Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
Cordova Reconnaissance Study Of Energy Requirements & Alternatives Cordova 1981
FINAL REPORT : ONNAISSANCE STUDY OF ERGY REQUIREMENTS AND ALTERNATIVES FOR CORDOVA PREPARED FOR : THE CITY OF CORDOVA AND STATE OF ALASKA ASKA POWER AUTHORITY PREPARED BY : ORRISON-KNUDSEN COMPANY ROBERT W. RETHERFORD ASSOCIATES DIVISION ANCHORAGE, ALASKA JUNE 1981 ALASKA POWER AUTHORITY RECONNAISSANCE STUDY OF ENERGY REQUIREMENTS AND ALTERNATIVES FOR CORDOVA FINDINGS AND RECOMMENDATIONS BACKGROUND This reconnaissance study addresses the total energy needs of the people in Cordova. Prior to this report most studies evaluated a specific alternative to produce energy. An exception was an overall study of the energy requirements of Cordova conducted by Marks Engineering for Cordova Public Utilities in 1977. That report recommended a diesel-hydro combination to meet Cordova's needs if the Power Creek hydroelectric potential was feasible. Subsequently, the Corps of Engineers began a study of the alternatives in the Cordova area which addresses Power Creek specifically. Through the Corps' geological investigations, it has been found that only a run-of-river plant appears feasible with the final results of their study due in late spring. Cordova Electric Cooperative owns, operates, and maintains the power system in the Cordova area which consists of five diesel engine driven generators totalling 8450 Kw: 600 Kw 1 @ 1950 Kw 750 Kw 1 @ 2650 Kw 1 @ 2500 Kw (New, installed 1979) 1@ 1@ Some of the units are in poor condition and are considered to be unreliable. After taking account of reserve requirements and unreliable units, the capacity available to meet peak load requirements is about 5000 Kw. In 1980 the peak power demand was approximately 3400 Kw and the total energy demand was about 16,400 MwH. The cost of diesel is approximately $1.05/gallon with approximate cost to the residential consumer presently at $0.23/kwh. FINDINGS Approximately 20 percent of the total energy used in Cordova goes toward the generation of electrical energy. About 26 percent of the total energy is used for space heating. In the production of electrical energy, at least two-thirds of the energy potential is lost in the form of waste heat. The projected electrical peak demand for 1985 ranges between 5,700 kw and 4100 kw. The respective energy demands for 1985 are forecast at between 26,300 MWH and 18,500 MWH. The range of peak demand for the year 2000 is 8,000 kw to 16,500 kw. The energy demand for the year 2000 is projected to range between 27,800 MWH and 80,000 MWH. These figures exclude space heating requirements which, if provided by electrical energy, would add another 140,000 MWH required in the year 2000. Hydroelectric projects, coal-fired generation, transmission interconnection, waste heat utilization and cogeneration are among the power production alternatives available to Cordova. The Silver Lake Hydroelectric development alternative would be the last major construction during the planning period and would be expected to tie into the transmission line in 1991. The following table shows the total discounted cost of each plan based on a 50 year period of analysis (from initial operation of the last major development) and FY 81 Power Authority evaluation parameters. The table summarizes the scheduling and cost implications of the most viable alternative plans. COSTS OF ALTERNATE DEVELOPMENT PLANS Earliest Year Accumulated Alternate Plan of Operation Present Worth Diesel Generation - Base Case 1981 168,527,000 Coal-fired Generation - Carbon Creek 1983 165,634,000 Diesel Generation w/waste heat 1983 148 ,968 ,000 Coal-fired Generation - Healy Coal 1983 93,065 ,000 Intertie/Valdez surplus Silver Lake 1983 89,297,000 Power Creek, Crater Lake w/ supplemental diesel 1983 61,720,000 The surplus energy cost from the Valdez area was recomputed and found to be in the range of 4-5 cents per KwH. This cost is somewhat less than the 6.25 cents per KwH used by the consultant. The difference is not sufficient to alter the rank order of the alternative plans. Technical All of the alternatives evaluated appear to be technically feasible. The only area of concern is the transmission line between Cordova and Valdez. There are three alternative routes which were proposed; (a) submarine cable, (b) along the old El Paso gas line route, (c) along Copper River. Each of the alternatives would entail a certain degree of risk and there is some question as to the reliability, all of which will impact the cost. Two newer methods of transmission are the Single Wire Ground Return (SWGR) and three phase transmission with the utilization of long spans without clearings and with helicopter placement of towers and conductors. The SWGR has been utilized somewhat in Alaska and much more in Europe. Three phase transmission without clearing has been utilized recently south of Anchorage and poses fewer environmental problems than the conventional three phase transmission line with clearing. This type of construction may be suitable for the overland routes. The development of a coal fired generating plant in the Cordova area has the potential of being economically feasible utilizing Healy Coal. It may require a minimum of one year of air quality data prior to any construction. Environmental The coal alternative would probably have the most potential for environmental degradation. Along with air quality constraints, there would also be the need to treat the water which would run off the stockpiled coal. Although these concerns exist, the technology is available to protect the environment and still provide energy to Cordova. Economic Diesel generation appears to be the only immediate alternative to produce energy for Cordova. The cost of continuing with diesel generation is expensive and will in all probability continue to escalate. The development of a hydroelectric plant, coal plant, and/or an intertie with Valdez could produce energy in the long term for Cordova at lesser cost. RECOMMENDATIONS The Power Authority recommends that a detailed feasibility analysis be conducted to formate a preferred power supply plan. This analysis would include the following alternatives: 1. Coal-fired generating plant utilizing the least cost coal source, 2. Power Creek run-of-river hydroelectric plant, and 3. An intertie between the communities of Cordova and Valdez with the option of developing hydroelectric sites along the line. The alternatives should be evaluated in a manner which will identify the preferred sequence of development required to meet the Cordova energy demands for the next twenty years. Eric P. Yould Executiye Director ny . Date: ) __-_— FINAL REPORT: RECONNAISSANCE STUDY OF ENERGY REQUIREMENTS AND ALTERNATIVES FOR CORDOVA Presented to: THE CITY OF CORDOVA AND STATE OF ALASKA ALASKA POWER AUTHORITY Prepared by: ROBERT W. RETHERFORD ASSOCIATES DIVISION OF INTERNATIONAL ENGINEERING COMPANY, INC. CONSULTING ENGINEERS ANCHORAGE, ALASKA June 1981 PREFACE This reconnaissance study has been conducted by Robert W. Retherford Associates to identify the energy requirement needs of the City of Cordova, Alaska, and to formulate and analyze alternative energy projects reasonably expected to be available to Cordova through the year 2000. The format of this study report is intended to conform with Alaska Power Authority Reconnaissance Study Regulations and incorporates comments of individuals and agencies that reviewed the February 1981 draft version of this report. APA25/j1 ACKNOWLEDGEMENTS We would like to express our thanks to the citizens of the City of Cordova, in both official and private capacities, for their valuable inputs and support of this work. The comments of reviewers of the draft report have helped significantly in assuring relevance to Cordova's needs. Information on coal, oil, gas, and geothermal resources was provided by C. C. Hawley and Associates. ii APA25/j2 TABLE OF CONTENTS SECTIONS PAGE I. INTRODUCTION AND SUMMARY I-1 II. ENERGY BALANCE II-1 III. ENERGY REQUIREMENTS III-1 IV. ENERGY RESOURCE ALTERNATIVES IV-1 V. ENERGY TECHNOLOGY ALTERNATIVES V-1 VI. EVALUATION OF FEASIBILITY OF ENERGY ALTERNATIVES VI-1 VII. CONCLUSIONS AND RECOMMENDATIONS VII-1 APPENDICES PAGE A. ENERGY BALANCE AND REQUIREMENTS - DETAILS A-1 B. | RESOURCE COSTS B-1 C. ENERGY TECHNOLOGY PROFILES C-1 D. ECONOMIC ANALYSES - DETAILS D-1 E. BIBLIOGRAPHY E-1 F. COMMENTS F-1 APA25/i iii LIST OF FIGURES FIGURE# TITLE PAGE 1 VICINITY MAP I-3 2 CORDOVA PETROLEUM BASED ENERGY BALANCE IN 1979 II-2 3 POPULATION PROJECTIONS - CITY OF CORDOVA I1I-4 4 PROJECTED YEARLY ELECTRIC CONSUMPTION - CITY OF CORDOVA III-5 5 PROJECTED YEARLY PEAK POWER DEMAND - CITY OF CORDOVA III-6 6 CITY OF CORDOVA - HEATING PROJECTIONS III-7 7 INTERTIE - TRANSMISSION ROUTES AND HYDROELECTRIC SITES IV-7 8 BERING RIVER COAL FIELD DEVELOPMENT Iv-19 9 PRESENT WORTH COST OF ALTERNATIVE PLANS VI-3 10a PEAK POWER - DIESEL ONLY SCENARIO - CITY OF CORDOVA VI-4 10b ELECTRICAL ENERGY REQUIREMENT - DIESEL ONLY SCENARIO - CITY OF CORDOVA VI-5 lla PEAK POWER - COAL SCENARIO - CITY OF CORDOVA VI-7 11b ELECTRICAL ENERGY REQUIREMENT - COAL SCENARIO - CITY OF CORDOVA VI-8 12a PEAK POWER - INTERTIE SCENARIO - CITY OF CORDOVA VI-10 12b ELECTRICAL ENERGY REQUIREMENT - INTERTIE SCENARIO - CITY OF CORDOVA VI-11 13a PEAK POWER - ELECTRICAL HEATING SCENARIO - CITY OF CORDOVA VI-13 13b ELECTRICAL ENERGY REQUIREMENT - ELECTRIC HEATING SCENARIO - CITY OF CORDOVA VI-14 l4a PEAK POWER - LOCAL HYDRO WITH DIESEL SCENARIO - CITY OF CORDOVA VI-15 14b ELECTRICAL ENERGY REQUIREMENT - LOCAL HYDRO WITH DIESEL SCENARIO - CITY OF CORDOVA VI-16 15 CITY OF CORDOVA - CURRENT ENERGY USE PROJECTIONS VII-5 16 CITY OF CORDOVA - PROJECTIONS OF CURRENT PETROLEUM FUEL USE REPLACEABLE BY OTHER RESOURCES VII-6 17 CITY OF CORDOVA - PROJECTIONS OF CURRENT PETROLEUM FUEL USE WITH GENERATION WASTE HEAT RECOVERY VII-7 18 CITY OF CORDOVA - IMPACT OF WASTE HEAT USE VII-8 MISC13/U1 LIST OF FIGURES FIGURE# TITLE PAGE Bea CITY OF CORDOVA - POWER CREEK vs. DEMAND B-18 Coss 2. tat HYDROELECTRIC POWER DEVELOPMENT DIAGRAM C2 352.158 C374 Aa DIAGRAM OF RUDIMENTARY STEAM POWER PLANT C354 1-6 (WAR RG Br aen L JACKET WATER & EXHAUST WASTE HEAT RECOVERY SYSTEM Crs... eae Ces on eae JACKET WATER WASTE HEAT RECOVERY SYSTEM Cassone C.335.451 RESIDENTIAL ENERGY CONSUMED FOR VARIOUS SIZES AND TYPES OF CONSTRUCTION - CITY OF CORDOVA C.3.954-6 C.3.6-1 WIND TURBINE GENERATOR C33 2652 C233652 WECS vs. DIESEL GENERATION - 18 kw INDUCTION GENERATION C.3°6-8 Crs a1. HEAT PUMP FOR BUILDING HEATING Lom FY fa’ MISC13/U2 TABLE # V=1 VI-1 VI=2 VI-3 A-10 Bod=1 BI=2 B.1-3 B.1-4 B..1=5 MISC13/U3 LIST OF TABLES TITLE FUEL ENERGY CONTENT COST OF ALTERNATE DEVELOPMENT PLANS EVALUATION MATRIX - ELECTRIC SCENARIOS EVALUATION MATRIX ~ NON-ELECTRIC SCENARIOS 1979 PETROLEUM BASED ENERGY BALANCE - CORDOVA AREA 1979 PETROLEUM BASED ENERGY SOURCE AND USE - CORDOVA AREA SUMMARY ELECTRICAL FORECASTS TO YEAR 2000 - CITY OF CORDOVA LOW ELECTRICAL LOAD FORECAST - CITY OF CORDOVA MEAN ELECTRICAL LOAD FORECAST - CITY OF CORDOVA HIGH ELECTRICAL LOAD FORECAST - CITY OF CORDOVA LOW HEAT ENERGY FORECASTS TO YEAR 2000 - CITY OF CORDOVA MEAN HEAT ENERGY FORECASTS TO YEAR 2000 - CITY OF CORDOVA HIGH HEAT ENERGY FORECASTS TO YEAR 2000 - CITY OF CORDOVA CURRENT ENERGY USE PROJECTED TO YEAR 2000 - CITY OF CORDOVA SUMMARY ESTIMATES FOR COST OF CARBON CREEK COAL PER TON INITIAL GEOLOGIC RECONNAISSANCE PROGRAM TO OUTLINE TARGETS DRILLING PROGRAM TO PROVE RESERVES CAPITAL COST DETAILS - CONSTRUCTION, TRANS- PORTATION AND MAINTENANCE EQUIPMENT MINING EQUIPMENT A-3 A-4 A-5 A-6 A-7 B-4 B-5 B-5 B-6 LIST OF TABLES TABLE # TITLE PAGE B.1-6 CAMP FACILITIES B-6 B.3-1 HEALY COAL COSTS B-8 B.3-2 BARGING COSTS B-8 B.4-1 KATALLA OIL AND GAS DEVELOPMENT COSTS B-10 B.5-1 PROJECTED SURPLUS MWh AT VALDEZ B-13 C.3.5.2-1 WASTE HEAT AVAILABILITY C.3.5.2-4 C.3.5.2-2 HEATING OIL USE C.3.5.2-6 D-1 DIESEL GENERATION ONLY - ECONOMIC ANALYSIS D-1 D-2a DIESEL PLUS INTERTIED SURPLUS PLUS SILVER LAKE HYDRO (SURPLUS ENERGY COST $0.0625/kWh) - ECONOMIC ANALYSIS D-2 D-2b DIESEL PLUS INTERTIED SURPLUS PLUS SILVER LAKE HYDRO (SURPLUS ENERGY COST $.01/kWh) - ECONOMIC ANALYSIS D-3 D-3 LOCAL HYDRO PLUS DIESEL - ECONOMIC ANALYSIS D-4 D-4 HEALY COAL GENERATION - ECONOMIC ANALYSIS D-5 D-5 CARBON CREEK COAL GENERATION - ECONOMIC ANALYSIS D-6 D-6a ELECTRIC HEATING BY INTERTIED HYDRO (SURPLUS ENERGY COST $0.0625/kWh) - ECONOMIC ANALYSIS D-7 D-6b ELECTRIC HEATING BY INTERTIED HYDRO (SURPLUS ENERGY COST $.01/kWh) - ECONOMIC ANALYSIS D-8 MISC13/U4 Il. introduction and summary I. INTRODUCTION AND SUMMARY I. | INTRODUCTION AND SUMMARY i. Introduction Cordova, population about 2500, is located on the east side of Alaska's Prince William Sound, on the Orca