hydro sites passing preliminary screenings for project viability. Project Name Statistical Installed 1996 Cost Area Capacity ($1000) (kW) Ambler (East Fork Jade Creek) NW/A 106 5,976.88 Ambler (Jade Creek) NW/A 1,225 7,660.10 Bettles (Jane Creek) NW/A 276 8,532.79 Brevig Mission (Teller, Don River) NW/A 119 14,796.56 Brevig Mission (Teller, Main Stem Bluestone River) NW/A 276 9,077.31 Buckland (Hunter Creek) NW/A 238 19,614.40 Elim (Creek at Elim) NW/A 28 4,328.21 Golovin (Eagle Creek) NW/A 200 8,540.65 Golovin (East Tributary and Upper Cheenik Creek) NW/A 164 11,749.30 Golovin (East Tributary Cheenik Creek) NW/A 99 6,637.49 Golovin (Kwiniuk River) NW/A 204 8,572.11 Kiana (Canyon Creek) NW/A 460 8,977.37 Kobuk (Dahl Creek) NW/A 140 4,639.95 Koyukuk (East Tributary Nulato River) NW/A 157 12,252.61 Nome (Numerous Creeks) NW/A 724 19,613.62 Nome (Osborn Creek) NW/A 479 8,540.65 Nome (Penny River) NW/A 219 6,668.94 Point Hope (Akalolik Creek) NW/A 454 17,726.18 Shungnak (Cosmos Creek) NW/A 1,235 9,653.38 Teller (Brevig Mission, Right Fork Bluestone River) NW/A 240 7,439.65 Wales (Kanauguk River) NW/A 36 9,437.19 Barabara Creek SC 3,000 15,377.23 Cape Chiniak (Myrtle Creek) Sc 238 4,529.85 Cape Chiniak (West Fork Twin Creek) SC 84 2,563.77 Ceres Lake Sc 2,000 8,175.37 Chitina (Fivemile Creek) Sc 100 1,168.64 Chitina (Haley Creek) Sc 100 1,689.26 Chitina (Liberty Creek) SC 100 1,698.69 Chitina (O'Brien/Fox Creek) SC 100 1,189.09 Chitina (Town Lake Penstock Repair) Sc n/a 300.00 Copper Center (Klawasi River) Sc 2,782 37,647.11 Cordova (Crater Lake) Sc 1,200 16,162.70 Cordova (Hartney Creek, Lower) Sc 216 4,669.06 Cordova (Hartney Creek, Upper) SC 306 5,360.77 Corr Va (Hen-y Car -- eki nwoil SC Sc 130 260 2,766.85 3,458.56 Cordova (Heney Creek, Upper) Cordova (Lake 1488) SC 4,300 46,968.41 Cordova (Lake 1975 Elevation - Dead Creek tributary) SC 2,200 16,240.57 Cordova (No Name Lake Sc 5,000 8,435.46 Cordova (Sheep River Lake middle, Lake 1022) Sc 1,200 8,858.49 Cordova (Sheep River Lakes, Lake 649) SC 3,000 46,612.92 Cordova (Sheep River upper Lake, Lake 2026) SC 1,200 8,858.49 Cordova (Unnamed Falls) SC 190 4,841.99 Gakona, Gulkana (Copper River Tributary) SC 1,075 5,752.11 Halibut Cove (Halibut Creek) SC 4,117 9,264.51 Harrison Lagoon (Lagoon Creek) SC 120 n/a Hope (Bear Creek) SC 626 2,518.76 Kachemak (Swift Creek) Sc 674 3,398.71 Kodiak (Virginia Creek) SC 120 2,610.95 LOCHER INTERESTS LTD. Page 15 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Project Name Statistical Installed 1996 Cost Area Capacity (51000) (kW) Larsen Bay (Humpy Creek) Sc 300 11,055.40 Meakerville, Eyak (Robinson Falls Creek) Sc 905 8,421.47 New Chenega (Crab Bay, Chenega Bay) Sc 16 956.00 New Chenega (San Juan fish hatchery, Sawmill Bay) Intertie SC 105 432.80 Ouzinkie (unnamed stream, site #1) SC 990 4,761.06 Ouzinkie (unnamed stream, site #2) SC 220 2,123.37 Port Graham - English Bay (Dangerous Cape Creek) Sc 985 10,627.24 Port Lions (Crescent Lake, Port Lions River) Sc 180 3,534.27 Port Lions (Mennonite Creek, Port Lions River) Sc 200 1,611.76 Seldovia Lake SC 1,500 i4,200.39 Suntrana (Moody Creek) SC 4,843 11,690.26 Talkeetna (Middle Fork Montana Creek) Sc 1,009 3,705.80 Whittier (Placer River) SC 3,917 11,294.58 Anita Lake SE 4,000 13,032.79 Chatham (Chatham Creek; 57.31', 134.57') SE 175 2,766.85 City Creek (Petersburg) SE 700 1,769.47 Elfin Cove (Margaret Creek; 58.07', 136.20') SE 780 3,458.56 Excursion Inlet (N Excursion Inlet; 58.25', 135.24') SE 920 9,338.12 Excursion Inlet (S Excursion Inlet; 58.25', 135.24') SE 1,700 10,375.69 Gunnuk Creek SE 1,800 7,407.67 Haines (Dayebas Creek) SE 4,490 9,409.02 Haines (Lake Project; 59.25', 135.40') SE 5,180 15,736.46 Hassler Lake SE 4,000 19,878.83 Hoonah (Gartina Creek) SE 450 8,473.48 Lake Josephine (Portage Creek) SE 2,000 23,917.92 Reid Falls SE 3,040 9,653.38 Rowan Bay (6415 Road) SE 250 2,540.37 Rowan Bay (Big Lake) SE 700 5,505.03 Rowan Bay (Small Lake/ Erode Creek) SE 250 4,718.59 Rowan Bay (Stink Creek/ Erode Creek) SE 280 4,718.59, Rowan Bay (Unnamed Creeks) SE 200 2,507.15 Skagway Project (Dewey Lakes, Icy and Snyder Creeks) SE 520 6,413.91 Triangle Lake (Annette Island) SE 3,000 32,149.77 Whale Pass Work Center (Neck Creek) SE 125 565.01 Adak (unnamed stream, site #1) SW 200 2,359.30 Adak (unnamed stream, site #2) SW 303 3,098.54 Adak (unnamed stream, site #3) SW 192 2,783.97 Akutan (Loud Creek) SW 150 1,955.37 Akutan (North Creek) SW 126 1,817.04 Akutan (unnamed stream, site #1) SW 1,500 10,302.26 Akutan (unnamed stream, site #2) SW 69 1,108.87 Akutan (unnamed stream, site #3) SW 112 1,516.24 Akutan (unnamed stream, site #4) SW 117 1,667.24 Atka (Chuniisax Creek) SW 271 722.79 Attu (unnamed stream, site #1) SW 101 2,170.55 Chignik (Indian Creek) SW 1,100 11,909.30 Chignik Bay (Indian Creek) SW 550 4,035.97 Chignik Bay (Negro Creek) SW 360 3,899.13 Contact Creek SW 3,000 n/a LOCHER INTERESTS LTD. Page 16 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Project Name Statistical Installed 9996 Cost Area ` Capacity ($1000) (kW) Copper River, Meadow Lake SW 1,500 8,534.01 Creek (sic) SW 900 9,320.83 Dillingham (Grant Lake) SW 2,700 37,034.30 Goodnews Bay (stream S of Chawekat Mtn.) SW 85 2,864.71 Ivanoff Bay (unnamed stream) SW 650 5,964.30 King Cove (Delta Creek) SW 700 6,568.38 King Salmon River SW 800 8,698.29 Kokhanok River SW 1,500 9,251.66 Nikolski (Sheep Creek) SW 120 1,596.46 Nikolski (unnamed stream, site #2) SW 1,000 7,664.57 Nikolski (unnamed stream, site #3) SW 130 3,208.64, Nyac (Tuluksak River, Slate Creek) SW 1,800 20,036.33 Pilot Point (unnamed stream, site #1) SW 47 2,894.07 Reindeer Creek SW 400 8,853.92 Sand Point (unnamed stream, site #2) SW 39 1,240.99 Squaw Harbor (unnamed stream, site #1) SW 104 1,997.54 Togiak (Kartluk River) SW 30 2,273.07 Unalaska (Pyramid Creek) SW 260 1,091.49 Unalaska (Shaishnikof River) SW 700 8,063.09 Unalaska (unnamed stream, site #2) SW 399 5,064.62 Allakaket (unnamed stream NW) Yukon 105 5,981.60 Allakaket (unnamed stream South) Yukon 82 5,589.96 Cantwell -Broad Pass (Carlo Creek) Yukon 1,710 8,115.85 Cronin Lake Yukon 2,500 9,329.12 Galena (Kala Creek) Yukon 761 24,941.22 Grayling (N. Fork Grayling Creek) Yukon 230 6,422.23 Hughes Yukon 45 5,023.95 Hughes (Creek Northwest) Yukon 45 5,389.26 Hughes (Two Creeks West) Yukon 45 5,347.74 Kaltag (North Tributary Kaltag River) Yukon 127 7,561.07 Kaltag (South Tributary Kaltag River) Yukon 115 7,537.48 Kaltag (stream 4 mi W of) Yukon 155 3,736.92 Manley Hot Springs (McCloud Ranch Creek) Yukon 37 2,081.53 Nulato (East and West Tributaries Nulato River) Yukon 381 23,561.98 Nulato (West Tributary Nulato River) Yukon 166 10,349.13 Tanana (Bear Creek) Yukon 185 R O3167 Tanana (Jackson Creek) Yukon 174 6,390.55 LOCHER INTERESTS LTD. Page 17 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Table 5.3 - Top ranked projects from Stage 1 economic screening and ranking. Project Name Community Output (kWh/year) BC Ratio Port Lions (Mennonite Creek, Port Lions River) Port Lions 1,785,000 3.79 Meakerville, Eyak (Robinson Falls Creek) Meakerville, Eyak (Cordova) 5,074,000 3.70 Atka (Chuniisax Creek) Atka 520,000 3.47 Rowan Bay (6415 Road) Kake 1,095,750 3.22 Rowan Bay (Stink Creek/ Erode Creek) Kake 1,227,240 3.08 Haines (Dayebas Creek) Haines 18,190,000 3.06 Port Graham - English Bay (Dangerous Cape Creek) Port Graham - English Bay (Seldovia) 4,488,000 3.05 Hassler Lake Metlakatla 16,980,000 3.04 City Creek (Petersburg) Petersburg 2,830,000 2.89 Reid Falls Skagway 11,335,000 2.86 Rowan Bay (Small Lake/ Erode Creek) Kake 1,095,750 2.83 Rowan Bay (Unnamed Creeks) Kake 876,600 2.67 Nyac (Tuluksak River, Slate Creek) Nyac (Bethel) 6,700,000 2.61 Rowan Bay (Big Lake) Kake 3,068,100 2.22 Haines (Lake Project; 59.25', 135.40') Haines (possible Skagway intertie) 44,200,000 2.09 Triangle Lake (Annette Island) Metlakatla 11,000,000 1.88 Ivanoff Bay (unnamed stream) Sand Point 2,848,950 1.78 Chignik Bay (Indian Creek) Chignik Bay (Port Heiden) 2,410,650 1.73 Shungnak (Cosmos Creek) Shung nak-Kobuk-Ambler 3,245,580 1.70 Anita Lake Petersburg 18,395,000 1.66 Port Lions (Crescent Lake, Port Lions River) Port Lions 1,581,000 1.58 Chignik Bay (Negro Creek) Chignik Bay - Port Heiden 1,577,880 1.53 Unalaska (Pyramid Creek) Unalaska 2,174,000 1.50 Hoonah (Gartina Creek) Hoonah 2,170,000 1.36 Akutan (Loud Creek) Unalaska/Dutch Harbor 1.292,000 1.32 Cordova (Sheep River upper Lake, Lake 2026) Cordova 5,260,000 1.25 Cordova (Lake 1975 Elevation - Dead Creek tributary) Cordova 9,420,000 1.22 Cordova (Sheep River Lake middle, Lake 1022) Cordova 5,000,000 1.19 Akutan (North Creek) Unalaska/Dutch Harbor 1,088,000 1.11 Whale Pass Work Center (Neck Creek) 1Wrangell 547,875 1.09 Skagway River lKake 25,230,000 1.05 Key Assumptions: Real discount rate: 2.0% Real diesel price escalation: 1.0% Fraction of diesel O&M saved: 50.0% LOCHER INTERESTS LTD. Page 18 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Second Screening and Ranking As anticipated, the results of the first stage screening and ranking procedure, done in an essentially mechanical manner and utilizing the information in the database "as is," produced a list of potential projects with some problems, requiring review and revision from the project team. For example, the top ranked site listed in Table 5.4 on page 18 (Port Lyons, Mennonite Creek) is located near a community that receives power from the existing Terror Lake Hydroelectric Project, at extremely favorable rates. Thus, model assumptions concerning avoided costs do not apply to this project, and its actual economic viability is much different than that calculated by the model. Another common problem with the first screening results was the inclusion of multiple sites from the same study area. Five Rowan Bay, four Cordova, three Unalaska and two Port Lyons sites were included among the 31 sites having first stage BC ratios of 1.0 or above. -1 his grouping of sites can be an artifact of the accuracy of the cost assumptions used in a particular study, for example. Alternatively, costs for some projects may be incomplete as the original study may have looked at a cluster of developments, and certain costs (transmission line for example) may have been allocated among all projects. Consideration of only a single development would be based on an artificially low cost. Finally, in some cases, the projects identified proved to be alternative developments considered for an area where another project actually has been developed. The Akutan Bay site, for example, is an alternative to a project that has since been developed. Accordingly, second stage screening of the sites identified as potentially viable began with a detailed review by the project team (economist, cost engineer, environmental scientist, and project consultant/advisor). This review included consideration of the following critical parameters: • Project Cost Estimate (completeness, reasonableness), • Location of project in relation to nearby PCE communities, • Proposed installed capacity, projected output, • Recent development or plans for future development by others which might affect project viability/desirability. This Project Team review eliminated a number of the projects included in Table 5.4 on page 18. In addition, some projects which were not originally in the database and/or which had a BC ratio slightly below 1.0, but appeared to be promising based on other factors, were added back into the list. Corrected information was input into the database as appropriate. A final list of potentially viable projects was developed from this review. This final list includes 15 projects, potentially serving ten communities, as shown in Table 5.5 on page 20. This list of projects was provided to DOE for their review and final selection of sites to be carried forward to Stage 2 evaluation. LOCHER INTERESTS LTD. Page 19 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Table 5.5 - Projects determined to be potentially economically viable following project team review of the results of first stage economic screening. Community Project BC Ratio Cost ($1,000;1996) Ambler/Shungnak/Kobuk Jade Creek 0.91 7660.10 Cosmos Creek 1.71 9653.40 Atka Chuniisax Creek 3.47 722.80 Chitina Town Lake na' 300.00 Gustavus Falls 2 na* 1859.40 Haines/Skagway Reid Falls 2.86 6939.60 Dayebas Creek 3.06 9409.00 Lake Project 2.09 15736.5 Hoonah Gartina Creek 1.50 8473.50 Kake Rowan Bay (un-named) 2.67 2507.10 Rowan Bay (6415 Road) 3.22 2540.40 Rowan Bay (Big Lake) 2.22 5505.00 Kiana Canyon Creek 0.95 8977.40 Old Harbor Old Harbor na" 5278.50 Unalaska Pyramid Creek 1.50 1091.50 " Project added to list by review team, no preliminary economic evaluation available. In addition to this list, supplementary information on the projects listed above along with data on the 131 projects identified as potentially viable from Stage 1 screening and ranking was provided to DOE for review and selection of a final group of projects to be carried forward to the next stage of the study. Following completion of DOE's review of this information, the following four projects were selected for final evaluation: PCE Community Atka Hoonah Old Harbor Unalaska Project Chuniisax Creek Gartina Creek Unnamed Stream Pyramid Creek LOCHER INTERESTS LTD. Page 20 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT 50 PR�3JEGTS SELEC'i'7 F4R#IwTAkCpVALEAT101 <. . The four projects identified above were subjected to an engineering review (limited to review of the available reports concerning these projects), to confirm that the design concepts and project costs appear reasonable, and to identify possible design concept modifications which might improve operation of the projects as envisioned or, reduce project costs. Results of this review are presented in detail as Attachment C. Following this review, and based in part on the findings of the engineering review report, a set of final costs, including both high and low cost, were provided to the project economist for completion of the Stage 2 economic evaluation. Detailed results of this second economic evaluation are presented in Attachment D. The general findings of both the engineering and economic evaluations are summarized below by community. As discussed, all projects except the Gartina Creek (Hoonah) development appear to be potentially viable developments. The Chuniisax Creek development at Atka, however, is viable only when the most optimistic assumptions are utilized, and given the uncertainty associated with the proposed non- traditional approach to construction, should be viewed with caution. Atka: Atka is a community of approximately 100 people, located on Atka Island, in the Aleutians. Based on data from Fiscal Years 1992 through 1997, Atka generates an average of 281,170 kWh per year (23,341 kWh per month), as shown in Table 6.1, below. The system peaks slightly in summer, due to fish processing loads. The fish processors have begun to largely provide their own power, however, and as a result, the utility served load declined at an average rate of 4.4% per year over the period 1992 through 1996. Currently, Atka provides power with two diesel generators, rated at 125 kW and 75 kW. Table 6.1. Atka average monthiv qeneration, in kWh, from data for Fiscal Years 1992 -1997. Month "Average Generation; kWh' January 24133 February 23736 March 22385 April 22730 May 23854 June 26252 July 24722 August 25832 September 21417 October 22120 November 22601 December 21390 Average Annual 23431 As detailed in Attachment C, a timber flashboard type dam anchored to a concrete foundation on Chuniisax Creek has been proposed. Water from this diversion would be carried via one 1,160 foot (ft) long, 28-inch diameter HDPE pipe to a 271 kW unit, rated at a gross head of 116 ft and a flow of 36 cubic feet per second (cfs). It is estimated that this plant could produce 1,760,000 kWh per year, some six times the energy currently generated by the utility. Alternatively, an 80 kW unit, capable of providing some 520,000 kWh of energy annually has been proposed. Such a smaller single unit could be installed during initial development, leaving space for a second unit, to be installed in the future, as demand requires. LOCHER INTERESTS LTD. Page 21 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Engineering review has indicated that minimal cost savings might be realized by consideration of an overhead transmission line in place of a buried line, as proposed. However, such a choice could increase project Operation and Maintenance (O&M) costs, so that no real savings would be realized. Moreover, even though the most recent and detailed report on this project has a cost estimate of $766,000, this cost is based on a non-traditional approach to construction (use of local labor with turnkey or force account methods). Such methods should be viewed as a relatively high risk approach. Use of more traditional construction methods could escalate project costs to around $1,200,000. Thus, costs of $766,000 and $1,200,000 provide adequate bracketing for the purposes of Stage 2 economic evaluation. As presented in Attachment D, net present benefit for an 80 kW project producing 540,000 kWh of energy per year is a negative $5,914, under mid -range assumptions. Thus, the project essentially breaks even under the mid -range case. Under the most pessimistic and most optimistic cases, the net present benefits are negative (- $534,090) and positive ($1,856,740), respectively. Figure 6.1 below summarizes the results of the probability of net benefits analysis for the Atka project. Considering all possible combinations of critical assumptions for this case, with their assigned probabilities, a largely positive probability distribution of net benefits results. Only twenty-eight of the 108 possible combinations evaluated are negative. The cumulative probability of these negative combinations is just 25%, so that if the assumptions used are accurate, there is a 75% chance that the project, as analyzed, will produce positive benefits. However, given the uncertainty of the low -end cost estimate used and the fact that the project only provides positive net present benefits under the most optimistic assumptions, the economic viability of this project may be viewed as questionable. Figure 6.1 0.12 0.1 0.08 0.06 �- 0.04 0.02 0 Atka Probability Distribution of Net Benefits d N 7 M U� C9 O C7 L ti O O O O O O T_ �_ r- Net Benefits (million 1996$) ® prob Break-even analysis (see Attachment D) shows that the best ways to achieve a positive net benefit for this project would be to reduce capital costs to the low end of the range estimated and/or to secure financing in the 2% to 3% (real) range. That is, this development is most sensitive to these two critical parameters and is less readily affected by fuel costs, annual maintenance costs, or load growth. LOCHER INTERESTS LTD. Page 22 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Hoonah: Hoonah is a community of some 900 people, located on Chichagof Island in Southeast Alaska. Data from the past five years indicates that Hoonah has generated an average of 4,377,531 kWh of energy annually. Average monthly generation over this period is 364,794 kWh. As shown in Table 6.2 below, the system peaks slightly in winter but remains fairly constant throughout the year. Hoonah's current system consists of three diesel units rated at 1,000, 855, and 610 kWh. As reported in Attachment D, the system grew at a rate of 4.1 % between 1992 and 1996. Table 6.2. Hoonah average monthly generation, in kWh, from data for Fiscal Years 1992 -1997. Month Average;, Generation; kWh January 382082 February 1 399233 March 344961 April 373645 May 339549 June 366274 July 315670 August 345431 September 373759 October 363652 November 386859 December 386417 Average Annual 364794 The proposed project consists of a low concrete gravity dam located on Gartina Creek, immediately upstream of a set of waterfalls, which form a natural barrier to salmon. An above ground 57-inch diameter penstock 210 ft long, would provide water to two vertical shaft turbines, rated at 225 kW, at a flow of 50 cfs and a net head of 65 ft. The penstock is sized to accommodate an additional 450 kW of installed capacity, to be added at a later date. Based on the equipment and site hydrology, the average annual energy output from this project would be some 2,170,000 kWh, equivalent to about 50% of the current annual energy generated by the diesel units in Hoonah Engineering review of the proposed project has identified a number of features which might be altered to reduce costs and/or improve project operations. An inflatable rubber dam with a concrete slab foundation, instead of the concrete structure proposed, could result in cost reductions on the order of $300,000. In addition, a rubber dam might provide an environmental benefit as it could be operated to allow gravel to pass downstream, helping to maintain fish spawning habitat. Alternatively, a timber flashboard dam also might be utilized, with comparable cost reductions. Additional savings are possible by substituting use of a mobile crane, both during installation and for future maintenance, for the bridge crane as proposed in the original study. Penstock costs may be reduced by some $300,000 by reducing the size and omitting the continuous concrete support of the pipe originally envisioned. Additional savings might be possible by substituting HDPE pipe, with wooden supports, for the steel penstock as proposed. Finally however, the costs estimated for mechanical equipment may be low, and based on recent experience costs, could increase by some $175,000 to account for this discrepancy. LOCHER INTERESTS LTD. Page 23 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Based on the above, high and low costs of $8,470,000 and $6,740,000 have been used in the economic evaluation of this project. Economic evaluation of the Gartina Creek development as configured indicates that the project would have negative economic benefits under all sets of assumptions. Estimates of net benefits yield values of a negative $7.1 million for the most pessimistic case, a negative $6.6 million for the mid -case, and a negative $1.7 million for the most optimistic scenario. As shown in Figure 6.2 below, the probability distribution of benefits for this project fall entirely in the negative benefits region. Figure 6.2 Probability Distribution of Net Benefits: Hoonah 0.16 0.14 0.12 0.1 m 0.08 ° 0 0.06 a 0.04 0.02 �I 0 M 00 M r 17 ccM N N tD t0 � to d' d' ih Net Benefits (million 1996$) Break-even analysis of this project indicates that capital costs would have to be substantially reduced or that fuel prices would have to increase at a dramatic rate to achieve a break-even result. The assi,mntions required concerning these two parameters, necessary to produce positive net benefits, are not considered to be plausible. LOCHER INTERESTS LTD. Page 24 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Old harbor is a community with a population of approximately 310, located on Kodiak Island some 40 miles southwest of the City of Kodiak. Average annual generation in Old Harbor over the 1992 - 1997 period was about 727,904 kWh, with average monthly energy production of about 60,660 kWh. As shown in Table 6.3 below, the system peaks slightly in winter, but is fairly constant. Old Harbor's load grew at an average rate of 2.1 % per year between 1992 and 1996. Energy needs in Old Harbor are currently supplied by three diesel generators with a total capacity of 536 kW (two units rated at 197 kW and one at 142 kW). Table 6.3. Old Harbor average monthly generation, in kWh, from data for Fiscal Years 1992 -1997. Month 1 Average Generation; kWh January 70167 February 62875 March 66470 April 62156 May 58960 June 46858 July 48236 August 52196 September 60703 October 63828 November 65705 December 69751 Average Annual I 60659 Past reports have considered a range of potential hydro developments for Old Harbor. Projects varying in size from 2,280 kW to 330 kW have been evaluated. Given the size of the load, projects at the lower end of this range have been selected for evaluation for this study. A cast -in -place concrete diversion, with stoplogs, would provide water to a 16-inch diameter combination HDPE and steel penstock, supplying a 330 kW turbine, rated for 7.5 cfs at 747 ft of head. This installation would be capable of providing some 2,665,000 kWh of energy annually, a surplus of about 1,900,000 kWh over the current load. Engineering review of this project concept indicates that costs for excavation and backfill for the penstock could be some $270,000 low. Some cost savings might be possible by substituting an overhead transmission line for the buried line as proposed, but this could lead to increases in project O&M costs. The major cost issue for this development relates to the assumptions made concerning the construction method. The most recent cost estimate developed assumed use of local labor via turnkey or force account methods, as well as an approach which uses "loose" engineering design with modification of design in the field to suit field conditions. Should this high risk approach not be suitable, costs could increase by nearly 50%, from $1,369,000 to $2,000,000. These two values are used in this evaluation to bracket possible project construction costs. Economic evaluation of the Old Harbor project, as detailed in Attachment D, indicates that the project has positive net benefits under most combinations of assumptions used. Net benefits range from a negative $1,000,000 under the most pessimistic case to a positive $440,000 for the mid -range case, and as high as a positive $5,300,000 for the most optimistic case. LOCHER INTERESTS LTD. Page 25 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT As shown in Figure 6.3 below, the probability distribution of net benefits falls almost entirely in the positive region. Net benefits are negative in only about 20 out of 108 combinations of assumptions and the indication is that there is an 85% chance of net positive benefits for this project, assuming the probabilities assigned are accurate. Fiqure 6.3 Probability Distribution of Net Benefits: Old Harbor r) 1 d Break-even analysis of the Old Harbor project indicates that low capital costs and load growth are both important to its economic viability. Given the project's ability to produce substantial amounts of excess energy at zero marginal cost, an increase in load such as off-peak heating or fish processing would greatly improve the economics of this project. LOCHER INTERESTS LTD. Page 26 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Unalaska: Unalaska, located on Unalaska Island in the Aleutian Islands has a population of around 4,090. Average annual energy generated by Unalaska, over the FY 1992 - 1997 period, was 25,194,869 kWh. Average monthly generation over this period was 2,099,572 kWh. The system peaks slightly in winter but is relatively constant year round. Currently, Unalaska is served by three diesel units providing approximately 8.0 megawatts of installed capacity (two units rated at 2,000 kW and one at 4,000 kW). Table 6.4. Unalaska average monthly generation, in kWh, from data for Fiscal Years 1992 -1997. Month Average' Generation; kWh January 2118404 February 2583722 March 2556576 April 2088508 May 2044527 June 1897441 July 1831638 August 2080769 September 1940942 October 2046122 November 2025393 December 1980829 Average Annual 2099572 Past reports have identified a number of options for supplying hydropower to Unalaska. Developments ranging in size from 1,430 kW to 90 kW have been studied. The most economical options appear to be projects that would: 1) support an installation sized at about 100 kW, designed to tie into the City's existing water supply line and use only the City's water supply demand or, 2) a slightly larger development, of about 260 kW, also utilizing the City water supply with additional water diversions. Both of these options have been evaluated in this study. Various options are possible to provide water to this project, over and above simply tying in to the existing water supply line. Increasing the height of the existing water supply diversion dam, and the addition of a second diversion dam downstream are possible options. A small concrete dam, sheet piling in a concrete strip which is anchored to bedrock, a small rubber dam, or a timber dam bolted to bedrock are all possibilities which have been proposed. Further analysis will be required to identify the best solution. Similarly, use of the existing water supply pipeline and partial or complete replacement of the pipeline with steel or HDPE pipe are options. For the 260 kW installation, a horizontal Francis turbine, rated for 22 cfs and 170-ft of net head is assumed. For the option utilizing only the available City water supply, a 100 kW Francis turbine is assumed. Because the possible range of options for this development is so wide, two alternative have been evaluated. These are the small (100 kW) development and the 260 kW alternative. Given the range of options possible for a development at this site, it is not surprising that a wide range of costs also exist. For this analysis, costs are bracketed using a high estimate of $1,283,000 and a low estimate of $400,000. As in the case of previous costs, the low range estimate assumes use of local labor and turnkey methods which have a higher risk associated with them. Economic evaluation of a smaller (100 kW) project, using the low -end cost estimate, indicate that the project has net positive benefits under all combinations of assumptions used. These range from $329,376 for the most pessimistic case to $830,356 for the mid -case, and $1,693,529 for the most optimistic assumptions. LOCHER INTERESTS LTD. Page 27 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Figure 6.4 below presents the probability distribution of results for this development. As shown, all combinations of critical assumptions produce positive results for this case. Figure 6.4 Probability Distribution of Net Benefits: Unalaska 100 kW Power Recovery 0.25 0.2 - -- - --------------------------- 2' 0.15 ---- ------ --------------------------- :n R 0 0.1 ------------------------- a 0.05 - - ----- --- ----- --- ------------- 0 v In rn. Co rn 17 ry v �n cp O O O O O T"' Net Benefits (million 1996$) ® prob For the 260 kW development, economic evaluation indicates that the project produces positive net economic benefits of $3,900,000 for the most optimistic case, a negative $165,000 for the mid -case (essentially break-even), and a negative $707,000 under the most pessimistic case. Probability distribution of net benefits shows that in two-thirds of the combinations of assumptions the project produces net benefits in the positive range (Figure 6.5 on page 29). LOCHER INTERESTS LTD. Page 28 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT Fiqure 6.5 0.18 0.16 0.14 0.12 0.1 n 0.08 0.06 0.04 0.02 0 Probability Distribution of Net Benefits: Unalaska 260kW to O 114: C� V: 00 M oD N I� O O O O — — N N M M Net Benefits (million 1996$) prob Break-even analysis indicates that low discount rates and/or low hydro 0&M costs are critical to the economic viability of this project. LOCHER INTERESTS LTD. Page 29 of 30 August 18, 1997 RURAL HYDROELECTRIC ASSESSMENT AND DEVELOPMENT STUDY PHASE 1 REPORT 7Q REOMMENDAT[ONS i?OR PHASE Based on the results of Phase 1 analysis, it is recommended that the two potential projects found to have generally positive net benefits under the economic evaluation be investigated further to better define their economic and financial viability. Community Project Old Harbor Unnamed Creek Unalaska Pyramid Creek Further review should include a site visit by members of the project team to meet with local utility managers and community officials, verify existing conditions, more detailed review of the proposed plan vis a vis site conditions, existing and anticipated loads, development of updated costs, and a final economic evaluation utilizing the same methods as those employed herein. LOCHER INTERESTS LTD. Page 30 of 30 August 18, 1997 Bibliography Information Source @ Addendum to Recon of Alts. for Haines-Skagway Region; by R.W. 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Page 3 Bibliography Information Source @ Energy Alternatives for the Village of New Chenega; by James F. Renkert; for B.S. degree; February 1982; NEW 001; DOE Library. @ Energy Consultant's Report to the Bering Straits Regional Strategy; by J. Gurke & J. Zimicki; for BSRS-. December 1986; BER 006; DOE Library. @ Engineering Report on Proposed Crescent Lake Hydroelectric Project; by H.T.Harstad and Assoc.; for City of Seward; December 1954; SEW 001; DOE Library. @ Evans Island Hydroelectric Study A Proposal; by Mountain Energy; for APA; 1987; NEW 002; DOE Library. @ Feasibility Assessment Hydropower Development at Grant Lake; by CH2M Hill; for City of Seward; April 1980; SEW-G 002; DOE Library. @ Feasibility Report City Creek Run of River Hydropower Project Petersburg Alaska; by NORTEC; for APA; July 1979: PET 001; DOE Library. ,@ Feasibility Study Copper Valley Inertie Vol. 1; by R.W. Beck; for State of AK DCRA DOE; April 1994; not catalogued; DOE Library. @ Feasibility Study Data Collection Program for the Proposed Hydroelectric Project at Atka Alaska; by NORTEC; for APA; February 1984; ATK 002 vol. 1 c. 2; DOE Library. @ Feasibility Study for King Cove Hydro Project; by Dowl; for APA; August 1982; TK1424 A4 F43f v.2; BLM/AR Library. @ Feasibility Study for Old Harbor Hydroelectric Project; by Dowl Engineers; for APA; August 1982; KOD-0 001; DOE Library. @ Feasibility Study of Coal Fired etc. for Kotzebue Findings and Recommendations; by APA; for APA; (1981?); KTZ 007; DOE Library. @ Feasibilty Report Tazimina River Hvdroelectrc Proiect: by Stone And Webster fnr APA- Marrh 1 QA7- TAZI 003-2; DOE Library. @ FERC application for Green Lake Project; by Sitka Alaska; for FERC; September 1977; SIT-G 001; DOE Library. @ FERC draft Application Leanne Lake Hydro Project by KEA; for FERC; April 1993; TK 1424 A4 L432; BLM/AR Library. @ FERC Notice of Application Filed with the Commission; by FERC; for same; August 1996; JHT at LIL file. Page 4 Bibliography 7/28/9 Information Source �@ FERC Order of Ruling on DI and Finding License Not Required; by FERC; for same; August 1996; JHT at LIL file. @ Final Feasibility Study Alternatives for Rehabilitation of Salmon Creek Hydroelectric Project; by R.W.Retherford Assoc.; for AK ELPCo.; March 1978; JUN-S 001; DOE Library. @ Final Report City of Sitka Alternate Energy Study; by OTT Water Engineers and Black and Veatch; for PA; February 1982; SIT 010; DOE Library. @ Final Report reconnaissance study of energy requirements and alternatives; by International Engineerino Co.; for City of Cordova and APA; June 1981; COR 007; DOE Library. @ Financial Analysis for King Cove Hydroelectric Project; by Dowl Engineers; for APA; May 1984; KIC 003; DOE Library. @ Financial Analysis for Old Harbor Hydroelectric Project; by Dowl Engineers; for APA; September 1984; KOD-0 002; DOE Library. @ Financiai Analysis for Scammon Bay Hydroelectric Project; by Dowl et al; for APA; September 1984; SCA 004; DOE Library. 0Findings & Recommendations Bethel Area Power plan; by and for APA; December 1985; BETH 014; OE Library. @ Findings and Recommendations Angoon Hydropower; by APA; for APA; December 1984; ANG 005; DOE Library. @ Findings and Recommendations Bristol Bay Power Plan; by and for APA; February 1986; BR1 040; DOE Librari. @ Findings and Recommendations Elim Hydroelectric Project; by APA; for APA; 1983/1984; ELI 003; DOE Library. @ Findings and Recommendations Grant Lake Hydro Project and Dave's Creek Trans Line; by APA; for APA; Septe[11ber 1986; Stvv-G 0u"8; DOE Library. @ Findings and Recommendations Scammon Bay; by APA; for APA; December 1985; SCA 005; DOE Library and Small -Scale Hydropower Recon. Study SW AK, April 1981 @ Findings and Recommendations Togiak Hydropower Waste Heat Recovery System; by APA; for APA; November 1985; TOG 004; DOE Library. @ First Stace Consultation Leanne Lake Hydro Project; by Trihey and Assoc.; for KEA; April 1992; TK 1424 A4 1-43; ELM/AR Library. Page 5 Bibliography Information Source @ Gartina Creek Project Reconnaissance Report; by Harza; for APA; October 1979; TK 1424 A4 G37; BLM/ AR Library. @ Grace Lake Project Alaska; by APAdmin; for same; March 1968; TK 1424 A4 L355; BLM/AR Library. @ Grant Lake Hydroelectric Project Detailed Feasibility Analysis; by Ebasco; for APA; January 1984; SEW-G 007 vol. 1; DOE Library. @ Grant Lake Hydroelectric Project FERC application; by Kenai Hydro Inc.; for FERC; September 1987; SEW-G 012; DOE Library. @ Haines-Skagway Region Feasibility Report; by R. W.Beck; for APA; June 1982; HAS 014 vol. 1; DOE Library. @ Humpback Creek Final Feasibility Report; by Cordova Electric Coperative, Inc.; for same; January 1986; COR-H 002; DOE Library. @ Hurrnpback Creek Reconnaissance Report; by APA; for APA; August 1985; TK 1424 A4 H85; BLM/AR Library. @ Hydabura Hydro Investigation, by HDR Engineering; for APA; November 1991; SOE 052; DOE Library. @ Hydro Alternatives for Alaska Railbelt; by US DOE APA; for same; February 1980; RAI 008; DOE Lib. @ Hydroe!ectric Feasibility Study and Preliminary Design for the City of Atka by Polarconsult; 1996; JHT at LIL files @ Hydroelectric Power Proposed Plan for Power Development in the Railbelt Area AK; by USDOI; for USDOI; October 1959; RAI 048; DOE Library. @ Hydroelectric Power Resources of the US; by Fed Power Commission; for same; January 1976; TK 1423 U54 1976; BLM/AR library. @ Hydropower Development Potential of Kenney Lake; by ACOE; for APA; October 1983; KEN 001; DOE Library. @ Hydropower Potential of Windy River for Seldovia AK; by ACOE; for ACOE; August 1984; TK 1425 S45 H95 1984; BLM/AR Library. @ Icy Creek Power Recovery Study; by Polarconsult; for City of Unalaska; April 1994; not catalogued; JHT @ LIL. 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Findings and Recommendations; by APA; for APA: July 1988; HAS 022; DOE Library. @ Kodiak Island Borough Electrification Planning Assessment; by NORTEC; for APA; May 1983; KOD 001 vol. 1; DOE Library. @ Kotzebue Coal -Fired and Other Energy Alternatives Feasibility Assessment: by Arctic Slope Technical. et al; for APA; November 1982; KTZ 005; DOE Library. @ Kotzebue Coal -Fired and Other Energy Alternatives Feasibility Assessment; by Arctic Slope Technical, et al; for APA; November 1982; KTZ 005; DOE Library. @ Kurtluk Pre -Reconnaissance Study; by Tudor Engineering; for DOWL Engineers; August 1982; TOG 001; DOE Library. @ Lake Elva Detailed Feasibility Analysis: by R.W. Beck; for APA; April 1981; ELVA 005-1; DOE Library. @ Lake Elva Hydro Project Feasibility Findings and Rec; by APA; for APA; April 1980; ELVA 006; DOE Library. @ Lawing Project Alaska; by US DOI BR: for same: September 1955: TK 1424 A4 1385• RI WAR i ih @ Leanne Lake Hydroelectric Project; Before the Federal Energy Regulatory commission, draft application for license for a major water power project, 5mw or less; by Kodiak Electric Association @ Mennonite Creek Hydro Potential Port Lions Alaska; by Kodiak Electric Assoc.; for Kodiak Electric Assoc.; 1978: KOD-P 003; DOE Library. @ Metlakatla Power Alternatives Findings and Recommendations; by APA; for APA; May 1986; MET-C 004; DOE Library. Page 7 Bibliography Information Source @ Midway Creek Hydroelectric Project Findings and Recommendations; by APA; for APA; October 1986; KOD-0 005; DOE Library. @ Neck Lake Hydropower Feasibility Study for Whale Pass Work Center; by USFS; for USFS; September 1984; SOE 049; DOE Library. @ New Chenega Village Hydroelectric Retrofit Proposal; by Mountain Energy; for APA; October 1987; NEW 003; DOE Library. @ North Fork Pyramid Creels Hydropower Study; by Polarconsult; for City of Unalaska; January 1 cog; not catalogued; JHT at LIL files. @ Nyac Hydroelectric Project Conceptual Design and Cost Estimate; by HDR Engineering; for AEA; ugust 1993; NYAC 001; DOE Library. @ Old Harbor Hydroelectric Feasibility Study Final Report by Polarconsult for AVEC; June 1995; JHT at LIL file copy @ Overview Pyramid Creek Hydro Project; by Energy Stream. Inc.; for same; January 1985; not catalogued; JHT at LIL files. @ Pelican Power Alternatives Phase I Reconnaissance; by USKH and ES; for APA; April 1982; PEL 001; DOE Library. @ Pelican Power Alternatives Phase II Feasibility Study; by USKH and ES; for APA; January 1983; PEL 004; DOE Library. @ Pelican Utilities Study; by HDR Alaska; for DCRA DOE; August 1996; not catalogued; DOE Library. @ Potential Hydro Sites; by USER; for same; May 1965; TK 1424 A4 A26; BLM/AR library. `, �« a� i —4 V Sites; Uy USBR; rvr same; May 1965; 'I K 1424 A4 A26; BLM/AR library. Water Power spects of the NCSSA; July 1973; by USDOI APA; for same; TK 1424 A4 A36; BLMINR Library. @ Power Cost Study 1979-1993 CVEA; by R.W.Retherford Associates; for CVEA; March 1979; VAL 003; DOE Library. @ Power Supply Planning Study; by CH2M Hill; for Ketchikan Public Utilities; May 1986; KET 014; DOE Library. @ Power Supply Study; by Tippett and Gee; for Golden Valley Electric Assoc.; 1976; FAI 007; DOE Library. Page 8 Bibliography Information Source @ Pre -reconnaissance Report Elim Hydroelectric Project; by Dowl Engineers; for APA; December 1982; ELI 001; DOE Library. @ Preliminary Appraisal Report Hydroelectric potential for (10 SE villages); by R.W. Retherford Assoc.; for APA; September 1977; SOE 001; DOE Library. @ Preliminary Evaluation of Small Hydropower Development at Scammon Bay; by ACOE; for ACOE; December 1980; SCA 001; DOE Library. @ Preliminary evalution of hydropower alternatives for Chitina alaska; by and for USDOE APAdmin; CPT 001; DOE Library. @ Preliminary Feasibility Designs and Cost Estimates for a Hydroelectric Project on the Port Lions River; by R.W.Retherford Assoc.; for USDOE APAdmin.; January 1980; KOD-P 001; DOE Library. @ Preliminary Power Study Vol. 1; by R.W. Retherford; for US DOI APA; Jan 1966; TK 1424 A4 H66 V. 1; BLM/AR library. @ Proposed Grant Lake Hydropower Project; by R.W. Beck and Assoc.; for Grant Lake Electric Power Co. Inc.; July 1954; SEW-G 001; DOE Library. @ Ram Creek Hydro Potential at King Cove; by R.W. Retherford Assoc.; for APA; March 1980; KIC 001; DOE Library. @ Re -Evaluation of Alternatives for Electric Generation Program; by R.W.Beck and Assoc.; for Sitka Alaska; September 1976; SIT 002; DOE Library. @ Reconnaissance assessment of energy alternatives Chilkat river basin region; by CH2M Hill; for APA; February 1980; TK 1424 A4 C55; BLM/AR Library. @ Reconnaissance Level Feasibility Study Walker Lake Hydropower Project; by OTT Water Engineers; for APA; June 1988; within HAS 020; DOE Library. @ Reconnaissance of Micro -Hydroelectric Potential Akhiok Village Koriiak• by Anal- \A/ocf Acen,, and Fryer: Pressley; Elliot; for Kodiak Island Borough; September 1980; AKHI 001 c.1; DOE Library. @ Reconnaissance Study for Togiak Hydroelectric Project; by Dowl Engineers et al; for APA; August 1982; TOG 007; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives Appendix A Elfin Cove; by ACRES; for APA; February 1984; VIL-A 004 Appendix; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives Appendix A; by ACRES; for APA; May 1982: VIL-A 002 Alatna; DOE Library. Page 9 Bibliography Information Source @ Reconnaissance Study of Energy Requirements and Alternatives Appendix C; by ACRES; for APA; May 1982; VIL-C 002 Brevig; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives Appendix E; by ACRES; for APA; May 1982; VIL-E 002 Galena; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives Appendix Elfin Cove Main; by ACRES; for APA; July 1983; ELF 002; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives Appendix F; by ACRES; for APA; May 1982; VIL-F 002 Atgasuk; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives Appendix G; by ACRES; for APA; May 1982; VIL-G 002 Gustavus; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives Appendix H; by ACRES; for APA; May 1982; VIL-H 002 Karluk; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives Appendix I; by ACRES; for APA; May 1982; VIL-1 002K: Koyuk; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives Appendix I; by ACRES; for APA; May 1982; VIL -1 002N: New Chen; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives Appendix K; by ACRES; for APA; May 1982; VIL-K 002R: Ruby; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives Appendix L; by ACRES; for APA; ;May 1982; VIL-L 002 St. Mi; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives Appendix M; by ACRES; for APA; May 1982; VIL-M 002 Shageluk; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives Appendix N; by ACRES; for APA; May 1982; VIL-N 002 Shish; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives Appendix 0; by ACRES; for APA; IMay 1982: VIL-O 002 Stebbins; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives Appendix P; by ACRES; for APA; May 1982; VIL-P 002 Teller; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives Appendix Q; by ACRES; for APA; May 1982: VIL-Q 002 Unalakleet; DOE Library. Page 10 Bibliography Information Source @ Reconnaissance Study of Energy Requirements and Alternatives Findings and Recommendations; by PA; for APA; May 1981; VIL-C 003; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives Findings and Recommendations; by APA; for APA; May 1981; VIL-N 006; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives Findings and Recommendations; by PA; for APA; May 1981; VIL-R 005; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives for Kaltag et al; by Holden and 'r ssoc. et ai; for APA; June 1981; VIL-H 003; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives for Kodiak Sand Point and King Cove; by CH2M Hill; for APA; December 1980; VIL-C 001; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives for Kodiak Sand Point and King Cove: by CH2M Hill; for APA; June 1981; VIL-C 002; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives for Tanana Findings and Recommendations; by APA; for APA; May 1981; TAN 003; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives for Tanana Report Summary; by Marks Engineering et al; for APA; July 1981; TAN 002; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives; by NORTEC et al; for APA; February 1981; VIL-N 005; DOE Library. @ Reconnaissance Study of Energy Requirements and Alternatives; by NORTEC, et al; for APA; July 1982; VIL-N 002: DOE Library. @ Reconnaissance Study of Energy Requirements and Alts for A, KC, LB, OH, O,and SP; by CH2M Hill; for APA; VIL-D 003; DOE Library. (a. Reconnaissance Study_ of Energy_ Requirements and Alts. for Elim, et al; by APA; for APA; 1981; VIL- H 004; DOE Library. @ Reconnaissance Study of Hydropower Sites near Cordova Alaska; by CH2M Hill Inc.; for ACOE AK District; October 