Inlet. Elevation ranges from sea level to 400 feet and the marine influenced climate ranges from a January average temperature of 26°F to a July average of 54°F. Rainfall is heavy, with an annual average precipitation of 90 inches (over 7 feet). The area's economy is chiefly supported by fishing and crabbing activi- ties in the Prince William Sound and by the long and diversified canning and freezing season for this harvest. Cordova, like many communities in Alaska, depends almost entirely on imported petroleum products for its electrical energy and heating needs. As the continually escalating cost of petroleum fuels in small Alaska communities is among the highest in the United States, it is obvious that high priority should be given to developing community independence from these fuels or, at least, reducing community dependence on petro- leum by implementation of reasonable alternatives. Without at least a stabilization of energy costs in the near term, Cordova risks signifi- cant loss of population and industry to other, cheaper energy sites. This final report describes work performed at a reconnaissance level to identify and evaluate the suitability of utilizing various existing and potential non-petroleum energy resources for the Cordova area. This report is based on reconnaissance investigations, verbal communica- tions with people who live in and are familiar with the area, informa- tion available from existing reports, publications and maps, comments of reviewers, and engineering calculations and estimations. The overall study area discussed in this report is shown on Figure 1. APA24/k1 Trl I. INTRODUCTION AND SUMMARY 2. Summary The work reported on in this study consists of the following: APA24/k2 Performance of site reconnaissance and data gathering. Establishment of an energy balance for Cordova. Forecast of electrical energy and peak power requirements for the area to the year 2000. Preparation of profiles for energy alternatives for Cordova, their combination into reasonable alternative plans, and technical, economic, and environmental analyses of these plans. Recommendations for specific data collection programs and feasibility level studies required to increase the confidence of analyses. | 4 Ww a > 2S LW ll. energy balance II. ENERGY BALANCE II. ENERGY BALANCE In order to establish a basic picture of energy use in the Cordova area, a petroleum based energy balance has been compiled for the year 1979, the last year for which full year data was available. Energy forms used are diesel fuel, gasoline, #1 fuel oi1, aviation gasoline, and propane. It is recognized that coal, wood, wind, and natural gas are energy sources which have been used on a small scale; utilization data was available only for wood, however. In the past few years, many residents of Cordova have installed wood stoves for primary and secondary heating uses. The present use of wood in Cordova is estimated to be between 800 and 1000 cords per year, equivalent to about 17.1 x 109 Btu per year based on U.S. Forest Service estimates for spruce. Wood energy consumed in Cordova, then, amounts to a little less than 2 percent of annual petroleum use; it is projected to maintain this level through the year 2000 and not significantly impact the development of non-petroleum based alternative energy plans. The following pictorial graph (Figure 2) summarizes the petroleum based energy balance in Cordova and the immediately surrounding area by energy form and end-use category. The data used as the basis for this graph is tabulated in Appendix A. Data was obtained from several local sources and best estimates were made for some aspects of the breakdown shown in Figure 2. APA24/L1 II-1 ENERGY AS WASTE HEAT EFFICIENCIES ASSUMED: TRANSPORTATION 30% ELECTRIC GENERATION 30% INDUSTRY* & HEATING 70 % * FISH PROCESSING ZF eXXX XNA) X y b Liven 4 FELECTRICITY 20.2 T — 0 GASOLINE i AV GAS 19.2% L 1.3x10° GAL. E E E N g R G| DIESEL FUEL FinpUSTRY 7.9% . Y #1 HEATING FUEL Y C] ORO AE LHEATING 25.7% SSG GSCI TLE SCA | 0 8% pe aan Seer Core 7 N 5.2x108 GAL. I : Zz S E i D D CORDOVA PETROLEUM BASED ENERGY BALANCE IN 1979 FIGURE 2 lll. energy requirements III. ENERGY REQUIREMENTS III. ENERGY REQUIREMENTS The future energy needs of Cordova to the year 2000 were projected based on the high, low and mean population growth scenarios shown in Figure 3. These population growth projections are based on projections made for Outer Continental Shelf (OCS) leasing impacts as follows: low = no OCS impact scenario; mean = most probable OCS impact scenario; and high = maximum probable OCS impact scenario. The growth projections used in this study were selected after review of existing appropriate studies indicated that the growth projections arrived at in the Alaska OCS Socioeconomic Studies Technical Report Number 33, October 1979, were the most reasonable. In the low projection, it is assumed that there will be no OCS leasing and that approximately half of the new growth for Cordova would come from new developments and improvements in the fish processing industry, while the other half would come through development of the local service sector. The mean and high growth projections use the same growth bases as above. In addition, they assume that Cordova will serve as a home base for the work force of a marine oi] terminal on Hinchinbrook Island; the sharp increase in population noted on the curves is a result of marine terminal construction and this home base activity. The high growth projection curve incorporates the assumptions that the impact of the Hinchinbrook terminal will be about twice as great as the mean case and will occur later in the 1980's. The growth in power need for the last two decades has greatly surpassed the growth in population for the City of Cordova. This is consistent with the increase in fishing and seafood processing activities in the area. The Cordova Public Utilities board operates and maintains the power system which extends from the southwestern shore of Eyak Lake near APA24/r1 III-1 III. ENERGY REQUIREMENTS Copper River Highway, south to Three Mile Bay, north to the Municipal Dock, and east to Cordova Airport on Mile 13 of Copper River Highway. The existing plant contains the following diesel engine driven generators: 1@ 600 kW 1@ 750 kW 1@ 1950 kW 1@ 2650 kw 1@ 2500 kW (new, installed 1979) Total capacity 8450 kW Less Largest Unit = -2650 kw 5800 kW "Firm" Capacity Due to the poor and unreliable condition of some of the units, the true firm capacity is estimated to be approximately 5,000 kw. The existing firm capacity is such that no new generation facilities will be required until 1985 to meet the projected system peak demand. Figures 4 and 5 show the estimated yearly total electrical energy consump- tion and corresponding peak power demands for the three population growth cases; the data used to create these figures are tabulated in Appendix A. In making these electrical projections, certain key factors and assumptions influenced trends. These factors are: e Actual population growth based on census figures has histori- cally been less than projected figures. Use of the Outer Continental Shelf leasing impact scenarios discussed was used as the most realistic base of projection. ae The seafood processing industry is expected to grow at a slower rate than population because of impacts of high energy costs. While the total volume of processing is assumed to increase slightly, the increased use of freezing rather than canning by many processors is expected to increase the amounts APA24/r2 Lis 2 III. ENERGY REQUIREMENTS of energy used by the processors. It should be noted that only one large processor has plans for expansion; the others expressed concern that rising fuel prices might drive them out of business in Cordova. e Chugach Alaska Fisheries, Inc., a wholly owned subsidiary of Chugach Natives, Inc., at present has its own electrical generation capability. Negotiations are presently in process for addition of this generating load to the Cordova Electrical Cooperative system in 1983; in our projections a demand of 1 MW and load of 1.6 MWh annually have been included in the 1983 fig- ures and projected thereafter at the same growth rate as other fishing related activities. e No known plans currently exist for new commercial or indus- trial facilities to be constructed in Cordova. We have con- sidered it realistic that one new commercial/industrial facil- ity would come on line in 1992 with a maximum demand of 600 kW and annual electrical load of 1 MWh. e Growth in the government (public) sector is expected to be steady at a rate lower than that of population increase. e The rate of increase in per consumer residential electrical use has slowed in recent years due to the rising cost of electricity. This trend is projected to continue until cheaper alternatives are realized. In line with the rising cost of energy, consumers are expected to implement reasonable energy conservation measures. In order to examine all petroleum based energy uses in Cordova that can reasonably be replaced with other energy sources, projections were made for heating requirements in both British thermal units (Btu) and the number of MWh that would be required for electrical provision of such heat. Figure 6 shows the heating requirements; projections are tabulated in Appendix A. APA24/r3 III-3 POPULATION 500 ° 1980 98! 1982 1983 1984 1985 I986 1987 |988 1989 1990 199! 1992 1993 1994 1995 1996 1997 1998 1999 2000 YEAR , POPULATION PROJCTIONS CITY OF CORDOVA FIGURE 3 MWH /YEAR (IN THOUSANDS) 80 75) 65) 60 a on Qa Sa + ou an 30) 25 20) 15 10 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 YEAR I99) \992 1993 1994 1995 PROJECTED YEARLY ELECTRIC CONSUMPTION CITY OF CORDOVA FIGURE 4 1996 1997 1998 1999 2000 \7000 14000 13000 CTT CECA EET PROJECTED YEARLY PEAK POWER DEMAND CITY OF CORDOVA FIGURE 5 1980 1961 1982 = 1983 1984 §61985 §=6 1986 1987 i988 61969 = 1990 1991 i992. 1993 1994 = 1995 1996 997) 1998 1999 2000 YEAR 10? BTU/YEAR 500 400 300 CITY OF CORDOVA HEATING PROJECTIONS FIGURE 6 250 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 IV. energy resource alternatives IV. ENERGY RESOURCE ALTERNATIVES IV. ENERGY RESOURCE ALTERNATIVES The following energy and power resource alternatives for Cordova were examined in the course of this study: hydroelectricity coal oil and gas geothermal wind solar tidal biomass waste heat and cogeneration conservation other resources These resource alternatives are briefly described in the remainder of this section. Appendix B contains amplified descriptions and costing details concerning those energy resources found potentially suitable for Cordova's twenty year electrical needs and/or heating needs; "resources" locally suitable for heating applications as cascaded or secondary uses, such as waste or low grade heat applications, are discussed in detail in Appendix C. a. Hydroelectric Resources a. Large Hydroelectric Sites There are several large hydroelectric sites along the Copper River drainage which conceivably could be developed at some future time. A recent listing (Alaska Power Administration) giving the hydroelectric potential of these Copper River sites shows the following: (1) Million Dollar - 440,000 kw (2) Cleve - 820,000 kW (3) Woods Canyon - 3,600,000 kW APA25/A1 Iv-1 IV. ENERGY RESOURCE ALTERNATIVES Within the perspective of this study these hydro sites are not con- sidered as potential energy sources for Cordova due to substantial environmental barriers, and the fact that these projects would be far too large for Cordova's requirements. b. Run-of-River Hydroelectric Development A run-of-river hydroelectric development at Power Creek could conceiv- ably be developed in two stages: a first stage of 6600 kW and a second stage of 6000 kW capacity. The dam would be near stream Mile 3.0 (up- stream of Ohman Falls) and the powerhouse would be near Mile 2.0. The U.S. Army Corps of Engineers' investigations to date regarding a baseline 6000 kW run-of-river project indicate potential project feasi- bility. The Corps has test drilled two Power Creek hydro sites and is scheduled to test drill the third (Ohman Falls) during the summer of this year; the first two drilled sites were ruled out due to the extreme depth to bedrock. The Corps is also studying the second stage develop- ment for Power Creek and the possibility of a storage project at the same Ohman Falls site. Only the first stage conceptual development of 6600 kW run-of-river Power Creek plant is considered for further analysis in this recon- naissance study. A run-of-river hydroelectric development on the Copper River appears too complex for serious consideration as a viable energy alternative. A cursory review of some of the problems and environmental concerns are: (1) The minimum economic head for a bulb turbine is about 15 feet. The gradient of the lower Copper River is approximately 5 feet per mile. With a head of 15 feet, the flow requirements are approximately one cfs per kW or 5000 cfs for a 5 MW unit. A run-of-river plant would require a long pipeline of large diameter or a barrage across the river to develop the head. » APA25/A2 IVe=2) S IV. ENERGY RESOURCE ALTERNATIVE ; sin, and (2) There are numerous glacier-dammed lakes in the ba e flood- breakout Flooding from these lakes has caused larg Flows in the lower Copper River. . i ice flows (3) Past experience on bridge destruction by ae ana indicates any structure in the Copper River wou resist these strong forces. jon without a (4) Winter icing would result in seasonal operation deep reservoir to draw from. (5) The Copper River is by far the most important salmon “en in the area. The construction of a barrage would ted suitable fishways. Pipeline construction with assoc! “ blasting would have to be carefully monitored to mee Siltation and shock waves while fish are in the river. inal ; ually margina (6) The cost of low head hydroelectric plants are US under far more favorable conditions. Estimates of Surplus Variation depending ° Engineers Teport jderable : o conside energy available at Valdez are subject t = of cs n developmental assumptions made. The Corp surplus S that their recent study for Valdez shows that ¢ e from >» With the addition of energy availabl wane pe Sie ee the proposed Pressure Reducing a ene “Alaska Pipeline, would remain available ee peak area nee Big. de in 1990 for win deman¢ As additional power i ° TIVES IV. ENERGY RESOURCE ALTERNA ipeline by using the The PRT js a system for recovering energy from a the south side of Pressure developed by change in pipeline elevati tricity. PRT energy is Thompson Pass to turn a turbine and generate oe but offers signi- Considered a Secondary (interruptable) energy sou aut oil from the Ficant short Fange energy potential until the supp North Slope is depleted. ociates for the A currently uncompleted study by Robert W. Me ardar-clenalien Copper Valley Electric Association (CVEA), serving CVEA from the Solomon areas, is investigating Surplus energy available oso PRT. a Gulch hydroelectric Project and operation of the ay current pipeline forecasts based on CVEA growth projections for an 1996 were developed Flow rates, and oi] supply expectations from 1983 are used in this ; for that Study. Projections derived in that sue a reasonable assumption study and are detailed in Appendix B; they eae variance with base for surplus Projections and are not at sign other plans. ute ar yess . along the ro! reser ately and increasing benefits as hydro “tee mands; sharing of Major benefits include balancing of energy de and increasing reliability. : Vy po % physica resen as Three general corridors can be found that a described briefly routes for such an interconnection. They a follows: — : ter erimeer 0 rox" A astern per'™ e of app i following the e — a disianc (1) Submarine a sa sclaadlate anal ex a William Soun ro he line)- : is over imately 84 miles (3 miles of which DAmD& YY... IV. ENERGY RESOURCE ALTERNATIVES (2) An overland route on a portion of the eastern perimeter of Prince William Sound crossing from the head of Port Fidalgo to the Lowe River via the approximate routing proposed in 1974 by the El Paso Alaska Company for a 42-inch diameter gas line - a distance of about 59 miles. (3) An overland route following the Copper River Highway to the Tasnuna River, up that river, over Marshall Pass and down the Lowe River to Valdez - a distance of about 130 miles. All three routes and the hydro sites are shown on Figure 7, Intertie - Transmission Route and Hydroelectric Sites. The submarine Route (1) is substantially longer and could not readily connect with the series of potential hydroelectric sites along the way. To use such a cable system at AC voltages would require substantial compensation (shunt reactors) at several points along the route. The cable system would need to come up to shore for connections to such compensation stations. A DC submarine system would not require com- pensation, could use lower voltage cables, but could not readily connect to the hydro sites along the route. The long overland Route (3) is clearly much more expensive, but may be more accessible depending on the final route chosen to complete the Copper River Highway. There are several streams and lakes along the route which could be considered potential hydroelectric sites. A brief discussion of the most promising of these sites is presented as follows: (1) Van Cleve Lake at elevation 801 is apparently dammed by Miles Glacier. The lake has a large drainage area. However, the surface is approximately 200 feet below the ice dam. A possi- bility exists that top of bedrock controls the elevation of the lake and runoff occurs under the ice of Miles Glacier. If this is indeed the case, development would require APA25/A5 IV-5 (2) (3) APA25/A6 IV. ENERGY RESOURCE ALTERNATIVES a tunnel approximately 5 miles in length and a lake tap. The writer cannot find any information on the lake depth to compute storage capacity or the nature of the outlet. With only 500 feet of head, this lake does not warrant recommending as a feasible site at this time. Tiekel River from the junction with the Tsina River (Mile 13.9) to its mouth, flows through a rugged canyon and falls about 55 feet per mile. A dam approximately 100 feet high located at river mile 10.5 would provide a usable storage of about 50,000 acre-feet which would regulate the flow to yield a sustained discharge of 250 cfs. A tunnel 6.5 miles in length to a power- house at river mile 4.1 would develop a total head of 700 feet. About 10,000 kW of prime power could be generated. This plan would involve relocating a portion of the Richardson Highway and the Trans-Alaska oil pipeline. For this reason alone, the Tiekel River is not considered further as a prime source of energy. Without the storage reservoir, development would be run-of- river and seasonal in nature. This type of development does not appear feasible due to the long tunnel required to develop sufficient head. Cleave Creek, Heiden Canyon, Brown Creek and Sheep Creek do not have feasible hydroelectric sites along them, either now or in the foreseeable future. Nearly all of the usable head would have to be developed by a high dam or an extremely long flume or tunnel and would be a seasonal operation as storage capacity is very limited. IV-6 LEGEND: INTERTIE ROUTE 1 —_———_ INTERTIE ROUTE 2 acc = INTERTIE ROUTE 3 veceseseceee BERING RIVER COAL POWER TRANSMISSION ROUTE SILVER LAKE TRANSMISSION ROUTE ESN CA ... -{ CARBON CREEK »| COAL PLANT ~INTERTIE—TRANSMISSION ASEOUTES & HYDROELECTRIC SITES FIGURE - 7 IV. ENERGY RESOURCE ALTERNATIVES Of the three, Route (2) is considered the only potentially viable route within the perspective of this study which considers electrical loads up to about 50,000 kW (including electric heat). This route with its length of 59 miles is the shortest and lowest cost routing, but it does have more difficult access than the other two routings. Route (2) passes within easy reach of a number of small hydroelectric sites. A brief discussion of these sites with estimated power capacity and annual energy production follows. The sites are listed in order from Cordova towards Valdez. (1) Sheep River Lakes Location: - A chain of three lakes, elevation 2,026, 1,022 and 649, discharge into Sheep River at mile 1.0 in Section 23, Range 4 West, Township 13 South, Copper River Meridian. The upper and middle lakes outlets are in Section 21 and the lower lake outlet is in Section 22. Drainage area: - The upper lake has a drainage area of 0.75 square miles; the middle lake has a drainage area of 2.0 square miles; and the lower lake has a drainage area of 4.0 square miles as measured from the U.S.G.S. map "Cordova (C-6) Alaska", 1963 revision. Run off: - Discharge measurements have not been made for any of these lake outlets. The mean discharge is estimated to be in the same order as Power Creek near Cordova which has an average discharge of 12 cfs per square mile over a 32 year run-off record period. The average discharge is con- servatively estimated as 9 cfs for the upper lake, 24 cfs for the middle lake and 48 cfs for the lower lake. APA25/A8 IV-8 APA25/A9 IV. ENERGY RESOURCE ALTERNATIVES Regulation: - Complete regulation is not considered economically feasible for the watershed. The upper lake would require 4500 acre-feet of storage by raising the lake level 175 feet; the middle lake would require 8700 acre-feet by raising the lake level 210 feet; and the lower lake would require 13,900 acre-feet by raising the lake level 230 feet. Lake taps are not considered feasible for these small developments. A dam raising the upper lake level 85 feet would provide 80% regulation; the middle lake level raised 78 feet would provide 75% regulation; and the lower lake level raised 51 feet would provide 70% regulation. Dam Sites: - A field reconnaissance of the power sites has not been made, but a study of the U.S.G.S. map 1:63,360 suggests that a plan similar to the following is feasible. The upper lake level would be raised 85 feet with a rockfill dam and a 16-inch diameter penstock 2,400 feet in length would convey the water from the dam to the powerhouse at elevation 1,100 on the maximum shoreline of the middle lake. The middle lake would be raised 78 feet with a rockfill dam and a 24-inch diameter penstock 1,000 feet in length would convey the water from the dam to a powerhouse at elevation 700 on the maximum shoreline of the lower lake. The lower lake would be raised 51 feet with a rockfill dam and a 36-inch diameter penstock 2,600 feet in length would convey the water from the dam to a powerhouse on the Sheep River at elevation 50. Power Capacity: - The power capacity for the upper lake is estimated at 480 kW primary and 600 kW average; power capacity for the middle lake is estimated at 425 kW primary and 570 kW average, and the power capacity for the lower lake is estimated at 1,411 kW primary and 2,016 kW average. The total capacity for the three lake development is 2,316 kW primary Iv-9 (2) APA25/A10 IV. ENERGY RESOURCE ALTERNATIVES and 2,581 kW average. This would provide about 20,288 MWh of prime energy and 2,312 MWh of secondary energy annually. Lake 1488 Elevation - Near Beartrap Bay Location: - The lake is located mainly in Sections 9 and 10, of Range 4 West, Township 13 South, Copper River Meridian. The discharge stream is a tributary to the main creek that discharges into the upper end of Beartrap Bay. Drainage Area: - There is 3.0 square miles of drainage area into the lake as measured from the U.S.G.S. map "Cordova D-6) Alaska", 1965 revision. Run-off: - Discharge measurements have not been made. The mean discharge is estimated to be in the same order as Power Creek near Cordova which has an average discharge of 12 cfs per square mile over a 32 year runoff record period. The average discharge is estimated at 36 cfs. Regulation; - Complete regulation would require a storage capacity of 16,940 acre-feet. This would require raising the lake level about 100 feet. Raising the lake level 37 feet would provide about 5,550 acre-feet of storage and 75% regulation. Dam Site: - A field reconnaissance of the power site has not been made, but a study of the U.S.G.S. map 1:63,360 suggests a plan similar to the following is feasible. A rockfill dam near the outlet raising the normal maximum lake level to elevation 1,525 would provide storage for 75% regulation. A 30-inch diameter penstock 3200 feet in length would convey the water westerly from the dam to a powerhouse at elevation 150. The average effective head would be about 1,325 feet. IV-10 (3) APA25/A11 IV. ENERGY RESOURCE ALTERNATIVES Power capacity: - The power capacity is estimated at 2,505 kW primary and 3,340 kW average. This would provide about 21,940 MWh of prime energy and 7,320 MWh of secondary energy annually. Dead Creek - Gravina River Tributary Location: - The Dead Creek power site is located in Section 7, Range 4 West, Township 12 South, Copper River Meridian. Dead Creek discharges into Gravina River at river mile 4.5. The dam site is 0.5 stream miles from the mouth of Dead Creek. Drainage Area: - There are 35 square miles of drainage area above the dam site as measured from the U.S.G.S map "Cordova (D-6) Alaska", 1965 revision. Run-off: - Discharge measurements have not been made for Dead Creek. The mean discharge is estimated to be in the same order as Power Creek near Cordova which has an average discharge of 12 cfs per square mile over a 32 year runoff record period. The average discharge is