1979; COR 003; DOE Library. @ Reconnaissance Study of Kisaraluk River Hydroelectric Power Potential & Alternate Electric E Resources in Bethel Area; by R.W.R.; for APAuth.; March 1980; BET 009 c.2; DOE Library. @ Reconnaissance study of Lake Elva and Alternate Hydroelectric Power Potentials in Dillingham Area; by R.W.Retherford Asso.; for APA; January 1980; ELVA 003-1; DOE Library. Page 11 Bibliography Information Source @ Reconnaissance Study of Lake Elva and Other Supplemental Report; by R.W. Retherford; for APA; June 1980; ELVA 003-2; DOE Library. @ Regional Electric Power System for the Lower Kuskokwim Vicinity; by R.W.Retherford Assoc.; for USDOI AK Power Admin.; July 1975; BETH 001; DOE Library. @ Regional Inventory & Recon. Study for Small Hydro Projects Aleutian Islands, Alaska Penninsula, Kodiak Island Alaska; by Ebasco Services Inc.; for Alaska District Corps of Engineers; October 1980; VIL U 002 v.1 & v.2 c.2: DOE Library. @ Regional Inventory & Recon. Study for Small Hydropower Sites Southcentral Alaska; by Ebasco Services Inc.; for Army Alaska Dist. Corps of Engineers; June 1982; VIL-U 005; DOE Library. @ Regional Inventory & Reconnaissance Study for Small Hydro Projects Northwest AK; by OTT Water Engineers; for ACOE; May 1981; not catalogued; LIL copy. @ Regional Inventory and Reconnaissance Study for Small Hydropower Projects Northeast Alaska; by Ebasco Services Inc.: for Department of Army Alaska District Corps of Engineers; June 1982; VIL-U 003 C.2; DOE Library. @ Regional Inventory and Reconnaissance Study for Small Hydropower Sites in Southeast Alaska; by CH2M Hill; for ACOE Alaska District; October 1979; TK 1424 A4 A24; BLM/AR Library. @ Relocation of Hydroelectric Project at Atka Alaska; by Northern Technical Services; for APA; August 1983; A T K 003 c. 2; DOE Library. @ Revisions to Review of SC AK hydropower potential; by CH2M Hill; for ACOE; January 1979; RAI 023: DOE Library. @ Rivers and Harbors in AK Hydropower for Sitka Petersburg/ Wrangell and Ketchikan; by ACOE; for ACOE: July 1983; TK 1424 A4 A47d; BLM/AR Lib. @ Rivers and Harbors in AK Interim Feasibility on Hydro Power for Ketchikan Area; by ACOE; for ACOE; 1979; KET 001; DOE Library. n SC Railbelt area Staae II Checkpoint reocrt hydro power & related purposes for Valdez AK; by ACOE; for ACOE; April 1978; VAL 005; DOE Library. @ SC Railbelt Area, AK Upper Susitna River Basin Supplemental Feasibilty Report; by ACOE; for ACOE-1 February 1979; RAI 006; DOE Library. @ SE Power Needs, Alaska: Why Hydro Power?; by R.W. Beck and Assoc.; for not specified; uctooe� 1974; SOE 006; DOE Library. Selection of Electric Generation Alternatives for Consideration in Railbelt Vol. II; by Battelle; for office AK governor; December 1982; RAI 018 Vol. 2; DOE Library. Page 12 Bibliography Information Source @ Small Hydroelectric Inventory of Villages Served by Alaska Village Electric Cooperative(AVEC); by USDOE Alaska Power Administration; for same; December 1979; TK 1424 A4 A362; BLM/AR Library. @ Small Hydropower Interim Feasibility Study and Environmental Assessment; by ACOE; for ACOE; March 1982; SCA 002; DOE Library. @ Small Hydropower Study and Environmental Assessment; by ACOE; for ACOE; November 1981; SCA 003; DOE Library. @ Small Scale Hydropower Reconnaissance Study Southwest Alaska; by R.W. Beck and Associates OIL-U ngineers and Consultants; for Department of the Army Alaska District Corps of Engineers; April 1981; 007 C.2; DOE Library. @ Small Scale Hydropower Report for Gustavus AK Letter Report; by ACOE; for same; June 1984; HYD 051; DOE Library. @ Small -Scale Hydropower for Anaktuvuk Pass, Alaska Letter Report; by Dept of Army AK Dist COE; for same; September 1984; ANAK 002; DOE Library. @ Snettisham Hydroelectric Project 1st Stage Development Design Memo. #26; by USACOE; for USACOE; October 1984; JUNE-T 006; DOE Library. @ Snettisham Project Alaska First Stage Development; by ACOE; for ACOE; December 1973; JUN-T 004; DOE Library. @ Snettisham Project Crater Lake Phase Rev. Mem. No. 26; by ACOE; for ACOE; October 1984; JUN-T 006; DOE Library. @ Suoplement to the Elfin Cove Reconnaissance Study; by APA; for APA; April 1984; ELF 003 supp; DOE Library. @ Surface Water Resources and Development Inventory Yukon Region Preliminary Draft; by Joint Federal State Land Use Planning Commission; for same; September 1973; HC 107 A48 A513; USFWS Library. AMA_-:-. tom.......,... I........ •Inr_a• TV 4A')A AA T9G• CI NA/OD I U—nni @ IaKaLz l IteteK rlufCGl, Dy ^rPlumm, wl aaIIIC, Jalluaiy IONN, 11\ i����� 1.� vuvurvi �iv,o.y. @ Takotna Micro -Hydro Investigation; by Eagle River Engineering Services; for APA; November 1991; TAKO 001; DOE Library. @ Tazimina River Hydroelectric Project Feasibility Study; by HDR Engineering; for INNEC; May 1991; TAZI 005; DOE Library. @ Tenakee Springs Small Hydro and Related Purposes Letter Report; by ACOE; for ACOE; April 1984; SOE 010; DOE Library. Page 13 Bibliography Information Source @ Thayer Creek Project A Reconnaissance Report; by HARZA Engineering Co.; for AK Alaska Power Authority; October 1979; ANGOO 010; DOE Library. @ Thomas Bay Project AK; by US D01 BR; for same; February 1966; TK 1424 A4 T56; BLM/AR Lib. @ Thomas Bay Project Appraisal Report; by R.W.Beck Assoc.; for Thomas Bay Power Commission; November 1975; PET 006; DOE Library. @ Tyee-Kake Intertie Project Detailed Feasibility Analysis; by Ebasco; for APA; March 1984; KAK 007; DOE Library. @ Unalaska Alaska Final Small Hydropower Interim Feasibility Study and Environmental Impact Statement; by ACOE; for ACOE; July 1984; not catalogued; DOE Library. @ Virginia Lake Project Appraisal Report; by R.W.Beck Assoc.; for Thomas Bay Power Commission; August 1977; PET 009; DOE Library. @ Water Power Aspects of the National Conservation Study System Areas; by US DOI APA; for same; July 1973; TK 1424 A4 A26; BLM/NR Library. @ Water Powers Southeast Alaska; by Federal Power Commission and Forest Service - USDA; for same; 1947; AiDEA Stan. @ West Creek Draft FERC License Appl.; by R.W. Beck and Assoc.; for APA; HAS 010 vol. 1; DOE Library. Page 14 Rural Alaska Hydroelectric Assessment: Stage I Economic Screening Results prepared by: Steve Colt Institute of Social and Economic Research (sacolt@aol.com) prepared for: Locher Interests and State of Alaska Department of Community and Regional Affairs Division of Energy January 25, 1997 1. General This memorandum reports the results of the Stage 1 economic screening and ranking process that was previously proposed as part of the "Phase 1 Evaluation Criteria". The Stage 1 economic screening process takes a pool of approximately 130 candidate projects and ranks them according to their benefit to cost ratio. 2. The Pool of Candidates The pool of 130 projects was developed from the universe of all known projects by eliminating projects which failed any of the following tests: • Projects with obvious geotechnical or hydrological problems were eliminated • Projects with obvious environmental problems were eliminated • Projects with no construction cost data available to allow economic analysis were eliminated • Projects with rated capacity of 5 N1W o'r larger and projects with capacity of 25k`N or smaller were eliminated. Rural Hydro Economic Screening Results 1/27/97 pace 1 Note that none of these tests involve economic analysis. 3. Procedures used to Fill Data Gaps tilany projects lacked complete data on the following key items: • Annual energy output (kWh/year) • Annual O&M cost • Load center data Annual Energy Output. For projects lacking a stated annual energy output, this quantity was calculated for using an assumed plant factor of 50%. The value of 50% was determined by the project team after inspecting the values for projects that do include an estimated plant factor. The calculation of energy output is simply: kWh/year = Capacity (kW) * 8766 (hrs/year)' .5 Annual O&M Cost. For projects lacking an annual 0&M cost, an estimate was calculated as 3% of construction cost. The value of 3% was chosen after analyzing the values which were given for 53 projects. For these projects, the average is 3.5%, and the range runs from 0.2% to 26%. There is no statistically discernible relationship between size of the projects and the 0&M percentage, or between construction cost and the percentage. I demonstrated this with a scatterplot and two regressions. Composite Load Centers and Avoided Cost. For several projects I computed a weighted average of load, fuel cost per kWh, and other 0&M cost per kWh. The weights are the amount of diesel generated kWh. The following composite load centers were used: Brevig Mission / Teller Chignik City / Port Heiden Elfin Cove / Pelican / Hoonah Shungnak / Kobuk / Ambler For projects not close to PCE communities, I assumed an appropriate connection to the Railbelt grid, to Copper Valley Electric, or to Kodiak Electric. I assumed the following avoided costs for these utilities: Rural Hydro Economic Screening Results 1/27/97 page 2 Assumed Avoided Costs of Non-PCE Utilities Avoidable fuel S/kWh Avoidable 0&M 5/kWh CEA/avoided 0.02 0.00 GVEA/avoided 0.03 0.00 MEA/avoided 0.03 0.00 HEA/avoided 0.03 0.00 CVEA/avoided 0.07 0.00 Kodiak/proxied by Cordova 0.07 0.13 4. Computations The computation of costs and benefits was simplified because no hydro project has a firm capacity associated with it in the database. Thus the benefits of the hydro project are the sum of avoided diesel fuel (or natural gas) costs and avoided nonfuel 0&,Ivl. Hydro Cost. I inflated the stated construction cost, transmission cost (if given), and the annual O&M cost to 1996 dollars using the Handy -Whitman hydraulic plant index, as proposed in the workplan. The present value of hydro O&M is computed assuming ping that the project is built in "year zero," which 1 take to be 1996, and then operates during years 1 through 35, with year 1 being 1997. (Of course, any actual projects will not be built until 1998 at the earliest, but there is nothing to be gained analytically by assuming a 1998 start date and it seems simpler to stick with 1996 as the "base year" for both the inflation adjustments and the discounting process.) Avoided Diesel Cost The number of diesel kWh displaced by hydro is the minimum of (1) estimated hydro output; OR (2) 150 percent of diesel -generated kWh sold. The cost of diesel fuel per kWh sold is taken from the 1995 PCE filings, or, for non-PCE communities, estimated as shown above. The cost of diesel per kWh said escalates at 1 percent per year. Avoided nonfuel O&M. The base case assumption is that 50 percent of average non - fuel O&M cost per kWh can be avoided by hydro. This is obviously a critical assumption and it is clearly not true for larger systems. For the non-PCE communities, I have generally assumed zero avoidable nonfuel O&M (see table above). For PCE communities, I also run sensitivity cases on this parameter, below. Discount Rate. The base case real discount rate is 2 percent. Rural Hydro Economic Screening Results 1/27/97 page 3 Benefit/Cost Ratio. The B/C ratio is computed as: PV(avoided diesel costs) / PV(hydro costs) 5. Base Case Results Under base case assumptions there are 31 projects with B/C ratios greater than 1. These are shown in Table 1. The ranking of each project under the aiternative scenarios is shown to the right of the base case ranking. Rural Hydro Economic Screening Results 1/27/97 page 4 Table 1: Base Case Rankings for BIC greater than 1.0 yaro screening Anatysis: QUICK summary I I I I I I I I I I cenarioName: 1 cenano ase Case ; 1 IKey Assumpticns:I I I I I I eai oiscount rate:; reai aiesei price escatation:l 1. 0% I I 1 traction or these: ZTEW saved: 1 I j ranKma I ranKir,c iranKing I I nyoro I I uncer 1 uncer i uncer I output ; oenent to j, a j a 125zX. O&M j 1 1 Kv nryr j cost ratio 1 avcieed j avo:cec I avetoea I I I I I I I sole _ netw Z Berg _rauor_,� rae rae - raer 11 r 71 Fort Lions ( ennonire Cre 1 Port Lions I 1,id::,U00 1 3.191 1 1 41 9I eaKervu e, Eyak ( ooins 1 eaKervile, I c, 0 r 4, 0 0 0 I 3.101 I 01 4 4001 t a (chunnsax reeK) I t a I -zu,uuu I 3.4i 1 31 1 1 19741 41 Rowan bay (4 0 cad) I aKe 1 1, ..c, r c 0 1 3.221 4I 91 C-73 1 Rowan bay unK reeK/ I aKe I 1,221,24U I3.081 51 141 64I wines ( ayeoaS reeK) I Haines 1 18,11 I3.061 d 1 61 Z 9 cr, Granam - Engnsin t3a j ortranam I e-,468,000 1 r 1 ; G! 101 iar., 1—assier L2Ke I etaKatia ! 1c.� .000 3.u4j 1� 111 iGJ� ,i/ CreeK ( etersourc) IF'eterscurd I G,a U,U 'U G.091 eco,i-,e:a rails I Kagway j 11,3 ,0 0 01 2.861 i t r I r l 19 r o Rowan Bay (3mail LaKei 1 aKe 1 1,095, 150 1 2.831 7 11 1:: 1 141 1., r o i ncwan 8ay (Unnamed Cr 1 aKe I a r 0'duu 1 i.d r 1 1! 191 yac ( uiuKsaK River, Sla! yac et ei I 6,tao,000 I in 1 _11 31 31 C r ; t•ccwan bay ig aKe) ( aKe 1 1 2.22 141 Gc 1 1 I 5 r j ,aines aKe rojec;; c i aines (poss 1 44,200,000 1 2.091 ibi -' I 14 11911 i nangie LaKe (Annette is I et aKat a 1 1 1,UUU,000 I 1.881 161 G 3E56iivanoTT 6ay (unnamed strel and Point j Zd4d,.zQj I 1.161 r 1 2-31 1 o igniK bay notan reeK 1 igniK Eay (1 2.410,oc 0 1 r 1 i i 1 r l nungnai( (COSMOS CreeKl6nungnaK- I 3,24,),=0 I I.Iul 1 ! 1 1 1 _z! vita LaKe I etersourg 1 1 1.cvj 1c! 1119 1Fort Lions rescenc aKe,1 ort Lions 1 1.5tal'uUU 1.561 211 G i 22' 223 1 Chignik bay(Negro CreeKI igniK 8ay1 1,ot 7,88U I 1.531 1 161 r j naiasKa ( yramia reeK)I naiasxa 1 4114,I .c 1 31 241 5�-j Conan artinaCreek) I Conan I 2,110, U()Q I 1.361 241 361 19 I Akutan oua U reeK lUnaiaSKalUutl 1,292,UQ0 1 1.321 251 2/1--­251 51 Corcova _ eep River up I oraova I I 1.2bi 1119 1 Ccroova (Lake 1975 Eieva Coroova I 9,42U,000 I 1.221 271 3ul 11 oraova (6heep River LaKlCorocva i 6,U00,000 I 1.191 281 311 11 18 j AKutan(North reeK) I naESM un 1,088,000 1 1.111 291 1 'Whate Pass Work Center IVVrangeil 1 4 r, 8 15 1.U91 3ul i r! 1..46,Skagway River I aKe I I 1.ubl �"i 451 a Scenario 2: Only Fuel is Avoided. Under this scenario the fraction of nonfuel diesel system C&M costs avoided by hydro is zero. Only fuel costs are avoided. Now, only 19 projects look cost-effective. Table two shows the top -ranked 31 projects: Table 2: Top 31 Projects Assuming only Fuel is Avoided Rural Hydro Economic Screening Results 1/27/97 page Table 2: Top 31 Projects Assuming only Fuel is Avoided Hydro Screening naiysis: QUICK Summary I I I I I I I I I cenano 1 ame:l cenano my Fuet is Avoided I 1 1 Key Assumptions:l I I I I 1 neat discount rate:l 2.0%1 1 1 real otese! price escalation:) 1. ,a I I traction or otesei U &Msaved:, ,a I ! I 1 ranKtna rarKlrC ;r2nKlrC 1 I I I nycro I 1 under 1 under under I I I output I benent to 15 ro 1 0 U&NI 1 G-_ ;c C&"'i I i I ryr I cost ratio I avoteec I avetcec aveicec I I I I I I t I �o�ecz am�mm�cti_ ., __, ergy _ rants a a rde = _ _ -' rcer ,� 1205 I City UreeK ( etersourg) IFetersourg I 1 •S 1 �I ' s 51 t o unnsax reeK) I txa I 5n,000 I 2.791 31 G! 1 I yac utuKsaK River, S a j Nyac ( etnei I 6, r 00,000 1 2.121 131 J 1 0 11 r 71Fort Lions (Mennonite Ure I Fort Lions I 1,i85,000 I 2.121 11 4 3991fvleaKervule, EyaK ( ootns i eaKervi e, I 5,U 14, MO I 2.061 21 5 654 f Haines ( ayeoas reeK) I Haines 1 18,190,000 1 1.831 01 0 1 001 eid ails 1 Ragway I 11,335,000 1 1.101 1 1 r. r vita aKe ;retersourg 1 18, 3, 0 0 0i co. a. cl 1 �i r 4 Rowan tray (04 1 c moac) 1 aKe 4! 5 r IHaines ( aKe ro)ect: :-. ! aines (pcss 1 44,200,00 1 1 .c ; 151 1 u; 648IChidnIK 6ay (Indian CreeKlChignm Bay (1 2,410,ac 11.231 181 1FIcrE Uranam - tngusn da l Hort Uranam I 4,488,000 1.231 r l 1 L 1 u 1 assier Lake I euaKaua 1 16,980,000 1 1. 2! 81 -- 31 ii 13 1Rowan Bay (StinK ureeki 1 aKe 1 1,22i,240 1 1.211 51 i 4 19751 Rowan Bay (mat(bmail LaKel I aKe I 1,095, r COI 1.111 ill 16 : i 223 1 Chignik day (N egro UreeK I ChignlK Bay 7 1,5 t 7,880 1.091 221 161 21 5 1 ate Flass Wom Uenter 1 range!i 1 541,810 1 1.091 . 1 11 1 24 1 undnaK (Cosmos UreeKIbhungnaK-K 1 3,245,560 1 I 191 1 1 is 1976 I Rowan Bay (Unnamed U, 1 KaKe I 816,600 I 1.051 121 1..1 i Z r I opper Center (Kiawasi rul doper Cant I 1 1,6_8,000 U. 1 31 w- 1 anout ove auout Cre I auout Uovel 1 d,r54, 0.ti31 r 9 1 Part Lions (Crescent LaKe,IPorT Lions I 1,581,000 I 0.881 11 22, i cc o f vanorr Bay unnamea stre! and Point I 2,848,950I 0.881 171 231 1 natas a yramid UreeK)ILInaiaSKa I 2,174,000 I 0.811 1 241 23 r l owan Bay(Big aKe) 1 aKe 1 3,U53,100 I 0.811 141 251 1 a aKona, tit ana kuopperlUaKona, Gul I 4,420,000 I 0. r l 411 1 31 titan oudCreek) lUnalaskajuun 1,292,000 I U.111 251 Gr 1 Z� 1191 nangte LaKe(Annette Isi I et aKat a 1 11,000,000 1 . r o t 161 cb 1 c 51 Corcova eep River up 1 oreova I 5,260,000 I • r I 251 291 "' 11 1 oreova(Lake 1975 C;evd croova 1 9,420,0001 . 58 i 211 Zu! 1116 i Corcova (S eep iver LaKI Corcova 15,000,OQU U,001 251 a". Scenario 3: 25% of nonfuel O&M is Avoided. Under this scenario the fraction of nonfuel diesel system 0&M costs avoided by hydro is25 percent. Table 3 shows the top -ranked 31 projects: Rural Hydro Economic Screening Results 1/27/97 page e Table 3: Top 31 Projects Assuming 25% of ncnfuel O&M Avoided yoro ScreeningAnalysis: Quick Surnmary j j I I I I I I I I 5cenano ame:; cenano C of nontuei U&M Avoicea j ey ' ssumptlons:i I eal clscount rate:I real alesel price escalation:1 1. o I ! rracnon or alesel 0&,'Vl savea:! 4 o I I ranKrne ranK1nc rar inc ! nycro I j uncer j uncer I uncer output I cenentto j�O% U&M I Uo G�o I I yr I cost ratio I avoicea I avcicea i avolcec I 1 I 1 I I I 4bo l mmunttyr; ne tKa (Chuniisax reeK) ! tKa I :LU'uuuI Ort Lions (M ennOnite re I ort ions I 1 rattn_rae I 1 ! 31 i I - _ rae_._ raer_ 4; I Iry Creek etersourg) I etersourg I830,000I eaKervi e, cyaK kKooins; Meakervide, 1 07, l 81 91 ! 11 ci 4 004 alnes ( ayeoas reeK) 1 halves I 1 j I o f c i c 1 1 yac I UIUKSaK River, Ia ; yac ( emel I e, r ! 71 , 1 : i o boo j ela ails j Kacway 1. 141 OWan Cay (C41 t 1 C0a0 i aKe i . / J I Rowan bay (z InK reeK/ ! aKe 91 Pori ranam - ngusn ba or -ranam! 4 4 I i4 1 1 1 assler LaKe ! etlaKat a !16,980,000I 1 11 / I Rowan ay ( rna aKe1 j I I 1I �! r I OWan Bay ,Unnamea ur 616,500 1 1.2i 1 01 ! Haines ( aKe Project; ca.L; alnes (pass j nita aKe I etersourg I 44, I 1.0 / I I oo! O I I I ! 14 1' 19 r 21 Rowan B ay ( E3 IgLake) I KaKe ! I c4I 141 0I 1 64 ( IgnIK ay (nalan reeK! IgnIK bay (I 4 o I 1.4 j 1 I 1 1 r ungnaK osmos reeK) nung GK 1 b,� ! I I ! 1 01 vanorr bay (unnamea stre; ana Dint ! -, 91 I nangle LaKe t nneae Isl I etlaKaua I 2,848,950 1 3 Q 22-3 I IgnIK bay (Negro CreeK! ChignIK 6ay7 ,c/1, 68UI I I LGI 1cI 1 ( ort Ions rescent aKe,j Part Ions 1 ,c I 1 • 1 I a nalas a yramlo reeK)I nalas7a 1 2,174,000 1 5I 231 I 1511 1VVhaie Pass VVorK Center IVVrangell 1 -47,815 I 1.091 301 11I r ( utan (Louc reek) ! nalasxar uU 1,292,UOO I 1.041 I r I 571 ICC-pper enter Nawas; il_onnar oraova eep Iver up I ...�.�.n.t. I oraovaI .. ---•- -- 5, 1 I I ! I . ...... .. . .. . .. . .. . .. .. r 11 I oraova aKe 1915 tleval oraova I c� I oonan artlna reeK) I ocnan I 1 I �41 I ! 1 jHalibut Cove (Hal IA' re j ,aucut ove; oraova veep F Iver L2K; Ccrcova j O'uuU'UUU I 1 v 6. Discussion The rankings seem rather stable across all three scenarios. For example, if we look at the base case, we can see that the top 12 projects would have a B/C ratio of greater than 1 (as indicated by a ranking of 19 or higher in the "Order2" column) under the assumptions of scenario 2: only fuel is avoided. Similarly, Table 3 shows that there are 25 projects with B/C ratios greater than 1 under the assumption of 25% nonfue! 0&M Rural Hydro Economic Screening Results 1/27/97 page 7 avoided. Looking back at Table 1, we see that the top 23 projects in the base case rankings would still have a SIC ratio greater than 1 under the scenario three rankings. What do these results mean? I suggest that, given the base case assumptions already agreed to (especially the discount rate and fuel escalation rate), the top 30 projects under the base case ranking above constitute a good pool for further analysis. However, other projects in the 30 to 50 zone might also be viable under special circumstances, such as an erroneously low assumption about load (because we used the wrong community.) These projects also deserve some passing attention before they are eliminated from further consideration. Some top -ranked projects may have artificially low cost estimates because (perhaps) no transmission is included in the cost. I suggest that these top ranked projects be assessed, one by one, for this problem, as well as other defects in the data. Rural Hydro Economic Screening Results 1/27/97 page 8 ` I �N c YI-IQI�I CIInI(04I NIA r cJ C� n C rIr r M f�i f7 C7 COIF r�r O N C� r r © r to N r N NiN iN `i NI I Ir lr IN IN IN I� IL.IC ImI IN I ' c'y e81� .° ln I NIc� ci �I cal IN m c� _ Ir b cDic o!r` Ci CIQ r.CDlr,rlr it IN N r NIC, N'1N m cc a l^Ir it IN IN Ir I I G I 1� I I CI`y °8IC1 �G Imo. I Q^• I r N C`i Q In CD n CO C� CIr N Ch I C to (D I I�IcO I IC�! 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IYI _ _ CO' DI tCi'vi m E =iz. vIEIoIol—S 031 ;� _ CI E'— MI._I�Ito(aliai3 N °' Cc =;�I =I �� cal =i l"';—Iml �a I N C) Cfl YIY I� CO C7 C71 9 cc y ail 0 �I?�I¢ = a�lY Z 21z Z'Y YIw' Z ni �I�IlIQI¢ Rl m 3 m NI .21z, � jl� 2 I! z �Ia I CS •y to 1 ¢ I I I tQ i Y, t �I >I aj — I°? s C) i >I� G�1 O U �- s mI`—° Q) ai w vJ Ea (7 co >I�IY U U (O y E _ I Z �I� G C. R` z m - E.�I° d W I 3ITv O` aE�i Y C> U I to l N 0 U f4 C I Cf l I �: M s �- U C7 ` N Y _' I t fC I t9 I = 1- , C � � tII I N _ ci 12 1 75 ' y O Z h rn N Cl 0 Y t71 C. G �I ivlvl t41 W I O LL. yl�lt� 4) I C) C7 { .'. I I C'� O I _I - ! ,'-_ -I� O) yIF-I-I cu 1 C71 N QJ OI E U O IOI� C m Iml`.•"^I�.� ZI cl a�i•'>;4." `° c EY1F=; cc mi=1� ^I cIUI C t2 I I E Olyl�l� CI•CC 1 NI='+ O O c4 rn — C I....'n EIaI rn vv m y m E Z i 0 1 U f0 I G O ~ I C C.i W. Y. ° `" I G1RIY N C) N c9IZI vl�I .o I¢ C7t~IR m YI vINY.IUJICfI T CDI CI oI Y Q caI vIZIW w "I p'ca �IY Z m Q �q Q c cI Y Y zi I I BIZ► M I N IQ ; to CD i GM ICI n t C14 r- i t r.- Tl��t•^.:CDIn�CDICDI�O C, I to N IC7IC�IQ;M C;r. C 1 r;niCp tD n•nitD Ir IN In Ic�I lta ltn tD M ► lm MInItDI(°IQIn I I CIn1 lnln I I I I O I N q lt°Ir I to tD tole I N I f0 O m toInIM I I N r to C ► ►r ►'�Ir►rIr I Ire I T rIr T rlrlr lr iT it rIr►r WAUeZa Dr. James H. Thrall Locher Lzterests Ltd. '0E VV F--weed Lane. Suite l01 Anchcrage. AK 9950.;-2A_-;-9 Subject: Alaska Rural Hydro Study Engineering Evaluation of Selected Sites Dear Jim, G C nsultinc _^cineer s Inc Scr'entists June 199i File: 7=0-.110 Ser. 9 i -242 .RECEIVE We are araching herewith, evaluations of four separate projects, including Gar,.ina Creeic for Hoorah, Old Harbor on Kodiak Island. Pyramid Creak for Unalaska, and Chuniisa.; Creak for .-.��a. We rec�:ved a folder of i:,fcrnation and USGS :naLcing For e..�c^ o ' ` :Ote [lal ^i..er �.vere :;,uitipie reports :or each drainage basin. ... -ac havi z va ; n� ions zc;ten::_: proiects. lavcut and were often at different locations within the basin. This made evaluation a process or mixing and matching features from altemative to alterative. Several of Ul e repots were wTtten in na,*rative fashion to anon -technical audience. Therefore, tie tendency was to leave out relevant enginee^fig facts regarding :he prole::. The information contained within the folders was not always complete; often missing appendices and figures. - - ` We have atternoted to consolidate information and give input into each projec:'s pore for deve'.Ccr.:ent. Financial evaluation is not par, of our scone OF work, however, we h_ve COIiuT:e.