estimated at 420 cfs. Regulation: - Complete regulation would require a storage capacity of 160,000 acre-feet. A dam forming a reservoir with a normal maximum water surface elevation of 350 would provide 36,800 acre-feet of storage above the 300 foot contour which would regulate the flow at 75%. Dam site: - A field reconnaissance of the power site has not been made, but a study of the U.S.G.S. map 1:63,360 suggests that a plan similar to the following may be feasible. A thin arch concrete dam near stream mile 0.5 approximately 275 feet high and a crest chord distance of approximately 640 feet would provide storage for 75% regulation and an average effective head of 260 feet. IV=ait (4) APA25/A12 IV. ENERGY RESOURCE ALTERNATIVES Power capacity: - The power capacity is estimated at 5,730 kW primary and 7,644 kW average. This would provide about 50,195 MWh of prime energy and 16,767 MWh of secondary energy annually. Remarks: - The Alaska Department of Fish and Game reports that the Gravina River supports a good run of pink and chum salmon. Fish mitigation measures, probably in the form of a hatchery, may be required for Dead Creek hydro development. A dock and approximately four miles of construction access road and clearing of the reservoir are other factors to be considered. Lake 1975 Elevation - Dead Creek Tributary Location: - Lake 1975 is located in Section 31, Range 5 West, Township 11 South, Copper River Meridian. The outlet stream discharges into Dead Creek at stream mile 1.2. Drainage Area: - There is 0.80 square miles of drainage area into the lake as measured from the U.S.G.S map "Cordova (D-6) Alaska, 1965 revision. Run-off: - Discharge measurements have not been made. It is estimated that the runoff in the area is 12 cfs per square mile or an average discharge of 9.6 cfs. Regulation: - Complete regulation would require 5,200 acre- feet of storage. About 900 acre-feet of storage could be obtained by raising the normal maximum water surface to elevation 2,000 which would provide about 45% regulation of the runoff. IV-12 (5) APA25/A13 IV. ENERGY RESOURCE ALTERNATIVES Dam Site: - A field reconnaissance of the power site has not been made, but a study of the U.S.G.S. map 1:63,360 suggests a plan similar to the following may be feasible. A rockfill dam raising the lake to a normal maximum water surface of 2,000 feet elevation would provide storage for 45% regulation. A 16-inch diameter penstock 3,700 feet in length would convey the water to a power house at elevation 350 in the Dead Creek valley. The average effective head would be about 1,600 feet. Power Capacity: - The power capacity is estimated at 484 kW primary and 1,075 kW average. This would provide about 4,240 MWh of prime energy and 5,177 MWh of secondary energy annually. Lake 1878 Elevation - Fidalgo Creek Tributary Location: - The lake outlet is located in Section 22, Range 5 West, Township 11 South, Copper River Meridian. The outlet stream discharges into Fidalgo Creek at stream mile 4.1. Drainage Area: - There are 2.25 square miles of drainage area at the outlet of the lake as measured from the U.S.G.S. map "Cordova (D-6) Alaska", 1965 revision. Run-off: - Discharge measurements have not been made. It is estimated that the runoff in the area is 12 cfs per square mile or an average discharge of 27 cfs. Regulation: - Complete regulation would require 14,600 acre-feet of storage. Raising the normal maximum water surface to elevation 1,950 would provide 3,600 acre-feet of storage and provide for 50% regulation. IV-13 (6) APA25/A14 IV. ENERGY RESOURCE ALTERNATIVES Dam Site: - A field reconnaissance of the power site has not been made, but a study of the U.S.G.S. map 1:63,360 suggests a plan similar to the following may be feasible. A rockfill dam raising the lake to a normal maximum water surface of 1,950 feet elevation would provide storage for 50% regulation. A 26-inch diameter penstock 5,300 feet in length would convey the water from the dam to a powerhouse located at the 500 foot contour in the Fidalgo Creek basin. The average effective head would be about 1,375 feet. Power Capacity: - The power capacity is estimated at 1,300 kW primary and 2,600 kW average. This would provide about 11,388 MWh of prime energy and 11,388 MWh of secondary energy annually. Fidalgo Creek - Run of River Plant. Location: -The dam site is located in Section 15, Range 5 West, township 11 South, Copper River Meridian. The power- house location is approximately 1,100 feet downstream from the dam at the 500 foot contour. Drainage Area: - There are 7.5 square miles of drainage area above the dam site as measured from the U.S.G.S. map "Cordova (D-6) Alaska," 1965 revision. Run-Off: - Discharge measurements have not been made. It is estimated that the runoff in the area is 12 cfs per square mile or an average discharge of 90% cfs. Regulation: - the site does not provide sufficient storage for regulation. Preliminary estimates are made by utilizing 50% of the water over a 6-month period. Iv-14 7) APA25/A15 IV. ENERGY RESOURCE ALTERNATIVES Dam Site: - A field reconnaissance of the power site has not been made, but a study of the U.S.G.S. map 1:63,360 suggests a plan similar to the following may be feasible providing no transmission costs are charged to the project. A rockfill dam at the 600 foot contour that would provide a normal maximum water surface at the 900 foot elevation would provide for most of the potential head. A 36-inch diameter penstock approximately 1,100 feet in length would convey the water from the dam to a powerhouse at the 500 foot elevation. The average effective head would be about 360 feet. Power Capacity: - The power capacity is estimated at 1,140 kW annual average utilized in a 6-month period. This would provide about 10,000 MWh of secondary energy annually. Silver Lake - Duck River Location: - The lake outlet is located in Section 6, Range 7 West, Township 11 South, Copper River Meridian. Duck River discharges into The Lagoon off Galena Bay in Section 1, Range 8 West, Township 11 South, Copper River Meridian. Drainage Area: - There are 25 square miles of drainage area at the lake outlet as measured from U.S.G.S. map "Cordova (D-7) Alaska," 1965 revision. Run-off: - The U.S. Geological Survey gaged Duck River for the 7-month period, June through December in 1913. The total discharge was 158,690 acre-feet for this period or 5,943.4 acre-feet per square mile. The average discharge of Power Creek for these months are 154,710 acre-feet or 7,546.8 Iv-15 APA25/A16 IV. ENERGY RESOURCE ALTERNATIVES acre-feet per square mile. This insufficient data indicates that the discharge per square mile is 79% of that for Power Creek on 9.5 cfs per square mile. A lower discharge per square mile is expected as the basin is protected on the south, east, and north by mountains. For this preliminary study, 9.5 cfs per square mile or an average discharge from Silver Lake of 237.5 cfs is used. Regulation: - Complete regulation would require 90,000 acre- feet of storage. Raising the normal maximum water surface to elevation 395 would provide 102,000 acre-feet of storage. Dam Site: - A field reconnaissance of the power site has not been made, but a study of the U.S.G.S. map 1:63,360 suggests a plan similar to the following would be feasible. A rockfill dam at the lake outlet raising the normal maximum water surface from elevation 306 to 395 would provide storage for complete regulation. A 76-inch diameter pipeline 5,300 feet in length would convey the water from the dam to a surge tank on the hill overlooking The Lagoon. A penstock 1,100 feet in length would then convey the water to the powerhouse at tidewater approximately 1,000 feet south of the mouth of Duck River. The average effective head would be about 335 feet. Power Capacity: - The power capacity is estimated at 5,645 kW prime and average power. This would provide about 49,450 MWh of prime energy annually. Transmission Line: - A transmission line approximately 18 miles long would need to be constructed between the hydroelectric site and the intertie transmission line. Because the terrain is similar to the intertie route it is envisioned that configuration, construction methods, and costs would be similar to the intertie transmission line. IV-16 IV. ENERGY RESOURCE ALTERNATIVES Studies of possible single wire ground return (SWGR) electric lines have been made which show potential benefits for transmission systems under some conditions. There is a small demonstration SWGR project operating today that is successfully delivering electricity from Bethel to Napakiak. The project is also demonstrating a single phase to three phase state- of-the-art converter which is in use supplying three phase power to the BIA school in Napakiak. Construction costs for the line to Napakiak were found to be about one third of the cost of conventional construc- tion. The transmission system of Route (2) could obtain substantial savings in the line costs by using this SWGR concept. Without an in-depth analysis, it is estimated that the overhead line costs can be reduced by up to one- fifth and that the single phase substations will cost 70% of the three phase equivalent. To these costs must be added the estimated single phase to three phase conversion costs. In summary, a potentially feasible transmission intertie to connect the Cordova and Valdez areas is represented by Route (2). Along this route are potential hydroelectric sites which could supply energy. The inter- tie could provide the opportunity to share capacity reserves and develop lower cost energy in the communities of Cordova and Valdez. d. Local Small Hydroelectric Development Crater Lake, close to Cordova, offers the possibility of a 435 kW prime powerplant with high head. Only a small dam would be required to dam the neck of the lake. It should be noted that the cannery at Orca has a water right of one cubic foot per second; a dual purpose water supply and hydropower project is attractive for Crater Lake discharge toward Orca. APA25/A17 IV-17 IV. ENERGY RESOURCE ALTERNATIVES 2s Coal Resources Coal is a viable alternative energy resource for Cordova. Two sources of coal for Cordova have been considered. 1) the Bering River Coal Fields east of the Copper River Delta, and 2) the Healy Coal Fields south of Fairbanks. Without large scale development for a world market, the Bering River Coal Fields, with an estimated delivered cost of $120 per ton, do not appear capable of delivering coal or energy to Cordova at competitive prices. The coal from the Usibelli Mine at Healy could be delivered to Cordova in 1981 for about $45/ton. The near future devel- opment (5-8 years) of the Beluga Coal Fields on Cook Inlet may reduce the cost of delivered coal still further. Despite the projected high cost of Bering River coal, these fields are of great local interest and, consequently, are reported on in some detail following. Development and production costs are identified in Appendix B. The Bering River Coal Fields are located 55 miles east of Cordova in the rugged terrain around Kushtaka Mountain (see Figure 8). Exposures of coal have been mapped over an area of 45 square miles. While the fields have been investigated several times over the years by various govern- mental and private agencies and some small scale mining took place in the early 1900's, several problems have plagued development: 1) access to a good shipping point is difficult; 2) the coal is faulted and folded to the extent that it is difficult to follow any one seam for more than a few hundred feet; 3) high annual precipitation, deep snowpacks, ava- lanching, flooding, and high winds are common in the area; and 4) recently, many of the lands through which access might pass have been classified as environmentally sensitive. Despite these problems, the fields still hold an allure. This is prin- cipally because estimated reserves are great (Sanders, 1976, estimated speculative resource for a 2 square mile area near Carbon Creek at 1.6 million short tons) and the quality of the coal is very high, yielding 10-15,000 Btu/1b. APA25/A18 IV-18 ee ye BERING RIVER COAL FIELD DEVELOPMENT FIGURE IV. ENERGY RESOURCE ALTERNATIVES The best known deposits in the Bering River area are those adjacent to Carbon Creek, which flows southwesterly along Kushtaka Ridge. The coals are Tertiary in age and range in grade from semibituminous to semi- anthracite. The coal ranges in heat content from 10,000 to 15,000 Btu/1b., has an average moisture content of 4% or less, and a relatively low ash and sulfur content. It should be noted that because of the sheared nature of the deposits, considerable mixing of the coal with the country rock may be expected. If washing is not effective in removing the foreign material, the overall character of the product will suffer. The coal is exposed on the surface in isolated pods and lenses that usually occur near the apex of folds or along associated faults. The thickness and persistence of beds is so variable that Sanders estimates coal-to-waste ratios for a small mine may run as high as 1:20. Any mining operation would have to be prepared to handle vast quantities of waste rock. A vigorous exploration program would be necessary to keep ahead of mining. Hydraulic mining methods, such as those used at the Kaiser Mine in British Columbia, have been suggested for the Carbon Creek coals. The abundance of natural ground water expected in any under- ground operation may become a positive factor for hydraulic mining instead of a negative one for traditional mining techniques. In the unlikely case that Bering River coal is mined, a mine mouth plant could be constructed for 25-50% more cost than a plant at Cordova. If the mine mouth power plant was built in the Carbon Creek area, a trans- mission line approximately 63 miles in length would be required to deliver the electric power to the Cordova diesel plant vicinity. The transmission line route would be mostly at elevations below 100 feet and would roughly parallel the road system that would connect the coal mining area to Cordova. About 37 miles of this road system already exists (a portion of the Copper River Highway). (See Figures 7 and 8). APA25/A20 IV-20 IV. ENERGY RESOURCE ALTERNATIVES 3. Qil_and Gas Resources The potential for economic exploitation of oi] and gas resources within the immediate vicinity of Cordova in the near future is low. The Katalla oil fields, about 50 miles southeast of Cordova, have produced oil in the past, but current exploration and development costs would be extremely high in relation to expected production. There is good potential for petroleum reservoirs in the eastern Gulf of Alaska from 50 to 100 miles away, although initial stratigraphic test wells in the closer, western parts of this province have shown discouraging results. While development of these fields would undoubtedly bring indirect economic benefits to Cordova, world demand will regulate price and thus direct savings on the cost of fuel is unlikely. The Copper River Basin (120 miles inland) is rated very low in potential for oi] and gas and is hardly any closer than currently producing wells in Cook Inlet. A closer look at the problems confronting the exploitation of the Katalla oil fields follows. Oil and gas from seeps along the shore were reported at Katalla in 1853. Between 1920 and 1933, the Katalla area produced a total of 154,000 barrels of oil from 16 shallow wells ranging in depth from 300 feet to 2000 feet. The light (37.96 API), clean (0.00%+S) oi] furnished fuel and lubrication oi] to Cordova and the McCarthy copper mines until the refinery at Katalla burned down in 1933. Since that time there has been no recorded production. Through the years, claims and/or leases have been held by Chilkat Oi] Company, Standard 0i1 of California, and Arabian Shield. Little activity has occurred in the area since 1961 when Richfield Oil Company drilled two unsuccessful wildcat wells (each about 6000 feet deep) along the Bering River ten miles east of Katalla. With available information, potential reserves are difficult to esti- mate. There are no accurate subsurface structural maps and drilling logs for the original wells have been lost. Past wells were drilled over known oil and gas seeps and usually produced about 100 to 300 barrels per day for the first few hours, then subsequently dropped to APA25/A21 IV-21 IV. ENERGY RESOURCE ALTERNATIVES less than 10 barrels per day. Pay zones were most commonly found between 360 feet and 750 feet in depth. The reservoir rocks are complexly faulted and folded sandstones, conglomerates and calcareous shales. Many, thin, intercalated organic-rich shales and coal partings are the probable source of the oi] and gas. Numerous local seepages suggest that traps are small and scattered. Therefore, while there may be a substantial amount of petroleum trapped below the surface, it is probably not concentrated in any one spot. If production were similar to the early days, it is possible that another 200,000 or more barrels might still be available. Production rates would be extremely slow unless some method of enhancing flow within the reservoir were used; 1/2 to 2 barrels per day per well. Previous attempts at enhancing flow by suction produced mostly salt water. R.H. McMullin of the U.S. Geological Survey has estimated that the onshore Gulf of Alaska province could have as much as 0.8 billion barrels of crude oi] and 0.9 trillion cubic feet of associated gas. These figures are based on a general knowledge of the lithologic, stratigraphic and structural disposition of Tertiary section from Icy Bay north to the Copper River. These figures, however, do not reflect the statistical probability of actually finding the oi] or gas. Exploration for oi] and gas, by its very nature, is a game against the odds. An oi] company executive might consider it a worthy gamble if he can expect to strike oi] in one of five or ten or perhaps even more wells drilled. At the costs involved in a single well, the stakes are very high indeed for the small entrepreneur, cooperative, or utility. Other complications at Katalla include access, transportation, and land status. The shoreline is exposed and shallow so a port facility would be costly. Access overland would need to cross rugged terrain, many miles of swamp, and several rivers. In addition, the route would cross environmentally sensitive areas. A cursory examination of land status records and the historical index at the Bureau of Land Management APA25/A22 IV-22 IV. ENERGY RESOURCE ALTERNATIVES shows that since the turn of the century numerous applications for coal, oil and gas permits and leases have been filed in this area. It appears for the most part that existing rights have either expired or been cancelled. Land status and current leasing procedure would need to be addressed carefully before specific sites might be considered. However, to identify all outstanding mineral rights would require an intensive land status review beyond the scope of this report. Besides the natural gas that occurs along with the oi] at Katalla, several observations of natural gas have been made in the Cordova area. Reportedly, geysers of mud and gas were observed on the Copper River Delta during and shortly after the 1964 earthquake. The most reasonable explanation is methane ‘gas derived from buried organic debris was released during settlement of the loose Delta sediment. There is little chance that any methane could be collected from shallow wells in the Delta. Periodically, large exhalations of gas have been noted from beneath the surface of Kushtaka Lake. In winter the gases have been known to burst through the ice. The gases here are probably related to buried coal seams which are prevalent in the area. While these gas occurrences are a curiosity, it is unlikely that any use can be made of them in the near future. It should be noted at this point that Chugach Natives, Inc., is the Alaska Native Regional Corporation for the area encompassed in this study. Once Chugach receives its Alaska Native Lands Claim Act of 1971 entitlement of about 377,000 acres, Chugach will become primarily a natural resources company. Lands currently under consideration for transfer to Chugach include several of the small potential hydroelectric sites discussed jin this study, along with the Bering River coal field area and the Katalla oil] and gas area. Chugach Natives, Inc., has determined that neither the Bering River or Katalla resources show sufficient economic promise to justify development solely for local use. However, as a natural resources company, Chugach APA25/A23 IV-23 IV. ENERGY RESOURCE ALTERNATIVES has begun and intends to continue to pursue the development of these resources for non-local consumption. If Chugach's negotiations are successful on the coal resource in particular, then the economics of utilizing a portion of the coal for local use are altered radically and could become a viable energy alternative for Cordova. 4. Geothermal Resources The possibility of utilizing geothermal energy for generation of electric power or for heating in Cordova is very remote. No geothermal resources have been recorded in the literature or reported by local residents to exist within a reasonable distance of Cordova. 5. Wind Resources Wind generating and heating devices are generally uneconomic unless mean annual wind speeds are at least 12-15 miles per hour (mph). The mean speed at the Cordova Mile 13 Airport is 4.4 mph and Corps of Engineers data for Cordova indicates a mean wind speed of 7.9 mph at the small boat harbor. This resource has thus been eliminated as offering any significant contribution to Cordova's energy future. However, Wind Energy Conversion Systems are discussed at length in Appendix C because of a great deal of locally expressed interest in such systems. It has been estimated that fuel oi] will have to rise to more than $5 per gallon before wind heating becomes economic in areas with significantly higher wind speeds than Cordova. The only two proximate sources of wind with possibly sufficient speeds are the adiabatic winds off glaciers and high winds verbally reported in the Copper River Delta. However, no data is currently available for these resources and both resources are considerable distances from Cordova. APA25/A24 IV-24 IV. ENERGY RESOURCE ALTERNATIVES 6. Solar Resources A comparable study indicates that with proper new design considerations, passive solar heating can provide 40% of the heat required by an average residence, even in the coldest months. Active solar collectors and heat storage facilities installed in newly built homes have been found to be competitive with fuel oi] furnaces only if the cost for diesel oil is more than $2.50 per gallon at present equipment cost. Solar photovoltaic energy conversion is still uneconomical at an estimated $1/kWh for the present state-of-the-art. ‘ Tidal Resources Large tidal currents were verbally reported in The Narrows area near Cordova. However, our present understanding is that these currents are of insufficient magnitude for economic energy capture. Furthermore, tidal facilities are very capital cost intensive and require expensive storage facilities unless they are part of a large power grid. These factors serve to eliminate this resource for further consideration for Cordova. 8. Biomass Resources Due to Cordova's location in the Chugach National Forest, wood is in quite abundant supply. However, the magnitude of wood supply required to fulfill all of Cordova's present and future energy needs would greatly decimate this protected (and likely environmentally unobtainable) resource. Use of wood for residential heating is expected to continue to provide about 2 percent of such needs in Cordova. Another biomass resource available in Cordova is the use of cannery waste to produce biogas (two-thirds methane) by anaerobic digestion. The wastes are decomposed in atmospherically sealed and heated tanks, resulting in biogas and a high quality fertilizer effluent. However, a rough calculation for wastes at the large St. Elias Ocean Products APA25/A25 IV-25 IV. ENERGY RESOURCE ALTERNATIVES facilities indicated that only about 20 kW of base load generation could be obtained. This contribution to the overall Cordova energy picture is essentially negligible. 