^.red On tie cost estimates that were made available. ' In comparing cost estimates, be careful that apples and apples are compared. Some of tie estimates have been performed using standard contracang procedures (e.g., Harza - Gartina, Corps - Old Harbor). Others have used the theory that the community can contract and construct the projects (e.g., Polarconsult - Old Harbor, Polarconsult - Chuniisax), thereby saving contractor overhead and profit and not paying state/`ede,al prevailing waves. If this type of consa-uction/financing can be performed, then perhaps a 1/3 savings in costs can be realized over typical contracted ventures. To surnmarize, please note the following: Gar:ina Creek (HoonaA): financially marginal. Old Harbor (Kodiak Island): energv output greater than can be used by community which requires that the financial aspects of the project be examined more closeiv or the project downsized. If all the energy could be put to economic use, then the project is viable. Note that the project is in a wildlife refuge. Harza Northwest, Inc. 2353 130th Avenue N._., Suite _Co Bellevue. Washington 98CC5 Post CffiCE Ecx C-35900 Bellevue. Was.1ington 98CC9 lei: (206) 882.2a55 Fax: (206) 883-7555 Dr. James H. T'nrall 6 2� i' 9 i Paze 2 Pvramid Creek (Urzalas"(a ): proiect aopea.rs to be financially viable for immediate development. Has pote:u:al to :;,eet a larger Donlon oC the community's demand by looking closer at oche: prOiec:s in the drainage basin. Churiisax Creek proiec: is oversized for the community and is, ti^e:e:ere. ,:et viable as currently conC gored. If all the energy could be put to economic use, ten project is viable. If you have questions, please contact me. Very truly yours, _arza Northwest, Inc. d 77/Zw�' -- David P. i hcmcscn. 3; t— Proiec: Encl: Evaluations of drainages for hydro potential Carina Creek - �;nnnnn Gartina Creek - Noonah General Two secarate pieces of literature were provided regarding the development of Carina Creel: (i) Water Powers o''Southeasr:llaska. Federal Power COMMIssioPJU.S. Forest Service (date unknown), and (_) Gartina Creek A Reconnaissance Reporr, Harza Engineerng Company dated October 1979. Tne PC.,L;SFS describes hundreds of sites and contains limited info r„iation describing a hydropower deveieoment planned in 19= . The Harza analysis is much more thorough. We have used the Harza report as the basis for our analysis. The installed capacity of the proposed plant is 450 kW with an average plant factor of 5517o. The average daily load of the village is approximately 490 kW with a pet k dernard of about 750 kw. So, unless the project is configured upwards, it cannot meet even the baseload of Hoonah. Hydrology Tne arainase area was esum,ated to be 10.3 square miles with a runoff average ;low oI 77 c:s or 7.z c:s`square „rule- Ti,e range of average monthiv Steam flow is from ''9 to I �9 cfs. However, during the cooler months (December through Act-,!), the stream flows are, on average, less than the annual average flow. A run -of -steam piano is proposed as no significant storage is available. - A very thorough hydrological analysis has been per,-or,ned which il-Zc- 'lucies average monthly flows, flow duration curves, and hydrograpns. This perdon of the re oer` sheuic be adequate for use in fur-u�er studies, if warranted. If the proiect economics are acceptacte, based on an updated cost estimate. it is recommended that a steam gauge ce installed at the site and operated for a period of at least 2 years to verify the site - hydrology. Diversion A low concrete gravity dam with an uncontrolled spillway was proposed in the Harza study. The dam was shown to be located approximately 120 ft. upstream of the falls and founded on competent material. Another alternative for such a structure would be to use an inflatable rubber dam with a concrete slab foundation. This would greaciv reduce the quantity of concrete rewired for the project. If it is assumed that one-half of the concrete volume can be reduced and a rubber dam installed, then perhaps S300,000 (1996) car, be saved. Rubber dams provide the ability to impound water, and vet be lowered to steambed during high runoff events to provide increased spillway capacity. A rubber dam would also allow gravel and sediments to be passed downstream during major flow events. This would be advantageous in lieu of the probable requirement for pet iodic dredging of the forebay in front of the power intake. .Ar,Otller cost effect type of dam may be a timber flashboard type as Pol -consult proposed for t1ne Chunnsax proiect. Carina C:eta - :iccnah No mention is made of trash rack cleaning, but --is maybe a consid.—mcion, depende- i on the type of vegetation upsceam. Penstock: An above -ground, Steel penstock with ad lame,,-- cr 5 7-inches has been proposZ :. T ne ie:,ath cf the penstock is about 210 ft. The penstock. was sized for a g-ezte- hvdrau"c cauaciiv man is proposed to be initially installed (900 1-1W vs. ^ 0 kW p roocse,4 If only . a 4 0 kW project is considered, the penstock size could be reduced to 2—inches wiLhouc anv appreciable increase in head loss. This would reduce the cost of the pipe suppiv and Mstalladcn by about 5200,000119961. In addiaen. cent.nuGus coric-e:e SUT)COiC OIL the pipe is indicated. Assuming that this can be orlutted and that one-half of this conc-e:e can be saved, the costs may be reduced by another S110,000 (1996). .mother option is using PIDPE pipe supported above ground on wooden supports. It is not anticipated that this would save more than that indicate for small diameter steel pipe, but should be examined if the costs are recompute. T ne be^stet'.% would biiurczie ac the powe:aeuse :o convey wale- :e :wc =:Sz. Powerhouse The proposed powerhouse would be 42 ft. long by 15 ft, wide with a concrete subsSucm,re and a prefaor e--%r J ;petal SL'persu C''re. �7rliS is a re connnin rnn= rt„r�rinn l •b ✓•ced • ♦ul 1J I�.uJ llllll Vl�. b1..111.� wll.:llli ll. Other types of supers—auctures may include :.`lose capable or beg consuucted using Iecal labor (i.e. wood -frame or log). A bridge crane has been proposed for the powerhouse. Alternately, for small installations, mobile trades are used during installation and for fuPlre maintenance. T h.- Harza study also proposes a potable Ovate; and san.;=, ; syste;n to be ;-.stalled. .-gain, for small installations, these costs can be eliminate, saving S225,000 (1996) from the Harz- estimate. Turbine/Generator Trn,- T-Tnr-sn rPnnrr nrnrnePe rcvn vPr-rit-n1 cnnrr nrnnPllPr nirnirPc Pnr-in rnrAA Ir '71; lrw . uv ...+ __ I-e-11 L/L Vt/V V...J I,r V .. --- JI••�a♦ r• • u..a ♦•nl Vu—, ... •+•.•I 1LLl\. J. 4I --- .a - with a flow of 50 cfs and a net head of 65 ft. This selection is appropriate. Typically, for small installations, the turbine generator procurement specifications are written to allow bidding for any manufacmrers' ecuiumenc. This usuallv results in a vane:v of unit rapes and variation in costs. The bids are then evaluate' based upon perfomiarlce c :e; a such as energy output, plant cost, 0&1YI cost. and unit cost. This method of procurement allows for potential savings in equipment and powerhouse costs. Based on the equipment selection and the site hydrology, the annual average one-gv output is estimated to be 2,170,000.<Wh. Based on current machinery pricing it would also be well to examine whether a single aeneratinz unit should be installed. This will save installed cost but potentially reduce the energy output. Tnne mechanical equip menc costs. based on our : ce:lt exile: ierice, r;iav be about S i7S,000 (1996) low, 2 Gartiria Creez - Lconaa Transmission Line A ? miie long, 12.5 kV transmission line is proposed :tom the powerhouse substation ccthe town of Hoonah. The line is proposed to be ove-"11eaden wood poles. Depending on the nature of the surrounding vegetation, trees, and geology, it ._ be possibie to :7- ch or plow in and direct but an underground lire which would ;ecuce long tern 0&�l costs. Access Roads Tine indicates that in 1979 Forest Service roads were proposed to be consmac:ed in the area. If such roads have been consusctcd, then a 0.6 miie ;cad is proposed to access the powerhouse on the west side of the creek. Project Control Features The protect is proposed to be automatically or remotely cont.ciled by operators in Hoonah. ' Cost The costs or the proposed plant configuration are based or, 19'9 costs. Based or, cor'susc on costs indices, the costs indicated in the report should be increased by 73 c to SS, 70.000 (1996 costs). This cost includes on -site consLL,:c:icn. transmission 1;ne construction, engineering and administration, and a 2J�o COntingenCV. This has a cost of L Financed about 319,000/kW; which would not seem viable. at S o for 20 years. and the O&tii costs are escalated in properaon to the corisu,ic:ien costs, then the cost of ener_v would be approximately =3c/kV ri (amot-dzation plus 0&.1V interests during �• cons :c:ion, etc. are not included), as compared to cure .t reve-ues of about 33,t/'-kWh in 1997 for Z'iesei. Probably net viable. It is our opinion that several features, as itemized above, could reduce construction costs. The cost estimate contains costs for land acquisitions at 560,000 (1996) and reservoir clearing 5260,000 (1996). li these costs can be eliminated (i.e., assumed the timber is the reservoir are logged and sold) and the other savings above can be realized, then the 1 ..�...� way estirTrate Cali eas"V be reduCed to 56,7�C1,000 (1996). If the O&�i costs can be halved, because the same O&tii crew that maintains the diesel plant is available, then the cost of energy would be about 33(-/k-h (amortization plus 0&fin. This may be viable as u•iis would be a relatively fired cost (0&-,,,l is a small component), whereas, diesel produced energy escalates over time. Environmental Anadromous fish spawn below the falls (which at 50 feet high is assumed to be an impassable barrier) and in the assumed location of the proposed powerhouse. Draft tube racks may be required to preclude upsceari'miQrants from entering the turbines. This COS", was net considered in the cost estimate. 7rie proposed gravicv dam would also hinder u.e dcwnst:rei?m movement Of Qra��els w' be - • - n1Cn may _� u:re t0 SllpDIV downstream spawning beds. A rubber dam installation could ce operated to allow the Carina Creek - Hoonaa gravel bedload to be passed dur;ng major flow events. No other impac:s have been identified. Recommendations Tneugh we have not perfo=ed a :financial analysis of tiie prejec;, the cost indicated above would indicate :hat deveiecment of :he prole,; -may to r:a.:_�ra1 ac best. If grant or low interest money can be obtained the financial ascec:s c-: e project would need to be reexamined in detail. If the cost of replacement power and associated ffinancing make the project viable, then the plant layout and cost estimate should be redone. We believe that a more economical layout should be pursued. Old Harbor - Kodiak Island General Four documents were examired: (1) Community F.7,;dr000wer Re orrs, U.S. A rm y Corps of Engineers dated Oe;ober 1980.(2) Old Har'or Hvdroe!ecrric Feasioiiiry Srudv, Polarccnsuit Alaska dated Ju-.e 199; (3) ;:er re r 0 .i':e Vcxiand d� ., , le � e b v r•: � � te.. Jute 1995, and (^) le::er repel- by .las:a Village C-ecer_:: e (AVEC) dated October 1996. T fie Corps report gives brief inform aiion for = di ;erera projec: configurations (2280 kW, 680 kW, and 3=0''<W). The consensus of the Polarconsult and Ati7EC recor-s is that a protect of about 31-0 kW more closely requirements of the community_ of Old Harbor. Voxland favors`a 600 to 800 kW installation. The Polarconsult study is the mcst thorough study of those provided and was be Lie basis for this analysis. Arother study by Dowl Engineers was referred to in the Polarconsult report, but was not available for review. Hvdrologv The Polarconsult report desc::bes the development of a high head/low flow plant from the Bariing Bay tributary. The repot indicates a discrepancy for the assumed drainage basin runoff of 5.7 to 12 cfs per square mile. Polarconsult used the high value for their evaluations and performed a sensitivity analysis if the runoff was less. A stream gauge was installed on the tributary in 1993, which we assume is still collecting data. It will be important to continue to gather, data from this instrument to assist in verifying the stream hydrology and, therefore, power generation capability. From the study, a drainage basin of 1.31 square miles is being used which would produce an average stream flow of about 22 cfs. However, the turbine design flow is 7.5 cfs. The repot has a plot of stream flow for a one year period. During that period stream flows vary from about 2.5 to 40 cfs (which appears to be the maximum capable of being recorded at the gauge). Furzuher review of the data is required. Diversion A cast -in -place cone.-;,- diversion with s:eplcgs is proposed in association with a desanding suscrure. From the description, appareitly:he diversion would be constructed Gamna Creek - :ccnah on soil material, therefore, special considerations will be required to ensure smbility and waterd2hmess. Trashrac'.< bars are described as being "one half pipe diameter". Typicaily, the trashrack spacing is dic:aced by the turbine dimensions. For machines in this size range, the rack, spacing may be 1- ch or less. We concur that a desarding su'ucture be installed at the site. We are familiar with streams with steep g-acien:s on Kcdia'.< Island and their acuity to produce coarse :c r:ne sediments that can desuov turbines. The desander needs to be designed to allow water velocity to be reduced. with adequate detention time, to allow sediments to settle out. Proceriv designed desanders can be costly. Penstock A combination of 16-inch HDPE and steel pipe is proposed to be buried for the penster.<. This may be appropriate, cut the HDPE section will require select bac:uill so as not to damage the pipe. If the excavated trench mate^al is not suitable as backriil, then the costs for bacfill will increase for imported material. This is also a consideraticr er tiro proposed 10 gauge steel pice. In,conirg select granular material could increase :i'.e per:stccl< ccst by S1 lO.CCC. I: CeCrCC:< a --cot'ntere-L - e ccst Cr the increase by S=0/ft. I` ,:aifof tie pipeiir:e is in roci<. Lie costs could increase by g:00,000. The 10 zauge steel pipe is appropriate for operating pressures and handling. The a:rcine shutoff valve will need to be carefully con oiled to limit pressure rise. It may be prudent to increase the thickness of the pensteci< ar u:e lower section of the penstock. The I-MPE give would ce fusion butt -welded. The steel pipe is proposed to have cell and spigot type joints. This is appropriate for suaight pipe runs. Every bend will need to ce examined for thrust and t:`irust bloc.<s added where required. It would be a_Dv_ rocrate to add a cost line for thrust blocks. It is proposed that the 16-inch steel pipe ce welded as it nears the powerhouse. It is also proposed to paint the interior of the pipe at each joint. This requires special equipment for small diameter pipe. The report also proposes to transfer the full thrust at the powerhouse into the pipe m tension. This theory will require a thorough geotec-Imical analysis of the site soils and the soil friction transfer mechanism. Construction inspection W iu be extremely imper-ant to ensure that the pipe is installed correctly. Powerhouse The powerhouse will have a concrete slab with turbine pit and wood -frame superst,-ucnure. It is assur ned that this type of construction can be performed by local labor. Turbine/Generator A 330 kW impulse turbine has been selected. Tnis is an appropriate selection. The turbine is to have a design flow of 7.5 cis at a zross head of 747 feet. Based on the hydrology of the site, a larger instaIlatien may be possible. 5 r Transmission Line A buried transmissier, line is proposed. As suzzested in the retort, this may be mcre costly than ove:head line, but may be more ccst e: ec:iye than en-QoinQ maintenance. C Garira Creep - riecnah Access Road No access roads are indicated in the noon. Project Control Features Remote control is proposed. Cost The cost estimate of 51,369,000 (1996 costs) is based on the assumption that the can be performed by the ccmmur_ity via nsnkey or force account me:heds. ; �,e la:oor rates of 520/hr used in the cost estimate are low in comparison to state and federal prevailing wages. Prevailing wages with a contractor's overhead and profit can ce 2 to 3 times higher, depending on craft. This could increase the construction costs by 5200,000 (1996). The report also proposed loos.'. enginee—"'ng design, that can be modified in the `eld as necessary to suit field coreitions. i nis «:e:hed requires a very ,-io�yied_g_abiz e:c engineer, with a diverse e-ginee ng%cors��ctien bac'.--round. In snort, the estimate was prepared assuring non-Saditicnal contracting. Tv contractor mobilization, overhead, and prof -It have been excluded. T nis May add 30 to 6010 to the bottom line. the contingency of 1-5 ,o is low for this level of studv; _f-o or higher is more appropriate. If standard contacting procedures are used, the cons -,ctien cost estimate could increase to approximately 52,000,000 (1996). If financed at 8% for 20 years, and based on Lhe cost ranges indicated above, the cost of energy would be between approximately 22 to 31 t/kW n (amorization plus O&tii; interests during construction, etc. are net included), if only the amount cu..e:.tly required is generated (surplus of 1,920,000 kWn). Compare this to current revenues of accut 38 t/kW`h in 1997 for diesel. If other uses could be made for the power (e.g., added industry), and the entire project potential could be marketed, then the costs would range from 6 to 9(�/kWh. Fnvironmantnl The project is located within the Kodiak Wildlife Refuge and could be a `'major impediment" to development. Other environmental issues were not identir:ed in the repons. The tvpical issue, cf course, is access to the seam by migrating fish and preserving spawning reaches, if any. The powerhouse, to our reading of the report, would be at elevation 83. It is not known whether an impassable barren exists between Midway Bay and the powerhouse. il ,i rii rin ('-potc _ r:n nnnn Recommendations Financially the project ,,-gears viable. Investigation into the viability of a project in a wildlife rensge and fishe :es access to the creek should be investigated. The deve?ocmezt scenaro would also nee tc be investigated with respect to state prevailing wage laws. A refinement of the layout and site constraints is necessar; to verify costs. Pyramid Creek (Ic;j Cree s) linalas;a Pyramid Creek (Icy Creak)- Unalaska General Four separate studies were provided re: Unalaska hydro development as follows: (1) Una"csha- Azaska Final Small Hvaropovver Interim Feasibility reporr and Impact Starement n�':rcrmenta: U.S.li.S. Army Corps of EnQTneers dated July 1984, (2) Overview Pyramid Crepe HYdroelecrric Project., Energy Stream. Inc. (ESI)dated January 1985, (3) :Vomit Fork Pyramid Creek Hydropower Studv, Polarconsult Alaska dated January 1993. (�) Icy; Creek Power Recovery Stuav, Polarconsult A.iaska dated April 1994, and o S!?ea T () mrtotiv Dara Report Pyramid Creek Drainage Basin, Car ick and Ireland dated August 1996. Several sites and configurations were idendfled in the repots. Each report descr:ced different syste ns. None of the repots contained site maps to icenar'y exact locations of diversions, pipelines, powerhouses, etc. The ESI report proposes to construct and own three separate power, generating ^lams in the P..-amid Creek drainage with a total installed capacity of 1 130 kW. wcud . alai'. a 90 kW' u n One ect.o^ 1 P.lt G� LLne Ca'v'j exit:n� water SupDiV l:ue. the Gt; lnvoive ( ) d:vendrig excess water at the exlsdrig diversion dam and (2) conszuc::ng a new dive. -Sion on Pyramid Creek below the East Fork of Pyramid Creek. T ne pcv er ;:or the system would be sold to the city. The citv's power requirements average 3-Coo to ='00 `,V. ESI's proposal would meet accroximateiv 25�0 of tine city's ener_v requirements. -' The Polarcorsult repots are wr��en to infor-111 the city of hydro potential and lack much enzinee::.-:a data. Their repots seem to info—n the city of how LL`iev might proceed to develcp a site. T'ney may be considered proposals rather than `easbilicv repots. 1 nev proposed foul' layouts. iI?C[udi* � (1) diver' g ECS' . . _ �in the t Fork Pyramid Creek info existing reservoir (no estimate of power output), (2) install a generating unit downstream Of the e„fisting diversion at an existing waterline blow -off valve (400-500 VN�, (3) a 550- 750 kW option, and (4) a water pipeline "power recovery" option (100 kW). It appears as if the most economical development would involve retrofitting a "power •���.�,y gerieraan� unit on the city's existing water supply pipeline, near the chloHnation building. This option is mentioned in three of the reports with sizes ranging tom 90 to 260 ktii%.�The system would be designed to either use Only the citv's water supply demand (90 kW� or to divert more water and waste Lhat not used to supply :he eity's water demand (260 kW). . HvdroloQv The 1996 streamflow• study is a good start at quantifving the hydrology in the Pyramid Creek watershed. In 1994 five gauges were installed at�various locations in the drainagt. Two have since bee., washed cut. One was installed below the city's water suopiv dam (EL 500:t) on what is called Icy Creek. The measured flows below the dam rangy, =-,m about 1 cfs to about 1000 cfs, with 26 cfs being the mean (this corresponds to valt:es Gamna C-.-t c - iccnah taken by the Corps). L-i 1995 approximately 3.9 cfs was being dive ;ed at the darn, or. average, for the water supoiv system. The gauging studies indicated that L` e mean annual ninoff varied `om 8.5 to 12.E cfs,'sauare mile. It is not clear wne;.her t1,e L. cfs value. which was computed immediately below the dam, was adiusted or the citv's wale: diversion. In addition. the s,earnflow studv also gauged water from the E=st for:% P.,Tarnid i nis enables study of other development alternatives in the basin. Diversion Aorarrrerltly in 1993-94 the city replaced the diversion darn at Eli. 500 on ic, Cr..::. : ^e existing rese^�,oir has a storage capacity of 8 million gallons (1841. acre-ft.). L^C.e�Sins t :e dam height would increase the storage and would enable the sys.ern to run in a more flexible mode of operation. Otherwise, running in a run-or-sl.eam mode wILj r-Linor drafting capabilities would be recuired. ESI discusses adding another intake to the existing diversion- and consusc; na anotltler diversion dcwnsaeam. The downs: eam diversion is shown to be 10 feet high cv SO fe�t Ions: and ccnsiSt cI ghee' piling in a COnCrete Szrip fOL1ncatic"n. _o sheet pile would be cac:�llled en both sides wiL-i rock slopes. ',,o in e^.ticr, is ...a C-- ci grouting the slope faces to allow excess flow to over -,op the dam and not erode --he downslope. For this application a low concrete dam, small rubcer dam, or till cer dam may be gee-. Ll Fur",e_ studies ale nec..ssan� The Polarconsult option which divers water into the city's water supply rose: Moir, indicates that a timber dam bolted to bedrock would be used. Penstock It is not clear whether any of the supply pipeline was replaced. Tne existing 16-inch diameter wood stave pipeline was to be replaced with 24-inch diameter steel pipe. Depending on the type of turbine unit installed, the pipeline may need to be upgraded to handle hydraulic transient pressures. It may be assumed, however, that gate closure tines would be limited to preclude excessive pressure rises. ESI proposes to replace can of the existing pipeline and install new pipeline to a new powerhouse located near Captains Bay. tilate:ial types are not discussed in anv detail. For low head aoolicadons, curled or exposed HDPE pipe may be used. Steel pipe is also an option. Turbine/Generator Tne Corps report recommends installing a 260 kW horizontal Francs turbine (1 i0 ft. net head and 22 cfs) coupled to a synchronous generator. The total gross head for t2 is opcen is 460 feet, but 80 psi must be maintained downstream of the plant to supply water to !