9. Waste Heat and Cogeneration Resources The present use of fossil fuels (coal, gas, oil) to produce more useful forms of energy (electricity or motive power) is far less than 100 percent efficient. For example, if a machine burns a certain quantity of fossil fuel and produces useful output (shaft horsepower or elec- trical energy) equivalent to 30% of the fuel burned, the energy repre- sented by the remaining 70% of the fuel will appear as unused or "waste" heat. Such heat most often appears as hot exhaust gas, tepid to warm water (65°F-180°F), hot air from cooling radiators, and direct radiation from the machine in question such as a steam turbine or diesel engine. a. Diesel Waste Heat Diesel waste heat can be recovered from engine cooling water and exhaust or from either source separately. The waste heat is typically transferred to a water-glycol circulating system in Alaskan appli- cations. The heated circulating fluid can be used for space, water, or process heating. Capture of diesel waste heat to power binary cycles could provide about 300 kW based on current diesel usage. Several binary cycle projects are currently in the planning stage in Alaska. b. Gas Turbine Waste Heat Gas turbine waste heat is typically recovered from the exhaust stream passing through commercially available waste heat boilers and producing steam or a heated water-glycol mixture. APA25/A26 IV-26 IV. ENERGY RESOURCE ALTERNATIVES Small combustion turbines with waste heat recovery are manufactured both domestically and overseas. Current installed capital costs for cogeneration equipment depend on site conditions, local labor costs, and ancillary equipment; however, average values for systems are reported to range from about $350/kW to $700/kW. c. Steam Turbine Cogeneration Approximately 30% to 40% of the heat supplied by the fuel ina conventional fossil steam electric generating station is converted into electric energy. These losses can be reduced when one of a number of alternate schemes for converting power plants into cogen- eration plants is implemented. For example, the total loss can be reduced to less than 25% if cogeneration of steam is employed. Such steam could be used for district heating. The actual annual fuel savings achievable in a district heating system are determined by such factors as the percentage of total system heat load to be supplied by peak heating plants, the oper- ating point of each cogeneration unit, loading sequence selected for the cogeneration units, total heat of the steam extracted from each cogeneration unit, fuel differential required to replace the reduced electric generation of cogeneration turbines by less efficient units, and unit availabilities. Results obtained from an analysis of these variables will vary from system to system depending on the type of cogeneration units and district heating equipment installed. A recent study for a planned district heating system using modified turbines indicated that slightly more than 50% fuel savings can be achieved over a typical annual heating cycle. 10. Conservation Construction of, or retrofit for, well insulated homes in the Cordova area can provide significant residential fuel savings. Estimates for a APA25/A27 IV-27 IV. ENERGY RESOURCE ALTERNATIVES 1000 square foot "typical" home indicate: a well insulated home uses about 540 gallons of oil per year; a home with average insulation would use about 830 gallons per year; and a poorly insulated home would require nearly 1380 gallons per year. Clearly, individual savings can be signi- ficant. Current commercial equipment allows recycling of diesel lubricating oi] to replace 5% of the diesel fuel. At current prices, this could save about $75,000 and 65,000 gallons of diesel fuel per year. Such a system is currently being implemented in Cordova on a limited scale. 11. Other Resources The following resources and technologies are either still in need of technology development for economic utilization or offer only small, decentralized applications that will serve to replace some diesel fuel uses. a. Uranium No commercial technology exists in the 10 MW range. b. Coal Gasification The technology is costly and unproven commercially. Gs. Fuel Cells The technology is costly and still in the developmental stage. d. Hydrogen Hydrogen can be produced from surplus hydroelectric power; this technology is expected to become economic in the 1990's. APA25/A28 IV-28 IV. ENERGY RESOURCE ALTERNATIVES Hydrogen stored as hydrides may make significant impact in the transportation sector in the long term. e. Heat for Heat Pumps This is a proven small scale technology and is discussed in detail in Appendix C. APA25/A29 Iv-29 V. energy technology alternatives V. ENERGY TECHNOLOGY ALTERNATIVES V. ENERGY TECHNOLOGY ALTERNATIVES Appendix C contains detailed profiles of appropriate energy conversion technologies for Cordova, including descriptions, performance character- istics, costs, special requirements and impacts, and a summary and critical discussion. Brief abstracts of the following relevant pro- files are presented in this section. diesel-electric generation oi] heating hydroelectric generation electrical heating transmission interties coal fired steam-electric generation coal and wood heating diesel lube oi] recycling diesel waste heat recovery and use steam cogeneration systems conservation wind energy conversion systems. heat pumps A general summary of energy available in the primary resources considered is shown in the following table, Table V-1. APA25/b1 V-1 V. ENERGY TECHNOLOGY ALTERNATIVES TABLE V-1 FUEL ENERGY CONTENT Energy Content Fuel Type in Btu/pound No. 6 Fuel Oil (Diesel) 17,400 = 19,000 Biogas 15,000 ” 15,700 Bituminous Coal 13,000 - 13,600 Sub-Bituminous Coal 11,000 Lignitic Coal 6,500 - 7,000 Wood 5,000 = 8,600 Water at 100 Foot Head 8 Hot Water at 1°F Temperature Difference 1 Air Moving at 22 mph (stp) Aly ue Diesel-Electric Generation In the diesel fueled engine, air is compressed in a cylinder to a high pressure. Fuel oil is injected into the compressed air, which is at a temperature above the fuel ignition point, and the fuel burns, convert- ing thermal energy to mechanical energy by driving a piston. Diesel engines driving electrical generators are one of the most efficient simple cycle converters of chemical energy (fuel) to electrical energy. 2s Oil Heating Fuel oi] is burned with air in a burning unit which produces hot air or hot water for space heating. This is the most widespread heating technology practiced in Cordova. APA25/b2 V=2 V. ENERGY TECHNOLOGY ALTERNATIVES a. Hydroelectric Generation Hydroelectric generation involves water turning a turbine which in turn drives a generator. Several families of turbines exist; application is a function of flow and head (distance from the top of the water surface to the turbine). Development of hydroelectric sites in the Arctic encounters many problems which are not present in more temperate areas of the world. Logistics problems associated with engineering and construction of hydroelectric projects in the harsh Arctic environment are certainly among the most difficult and challenging of any in the world. In addition, construction itself is a challenge, since only in protected locations, such as heated enclosures and underground, can construction proceed with any efficiency during the cold period. Hydroelectric sites must be chosen which have adequate storage to allow for generation during the cold months when inflow is diminished, as well as to provide carry-over storage for dry years. 4. Electric Heating Since the capacity of the hydro project is typically relatively large compared to the initial demand of the supplied area, the cost per kWh is rather high since the large investment has to be paid for whether its capacity is used or not. Utilization of this surplus capacity in electric home heating (at a rate comparable to cost for heating with other systems) is an attractive possibility. The problem arises when -- at a later point in time -- the area demand (minus the electric heat) approaches the capacity of the hydroplant. APA25/b3 V=3 V. ENERGY TECHNOLOGY ALTERNATIVES The following scheme appears to allow for all the benefits and avoids most of the problems electric home heating can have for a utility and the homeowner: a The homes are built with a conventional heating system plus elec- tric heat. 2. The utility pays for the installation of the electric heat and its control. 3. The utility sells the energy for the electric heat at a rate equal or lower than the other heat supply fuel cost. 4. The utility is allowed to control utilization of the electric heat -- that is, turn it off during times of peak demand. During these times the "normal" heating system supplies comfort heating for the home. The existing alternate home heating system actually provides peaking capacity to the utility. 5s Transmission Interties Transmission interties provide electrical power connections between communities and electrical generation sources. The electricity is transmitted by wires or a single wire with ground return. The large (50 MW) transmission intertie discussed in the previous sec- tion is of size proven to be economic in other locales. Costs could conceivably be lowered by using single wire ground return (SWGR) trans- mission. Demonstration projects utilizing this type of transmission are presently under contract with the State of Alaska, Divison of Energy and Power Development. As SWGR is increasingly proven technically and economi- cally feasible in Alaska, this type of construction holds great promise for providing less costly electric energy. APA25/b4 v-4 V. ENERGY TECHNOLOGY ALTERNATIVES 6. Coal-Fired Steam-Electric Generation For coal-fired steam-electric generation, coal is ground to roughly 2-inch diameter or less chunks and fed into a boiler or pulverized and blown into a boiler. The coal is then burned in the boiler to produce steam that is then expanded in a turbine which drives a gener- ator to produce electricity. Steam plants account for the majority of electrical generation in the United States today. Although steam plants can accommodate a wide range of loads, U.S. economies of scale indicate that the cost per unit increases sharply in sizes below about 50 MW. It should be noted that European coal-steam generation units are more economically employed in the less than 10 MW range. A 5 MW coal-steam plant for Cordova could be constructed at a capital cost of about $1,700/kW; a 10 MW plant could cost about $1,200/kW. Operating costs for such plants are relatively high due to the need for highly skilled operators. It should also be noted that storage requirements for a coal plant in Cordova could be a stockpile 20 feet high and 250 feet square. Due to the high rainfall in the Cordova area, a 20,000 gallon per day (nominal) treatment plant would be required to treat runoff from the stockpile. A similar plant at Elmendorf Air Force Base operated well enough to discharge water to Ship Creek, a salmon spawning area. Ta Coal _and Wood Heating Coal or wood is mechanically or hand fed into a combustion chamber where it is burned with air to produce hot air or heated water for space heating. APA25/b5 V-5 V. ENERGY TECHNOLOGY ALTERNATIVES 8. Diesel Lube Oi] Recycling A number of proven commercial systems exist for cleaning and recycling diesel engine lubricating oi] for use as diesel fuel when blended as 1 part recycled oil to 20 parts diesel fuel. These systems are generally suited to fleets of diesel engines (25, more or less) as fewer units do not produce enough used lube oil for the 1:20 ratio of the fuel mix. 9. Diesel Waste Heat Recovery and Use Typically 30% of the fuel energy supplied to a diesel-electric set is converted to electricity, 30% is transferred to cooling water, 30% is exhausted as hot gas, and 10% is radiated directly from the engine block. The exhaust heat in a diesel is of higher temperature and more easily used than the cooling water heat, but higher initial costs and increased operating complexities are encountered when attempting to recover energy from the exhaust. 10. Steam Cogeneration Cogeneration involves use of some of the steam used to drive turbine- generators for heating or industrial process loads. Cogeneration is widely used, particularly in the Scandanavian countries, to provide steam for district heating systems. 11. Conservation Conservation measures for Cordova would mainly be of the passive type: insulation, arctic entrances, double or triple glazed windows, and the like. These measures decrease heating energy requirements for the typical residence. 12. Wind Energy Conversion Systems As has been noted in the previous section, the wind speeds at Cordova are apparently too low for economic generation of energy from the wind. APA25/b6 V-6 V. ENERGY TECHNOLOGY ALTERNATIVES However, a detailed profile of the technology is presented in Appendix C because of local interest and the possibility of properly located residences adapting this intermittent energy source. 13. Heat Pumps A heat pump operates much like a refrigerator or air conditioner. The heat pump extracts heat from a source at low temperature (air or water) and rejects it to a sink (a building, for example) at a higher temperature by input of electrical and mechanical work APA25/b7 V-7 VI. evaluation of feasibility of energy alternatives VI. EVALUATION OF FEASIBILITY OF ENERGY ALTERNATIVES VI. EVALUATION OF FEASIBILITY OF ENERGY ALTERNATIVES This section outlines the six electrical plans and a combined electrical- waste heat recovery plan formulated to meet Cordova's energy requirements to the year 2000. These plans, or scenarios, are designed to meet Alaska Power Authority "Standard Criteria" for reconnaissance studies; a base case plan is developed that results from a continuation of current energy practices and serves as a basis for comparing alternative plans that also meet forecasted requirements. All plans are intended to provide a common level of reliability. The following development scenarios are necessarily speculative. They implicitly contain various assumptions regarding resource availabilities, development costs, market prices, and technology state-of-the-art. They are based on the data available for this study and engineering experience with other projects in Alaska. The scenarios have been presented in a way which allows easy adjustment of parameters used for the analyses as more specific data become available. Only the utilization of local hydro, transmission intertie with Valdez (with and without small hydro development) and Healy Coal, appear to be technically and economically feasible for Cordova's overall needs at this time. Table VI-1 summarizes the alternative plans evaluated based on APA recommended economic factors and Figure 9 graphically compares the present worth cost of the alternatives. Appendix D contains details of the analyses. TABLE VI-1 COSTS OF MEAN ALTERNATE DEVELOPMENT PLANS EARLIEST YEAR YEAR YEAR OF 2000 ACCUMULATED 2041 ACCUMULATED ALTERNATE PLAN OPERATION _ PRESENT WORTH PRESENT WORTH Electric w/heating (Surplus @ 6. 25¢/kWh) 1983 $104 ,734,000 $237 571,000 Electric w/heating (Surplus @ 1¢/kWh) 1983 96,758,000 229,595,000 APA25/C1 Visi VI. EVALUATION OF FEASIBILITY OF ENERGY ALTERNATIVES Diesel Generation - Base Case 1981 64,383,000 168,527,000 Coal Generation - Carbon Creek 1983 76,190,000 165,634,000 Diesel Generation w/Waste Heat 1983 56,507,000 148 , 968,000 Coal Generation - Healy Coal 1983 43,236,000 93,065. 000 Intertie (Surplus @ 6.25¢/kWh) 1983 45,076,000 89,297,000 Intertie - (Surplus @ 1¢/kWh) 1983 37,194,000 81,415,000 Local Hydro 1983 28,220,000 61,720,000 poe Diesel Generation Base Case Plan a. Plan Components Diesel generation for power and fuel oi] for heating. b. Timing of System Additions 2500 kW additions in 1985 and 1995. Cc. Plan Description This base case plan assumes exclusive continuation of diesel generation for power and fuel oi] for heating; this plan results from continuation of present practices in Cordova and serves as the basis for comparison of the alternative plans following. All plans are based on the mean growth scenario as it is the most probable scenario and provides the most meaningful base for comparisons. Figures 10A and 10B follow illustrate this oi] based plan. Be Healy Coal Generation Alternative Plan a. Plan Components Coal-fired steam-electric generation at Cordova with diesel generation supplement. b. Timing of System Additions 5 MW coal-fired generating units in 1983 and 1991. APA25/C2 vI-2 6 3YNSI4S VAOGHOD JO ALIS SNV 1d 3LVNYSLIV 40 L1S09 HLYOM LN3S3ud ACCUMULATED PRESENT WORTH (MILLION DOLLARS) ° $ 8 8 $ § 8 & 8 & 8 - on $ 8 8 8 8 8 O12 022 oe Ove COAL GENERATION — CARBON CREEK ERATION WITH WASTE HEAT U< U< am am mp m> Ow nD COAL GENERATION — HEALY COAL Q Oy 38 59 b ° = =o °o °o x a a INTERTIE (SURPLUS @ 6.25 ¢/KWH) 7 z INTERTIE (SURPLUS @ 1¢/KWH) LOCAL HYDRO 14000 13000 11000} HIGH PROJECTION 10000 = 9000 + [ x DIESEL < CAPACITY a 8000 i 7000} 600 500) 1981 BASE LOAD PEAK POWER 4000) } DIESEL ONLY SCENARIO CITY OF CORDOVA ' FIGURE I0A 1980 1981 1982 1983 1984 1985 1986 1987 988 = 1989 1990 YEAR 1991 I992 1993 1994 1995 996 1997 1996 1999 200: 10- MWH ENERGY REQUIREMENT MEAN PROJECTION Oo 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 I997 1998 1999 2000 YEAR ° 198 ELECTRICAL ENERGY REQUIREMENT DIESEL ONLY SCENARIO CITY OF CORDOVA FIGURE 10B VI. EVALUATION OF FEASIBILITY OF ENERGY ALTERNATIVES Cc; Plan Description This plan is based on mean population growth and assumes retire- ment of present diesels except for back-up and peaking use. Coal-fired units are sized in 5 MW increments, a reasonable economic size. This plan attempts to keep the required reserve capacity low and to phase the transition to a totally coal-fired plant in such a manner as not to render the existing diesel plant obsolete at an early date. Figures 11A and 11B depicts this alternate electrical generation plan. 3. Carbon Creek Coal Generation Alternative Plan This plan is identical to the preceding Healy coal plan except the power plant is located at the Carbon Creek mine mouth and electricity is transmitted to Cordova. 4. Intertie with Valdez Alternative Plan a. Plan Components Surplus electrical energy by intertie with Valdez supplemented by Silver Lake hydroelectricity almost entirely replacing diesel generation. b. Timing of System Additions The intertie is assumed to be operational and surplus energy available in 1983 and Silver Lake is assumed on line in 1991. c. Plan Description Diesel generation would be supplemented by surplus energy available by intertie with Valdez and briefly replaced by the surplus in 1986. APA25/C6 VI-6 remn new CEE - PT LAL Cee ' = EXPAND RETIRE COAL & PLANT a LOW PROJECTION PEAK POWER COAL SCENARIO CITY OF CORDOVA FOQURE IIA 1980 1981 982 1983)0=— 1884) Ss 1985) = 1966 )=—s 987) = 1986 OD S990 —s1991 1992 1995 B96 997 «6 1988)=— 1999 §=2000 ENERGY REQUIREMENT MEAN PROJECTION wa wf | 10° MWH 1980 = 1981 i982 61983 1984 1985 1986 1987 1988 1989 1990 61991 1992 81993 YEAR ELECTRICAL ENERGY REQUIRMENT COAL SCENARIO CITY OF CORDOVA FIGURE 11B VI. EVALUATION OF FEASIBILITY OF ENERGY ALTERNATIVES Diesel generation would be utilized as supplement until the 1991 addition of conservatively estimated Silver Lake hydroelectric potential and would then be retired except for slight use in 1997-2000. Figures 12A and 12B depict this alternate electrical generation plan. 5. Intertie Alternative Plan with Electrical Heating a. Plan Components Surplus electrical energy by transmission intertie with Valdez combined with new intertied hydroelectric projects replacing diesel generation b. Timing of System Additions Surplus available in 1983. Hydroelectric additions in 1985 (optimistic Dead Creek estimate); 1988-(Silver Lake); 1990 (Lake 1488), 1992 (Lake 649), and 1995 (Lake 1878). Cs Plan Description This alternative plan is not directly comparable with the other alternative plans and the base case diesel only plan: this plan assumes the development of sufficient intertied hydroelectric projects to provide all electrical generation requirements for Cordova and most of the electrical capacity required for total conversion of Cordova to electric resistance heating. It is recognized that all alternative plans would have to be formulated to meet the total demand that includes the space heating energy requirements in order for plans to be strictly comparable; however, the magnitude of the total energy requirement is such as to make the other alternatives highly impractical and of little relevance to this reconnaissance study. This alternative case is presented as illustrative of the cost APA25/C9 VI-9 14000 10000 PEAK POWER INTERTIE SCENARIO CITY OF CORDOVA FI@URE [2A 1980 196! 1982 1983)=— 1984 = 1985 =: 1986 1987 988 = 1989 fea 1991 1992 1993 1994 1995 wee 997 «1988 = 1999 =2000 YEAR ENERGY REQUIREMENT MEAN PROJECTION 7 PLP LA CLLLALELLE LA SASSI S ASA SAOSSINASSS ce 47 47 re oe 474 te 0 \ \ SA pee ANSANNN NANNNANN NANANANN NNNNANANN SLANSSAAS hte NNANANN SAAANA'N 4 J, 4 4 ee 4 4 ELECTRICAL ENERGY REQUIREMENT INTERTIE SCENARIO CITY OF CORDOVA FIGURE 12B VI. EVALUATION OF FEASIBILITY OF ENERGY ALTERNATIVES penalty of continued reliance on diesel generation. The accumulated present worth cost to provide an equivalent amount of heating with fuel oi] over the same period would be $72,800,000. Adding this amount to the present worth cost for the base case diesel generation proves that it would cost less to have electricity plus electrical heating by hydroelectricity than continuation of current practice, ji.e., electricity with diesel generation and heating with fuel oil. Figures 13A and 13B depict this alternative plan and reflect a relatively even rate of hydro site development and the fact that not all of Cordova is expected to utilize electric space heating. 6. Local Hydroelectric Alternative Plan a. Plan Components Diesel generation eventually supplementing hydroelectricity from two local projects. b. Timing of System Additions Hydroelectric projects in 1983 and 1985. Gs Plan Description Development of hydroelectricity from Power Creek and Crater Lake will require supplemental diesel generation to meet seasonal hydro MWH deficits. Figures 14A and 14B depict this plan. ts Diesel Generation With Waste Heat Recovery Plan a. Plan Components Waste heat recovery equipment installed in the existing power plant to provide steam to levelize heat load of two canneries; APA25/C12 VI-12 PEAK ADD SILVER LAKE ELECTRICITY & E MEAN PROJECTION DEMAND LECTRIC HE of o=="|~“—ADD SURPLUS DIESEL 1980 1985 1990 YEAR 1995 2000 PEAK POWER ELECTRICAL HEATING SCENARIO CITY OF CORDOVA FIGURE I3A wu Mw 200 180) 160 40 120 + + ELECTRICITY INCLUDIN HEATING, MEAN PROJECTION 100 80 60 40 1980 1981 RE 7 7, 1982 1983 \ N BS e) bh IN ah” OPA SS TSI RO RQ RQ RAS CON ammes A pee PSS SII RRR VLALLALSS VED ICLA CORIO ON GIO MOL ECT A A Te - \ KS SS KA 984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 YEAR ELECTRICAL ENERGY REQUIREMENT ELECTRIC HEATING SCENARIO CITY OF CORDOVA FIGURE I3B ESTIMAICU FCrAR AW 14000 13000! Le | CRATER LAKE 12000 == 11000} 10000 9000 + POWER CREEK 8000 7000 50 PEAK POWER LOCAL HYDRO WITH 4000) y . DIESEL SCENARIO CITY OF CORDOVA FIGURE I4A 996 B97 1998 1989 1990 1993 1994 1995 1999 2000 YEAR 1991 i992 1980 1981 1982 = 1983 1984 1985 1986 1987 1988 ENERGY REQUIREMENT MEAN PROJECTION < EI AAAS » 1980 1981 1962 = 1983, 1984 §=1985 1986 1987 1988 19869 1990 = 1991 i992 1993 1994 1995 1996 1997 1998 1999 2000 ELECTICAL ENERGY REQUIREMENT LOCAL HYDRO WITH DIESEL SCENARIO CITY OF CORDOVA FIGURE 14B VI. EVALUATION OF FEASIBILITY OF ENERGY ALTERNATIVES provide hot water for space heating of a motel, the community center building, and the swimming pool; and heat the city water supply. (See Example 1, Appendix C.3.5.2). b. Timing of System Additions System installed and operational in 1983 é. Plan Description This plan assumes continuation of diesel generation for power and, except as described in "a" above, fuel oil for heating. Waste heat recovery equipment would be installed on the existing generation equipment. 8. Evaluation of Alternative Plans a. INTRODUCTION In accordance with Alaska Power Authority (APA) Reconnaissance Study Regulations, the alternative plans presented have been evaluated on the basis of the economic, environmental, and technical factors following: a Economic - Present worth of plan costs using "APA Analysis Parameters for FY '81" e Environmental Community preferences oe Impact on community infrastructure = Timing in relation to other capital projects a Air quality - Water quality ss Fish and wildlife impact APA25/C17 Viet? VI. EVALUATION OF FEASIBILITY OF ENERGY ALTERNATIVES - Land use - Terrestrial impacts. e Technical - Safety = Reliability = Availability b. ECONOMIC FACTORS The costs of each alternative plan, both capital and operating, were assigned to their appropriate years in the 20 year planning period beginning in 1981. These costs were then discounted at 3 percent per year and summed to determine the present value of plan costs. Potential plan outputs other than electrical energy, such as heat for space or water heating, are considered as separate economic cases. The net benefits of these outputs or "residuals" are estimated by assessing their market value or the value of the saving realized in the residual's displacing some other energy source less the costs directly required to actually realize the benefit of the residuals. The net benefits were then discounted at 3 percent per year and summed to determine the present value of plan costs. The inflation rate used is zero. The costs of diesel oil, fuel oil, and other petroleum fuels are assumed to escalate over the 20 year planning period at an annual rate of 3.5 percent over inflation. All other costs are not escalated over the assumed zero percent inflation rate. Appendix D presents details of the economic factor analyses of the alternative plan costs. APA25/C18 VI-18 VI. EVALUATION OF FEASIBILITY OF ENERGY ALTERNATIVES G. ENVIRONMENTAL FACTORS Community preference evaluations were based on the preferences of Cordova citizens as expressed in private and public meetings. Naturally, the more vocal members of the community most influenced this evaluation. The evaluation of impact on community infrastructure - infrastructure is here taken as the underlying framework of the community as a whole - is highly subjective at the reconnaissance study level and is largely based on the least disturbance being best for the community. Evaluation of alternative plan timing in relation to other capital projects is chiefly a measure of how soon and easily a plan can be realized. Air quality impacts are largely