-';e city. We estimate tl`lat the escalated price of the equipment to be about S90.000 (1996) too high. ?. Turgo (i...pulse) unit could also be utilized. Polarconsult's 100 Franc:s option for a water supply flow only plant is also appropriate. 10 Ganina C:etk - -roonah i ne other options discussed in the various repots are not described in detail. However, for lower head applications with long penstocks, Francis units are appropriate. Powerhouse The Cogs repot indicates that pC�-:3br Ca(e steel building be structure would also be appropriate. Transmission Line The Corgis reports indicates that the existing trans. issicn line near the chlorinat:en building is capable of transmitting generated power. If other options are deve'.oped, the ESI repot indicates that the city recuires that the transmission line to be buried. ine ESI report discusses alignment routing and indicates the line is to be buried in conduit. Alternately, the line could be direct buried. Access Road Access road is already in place to the chlor'nat:en building. T e same access as e.;iszs for t he 'Ve-5:0n s::7lcture would be us.--::Cr t."' : Project Control Features The plant would be run by an automated prcgramrr:able logic cone oller (PLC). Enunciation of alarms to operators' homes would be appropriate. Cost The Corps has indicated that costs for the project would be 51,281,000 (1996 costs) for the water pipeline option, which car, generate power in e.;cess of that dive-ed eriv for water supply. This estimate contains a ?S7c contingency. i ^e Poiarconsuit estimate, in 1996, is S25 1,000 and produce energyubased on that diverted for water supply only. Poiarconsult's costs are for a city consucted plant (tur-lkey), which uses low labor rates and does not include bonds, overhead, profit, mobdization, etc. This cost could go to S400,000 if standard contracting methods are used. ESI does not give costs for their proposed development_ ` If financed at 817o for 20 years, and based on the cost ranges indicated above, the cost of energy would be between approximately 7 to 9c/ktiZh (amorszation plus 0&.\vI: interests during construction, etc. are not included), as compared to cur_ent revenues of about "k- h in 1997 for diesel. Environmental The ESI report indicates that salmon spawn in the lower creek, but are limited to access to the upper watershed by impassable barriers. There is no mention or minimum instream flows, however, ESI has assumed that during the spawning season the flows in t,` e creek are above normal al and enough excess water will pass the diversions ro enabie arnoie spawning flows. av Gamins Creek - Fcenan ESI also mentions the nee, nor a cultural resources survey, although tl` ere are no Dow sites in the basin. n Recommendations Tne project appears rnancially viable. Tne project may produce I to i% or the arnuallv Qenerated eaergv. Other,eveloornent ootiens are available and are described above. The Pyramid Creek basin appears wor-Lhv or r'urLher. investigador...', ret,ne-ne t or potential conriQuratiens, cons�uctien costs and environmental features is wa.,.anted. 12 Chuniisax C:e;s - d, a Chuniisax Creek - Atka General Two srudies were provided re: At:{a hydro development as follows: (1) Ar'a Sma ' Hydropower Feasioi::,; Study (sn aiI extort orovided), .^t!aska P w o er Author? (•�•? ) dated April 1987 (this may be the study identir:ed by Polarconsult as by "Ncrtec- which provides a "compre'.,ensive analysis" for hydropower develcumeat on Chuniisax and (2) Hydroelectric Feasibility Study and Preliminary Design jor the Ciry oT A.,;a. Polarconsult Alaska date^ November 1996. Polarconsult estimates that a 2471 kW unit can be installed to meet and exceed At.<a's current energy demand. Hvdrolozy Polarconsult identifies data which has been ccilected into.,: ittently ; cm 1e8_ to i CC4 s-,:eam gauge has been .I-.stailed f:om too; to i996. in a - . e data was rict mad :or ex�minatien. Tne ac,uai crinage basin size has not been acc.irtely dete.,.,ined. it is thought to be between 5 and 9 square miles. Poiarcorisult used 7 square miles. It accears as if Polarconsult did a re asonable job or estimating flow. Fur-dier refinement or date over a longer pe^od or rT,:,e is -�radent. Inn. 'In'* -�� r +�.� u„i6 u. si`:1 slow is 36 crS. Diversion A timber flashboard rvre dam is proposed, anchored to a concrete foundation.. The g5ecmezy of the dam adds to its stability. This concept appears to be sound. The dan: vyill raise the water su: ace -ppreximate1v 10 feet to `gin storage for'lcad levy I -- _ •e ir, Since the basin does act have trees a simple trashrack and slide gate will be used. The geologic characteristics of the basin are no[ known (e.g., high sediment load in the basin?). For this reason it is prudent to dete.-mine whether the intake pipe should be protected or raised above the bottom of the dam to prevent intake of coarse sediments. Penstock It is proposed to use 1060 feet of 28-inch HDPL pipe. The pipe will be exposed, or above grade on a wooden trestle. This selection is adecuate and probably cost efrective. r.DP'✓ has a high :he.,-,ial expansion coefficient and will move when the temperatures var i. Allowance must be made for thermal expansion. Thrust resuaints are shown on the drawings. Some innovative techniques have been proposed to install the pipeline, including floating the pipe to the site, dragging it into position, and mechanically coupling it together. Dragging the pipe is not recommended as it has the potential for damaging the pipe, will s-onen its life; and may damage plant life. Gar;ina Creek - Hconan TurbinelGenerator cross -flow unit has been precesed by Polarcerisult. This is an appropriate selec,ion. Alternately, a Francis unit could be used. The unit is rated at =71 k�V at a gross head of 116 feet and 36 cfs. It is est:-..aced that the plant could produce 1,760,000 kWh per year, which is greater than 6 tunes -.e one-gy curently used in Atka. The excess enerav produced will need to be deal; with as discussed by Polarconsult (e,g., installation of a load controller to direr; powe- to oti�ier sources). Hydro machinery operates more effc:ently at its rated cacac:r:, wherefore, reducirilz the size of the unit may be aperepriate. This decision would need ro e -Wade in combination with comparing the instantaneous output of the plant to the peak lead of the city. A riother develccment altetriative would be to install a single, smaller unit and provide space in the powerhouse for a second unit to be installed in the future, as demand requires. Powerhouse The powerhouse will ccns:st of a suspended concrete door over a wooden subsusc ure. Tne walls and roof will be wccd i?afied. This is an approor,•ate selec;:on. Transmission Line A buried transmission line ;:as been proposed. Overhead line should also be examined. Access Road The report indicates that the project will be accessed by ATv's. ine presence of existing roads is unknown. Project Control Features Tile project would be automa::c- ly controlled. Remote control is possible if required. Cost Polarconsult estimates that the project would cost 5766,000 (1996). Their estimate is highly detailed and includes administration. engineering arr4 Fl,.I i ;ncrA.- -� ..�... ua.+: � �. �1V 11 costs. 1-1 contingency of 10-201c,-,o is added for each line item. Tne cost estimate is based on --he assumption that the work can be performed by the community via turLcev or force account methcds. The Iabor rates of S26ihr used in the cost estimate are low in coraa:ar.sen to state or federal prevailing wages. Prevailint wages with a eontrac;er's overhead and profit can be 2- times hither, depending on craft. This could increase the cons=,c;icn costs by 5125,000, as estimated by Polarconsult. In addition, contractor overhead and profit for standard contracting procedures, may increase the total cost to S 1.200,000 If financed at 87o for 20 years, and based on the cost ranges indicated above, the cost of energy would be cenveen approximately 39 to 54e/kWh�(amor-szaticn plus 0&.,v1: intereszs during ccns4lc;ion, etc. are not included), it only 'u,e amount currently reClllred is ttnerated (surius of i.=' 70.000 kWh). Compare this to cu;r.ent revenues of about 14 Gar;ina Crer` - wccnan 38 c/ktiZ n in 1997 for diesel. If other uses could be made for the power (eq., added industry), and the entire project potential could be marketed, then the costs would range from 6 to 9c,,kWh. Obviously, different loan rates and durations will aiter, the numcers. Environmental 1 C1e APA report describes :he lower reach of Chunilsax Creek as containing six dlstinc: falls. It describes anadromous fish access to the base of the second falls uosueam of Nazan Bay. 'Though no actual location map is 'given by Polarconsult, we assume that :he trite^a to keep the powerhouse at or near the base of the second falls has been maintained, rerunin; water at or near the base of the falls. Recommendations Unless use can be made for the tremendous amount of excess ever zy produced, the project does not appear viable. Alternately, the project could be downsized to meet current needs and nets future projections. �If such is the case, cite cost estimate shculd ce redone based on a smaller project. 15 R. G. NVILLLAIMS, Inc. July 7, 1997 Dr. James Thrall Locher Interests LTD. 406 West Fireweed Lane, Suite101 Anchorage, AK 99503-2649 Subject: Alaska Rural Hydro Assessment Harza Report Review Dear Jim, P.O. Box 876 Wasilla, AK 99 Phone (907) 3 76-9 F-,x (907) 376-9 I have reviewed the Harza report and generally concur with their conclusions and recommendations. However, before I discuss the Harza report a brief recap of how the project costs were treated might be in order. For the initial database of all potential hydro sites, costs were taken from the various reports at face value and updated to 1996 costs using the Handy - Whitman Index for Pacific Region, Total Hydraulic Production Plant. Subsequently the list was further refined to 30 or so projects for which the costs were analyzed in greater detail. At this point the costs were review_Pri fnr coy pleteness and in some cases adjustments were made (based on project team experience) for such things transmission line or environmental costs. Harza correctly points out that some of the previous cost estimates are base using normal contracting procedures while others are based on the community building the projects. Harza says perhaps the latter approach can save as much as 1/3 in costs. I would not recommend using the community build approach. The track record for community constructed projects is not good; either the projects experienced great cost overruns or once completed, the projects failed to operate for any length of time. The cost range for Gartina Creek ranges from a high of S8,470,000 (1996 costs) to a low of 56,740,000 (1996 costs). The savings results from deleting or Dr. James Thrall 7r/97 Page 2 downsizing certain project features and assumptions about land acquisition and reservoir clearing costs. The costs reduction measures are worth pursuing. Costs for Old Harbor ranee from a high of about 52,000,000 (1996 costs) using conventional contracting features to a low of 51,369,000 (1996 costs) based on the work being performed by the community. As I stated above, I cannot recommend the community build approach. The Pyramid Creek costs range from a high of 51,283,000 (1996 costs) for 260 kW installation to 5400,000 (1996 costs) for a 100 kW "power recovery" installation. These costs assume standard contracting methods. Costs for Chuniisax Creek range from a high of S 1,200,000 (1996 costs) using conventional contracting methods to a low of 5766,000 (1996 costs) for a community built proiect. Again, I cannot recommend a community built project . the community already has a community built proiect, on another Watershed which has never worked properly. Attached is a table showing a high and !ow cost for each project. If you have any questions please contact me. Sincerely, n Remy G. !lliams, P.E. Consulting engineer N N C CC N C G T 21 a a u o Cn — � E U N N O C= U N y Y Q cC (D —lz y ` > _ W C C (D O c 6 O m m O O U O O O p cu O • U C fU) c C U O C� fU CJ 3 O � U U U U c~n c c o c O 3 � C o to too O T J 64 64 69 69 Cn O O O O O O O O O U O C7 a cl O o c b cli 0 /n c T T N_/ N N 69 69. 64 69 N N N Q U O � O ca U asi a) cu W c U U C o U a x cu C � Q U C� O C U RURAL ALASKA HYDROELECTRIC ASSESSMENT RURAL HYDRO ECONOMIC SCREENING CRITERIA Rural Alaska Hydroelectric Assessment: Proposed Stage 1 Economic Screening Method prepared by: Steve Colt nstitute of Social and Economic Research (sgcolt@aol.com) prepared for: Locher Interests LTD. and State of Alaska Department of Community and Regional Affairs Division of Energy November 1, 1996 1. General The goal of the screening process at this stage is to eliminate clearly uneconomical hydro projects while retaining those projects that may have potential. We want to use a very coarse screen that favors the hydro project. A hydro project is essentially a one-time capital investment that returns future benefits in the form of reduced diesel costs. The amount of the net benefit is the difference between the present value of the power system costs with and without the project: (1) NB = PVTC(diesel system) - PVTC(hydro system). where NB = net economic benefits PVTC(diesel system) = present value of total costs for the diesel -only system PVTC(hydro system) = present value of total costs for the diesel -plus -hydro system November 18, 1996 Page 1 of 9 LOCHER INTERESTS LTD. RURAL ALASKA HYDROELECTRIC ASSESSMENT RURAL HYDRO ECONOMIC SCREENING CRITERIA This total cost comparison is the most satisfying way to do the analysis since it avoids making direct assessments of avoided costs, capacity credits, and other such thorny issues. However, such a complete analysis is too complex to apply at this stage. I therefore re -write equation (1) by subtracting the amount of diesel costs that remain in the diesel -plus -hydro system from both terms on the right. This gives the more familiar comparison between the incremental cost of the hydro project and avoided diesel costs which the project makes possible: (1A) NB = PV(avoided diesel) - PV(hydro project). where: PV(avoided diesel) = present value of diesel costs avoided by the hydro project PV(hydro project) = present value of the incremental costs of the hydro project The rest of this memorandum considers how to make simplified calculations of these two terms. I first consider the present value of the hydro project. I then consider the elements of the present value of avoided diesel costs: fuel, nonfuel 0&M, and capacity. The final calculations I propose are extremely simple, but they reflect much thought about the effects of including more complexity. I have tried to make simplifications which bias the comparison in favor of the hydro project, and which do not lead to unstable rankings. By unstable rankings I mean a situation where the rankings of the hydro projects, relative to each other, could change dramatically due to a factor which I have ignored. 2. Hydro System Costs and Output 2.1 Hydro Construction Cost: The construction cost identified in the database will be restated in 1996 dollars using the Handy -Whitman index for Pacific Region Total Hydraulic Production Plant from their Cost Trends of Electric Utility Construction. I assume that project -specific associated transmission is included in the stated cost. If it has been omitted, the hydro project looks better and will be retained for further analysis at which time the cost estimate will be rectified. 2.2 Hydro Maintenance: Hydro maintenance typically runs less than 3 percent of capital cost. I propose to compute annual hydro maintenance as 1.5% of initial construction cost. November 18, 1996 Page 2 of 9 LOCHER INTERESTS LTD. RURAL ALASKA HYDROELECTRIC ASSESSMENT RURAL HYDRO ECONOMIC SCREENING CRITERIA 2.3 Hydro Output: I propose to briefly consider seasonality of hydro output as follows. The total energy capability of the project, as coded in the database, will be assumed to be available to displace diesel energy, unless available information can be used to designate a project as "summer only." When such a designation is possible, we will apply a generic factor to the total energy capability to get a more realistic number for available energy. Of course, we must be careful not to double -discount if the project's "total capability" is initially measured on a summer -only basis. 2.4 Hydro Lifetime: I propose 35 years as the hydro lifetime and the overall time horizon for the analysis. Under almost any plausible discount rate the benefits in subsequent years are trivial. This parameter will be built into the model so that we can change it easily if need be. 3. Diesel System Costs and Output 3.1 Common Diesel System Operating Parameters: The following basic assumptions about the diesel system were developed by Colt and Foster (1994) for their analysis comparing hydro to diesel in Thorne Bay, which is a fairly "typical" rural power system. Diesel Lifetime: 60,000 operating hours, run at 6,000 hours per year, giving 10 years as the effective lifetime. I also propose that the existing diesels will last 5 years on average after. the hydro project is in place. This leads to a convenient "replacement schedule." I assume the diesels are all replaced at years 6,16, and 26. The final generation wears out at the end of year 35. Diesel Production Factor: 35% of continuous rated power. Example: a 100 kW generator would produce 100 * 8766 * 0.35 = 306,810 kWh per year. Diesel Station Service: Ignored. Roughly offset by hydro transmission losses. November 13, 1996 Page 3 of 9 LOCHER INTERESTS LTD. RURAL ALASKA HYDROELECTRIC ASSESSMENT RURAL HYDRO ECONOMIC SCREENING CRITERIA 3.2 Diesel System Avoided Fuel Costs: I propose to use actual fuel cost per kWh sold, from recent PCE filings for the relevant communities that would be served by each project. Note that this measure subsumes generation and line loss efficiency. I have already obtained most of the data and "cleaned" it to remove bad data. I am currently waiting for a second database which will allow for a final round of "cleaning" and then the Project team will merge this data with the hydro project database. Each hydro project will therefore be measured against community -specific fuel savings. I propose to assume a 1% real escalation in future diesel prices. The base price will be based on PCE filings for fiscal 1996. 3.3 Diesel System Avoided Other O&M Costs: This is a potentially tricky area. PCE data provide overall nonfuel operating costs by community. My examination of these costs shows that they range, roughly, from about 5 cents per kWh (some AP&T communities) to 25 cents per kWh for mainstream systems (both THREA and AVEC) to above 50 cents for some very small systems. My detailed examination of Thorne Bay nonfuel 0&M costs suggests that about 60% could be classified as variable and thus avoidable by increased hydro energy, while about 40% are completely fixed G&A expense, related to distribution and administration. The expenses that vary with capacity (chiefly property taxes and insurance) are trivial. Table 1 summarizes these results. Table 1 Assignment of Diesel O&M Costs to Fixed and Variable Categories (Thorne Bay, 1994) Reported =xpense item Expense Personnel $90,683 Parts & Supplies $9,528 Repairs & Maint. $18,562 General & Admin. $17,966 Total O&M $136,739 Allocation of Reported Expense: Fixed O&M Variable O&M total $ $/kW total $ $/kWh G&A $0 $0.00 $60,455 $0.024 $30,223 $1,000 50.72 $7,528 $0.003 $1,000 $1,000 50.72 $16,562 $0.006 $1,000 $2,493 51.80 $0.000 $15,473 $4,493 $3.24 $84,545 $0.033 $47,701 boldface denotes a direct allocation by analyst November 18, 1996 Page 4 of 9 LOCHER INTERESTS LTD. RURAL ALASKA HYDROELECTRIC ASSESSMENT RURAL HYDRO ECONOMIC SCREENING CRITERIA Based on these considerations, I propose to assume that 50 percent of each community's nonfuel diesel O&M is variable with energy output and is avoidable with increased hydro energy. Note that this approach does take into account the tremendous variability in nonfuel O&M costs across communities. However, it is not feasible to investigate each community's cost structure to determine what percentage of these costs vary directly with energy output. 3.4 Diesel Capital Costs and Avoided Capacity: First of all, it is helpful to note that diesel capital costs account for only about 9% of the present value of diesel system costs in communities with low fuel costs (such as Thorne Bay). They account for even less in places with high fuel costs. I assume the base capital cost of diesel capacity is $500AW. This figure excludes possible emission control systems that can add as much as $125AW. The $500/kW figure is based on the assumption that the powerhouse building and land are already in place. Mark Foster and I have been updating our estimates of diesel costs over the past two months. Mark's latest comments on this subject are instructive (October 28 personal communication): As you are well aware, it is hard to find someone who knows how much they are actually paying due to the ever present confusion of grants and failure to account for labor. I'm still finding the $ per KW for Diesel -fired generator sets installed in smaller sites in rural Alaska (unit sizes under 700 KW) to be from as low as $200 per KW to around $400 to S500 per KW for installations within -the last few years. I'm inclined to believe the diesel manufacturer fellow who said the price jump occurs when they go from the in -line 6 to the V-12 engine block. Not only does this put a premium on the price for the engine -generator set, but it puts an additional increment on the weight which typically translates into higher freight and handling costs to land the equipment. The R. W. Beck addition of $125/KW for pollution control considerations appears to be "conservative" in the sense that they have picked a number on the high side of the range in order to cover contingencies. The manufacturers of diesels (CAT, Cummins) are attempting to improve their technology and stay competitive -- on both the capital cost and on fuel efficiency -- to respond to existing and future pollution control requirements. It is likely that their innovations will enable them to come in under the $125/KW pollution control premium originally estimated. How much of this cost is theoretically avoidable depends on the size of the hydro unit relative to the largest existing diesel. November 18, 1996 Page 5 of 9 LOCHER INTERESTS LTD. RURAL ALASKA HYDROELECTRIC ASSESSMENT RURAL HYDRO ECONOMIC SCREENING CRITERIA Case 1: Hydro is "small": If the hydro unit has a smaller effective firm capacity than the largest diesel unit, then hydro firm capacity can completely replace diesel capacity as if it were a perfect substitute. We can express the amount of capacity avoided in terms of "kWh per year for 35 years," which is related to energy, but the underlying concept is a capacity concept. The savings are in the form of avoided capacity, as shown in the following schematic (The schematic assumes a 20 year study horizon.). Of course, run -of -river projects may have an effective firm capacity of zero. Hypothetical Diesel Expansion Plans with and without Hydro substituting for one unit No -hydro diesel expansion plan: Year: 1--------- 10 11----- --- 20 diesel unit 1 $500 $500 diesel unit 2 S500 $500 diesel unit 3 S500 S500 With hydro diesel expansion plan: Year: Year: 1--- ------ in 11— ----- — 2 n diesel unit 1 [avoided] [avoided] diesel unit 2 $500 $500 diesel unit 3 $500 $500 In this example the savings appear to be the present value of (S500 now plus S500 ten years out). It is straightforward to express these savings as a present -value amount saved per kWh of annual energy delivered by the hydro project. The only pitfall with such a calculation is that the hydro project might not have the same production factor that I assume for diesel. Recall from above that I assume that every 1 kW of diesel capacity produces 1 * 8766 * 0.35 = 3,068 kWh per year. But a hydro project that produces 3,068 kWh per year might not have a firm capacity of 1 kW. In theory, we could address this problem by using all available information about firm capacity vs. energy capability. If the data base contains a firm capacity number, then we could use that to determine potential avoided diesel. If the database distinguishes a project as run -of -river or summer -only then the firm capacity is zero. If no firm capacity information is available, then we could favor the hydro project by assuming that it has a production factor similar to that assumed for diesel. In practice, as I conclude below, the entire issue of avoided capacity is irrelevant to this analysis because each community already has its initial capacity in place and we are not assuming load growth sufficient to require significant capacity additions. Under November 18, 1996 Page 6 of 9 LOCHER INTERESTS LTD. RURAL ALASKA HYDROELECTRIC ASSESSMENT RURAL HYDRO ECONOMIC SCREENING CRITERIA these assumptions only replacement capacity can be avoided, and the need for replacement does depend largely on run-time and hence energy output. Case 2: Hydro Unit is Large: The second type of capacity saving occurs when the hydro unit has a firm capacity larger than the largest diesel unit. In this case standard planning criteria require that the system be able to sustain the loss of the hydro unit. It is easy to see that under these circumstances the hydro unit avoids only the capacity of the largest diesel unit but it can defer the additional capacity beyond that of the largest unit. This is shown in the following schematic. Here, the hydro project replaces the energy output of two diesel units, but one of these must be maintained as capacity so that the system can still tolerate the loss of the largest (firm) unit, which is now the hydro unit. With hydro diesel exnancinn ninn- Year: Year: 1--------- 10 (11 --------- 20 diesel unit 1 1[avoided1 [avoided] diesel unit 2 5500 [sits idle for backup] SO [replacement avoided] diesel unit 3 $500 S500 In this case the hydro unit gets a capacity, avoidance credit for the diesel unit 1 as above, plus a deferral credit equal to the present value of all future replacements of unit 2. Having gone through this thought process, I would propose to simplify matters by referring to the assumed pattern of diesel replacements laid out above. This pattern has all diesels being replaced at years 6, 16, and 26 of the analysis. Under this assumption, there is sufficient life remaining in all diesel units for them to serve indefinitely as backup capacity, and whether a unit is needed or not for backup, its replacement is avoided forever when its energy production is supplanted by hydro. Thus, for this analysis, where all communities have existing diesel plants and we are not "ass %.+mui iy sigi L11IGc11 Il lUaa grovvtn, the only capital costs avoided are future diesel replacement costs for existing units. These costs are basically energy -related because diesels wear out with run-time, not calendar time. 3.5 Summary: Diesel Capital Cost: To summarize, I propose that hydro projects get no credit for capacity avoidance. They only get credit for deferral of replacement. The extent of the deferral depends on how much energy the hydro unit supplies. This model can be implemented as follows: November 18, 1996 Page 7 of 9 LOCHER INTERESTS LTD. RURAL ALASKA HYDROELECTRIC ASSESSMENT RURAL HYDRO ECONOMIC SCREENING CRITERIA 1. Express initial diesel capacity in terms of annual energy output (kWh/year) using the production factor of 0.35. Hence 1 kW of capacity = 3,068 kWh/year. 2. Compute the present value of avoided diesel replacement costs per kWh of annual energy displaced by hydro. 3. Apply this factor to the number of kWh of diesel energy displaced. 4. The Discount Rate and Load Growth 4.1 The Real Discount Rate: Economic theory tells us that the appropriate discount rate to use depends on who is providing the funds and what must be sacrificed to use the funds. Thus, the appropriate real discount rate ranges from 2% (the approximate real rate on a federal Rural Utilities Service 5% nominal loan) to perhaps 10% (the real return to the investors in an investor -owned utility). Somewhere in the middle of this ranee of investors lies the State of Alaska, for which I believe the long -run opportunity cost of" grants or subsidized loans is the foregone real return on the permanent fund. This has averaged about 7% between 1985 and 1995. In order to be most favorable to potential hydro projects, I propose to use a real discount rate of 2% for the screening analysis. 4.2 Load Growth: Although it is fair to say that most rural loads will continue to grow due to population growth, there is no way to make load projections at this stage of the analysis. I propose that we simply multiply the current load by a factor of 1.5 and use this as the ceiling on the amount of hydro energy that could be absorbed. This factor roughly approximates the case where load grows 2% per year and thus doubles in 35 years. This method of reconciling demand with hvrlrn n,,+ni i+ p.in;dq +k- r .4 t+...... __i:__ _r _ -.:+--•••-••-• •••iiYwIw v Ltl uk avviUQ UIG QIUILIQ.y IeJCIaIU[I of a hydro project simply because it seems to dwarf the load. Such a project might still be feasible based on the use of only a fraction of its potential output. 5. Summary of Proposed Procedure In summary, the major elements of my proposed procedure are: 1. Planning horizon = 35 years, load = 1.5-times current level„ real discount rate = 2%, real fuel price escalation rate = 1 %. November 18, 1996 Page 8 of 9 LOCHER INTERESTS LTD. RURAL ALASKA HYDROELECTRIC ASSESSMENT RURAL HYDRO ECONOMIC SCREENING CRITERIA 2. Net Economic Benefit = (Avoided diesel cost) - (hydro system cost) 3. Hydro system cost = hydro capital cost stated in 1996 dollars using Handy -Whitman 4. Avoided Diesel fuel cost = number of effective kWh provided by hydro times existing community -specific fuel cost per kWh sold. Effective kWh determined as carefully as possible from available coded data on seasonal availability, storage or lack thereof, etc. 5. Avoided Diesel nonfuel 0&M = number of effective hydro kWh times one half the average community -specific nonfuel operating cost per kWh. 6. Avoided Diesel replacement (capital) cost = number of effective hydro kWh times discounted stream of avoided replacement costs per kWh. Replacements avoided in years 6,16, and 26 at 3500AW plus S125/kW for units requiring emission control add-ons. Of course, several key parameters will be wired into the model, such as the discount rate, real fuel price escalation rate, and diesel capital cost per kW. By varying these parameters we can conduct sensitivity analysis on the entire set of hydro candidates. 6. References Colt, Steve, and Mark Foster, 1994. Electric Power Altematives for Thorne Bay. Prepared for Alaska Department of Community and Regional Affairs, Division of Energy. Anchorage: Institute of Social and Economic Research. June. November 18, 1996 Page 9 of 9 LOCHER INTERESTS LTD. RURAL ALASKA HYDROELECTRIC ASSESSMENT ECONOMIC EVALUATION PROCEDURE Rural Alaska Hydroelectric Assessment: Proposed Stage 2 Economic Evaluation Procedure prepared by: Steve Colt Institute of Social and Economic Research (sgcolt@aol.com) prepared for: Locher Interests LTD. and Slab of Alaska Department of Community and Regional Aiiairs Division of Energy November 1, 199e 1. Introduction In a previous memorandum I proposed procedures for a screening analysis of several hundred potential hydroelectric projects in rural Alaska. The screening procedure is designed to eliminate from further consideration projects that are clearly uneconomic. This memorandum proposes procedures for a more careful economic evaluation of a limited number of candidate projects (be^Neen 4 and 8, with 5 expected). There are three basic differences between the previous screening procedure and the prcocsed evaluation procedure that follows. First, the evaluation procedure will compare total costs with and without hydro. (The screening analysis looks at incremental hydro and avoided diesel costs). Second, the evaluation will be based on com. M,unity-specific parameters to a greater extent. Thirc, the evaluation will explicitly address the range of uncertainty surrounding the estimiated net benefits of each project. November 18, 1996 Page 1 of 10 LOCHER INTERESTS LTD. RURAL ALASKA HYDROELECTRIC ASSESSMENT ECONOMIC EVALUATION PROCEDURE 1.1 Methodology: Total Cost Comparison: The basic evaluation procedure is to compare the present value of total electric system costs without the hydro prciect to the present value of total costs with the prciect. In formal terms: NB = PVTC(diesel system) - PVTC(hydro system) where: NB = net economic benefits of hydro project PVTC(diesel system) = present value of total costs for the diese!-only system PVTC(hydro system) = present value of total costs for the diesel -plus -hydro system The total cost comparison is the most satisfying way to do the analysis since it avoids using "rules of thumb" to estimate incremental avoided costs, capacity credits, and other sometimes ambiguous elements. Instead, we concentrate on computing the total costs of running the electric system with and without the hydro prcject. The corncarison includes fuel, nonfuel OW41, and capital costs. 1.2 Using Critical Assumptions to Address Uncertainty: To take account of uncertainty, I propose a "critical assumptions" framework. For each project, the project team will make multiple assumptions about the following items that strongly affect the analysis: Cl: future price of diesel fuel (low, mid, high) C2: capital cost of hydro project (low, high) C3: real discount rate (low, mid, high) C4: effective energy capability of hydro project (low, mid, high) C5: load growth (low, mid, high) I _L a. � � of course open to recommendations for changes to this list. In some cases, it may be defensible to make only one assumption for items C2, C4, and C5. For example, if the load is already sufficient to absorb all hydro energy, then uncertainty about load growth (C5) is basically irrelevant. Similarly, the hydro capital cost and energy capability may be known with a high degree of certainty. However, given the low cost of running the model many times, there is no reason not to entertain multiple assumptions for these values. I propose to combine the critical assumptions in the following ways to generate results about the potential economic benefits of each hydro project: November 18, 1996 Page 2 of 10 LOCHER INTERESTS LTD. RURAL ALASKA HYDROELECTRIC ASSESSMENT ECONOMIC EVALUATION PROCEDURE 1. Probability Distribution of Outcomes: A combination of particular choices for each critical assumption forms a scenario. When run through the cost model, each scenario leads to a with -hydro system cost, a without -hydro system cost, and a net benefit result. If probabilities are assigned to each critical assumption then each scenario also has a probability attached to it. By considering every possible scenario, we construct the probability distribution of the net economic benefits. 2. Sensitivity to Key Parameters: The probability distribution of outcomes gives the reduced form or "bottom line" results of simultaneous variation in the critical assumptions. Sensitivity analysis provides further insight into why the net benefit varies by isolating the effects of changes in a single assumption, such as the pric= of diesel fuel. The sensitivity analysis is presented by showing a "base case" scenario and several "sensitivity case" scenarios. 3. Break-even Analysis: Break-even analysis is another way of doing sensitivity analysis: Here the net benefit is held constant and we show graphically what combinations of particular parameters are necessary to achieve that net benefit. Break-even analysis is particularly useful for two reasons. First, it can eliminate the need for costly further investigation by snowing that none cf the plausible values for some parameter are sufficient to make the project feasible. For example; engineering analysis might be able to resolve whether the effective stream flow, is equal 2 cfs or 4 cfs. But break-even analysis might show that the minimum required flow is 8 cfs. In this case the resolvable engineering uncertainty is irrelevant and not worth further investigation. The second advantage of break-even analysis is its Iona "shelf life." Because break- even relationships are shown graphically, each one essentially contains an infinite number of scenarios. Thus a decision -maker can return to a break-even analysis long after it is written and long after the critical assumption values that make up a probability or sensitivity analysis are obsolete. Although these three different ways of presenting the results may seem partly rPrjI inr'4=nf nr r'mmnlav n11 name inncn.-) fin nnr+�{�ininr� �L..� .14.. C.. ...-F:....I- - �+�.+..-.....� Call al G ua�cU on combining ltg. the r esullJ IUr pal li-- lal Jcei GI IOJ. Once the model has been set up for any one of these methods, the additional time and effort to perform the other two is minimal 1.3 Contents of This Memo: The remainder of this memo focuses on specific procedures for computing the present value of electric system costs with and without the hydro project. Section 2 covers load growth and the real discount rate. Section 3 covers diesel system costs without hydro. Section 4 covers system costs with hydra In Section 5, 1 briefly explain the logic of the cost model, to give a sense of the level of detail to be considered. November 18, 1996 Page 3 of 10 LOCHER INTERESTS LTD. RURAL ALASKA HYDROELECTRIC ASSESSMENT ECONOMIC EVALUATION PROCEDURE 2. Time Horizon, Load Growth and Discount Rate 2.1 Time Horizon: The time horizon for each community will be 35 years, unless project team engineers can make a convincing case for an alternative, based on the probable life of the hvdro project. 2.2 Load Growth: I propose to assess probable load growth for each study community by locking at the Past 5 years of actual data from Power Cost equalization (PCE) community filings, the past 5 years of population growth, and by performing a very brief assessment of future economic and population growth. From this I will generate three critical assumptions for load growth (low, mid, and high). The low case will be close to 0% per year. The mid case will be close to the 5-year historical trend, which is likely to be near 1 %. The high case is likely to be roughly double the mid -case. Note that there is little bias intrcduc=d by assuming overly hick load growth if the load becomes suffic;;,nt to absorb all hydro energy early in the study period. 2.3 Real Discount Rate: I propose to use three discount rate values for each study community, based on an assessment of the most likely sources of utility capital generally and hydro project funding in particular. For example, a very small community may be judged a likely candidate for low -interest loans or state assistance. In this case I would set the Icw value at 00,10 (to approximate the cost of a subsidized state loan cr combination cf grants and loans); the mid value at 2% (to approximate a federally subsidized Rural Utilities Service loan at 5% nominal, less 3% inflation), and the high value at 8% (slightly above the real return on the permanent fund). The highest rate I would consider would be 10%, for communities where a nrivate investor -owned utility operates the diesel system and would Iecically build the rhydro project. 3. Diesel System Costs 3.1 Diesel System Operating Parameters: Diesel Unit Lifetime: 60,000 operating hours, run at 6,000 hours per year, giving 10 years as the effective lifetime. November 1 S, 1996 Page 4 of 10 LOCHER INTERESTS LTD. RURAL ALASKA HYDROELECTRIC ASSESSMENT ECONOMIC EVALUATION PROCEDURE Diesel Production Factor: 38% of continuous rated power (Example: a 100 k')v cenerator would produce 100 * 8766 ' 0.35 = 306,810 kWh per year). The diesel production factor may be adjusted after cor,suitation with local utility managers in each community. Diesel Station Service: Determined for each community based on consultation with utility managers. Station service is added to energy requirements at the distribution busbar to get required gross generation. Peak vs. caseload Production: Eecause "peaking" units sometimes have different efriciencies than "taselead" units, the cost model contains an aicorithm for determining how much annual energy is produced by peaking units. The alcorithm is based on each community's annual load factor. 3.2 Diesel System Fuel Cost: I propose to use actual fuel prices and ef`iciencies from recent PCE filings for each study community. We will be careful to use compatible measurements of generation and efficiency so that the model accurate!y reproduces the current actual total cost of fuel for the current load. I propose three critical assumptions about future growth of real diesel fuel prices: Low 0% per year Mid 0.5% per year High 1.5% per year The initial price will be the average of actual prices for the past 5 years. 3.3 Diesel System Nonfuel O&M Cost: PCE data provide current overall nonfuel operating costs by community. These costs ranee, roughly, from about 5 cents per kWh (some AP&T communities) to 25 cents per kWh for mainstream systems (both THREA and AVEC) to above 50 cents per KWh for November 18, 1996 Page 5 of 10 LOCHER INTERESTS LTD. RURAL ALASKA HYDROELECTRIC ASSESSMENT ECONOMIC EVALUATION PROCEDURE some very small systems. The key question that arises in projecting future ncnfuel 0&M is to what extent these costs vary with production. A detailed examination of Thorne Bay nonfuel 0&M costs suggests that about 60% could be classified as variabie and increasing with higher energy production, while about 40% are complete!v fixed over some significant range of load growth and diesel production. The expenses '.nat vary with capacity (chiefly property taxes and insurance) are trivial. I propose to briefly examine each community's most recent annual PCE filing to mak-e a judgment about how much of their nonfue! 0&M seems to vary with additional e^ercy production. This will lead to a variable O&M cost parameter (S per kWh). 3.4 Diesel System Capital Cost: Mark Foster and I have been looking at the installed capital cost of actual diesel units. Mark's latest discussion with vendors indicates that within the under-7 00 kW engine size class, there is a wide range in cost depending on unit size, even be'cre considering possible emission control equipment. Surprisingly (to me), the avenge cost (S per kW�l seems to increase when mcvinc from the smaller in -line 6 engines to a V-12 configuration. I propose to consult with utility management in each study community to for„ a ii� r, �+ iF, nr� ri^4 i�ni+ •�Q I r^fir m of n r nianarr. r,-6 r,api'^I judgment about the appropriate t,,,1t sizes, likely re,,,e,,,e,,,s, a.,d Ier,�u..,,,e ,� mac. tcl costs to use in the model. The present value of all future diesel replacements is determined from a Giesel generation expansion plan that will be determine - within the model to satisfy the ne=cJs for replacement and new capacity. 4. Combined Hydro -Diesel System Costs 4.1 Hydro Capital Cost: I propose to use two critical assumptions for hydro capital cost: low and high. Trie project team engineers will determine these costs based on uncertainties about t construction costs and (possibly) project desion factors. The hydro capital cost will be input to the model as a series of annual construc:icn outlays to account for the interest during construction that accrues when constructicn takes more than one year. Associated transmission will be included in the estimates of hydro capital cost. November 18, 1996 Page 6 of 10 LOCHER INTERESTS LTD. RURAL ALASKA HYDROELECTRIC ASSESSMENT ECONOMIC EVALUATION PROCEDURE 4.2 Annual Hydro Maintenance: The project team engineers will provide an estimated annual maintenance cost for each candidate project based on its size and design characteristics. 4.3 Effective Hydro Energy Capability: The effective hydro enerey capability takes into account factors such as seasonal availability, likely coincidence of output and load, and the combined forced unavailabiiity of production and transmission facilities. I propose to make this a critical assumption with three values (low, mid, and high) if the project team engineers believe there is substantial uncertainty about this quantity. I want to use three values because it is natural to assume a mean value as the mid case for hydrologic factors such as stream flow. 4.4 Generation Expansion Plan and Diesel Capital Cost: A realistic diesel generation expansion and replacement plan will be deve!cped for each combination of load growth and effective hydro energy capability. In past studies I have developed these plans manually but it should be straightforward to have the model generate the plan based on diesel run-times, comparison of capacity vs. lead, assumptions about the firm capacity (if any) of the hydro project, etc. The diesel rep lacement/expansion plan determines the timing and present value of all diesel capital costs. 5. Mechanics of the Cost Model 5.1 Model Description: I propose to use a utility system cost model originally developed to assess coal power plants in Nome and Kotzebue (Mitchell and Colt, 1990) and later refined to study energy options for the North Slope Borcuch (Colt, 1992) and power generation options for Thorne Bay (Colt and Foster, 1994). The model is implemented on a spreadsheet and has no simultaneous elements. That is, it proceeds strictly forward through time. It is an annual model, although seasonal factors are incorporated in the calculations of "peaking energy" and the effective hydro energy capability. It also has no internal probabilistic or °monte carlo" elements. Once a set of critical assumptions is specified, the model produces a unique calculation of system costs. The model basically determines which diesel units must run, and for how long, to meet the load after deducting any assumed contributions from hydro units. Some diese! units November 13, 1996 Page 7 of 10 LOCHER INTERESTS LTD. RURAL ALASKA HYDROELECTRIC ASSESSMENT ECONOMIC EVALUATION PROCEDURE can be designated as "must -run" for maintenance purposes, and some diesels can be designated as "peaking units," with different fuel efficiencies from the "baselcadtt units. Once the units and their run-times have been determined, it is a matter or simple arithmetic to compute annual fuel costs and nonfuel O&M. To compute diesel capital costs, the model keeps track of peak load requirements and compares them to available diesel capacity after scheduled retirements (which occur on a ten-year cycle). New capacity is added when needed to maintain reserve maroins and a capital cost is recorded for that year. Hydro capital cost is recorded as the actual series of annual cash outlays incurred for construction. Finally, the stream of annual costs is discounted and added to get the net present value of providing electric service for the study period. To conduct the analyses referred to in the introduction, the data table, scenario manager, and coal -seeking tools of the spreadsheet software are used to quickly generate many model runs and to accurately record the output. In addition I will write several small programs in Visual Basic (the Excel macro language) to further automate the process of generating scenarios and recording results. 5.2 Presentation of Results: There wiil be three basic presentations for each community in addition to written discussion. The probability analysis will be shown as a graph of the probability density function for the net benefits of the hydro project. This gives a fairly intuitive picture of the likelihood that the project is feasible as well as a sense of how wide the range of uncertainty is. An example is shown in Figure 1. The sensitivity analysis will be shown in tabular form with a bar graph emphasizing several particularly "interesting" scenarios. The ne break-even analysis will be presented as a series of graphs showing various combinations of key parameters that produce some given level of net benefit. An example, drawn from the Thorne Bay Alternatives study, is shown in Figure 2. November 18, 1996 Page 8 of 10 LOCHER INTERESTS LTD. RURAL ALASKA HYDROELECTRIC ASSESSMENT ECONOMIC EVALUATION PROCEDURE 0.18 0.16 0.14 >, 0.12 1 — 0.1 R 0.08 0.06 0.04 0.02 0 Figure 1: othetical Probability Distribution of Net Benefits Probability Distribution of Net Benefits N r- C r' N c'') c to (D r- q G7 � I amount of net benefit ® prcbabiiity I� Figure 2: Example of Break-even Presentation I Breakeven Combinations of Net MSW fuel cost and net Wood Waste fuel cost for low diesel/mid load and initial MSW volume = 3,650 tons so 70 -- ------ -------------------------------------------------- ------------------------ 60 --------------=------------- 60--------- -------------------------------------------------- Combinations - - - - - - Combinations in this area G 50 ---------------- - are more cosily than diesel------------- R40 --------------------------------------- 0 30 3 Combinaticns in this area a20 -are less costly than diesel --'-----------'-------_- 10 -------------I i N 0 C.7 z 0 -100 -80 -60 '0 -10 Net Cost of MSW Fuel (51ton) i November 18, 1996 Page 9 of 10 LOCHER INTERESTS LTD. RURAL ALASKA HYDROELECTRIC ASSESSMENT ECONOMIC EVALUATION PROCEDURE d 6. References Colt, Steve, and Mark Foster, 1994. Electric Power Alternatives for Theme Bay. Prepared for Alaska Department of Community and Regional Affairs, Division of Energy. Anchorage: Institute of Social and Economic Research. June. Colt, Steve, 1992. North Slope Borough Energy Assessment: Chapter 5: Economic Evaluation. With Robert Schutte and Alan Mitchell. Prepared for the North Slope Borough. July 1992. Mitchell, Alan, and Steve Colt, 1991. Economic Analysis of Coal -Fired Power Plants to Serve Nome, Kotzebue, and the Red Dog Mine. Prepared by Analysis North for Arctic Slope Consulting Group. September 1991. November 13, 1996 Page 10 of 10 LOCHER INTERESTS LTD. Rural Alaska Hydroelectric Assessment: Stage 2 Economic Evaluation of Hydroelectric Projects in Atka, Hoonah, Old Harbor, and Unalaska prepared by: Steve Colt Institute of Social and Economic Research (sgcolt@aol.com) prepared for: Locher Interests and State of Alaska Department of Community and Regional Affairs Division of Energy July 15, 1997 1. Introduction This memorandum summarizes the economic evaluation of four candidate hydro projects: Chuniisax Creek, serving Atka Gartina Creek, serving Hoonah call unnamed lalilcu cieCR, serving lg VIU fldI UUr Pyramid Creek, serving Unalaska For each site, the evaluation procedure compares the total costs of electric power with and without hydro over a 35 year planning period extending through the year 2032. The analysis is based on community -specific parameters to a limited extent, and it explicitly addresses the range of uncertainty surrounding the estimated net benefits of each project by looking at many different combinations of five critical assumptions affecting project economics. The evaluation procedure was summarized in a previous memorandum and for the most part has been carried out exactly as proposed. The major difference is that only Rural Hydro Economic Evaluation 7/15/97 page 1 one assumption about hydro output is used, rather than several critical assumptions. However, the annual hydro maintenance cost has been introduced as a critical assumption, so there are still five critical assumptions forming each scenario. The rest of this memo is organized into four sections, one for each candidate site. An Appendix provides further notes on model mechanics. 2. Atka (Chuniisax Creek) 2.1 Baseline Data and Assumptions Total Atka energy requirements served by the public utility (net of station service) were about 275,000 kWh/year in 1996. The system peaks in summer due to fish processing activity, which largely provides its own power. Otherwise the load is fairly constant. The utility -served load declined at an average rate of 4.4%/yr between 1992 and 1996 as fish processing load was taken off -system. The fish processing load is not considered explicitly here. The hydro project would provide 520,000 kWh/yr, which is more than enough to meet current connected loads. A hydro capacity of 80 kW listed in the project database is treated here as firm, which allows some potential deferral of diesel capacity. Figure 1 shows hydro output compared to current diesel generation. 70,000 60,000 50,000 40,000 3 30,000 I Y 20,000 10,000 I Figure 1 Atka Hydro output vs Diesel Generation hydro diesel', m E mm m cue v�i c °c � E The current diesel system consists of two diesel generators with a low average efficiency of only about 8 kWh/gallon, measured net of station service. In addition, the Rural Hydro Economic Evaluation 7/15/97 page 2 price of diesel fuel is high at an average of $1.23 for the 1992-96 period. In 1992 the price climbed to $1.49. Table 1 summarizes the baseline data and assumptions for Atka. Table 1: Atka Baseline Data and Assumptions Atka I I ase me Data and AssTm--ptions I I ! Energy Requirements 1 ActualActual I o e I I CY95i i enera ion yr i ess: 6tation Svc 2.5%1 1= us ar Requirements yr 1 254I 1 I eaK Loadat a ion I 160 ILoad actor I I Peak oad (at busbar) I I I I Fuel rites an Oency j ! Total Fuel Cost - I ! I l Total Uallons used GY92-96000 gal I / I verage Price -INFo-d-e-171997 I galI Base Price I ! I 1.231 vg us ar EfficiencykWh/gal IModel 1997 Base Efficiency I I I I I 1 Cost Ot Capital (See Critical Assumptions.]I i I I ! I I Diesel pera ing egime kVV I max hours 1 nitia um I itetime I Iperyr I ours Hours Unit eere I I6,000 1 12,000 60,000 Unit New Diesel 125I , Unit eere ! New Diesel Units I unit 3 must -run time I hrs 1 I I I New iese os I ► I ew D iese ape a os I I I INew Diesel Efficiency IkVVh/gal 1 11.0 1 omposi a Overhaul cost Vhr 1.00 j ter nonfuel variable cost I I i Hydro Operating Parameters j Hydro E—ne-rgy--Capablilty I MVVh1yr 1 520 lt=tTective Firm Capacity I kW..I I Hydro avai a M o I I95.0%1 Hydro Annual Maintenance 1 yr 1 I1 i,uuu I Rural Hydro Economic Evaluation 7/15/97 page 3 2.3 Atka Critical Assumptions Table 2 summarizes the values used for the five critical assumptions. Below each assumption value is the probability assigned to that value for the purpose of building the overall probability distribution of results. Load growth, which is important in this community because hydro output exceeds load, ranges from 0% to 3% per year. Real dollar fuel price growth ranges from 0 to 1.5%. Note that the high value of 1.5% is actually rather extreme since perhaps 75% of the delivered price consists of transportation and refining costs rather than the nonrenewable crude oil itself. The real discount rate ranges between 0 and 5%, reflecting a range of possible capital subsidies. The high value (5%) is intended to reflect tax-exempt bonding or some other form of quasi -public financing. The low hydro capital cost reflects a "community -built" approach where the community serves as the general contractor. The hydro maintenance amounts are incremental to current diesel O&M costs.' The low value of zero assumes minimal materials needs2 and the use of existing diesel system labor, which is plausible because the diesel units would be turned off most of the time, at least in the early years. Table 2: Atka Critical Assumptions Critical Assumptions pro i i ies below each)I I I LOW Mid Fri-g Load rowtff- Ul Energy Reqts and PeakGrowth I o yr 0.0%i 1.0%i 3.0% I0.251 0.501 Fuel rice Growth . 1 0.501 I I ZT Keal DiscountRate 0.0%1 Z. U %o U.LC I U.0U U.LS I I I Hyciro Capital Costj I76ti,000 1,200,000 not use Hydro Net Maintenance j yr U I 10,U00 not net o iese I0.501 0.5UI use 'Diesel overhauls are treated in this analysis as an amortized capital cost, expressed as a fixed amount per hour of diesel unit running time. The hydro project gets no explicit credit for reducing the cost of tube oil and other diesel -system materials that are quasi -variable with energy output: Using a very low hydro O&M cost gives implicit credit for offsetting such costs to some extent. Rural Hydro Economic Evaluation 7/15/97 page 4 2.4 Atka Results Range of Results. Under mid -range assumptions, the hydro project essentially breaks even. Under the most pessimistic set of assumptions, the net present value of net benefits is-8534,000. Under the most optimistic values of the critical assumptions, the project has positive net benefits of more than $1.8 million. Table 3 summarizes this range of results. Table 3 ResultsSummary: Atka Net 5enefits ot Hydro, NPV over 35 years I mid -range I most most assumptions I pessimistic optimistic ase name I mmmmm j 11hrrim hhIII Critical assumptions: Load Growtha o l o 1C2 - TUAT Price Growth 0.5%i U.0%1 0 Real iscoun ate 1 o I-77 o f o Hydro Capital Cost : Hydro Net Maintenance 10,000 10,000I ResuIFS7NPV,- I I I lese - n y System Cost1 I 1 Dies—eFFUel1,1Ub,W9 IL)iesel nonfuel pera Ing 223,4351 IDiesel Capacity Total os without y ro 3,362,BU5— I I I I With Hydro System Cost lese ue Diesel nonfuel pera Ing 26,856 Diesel apace I Hydro Cons -IL riJG1-On l,1 /b,411 I 1,142,657 766,000 y ro am enance IZ4b,UbbI a, Total os with y ro I .Net Benefitof Hydro Project , Probability Distribution of Results. When all 108 possible combinations of assumptions are considered with their associated probabilities, the resulting probability distribution of net benefits is largely positive. Only 28 out of the 108 combinations of assumptions produce negative net benefits. The cumulative probability of these 28 negative combinations is only 25%. Therefore, if the probabilities attached to the Rural Hydro Economic Evaluation 7/15/97 page 5 assumptions are accurate, there is a 75% chance that the project will produce positive net benefits. The probability distribution is shown in Figure 2. 0.12 I 0.1 0.08 i — 0.06 0 0.04 0.02 0 Figure 2 Atka Probability Distribution of Net Benefits � N r ei IQ m o ch to r� 0 0 0 0 0 0 .- Net Benefits (million 19965) Break-even and Sensitivity Cases. ® prob Table 4 reports several break-even results. Each starts with generally pessimistic assumptions and considers how much a particular parameter would have to change in order to bring the net benefits up to zero. The first section shows that with zero load and fuel price growth and a high real discount rate of 5%, the capital cost of the hydro project would have to be below about $640,000 to provide positive net benefits. The second section considers fuel price escalation. With all other assumptions taking pessimistic values, real fuel prices would have to increase at 4.8% per year to produce break-even results. But with a lower discount rate of 2% real, only 1.5% fuel price growth is required. This result underscores the fact that fuel price growth and the discounting process largely cancel each other out when computing net benefits. The final section considers load growth. There is no amount of steady load growth that can overcome the combination of all the other pessimistic assumptions. Additional analysis (not shown on the table) shows that an initial one-time increase of 100 MWh Rural Hydro Economic Evaluation 7/15/97 page 6 (about 40% of current load) per year is similarly not sufficient, by itself, to get to break- even economics. Table 5: Atka Break-even Cases Hydro Capita Cost-7 I ni is oa rue I nitiai Initial reaKeven jCase growt I growl I rate CaOltal st Net Benerits I Capi-t-aTC—ost 1IIhrnM 0o of a639,205 Fuel rice thscalation nitiaoa Initia I Initial reaKeven Case I growl ue growl crate I CapitalCost I Net ene i s ue growl mm j o 0 0. of I ( o mmm I o 0 0' 0 Load Growth —load ni is initial Initial rea even ase growl ue growl I rate I Capital Cost I et Bene i s ca growl mm U.0% o. Ho-f 5. of 1, I (53 one. I mmm 0.0%j a ( o Discussion. Assuming the probabilities used here are accurate, there is a 75% chance that the project will be economic. Since it is unlikely that fuel prices will increase more than modestly, the surest way to pin down a positive net benefit would be to secure financing in the 2% to 3% (real) range and/or reduce the hydro capital cost to the low end of the assumed range. Simply adding load to the system is not sufficient to overcome high hydro costs and low diesel fuel prices. Rural Hydro Economic Evaluation 7/15/97 page 7 3. Hoonah (Gartina Creek) 3.1 Baseline Data and Assumptions Total Hoonah energy requirements (net of station service) were about 4,591,000 kWh/yr in 1996. The system peaks in winter and the annual load is fairly constant. The load grew at an average rate of 4.1 % between 1992 and 1996, but further load growth is not very important to this project's economics because the current load can already absorb all projected hydro output. The hydro project would provide 2,170,000 kWh/yr, which is significantly less than current connected loads. None of the capacity from this project is treated as firm. Figure 3 shows hydro output compared to current diesel generation. 450,000 400,000 350,000 300,000 250,000 200.000 150,000 100.000 50,000 Figure 3 Hoonah Hydro Output vs Diesel Generation hydro �— diesel co a m Z = aa)i o (D w E m E M U) C c -o The current diesel system consists of three diesel generators with a high average efficiency of about 14 kWh/gallon, measured net of station service. The price of diesel fuel is relatively low at an average of $0.88 for the 1992-96 period. Table 6 summarizes the baseline data and assumptions for Hoonah. Rural Hydro Economic Evaluation 7/15/97 page 8 Table 6: Hoonah Baseline Data and Assumptions oona I I I I Baseline Data and Assumptions I I I I ! nergy Requirements I 1Actual I ctua j o e I I ICY95IGY96I1997 1 Generation I Yr I less: Station Svc 2.5%1 o I 1= us ar Requirements IMWhJyr 1 I4,591I 4,591 I I IP eaK Loadat Station) IKVV Load actor Peak oao at busbar) IMonthly load profile 1 ractions are on hyaro outputsheet] j I Fuel Prices anTEfficiency ITotai FuelCost I souu I I ITotal Gallons used CY92-96000 gal 1,538 1 verage Price ga 1 I 1 iModel 1997 Base Price I vg usoar mciency I 9a I i 14.11 IModei 1997 base Efficiency I I I I I I I I I Cost ot Capital Loan Balance 1211311196I i 1 I IRUS interest pai Implied nominal interest rate I I I I I Diesel Operating Regime IKVV I ax ours IInitial Cum Lifetime I II per yr I Hours Hours Unit New 1,000 kW M7—I---FMO I Unit at 3512 I I 14,000I Unit a (backup) D,uuu 1 0I 60,000 New Diesel Units Unit must -run time I rs 80 Rural Hydro Economic Evaluation 7/15/97 page 9 3.3 Hoonah Critical Assumptions Table 7 summarizes the values used for the five critical assumptions. The assumed probabilities below each assumption value are the same as those used for other communities. Table 7: Hoonah Critical Assumptions I I Low I Mid High Load Growth I I I Energy Reqts and Peakrowt I o yr I Q.U%l. o 0- not critical Hoona — oa exceeds hydro) i 0.251 I I Fuel rice Growth 0. U U.b%i o I0.2b 0 bol 0. I Real DiscountRate U. U 2. U % b. U N i I I Hydro Capital CostI19963 b.t4U,UUU 8,4ta,000of I0. U. bU Used I Hydro Net Maintenance I yr 29,000 I 69,000 of net or oiese I j I Used Load growth is not important for this project. The real discount rate ranges between 0 and 5%, reflecting a range of low-cost financing options. The utility serving Hoonah (THREA) is currently debt -financed with 2% nominal debt from federal government sources, making its current average real discount rate about zero. The range of hydro capital costs reflects different construction assumptions and features. The hydro maintenance amounts are incremental to current diesel 0&M costs.3 The low value of $29,000 is derived by deducting a $40,000 credit for using existing labor. This assumption requires further scrutiny because the diesel plant would not be turned off with this project. 3.4 Hoonah Results Range of Results. The project has negative net benefits under all sets of assumptions. Under mid -range assumptions, the hydro project has a negative present value of net benefits of about -$6.6 million. Under the most pessimistic set of assumptions, the net benefits are -$7.1 million Under the most optimistic values of the critical assumptions, the project still has negative net benefits of about -$1.7 million. Table 8 summarizes this range of results. 'Diesel overhauls are treated in this analysis as an amortized capital cost, expressed as a fixed amount per hour of diesel unit running time. Rural Hydro Economic Evaluation 7/15/97 page 10 Table 8 ResultsSummary: Hoonan e ene i s o y ro, over years I I mi -range I most I most I I assumptions I pessimistic I optimistic ase name I mmmmm IIhmm hnill Critical assumptions: 1 oa rows I a I0 Uo : ue rice rowt I . o of 5�0 I ea iscount Rate 2.0%1 5.0%1 0. Hydro-C-a—pitai Cost I 8,470,000 jHydro Net Maintenance 69,OOU 1 69,000 Results: I I I less - n y ys em os I I iese ue 18,579,692 1 4,757,867 20,206,160— ILAesel nonTuel Operating I893,741I 1Diesef uapacity1 1723,214 Total os without Hydro j , r, 6,061,279 23, i 18,469 I I I I Wit n Hydro Systern CostI I iese ue I Imesel nonfuel pera ing 893,7411 I-,262,M-A-- Diesel Uapacity1 I I I I y ro ons ruc ion 1 y ro Maintenance I I otal ust with Hydro 1 1 I I e ene i o y ro Project I o I I ) (parentheses indicate negative numbers) I I I Probability Distribution of Results. When all 108 possible combinations of assumptions are considered with their associated probabilities, the resulting probability distribution of net benefits falls entirely in the negative benefits region. The probability disc ibu iol lI Is ai own in r-igure 4. Rural Hydro Economic Evaluation 7/15/97 page 11 0.16 0.14 0.12 0.1 0.08 a 0.06 0.04 0.02 0 Figure 4 Probability Distribution of Net Benefits: Hoonah ............... III Eli � -. C7 M N !- '7 (D 7 � 7 C7 M N N Net Benefits (million 19965) Break-even and Sensitivity Cases ® prob Table 9 reports some break-even results. The first section shows that even with combinations of fuel price escalation and lower discount rates, the capital cost of the project would have to be substantially reduced to break even. The second section considers fuel price escalation and shows that even with most optimistic assumptions about the discount rate and construction costs, real fuel prices would have to increase at more than 2.8% per year to achieve a break-even result. Rural Hydro Economic Evaluation 7/15/97 page 12 Table 9: Hoonah Break-even Cases Hydra, Capital CostI I I Initial ue I nna ni is reakeven Case I g rowth I rate Capital Cost et enents api a ost immm a .5 1 . o o,i i o Im % o 6,t4O,OOO,1 t, �m m m 1.5%1 2.0%1,r i I I I I Fuel rice hscalation Initial -Initial Initial --Tr-eakeven Case ueI growl drate I Capital Cost I et enents rue gr-o-w—T— imnill 1.0%1of 6,740,000,/ o Im h mm a oI I , -)To Im mmm I bulb 1 2. U w1b1 o Discussion. There is no set of plausible assumptions that produces positive net economic benefits for the Gartina Creek project. Rural Hydro Economic Evaluation 7/15/97 page 13 4. Old Harbor (Unnamed Creek) 4.1 Baseline Data and Assumptions Total Old Harbor energy requirements (net of station service) were about 713,000 kWh/yr in 1996. The system peaks in winter and the annual load is fairly constant. The load grew at an average rate of 2.1 % between 1992 and 1996, and further load growth is important to this project's economics because the current load cannot absorb all projected hydro output. The hydro project would provide 2,664,000 kWh/yr, which is significantly more than current connected loads. Based on recent studies of streamflow and the small amount of streamflow diverted to the project, 220 kW of capacity from this project is treated as firm. Figure 5 shows hydro output compared to current diesel generation. Figure 5 Old Harbor Hydro Output vs Diesel Generation i 450,000 400,000 350,000 300,000 s 250,000 3 200,000 150.000 100,000 50,000 hydro diesel T C E E 2 m N ° c The current diesel system consists of three diesel generators with a high average efficiency of about 13.3 kWh/gallon, measured net of station service. The price of diesel fuel is high at an average of $1.27 for the 1992-96 period, due to the need for river transport. Table 10 summarizes the baseline data and assumptions for Old Harbor. Rural Hydro Economic Evaluation 7/15/97 page 14 Table 10: Old Harbor Baseline Data and Assumptions Uld Harbor I ► Baseline Data and Assumptions I ► I i I I I Energy Requirements I Actual ctua I ode ICY90 UY96 1997 Generation j Syr 1 1less: Station 6vc r o I I 3 1= usbar equiremen s I MWhyyr 713I 713 I I PeaK LoaETaTM—tion)I 1551- Load factor Peak oad (at busbar� I I I uei Prices and Efficiency j ITotal FuelCost - I jVotalllons used CY92-96 j ga I I277 j verage Price i gal1.271 l Model Base rice j ( 11.211 vg 61 ar f iciencykWh/gal I I 1 iModel 1997 Base Efficiency I i I13.21 Cost o api a Isee critical assumptions iese pera mg egime IKVV I ax hours 11nitial Uum I Lifetime I I Iper yr j ours I ours jUnit Cummins LTTI 0I142 I I ni . at 3306197i -Cat-33G6—I197 j Unit 3: 6,000 UI60,000 I New Diesel Units 2 � 0 6,000I IUnit must -run time h rs j80 I I New Diesel Cost New Uiesel CapitaMost j ew iese iciency I—KWn/gal13.2 1 omposi a Overhat os r I IOther nonfuel variable cost I VkWh I I I Hydro Operating Parameters I I l Hydro nergy apa i i I yr - Hydro ective apace I kW lHydro-availabiFity % 95.0%1 l Hydro Annual Maintenance I yr I I40,000 1 Rural Hydro Economic Evaluation 7/15/97 page 15 4.3 Old Harbor Critical Assumptions Table 11 summarizes the values used for the five critical assumptions. The assumed probabilities below each assumption value are the same as those used for other communities. Table 11: Old Harbor Critical Assumptions I Low I Mid I -High Load Growth I I I Energy Reqts an eeaK GrowulI o yr 2. 0 ,01 0 I I I I 5I0.25 I I I I Fuel Price Growth 0.0%1 U.11,o0.251 l 5 0 .o I I I I Real DiscountRate U. U 2. U,01 0 0.251 .5 I I I I HydroCap-i a osT not •5 U 1 0.5U 1 use Hydro Net Maintenance yr U I �5, not Inet or diesel 0_t)o. 50 used Load growth is important for this project. Growth has averaged 2.1 % from 1992-96, but load declined during two of the four years. The real discount rate ranges between 0 and 5%, reflecting the tax-exempt status of the utility, AVEC. The low hydro capital cost reflects a "community -built' approach where the community serves as the general contractor. The hydro maintenance amounts are incremental to current diesel 0&M costs.4 The low value of assumes use of existing labor. This assumption is plausible because the diesel plant would be essentially turned off all the time. 4.4 Old Harbor Results Range of Results. The project has positive net benefits under most sets of assumptions. Under mid -range assumptions, the hydro project has a positive present value of net benefits of about $440,000. Under the most pessimistic set of assumptions, the net benefits are -$1 million. Under the most optimistic values, the project has substantial positive net benefits of about $5.3 million. Table 12 summarizes this range of results. `Diesel overhauls are treated in this analysis as an amortized capital cost, expressed as a fixed amount per hour of diesel unit running time. Rural Hydro Economic Evaluation 7/15/97 page 16 Table 12 Results ummary; Uld Harbor Net Benefi o y ro, over years I I I I I mi -range I most 'Imost I I assumptions I pessimistic I optimistic ase name I mmmmm I mm I hl Gritical assumptions: LOaCI Urowtho I. Uo f o ue nice GrowthI o f o o eaDiscount Rate o I o I o I y ro api aCost I yoro Net Maintenance 25,000 2�,QQO Results: I I Diesel -Only ys em os 10 iese ue I ,5e I iese non ue pera tng iese a p a c i ty 236, UI 107,009 fotal Gostwi ou y ro I I I I � VVILII nydro bystern CostI j less tie I67,329 65,405 675- juiesel nonfuel pera ing Diesel apaci I y ro on 1,960,784i l y ro maintenance Total os wi y ro I 2,649,418 2,3 58,3 i 7I I I e4TI- belleut or Hydro Projec I I T (parentheses indicate negative numbers) Probability Distribution of Results. When all 108 possible combinations of assumptions are considered with their associated probabilities, the resulting probability distribution of net benefits falls almost entirely in the positive region. Net benefits are negative in only 20 out of 108 combinations, with a cumulative probability of only 15%. As the probability distribution shown in Figure 6 indicates, there is an 85% probability of positive benefits if the individual assumption probabilities are accurate. Rural Hydro Economic Evaluation 7/15/97 page 17 Figure 6 Probability Distribution of Net Benefits: Old Harbor 0.14 0.12 0.1 0.08 :o 0 0.06 a 0.04 0.02 0 O e— tD N 00 Ul I. C7 O Net Benefits (million 1996$) I®p or Break-even and Sensitivity Cases Table 13 reports some break-even results. The first section shows that even with modest load growth, flat fuel prices, and a high discount rate, the break-even capital cost is essentially equal to the low critical assumption value of $1.4 million. With high capital costs and low loads, however, the required increases in fuel costs are quite high, given that most of the delivered cost of fuel in Old Harbor is due to transportation expense. Table 13: Old Harbor Break-even Cases Hydro Capita Cost I I I I ni is oaI fuelI Initial Initialrea Feven Case gro I growt I crate api a os et ene its capital Cost 111hrnm 1.u%1 0.071 5.01% i , iminnim o 01 o(680,298) Irnhhmm o �o 0 I I I Fuel rice sca a ion I I I I Initial oaInitial Initial BreaKeven ase growth fuel growth rate 1..Uapital Cost I et Benefits ue gro 111hrnm I1. 0 77 o 5. of 4.47 Im mm o 0 01 a 111 mmm 1. UU/0 o .U"o I o Rural Hydro Economic Evaluation 7/15/97 page 18 Discussion. The Old Harbor analysis shows that under a wide range of assumptions this project is economic. In addition, since the project has substantial excess energy production at zero marginal cost, any immediate and substantial increase in loads, such as off-peak heating or fish processing, would dramatically improve the economics further. Rural Hydro Economic Evaluation 7/15/97 page 19 5. Unalaska (Pyramid Creek) 5.1 Baseline Data and Assumptions Total energy requirements (net of station service) in Unalaska were about 28,746,000 kWh in 1996. The load far exceeds the output of the proposed Pyramid Creek projects; load growth is unimportant. The system peaks in winter and the annual load is fairly constant. Two hydro projects are considered here. The larger, named the "260 kW project" would provide 2,11-4,000 kWh annually and is assumed (here) to provide 260 kW of firm capacity. The smaller is a power recovery project to be grafted on to the existing water supply system, assumed here to provide 100 kW of constant output, or about 877,000 kWh per year. Figure 7 shows the output of the 260 kW project compared to current diesel generation. The picture for the 100 kW project would look substantially the same. Figure 7 Pyramid Creek 260 M Output vs Diesel Generation 3,000,000 2,500,000 2,000,000 1,500,000 Y 1,000,000 500,000 o > 5 M a t > U .� w W G m m C c The current diesel system consists of 7.5 MW of installed diesel capacity, with a current average efficiency of about 13.6 kWh/gallon (measured after station service). Table 14 summarizes the baseline data and assumptions for Unalaska. Rural Hydro Economic Evaluation 7/15/97 page 20 Table 14: Unalaska Baseline Data and Assumptions na as a y- ram id Greek! ! I ! Baseline Data an ssump ions ! I 1 Energy Requirements Actual AclualModel ICY95I eneration MWhlyr I 25,48 i ! o !less: Station Svc I o, 114 82F!828 1= us ar Requirements I yr j , i � I I Peak oa at tation IKVV 5o oa actor ( I i0.613 Peak oad (at busbar)!kVVI I Fuel Prices and Efficiency I I I ota ue os - ! ! 16,895 otal Gallons used CY92-96 000 gal9,205 verage Price galI I liviodease Price I0.751 vg Busoar Efficiency ga1 13.491 IModel 199i Base E iciency 1 13.61 1 1 I ! u0st or CapitalI I ! see critical assumptions ! ! ! I I I I Diesel Operating Regime !KVVMax hours I Initial um Litetime I ! Iper yr Hours Hours Unit xis I4,UUUI Unit Exist 6,000! Unit xis I2,000 6,00UI !New Diesel Units 1 2,500I Unit must -run time hrs ! 1 lHequired Reserve Margin o I o 1 New Diesel Cost! New Diesel CapitaFCost I ! lNew-Diesel Efficiency galITT It-omposite Overhaul cost ! 5ihr I I 5.0 Other nonfuel varfable cos ! ! I I I ! Hydro Operating Parameters I I I ! y ro nergy Capability yr 2,174 y ro Effective CapacitykW! Hydro availa ii o ! o95.0%f ! Hydro Annual Maintenance 57yr 1(260 kW is per — pro ao y NOT incremental to existing iese I Rural Hydro Economic Evaluation 7/15/97 page 21 4.4 Old Harbor 260 kW Critical Assumptions Table 15 summarizes the critical assumption values used for the 260 kW project. Table 15: Unalaska 260 kW Critical Assumption_ I I I ow i ig Load ro Energy Heqts and PeaK Growth I o yr I o a J. o f I not critical to Unalaska) I I uel PriceGrowth I I To of 1.3410 I I I Real DiscoinfR—aFe o of a. ,o I I y ro api a os I not not used M used Hydro Net Maintenance I I yr 1 0 I 80,000 not net or a iesel0. 5u o U used For the 100 kW project, the single assumed capital cost is $400,000 and the single assumed net maintenance cost is zero. Load growth is not important for these projects. The real discount rate ranges between 0 and 5%, reflecting the tax-exempt status of the city utility. The hydro maintenance amounts are incremental to current diesel O&M costs.5 The low value of assumes substantial use of existing labor. The high value of $80,000 is reduced somewhat from the "stand-alone" value of $120,000 estimated by the Corps of Engineers, but since Unalaska is a fairly large utility, it is less plausible to assume that there is unutilized labor available at the diesel plant (which would be almost completely unaffected) that could simply be transferred to hydro maintenance. This question requires further scrutiny. 5.4 Unalaska 260 kW Project Results Range of Results. The Unalaska 260 kW project has positive net benefits under about 2/3 of the combinations of assumptions. Under mid -range assumptions, the project essentially breaks even, with net benefits of about-$165,000. Under the most pessimistic set of assumptions, the net benefits are-$707,000. Under the most optimistic values, the project has substantial positive net benefits of about $3.9 million. Table 16 summarizes this range of results. . 50iesel overhauls are treated in this analysis as an amortized capital cost, expressed as a fixed amount per hour of diesel unit running time. Rural Hydro Economic Evaluation 7/15/97 page 22 Table 16 Results Summary: na as a Net Benefits of HyUr-0, NPV over 35 years I I I mid -range I most mos I I assumptions I pessimistic I optimistic ase name I mmmmm IIIhmm hl rt t i c a assume ions: Load GrowthI al of o p-2— r-uei Price rowt I o . o I a IGI Real iscount ate I �. ,, I -. o I o : ydro ape a os ydro Net Maintenance 80,000 80,000I Results: iese - n y System Cost iese ue Diesel nonfuel pera mg I1,117,17 725,249I iese apact ODU- 7-015T-Cubf wilhout Ryaro 65,81U,244 32,058.oI6I I I With Hydr-o-S-ys-fe—m-Co-st juiesel Fuel JUiesel nontuel Operating 1,117,176I I iese apace I I y ro ons ruc Jon I1,221,90bI Iriyaro maintenance O o a os wi y ro I o I o I Net Benefitof iydro Project , (parentheses indicate negative numbers) Probability Distribution of Results. Because there is only one capital cost estimate for this project, there are only 54 combinations of assumptions. As the probability distribution shown in Figure 8 indicates, there is an 66% probability of positive benefits if the individual assumption probabilities are accurate. Since load growth does not matter, the major determinants of project economics are the annual hydro maintenance cost and the discount rate. Rural Hydro Economic Evaluation 7/15/97 page 23 0.18 0.16 0.14 0.12 = 0.1 a 0.08 a 0.06 0.04 0.02 0 Figure 8 Probability Distribution of Net Benefits: Unalaska 260kW U� O 11� CA CO M C7 CV t` O O O O r — N N CO M Net Benefits (million 1996S) Break-even and Sensitivity Cases Table 17 reports two break-even results. The table does not show it, but both cases assume the high hydro maintenance cost ($80,000 per yr). The first case shows that with flat fuel prices and a high discount rate, the hydro construction cost would have to be reduced to a low value of $540,000. Starting from the same set of -assumptions, fuel prices would have to rise at 2.4% per year to compensate for high construction and hydro O&M costs. Table 17: Unalaska 260 kW Break-even Cases ,-4— ..apital 'Gost i I Initial I oad fuel Inivai Initial Breakeven Case growth gro ( rate apita ost a enetits capital Cost 111hrrim 1.U%J T of o. o (- i, ) 5.39,7 88 I I I I I I I Fuel rice Izscalation Initial I ---load —Case Initial ( ni is rea even I growl Capital Cost I Net ene i s ue gro mm I o 6 5. of ) o Discussion. The analysis shows that the Pyramid Creek 260 kW project is economic under some combination of low discount rates and/or low hydro O&M costs. Load Rural Hydro Economic Evaluation 7/15/97 page 24 growth is irrelevant. Only a substantial sustained increase in fuel costs could overcome a combination of higher discount rates and/or hydro 0&M costs. 5.5 Unalaska 100 kW (Power Recovery) Results Range of Results. The Pyramid Creek 100 kW project has positive net benefits under all combinations of assumptions. These range from $330,000 (most pessimistic) to $1.7 million (most optimistic). Table 18 summarizes this range of results. Table 18 ResultsSummary: Unalaska 100 kVV Net SeneTItSot Hydro, NPV over 35 years I � mi -range most ( most assumptions I pessimistic 1 optimistic ase name mmmmm IIhmm I h I mm Criticat assumptions: I Load ro 0I °I Fuel Price Growth 0.5* U. U a l a Real Discount Rate i o I 5. 0 To o Hydro Capitaf Cost 1400,000 1 Hydro Net maintenance U 1 Results:I I I iese - n y System Cost iese ue I --T35,410,40.5- juiesel nontuel Uperating Uiesel CapacityI4,389,924I ULidl Uasiwithout y ro Wit n Hydro System Uost '1�15iisel Fuel 133,316,875- Juiesel nonTuel Operating I1, 1 17,17F 725,;T 1,577,8 Diesel apace I 5 I Hydro ons ruc ion 1 ., . M . _ maintenance I V I 0 - - o a os wi y ro I I e ene i o y ro rojec co I I Probability Distribution of Results. Because there is only one capital cost estimate and one maintenance cost for this project, there are only 27 combinations of assumptions. All combinations produce positive net benefits, as shown in Figure 9. Rural Hydro Economic Evaluation 7/15/97 page 25 Figure 9 Probability Distribution of Net Benefits: Unalaska 100 kW Power Recovery 0.25 0.2--------------- ------ --------------------- 0.15--------------- --------------------------- 0 0.1---------- j 0.05 _ _ _____ --- - ---- --- ------------- 0 v Un r` C� rn cD Net Benefits (million 1996$) Discussion- This project looks promising due to its low construction cost and -- what is assumed here -- its low incremental maintenance cost. The low maintenance remains to be verified. Rural Hydro Economic Evaluation 7/15197 page 26 Appendix: Notes on Model Mechanics The economic evaluation model computes the total system cost of electric power with and without the hydro project. The model is basically an annual dispatch model with some monthly detail to take account of the variable hydro output over the year. The key feature of this model is that it develops a diesel capacity expansion plan automatically. In addition the model tracks the hours of operation of individual diesel units so that the proper amount of overhaul savings can be attributed to the hydro project. The model attempts to capture the fact that overhauls can only be saved and replacements can only be deferred if units are turned off. In small systems, merely reducing energy output is not sufficient to effect overhaul savings and deferral of replacements. The model is implemented in Excel 5.0 and is not designed for external use. Evaluation copies can be obtained from the author. The Diesel -only System. The diesel system is modeled as a set of individual units. The model completes an annual cycle of diesel system operation as follows. 1. Evaluate Capacity; make Retirements and Additions. At the start of the year, all units that were in use at the end of the previous year are evaluated. Units that exceeded their allotted lifetime hours during the previous year are retired. The remaining capacity is checked against a benchmark to determine if additions are needed. The benchmark is the current year peak load plus the capacity of the largest diesel unit. (For Unalaska, a larger utility, the benchmark is peak load plus a 25% reserve margin). If an addition is needed, it is made in increments of the specified size of new diesel units. So, for example, even a 1 kW capacity deficit triggers a 125 kW capacity addition if that is the specified size of new units. 2. Allocate run-times and energy production to units. The designated backup unit is run for 80 hours as a must -run unit. A "primary unit" is run for 6,000 hrs. A "secondary unit" is run for the remaining hours of the year. The 6,000 hour limit captures the practice of sometimes running units in parallel to reduce generator loadings or to meet high peak loads, as well as necessary down times for maintenance. The three units generate energy in proportion to their run times. Different efficiencies are attached to each unit's production, so that the replacement of existing inefficient units with new more efficient units is accurately captured. 3. Record Hours run, allocate overhaul cost. A separate hours meter for each unit keeps track of the annual and cumulative lifetime hours of that unit. The annual hours of run time determine the [levelized] overhaul cost. The cumulative lifetime hours determine when the unit must be replaced. 4. Tally up Total Costs. The annual costs of the diesel system are discounted and summed to a net present value. For simplicity, all costs are considered to occur at the end of the year and the benchmark date is 12/31/96. So, for example, costs occuring in 1997 are discounted by one period. Diesel plus Hydro System The hydro unit is characterized as a set of 12 monthly energy outputs and a firm capacity (which may be zero). The hydro unit is considered by the model during the four -step process described above as follows: 1. Evaluate Capacity; make Retirements and Additions. At this stage the hydro unit's firm capacity (if any) is counted in computing total available resources. Therefore, even a small amount of firm hydro capacity could be effective in forestalling a major diesel unit addition. for a few years. 2. Allocate run-times and energy production to units. At this stage, the monthly hydro energy output is compared to the monthly energy demand to determine which months, if any, the diesel system can be turned off. Figure A-1 shows a hypothetical comparison of hydro output to monthly loads. 70,000 60,000 50,000 L 40,000 3 30,000 20,000 10,000 Figure A-1: Hypothetical Hydro Output vs Monthly Load r--nyd�o load In the case shown here, the diesel system can be turned off during September, October, November and December. During the months of January through June, the system must be on. In addition, the backup or "must -run" diesel unit is always run for its specified minimum hours, even if hydro is sufficient to meet the load in every month. The above comparison is used to determine hours of running time. The next step is to determine energy production. To determine required diesel energy production, the model subtracts total annual hydro energy multiplied by availability from annual energy requirements. No allowance is made within the model for the possible case where there is excess hydro energy in some months but diesel is required in other months. Such a case is shown in the Figure A-1 above, where the annual calculation made by the model would allow the excess hydro energy in Sept -December to offset the hydro energy deficit in January -August. The validity of the approximation depends on how much storage exists at the project. The problem occurs to some extent in Atka, where for several years annual hydro output exceeds annual energy requirements in some months but falls short in others. To test for possible bias, several sensitivity cases were run where the Atka model was changed to give zero credit for surpluses in some months as an offset to deficits in other months. (In other words, while the basic model assumes perfect storage, the sensitivity cases assumed zero strorage between months.) The cases showed that the basic results are not significantly changed.' However, further study of this site will require a monthly or daily dispatch model to take account of the actual match between hydro output and load. 3. Record Hours run, allocate overhaul cost. As mentioned above, hydro energy can reduce the number of hours of diesel run-time if (and only if) monthly hydro output exceeds monthly energy requirements so that the entire diesel system can be turned off. In reality, of course, the hydro output might allow a particular unit to be turned off even though the whole system cannot be turned off. In the 4 projects under study this simplification is not a problem because three places run one primary diesel unit, while the 4th (Unalaska) has unit sizes and total loads far greater than the hydro output there. 4. Tally up Total Costs. The hydro project is assumed to be built in 1997, so construction costs get discounted by one period. 1Net benefits are reduced by about 5%. Project Name: Ambler (Jade Creek) ID: 1 Existing/Proposed: proposed Project Location: 130 miles E of Kotzebue. Ambler River A-4,5 Statistical Area: NW/Arctic File Name: NW/A 1 PCE Community Served: Ambler-Shungnak-Kobuk Information Source: @ Small Hydroelectric Inventory of Villages Served by Alaska Village Electric Cooperative(AVEC); by USDOE Alaska Power Administration; for same; December 1979; TK 1424 A4 A362; BLM/AR Library. Information Summary: Hydroelectric powersite reconnaissance for majority of Western Alaska served by AVEC, 10 to 20 miles or less from subject village. Level of Effort: reconnaissance Data Input By: CNF @ LIL 10/7/96 Maps/Drawings: USGS Geotechnical Conditions: Land Use/Status: Environmental Concerns: Stream/Lake Name: Drainage Area(sq mi): 7 Mean Ann Prec(in): Avg Ann Runoff(1000 ac ft): Active Reservoir Storage(ac ft): Flow(cfs): 100 System Freeze/Seasonal Op: unknown Head(ft): 200 Firm Energy(kWh): n/a Population Served: 275 Customer Class: n/a Peak Load(kW): 70 in 1978 Avg Ann Load(kWh): 244,000 Existing Generation: diesel An Development Plans: n/a Change Customer Class: n/a Change Peak Load(kW): est. 100 in 1979 Change Avg Ann Load(kWh): System Type: Diversion Structure/Dam: Spillway: Gates/Intake: Water Conduits: penstock, d=48 in, L=5,000 ft Power Station/House: Generator: Transmission Line: L=10 mi Required Infrastructure: road, L=10 mi Installed Capacity(kW): 1,225 Plant Factor(%): 30 Avg Ann Energy Prod(kWh): 1,073,100 summer 3,219,300 year around operation Construction Cost(S): 4,519,000 in 1978 Transmission Cost(S): 400,000 in 1978 Annual OM Cost(S): Cost/kW(S/kW): 3,700 in 1978 Cost Estimate Assumptions: power plants - 900S/M diversion structure - 10,000S I.s. pipeline - steel @ 2S/lb. trans In - 7-15kV/1 phase, 40K S/mi. roads 25K S/mi. 25 o contingency to all S above. Non -Viable: Additional Info/Remarks: Wind generation may be feasible here. One of best 9/48 sites considered in this investigation to have ;ood hydroelectric power potential. ,e Name role-; Na cw 'Rs:,nci F ctr; Lo Iricrmat Inicrmat eve! ci Data Irt M act/D u ectec= �and Us nvircru I Stream/I D' rana_gt Mean Az Avg Anr AGive R a c( t N I Text INum I Text INum I Text ! Text I Text I Text I Text I Text I Text 1 Text I Text I Text I T ext I Text 1 T ext I Text 1 7" 1 T ext : fl Text 1 T ext o i Text I Facef fie mmiber. bu statrstrcal area and Crete- r'urc I Umme numoer reore-�nttng e�c- datacasa try I Name of oroir; (with asrcciated water, or Coe des I 1 if unique emir; !geadon and mcs; dra�ieC reccrc: 0 i Existing or Crcoosed orciew•::ate cf hvicesystem iridai LautudC. I—XwCe. name of USij auacarc Statistical area erccmoa.. rr, ^rcir_t S"c. Si I Served at catenaaity served bvrthe Crciec• I Doct:ment title. author, acercv, date. lrary r 196ei =fnaru of information =L7C_ Ccc=er I Intent of reccrt letter reocrt, cererai reccnne I Database entry added bv: nca<Qll:rcamzad( I Are macs of drawings ncuded in nfcrrnaacn I Db_--vvanors or test: at site. nc des to rain I Land =e. status, and/or lard owner at time c I Ism to Or concerns that mirnc affect oroiec' m I Waterboav QnoaGed bu i %xCro Croiew 19 asn size assocated with or6etx ter hvdro a I Mess annual orec oitatien =ccated with dtj i Voiume of average annual tt=it a---v ted 1 Active reservoir storage vciume ide"aried for I I Sustem flow: measured. c.'jctiatel er a^amat _ _-- �Ctlity