of two classes, hydro impacts (minimal) and fossil fueled impacts (average). The fossil options are assumed to have average performance emission abatement equip- ment; relaxation or tightening of typical emission abatement designs can have significant impact on the plan costs used in this study. The impacts of coal storage runoff due to precipitation are the Major considerations in water quality evaluation. Fish and wildlife impacts were chiefly evaluated based on water quality impacts, air quality impacts, and habitat disruption impacts. The major criteria for the land use impact evaluation was the amount of "local" (within 100 miles) land converted to strictly power production use and its proximity to Cordova proper. Hydroelectric facilities, it should be noted, offer secondary recreational uses. APA25/C19 VI-19 VI. EVALUATION OF FEASIBILITY OF ENERGY ALTERNATIVES The terrestrial impact evaluation is a measure of overall disruption of organic life on earth, any long-term change from present being taken as negative. This evaluation reflects the perception of worldwide carbon dioxide production from coal-fired power plants as the most significant terrestrial impact. Appendix C presents details of many environmental impacts of the components of alternative plans. d. | TECHNICAL FACTORS Safety is evaluated on the basis of risk of catastrophic accidents to workers and the normally proximate public. Reliability is taken as the measure of consistency of performance. Availability is taken as the measure of readiness for performance. e. EVALUATION MATRICES Evaluation of the above factors has resulted in the following evaluation matrices, Tables VI-2 and VI-3. Economic evaluations resulted in the quantitative present worth costs previously indicated and are ranked alphabetically, "A" being best. It is recognized that the evaluation of many environmental factors is necessarily subjective and that the technical factors are actually qualitative in relative evaluation. The following values were used in the relative evaluation of these subjective or qualitative factors: Value Interpretation a8 Best Possible Plan 2 Very Good Plan 3 Above Average Plan APA25/C20 VI-20 VI. EVALUATION OF FEASIBILITY OF ENERGY ALTERNATIVES Value Interpretation Barely Above Average Plan Average Plan (Neutral value) Barely Below Average Plan Below Average Plan Very Poor Plan won onw + Worst Possible Plan The evaluation matrix results show advantages for the local hydro plan and intertied surplus plus hydro plans. The reader should note that no economic rankings have been assigned to the non-electric scenarios as such evaluation would require a separate feasibility study. However, the following examples of residual benefits point out the savings inherent in substitution of coal for diesel and in utilization of diesel waste heat. Based on costs developed in this report, the substitution of Healy coal at 8,000 Btu/pound for diesel heating saves the equivalent of $8.91 - 2.81 = $6.10 per million Btu. This means a saving of $0.84 per gallon of diesel displaced at 1981 costs, or an equivalent annual savings of $1.38 per gallon displaced, assuming coal heat comes on line in 1983 and diesel price escalates at 3.5% per year. The substitution of Carbon Creek coal at 12,000 Btu/pound for diesel heating saves the equivalent of $8.91 - 5.00 = $3.91 per million Btu. This means a savings of $0.54 per gallon displaced, or an equivalent annual savings of $1.07 per gallon displaced. Actual benefits of coal heating will be a direct function of amount of diesel displaced, cost to convert heating systems to accept coal, and environmental impacts associated with it. APA25/C21 VI-21 APA 25L1 FACTOR (A) ECONOMIC (Present Worth) (B) ENVIRONMENTAL Q) (2) (3) (4) (5) (6) 7) (8) Community Preferences Infrastructure Timing Air Quality Water Quality Fish and Wildlife Land Use Terrestrial Impacts Total ENVIRONMENTAL RANKING (C) TECHNICAL (1) Safety (2) Reliability (3) Availability Total TECHNICAL RANKING OVERALL RANKING DIESEL- ELECTRIC IDnnnunrew wo nN a ole Mm % TABLE VI-2 EVALUATION MATRIX LOCAL HYDRO A [east eo erin airea teeta nN ra) wl » eH ELECTRIC SCENARIOS CARBON HEALY CREEK ELECTRIC COAL INTERTIED COAL HEATING ELECTRIC _HYDRO ELECTRIC G Cc B E 5 5 3 2 5 5 2 a 6 2 4 2 1 5 1 5 1 7 2 7 4 7 4 Z 5 6 4 6 5 6 4 6 32 43 24 42 5 7 2 6 1 3 2 3 3 2 1 2 3 2 Z 2 7 7 5 7 4 4 2 4 DIESEL ELECTRIC __W/WASTE HEAT _ Ins|ino) S |nO)on ns) es) leo Np ~ ol m © APA 25L2 TABLE VI-3 EVALUATION MATRIX NON-ELECTRIC SCENARIOS DIESEL COAL LUBE OIL co- HEATING HEATING RECYCLING GENERATION CONSERVATION WECS (A) ECONOMIC N/A N/A N/A N/A N/A N/A (B) ENVIRONMENTAL (1) Community Preferences 9 6 2 3 1 a (2) Infrastructure 5 4 5 2 3 5 (3) Timing aL 2 2 2 1 7 (4) Air Quality 6 7 5 5 1 1 (5) Water Quality z 6 2 7 1 1 (6) Fish and Wildlife 2 6 2 7 1 2 (7) Land Use 2 5 2 6 1 3 (8) Terrestrial Impacts_2 6 m4 _6 ml 3 Total 29 42 22 38 10 25 ENVIRONMENTAL RANKING 5 7 3 6 1 4 (C) TECHNICAL (1) Safety 2 3 Z 3 1 2 (2) Reliability 2 2 1 3 1 7 (3) Availability 1 1 3 2 Lb 9 Total 5) 6 5 8 3 18 TECHNICAL RANKING 2 4 2 5 1 7 OVERALL RANKING 3 4 2 4 1 4 Vil. conclusions and recommendations VII. CONCLUSIONS AND RECOMMENDATIONS VII. CONCLUSIONS AND RECOMMENDATIONS Utilization of any one of the previously listed resources depends on economic feasibility, land status of the site, and environmental con- siderations. Location of several resources within National Forest lands precludes development in the foreseeable future, as does possible dis- turbance of the fisheries if mitigation cannot be achieved. Economic feasibility is chiefly determined by the cost of construction for the necessary facilities, the cost of operation, and the intensity of use in relation to capacity of the project. Approximate 1981 construction costs of those alternatives meriting detailed feasibility analyses for Cordova are: e Crater Lake Hydro - $2,975,000. e Power Creek Hydro - $21,600,000 first stage, $12,300,000 second stage, plus distribution costs. e Intertied Hydro with Valdez - $12,120,000 for single wire ground return transmission plus about $5000/kW installed for hydroelectric developments along the route. e Healy Coal Power Plant - $12,000,000 for an optimistic 10 MW design; environmental mitigation costs could add $5,000,000 to this. Note that the coal at $45/ton (delivered) could provide an economic means of heating homes. The three most viable alternative energy sources to supplement or replace the use of diesel fuel for electrical power generation have been found to be local hydro, hydroelectric energy intertied with Valdez, and Healy coal. In addition, the very attractive option of local natural gas pro- duction merits further investigation, based on strongly expressed local interest. APA25/D1 VII-1 VII. CONCLUSIONS AND RECOMMENDATIONS The economic analysis indicates that coal development can compete with diesel generation and that hydro development would eventually produce the cheapest electric energy. The uncertainties involved in the assump- tions made for the evaluation of these resources indicate the require- ment for base information such as: a Investigations of Healy coal in regard to: a) Availability b) Transportation methods c) Environmental impacts Field reconnaissance of the small hydro sites to assess: a) Technical feasibility, including geology and access b) Environmental impacts Geophysical surveying of potential gas sites followed by drilling and testing of at least one well. The field investigations then have to be followed by: 4. Individual feasibility studies of: a) Methods of utilization b) Capacity and demand c) Economic aspects d) Equipment availability e) Constraints oe Creation of generating plant waste heat utilization systems in consonance with residential and industrial conservation programs merit prompt implementation as such scenarios offer immediate, short term relief to increasing diesel fuel use and costs. APA25/D2 VII-2 VII. CONCLUSIONS AND RECOMMENDATIONS It is recognized that the use of petroleum fuels for transportation appears to be the only viable energy resource in Cordova for this use sector. Furthermore, even if a large portion of the community were to switch to coal heating or district heating from a coal-fired plant, diesel use for heating will likely not be totally eliminated in Cordova. Hence, the efficient use of this resource cannot be over emphasized if costs for energy are to be kept as low as possible. As existing energy technologies are being improved and further developed and new technologies are introduced, results of resource evaluations in this report may become obsolete and inadequate. Periodic review is therefore advised in order to maintain the usefulness of this study. Approximate costs for determination of feasibility of the most attrac- tive significant energy resources for Cordova are: e Natural Gas - a minimum of $1,500,000 in field work is antici- pated. # Intertied Hydro - costs could reach $1,400,000 for meeting year 2000 needs. This cost would include evaluating the trans- mission line route and three (3) potential hydroelectric sites. The evaluation would include hydrologic studies, and archaeological assessment, geology, preliminary design and economic analysis. e Power Creek - if drilling by the Corps of Engineers proves successful, feasibility work to the point of beginning FERC licensing applications would run $300,000 to $400,000. e Crater Lake - feasibility costs would run $300,000 to $400,000. e Healy Coal - feasibility could be determined for $400,000 to $600,000 depending on the amount of environmental monitoring required by regulatory agencies. APA25/D3 VII-3 VII. CONCLUSIONS AND RECOMMENDATIONS Close contact between the City of Cordova and Robert W. Retherford Associates will permit selection of a milestone type feasibility approach which will enable early client decision as to which major direction to pursue. It cannot be overemphasized that if Cordova wants to at least stabilize, and hopefully reduce the local cost of energy, immediate short term, small scale measures should be implemented to at least "hold the line" until the feasibilities of larger projects are determined and large scale energy projects are constructed. These small scale measures can be generally called "conservation" measures and offer the potential of reducing current non-transportation fuel use on the order of up to 15%. These measures are: lube oi] recycling; waste heat recovery and use; residential conservation; wood use for residental heating; and improved industrial heat efficiencies. If these measures are implemented in the short term, the long term development of the Cordova area can proceed in a deliberate and consistent manner. The final figures underscore the importance of implementing non-petroleum energy technologies for Cordova: these figures show the requirements of continuation of current fuel use practices and the savings possible with waste heat recovery. APA25/D4 VII-4 MILLION GALLONS | GENERATION NOTE: "OTHER" COMPRISES ALL USES OTHER THAN TRANSPORTATION OR GENERATION. _ 5% INCREASE GENERATION _ 22%108 1.3x108 83% INCREASE GENERATION “8X 10° 194% INCREASE GENERATION _ 64 x106 dl CITY OF CORDOVA PROJECTIONS OF CURRENT PETROLEUM FUEL USE REPLACEABLE BY OTHER RESOURCES FIGURE 16 MILLION GALLONS NOTE:"OTHER" COMPRISES ALL USES OTHER THAN TRANSPORTATION OR GENERATION. ASSUMES |/3 OF GENERATION FUEL INPUT EQUIVALENT IS RECOVERABLE. 31% INCREASE BASELINE GENERATION GENERATION 2.2 x 106 1.3 x 106 1979 LOW 2000 51% INCREASE GENERATION | 2.8 x 106 MEAN 2000 163% INCREASE GENERATION 64 x 106 HIGH 2000 CITY OF CORDOVA PROJECTIONS OF CURRENT PETROLEUM FUEL USE WITH GENERATION WASTE HEAT RECOVERY FIGURE 17 % ENERGY 100 80 60 40 20 OTHER TRANSPORTATION BOAT TRANSPORTATION INDUSTRY (1979: 228.2 x 109 BTU) HEATING (2000: 528.0 x 109 BTU) ELECTRICITY NOTE : SCENARIO ASSUMING 50% OF GENERATION WASTE HEAT IS ONLY UTILIZABLE HEAT. (1979 SAVINGS: (1979+ 165.6 x 109 BTU) | 62.6 x 109 BTU) REDUCED HEATING ENERGY (2000: 383.2% 109 BTU) (2000 SAVINGS: 144.8 x109 BTU) e—_— UTILIZABLE WASTE HEAT ——e CITY OF CORDOVA IMPACT OF WASTE HEAT USE FIGURE 18 A. energy balance and requirements - details HEATING 10° BTU % of Total 228.0 25.7 INDUSTRY 10° BTU % of Total 70.0 7.9 APPENDIX A ENERGY BALANCE AND REQUIREMENTS - TABLES TABLE A-1 1979 PETROLEUM BASED ENERGY BALANCE* CORDOVA AREA BOAT OTHER ELECTRIC TRANSPOR- TRANSPOR- GENERA- TATION TATION TION TOTAL 10° BTU 10° BTU 10° BTU 10° BTU % of Total % of Total % of Total % of Total 320.6 89.6 179.8 888.0 36.1 10.1 20.2 100 * Note that wood for residental heating provides 17.1 x 109 Btu. APA21/B1 CONSUME TOTAL ELECTRICITY 1000 Gal No. Cons/MWH 9 Ave. kWh 10 BTUs of 1] month / Ave. ¢ ood cons kWh iInYPE 1,448.8 696/ 4,230 aaa Ben nea 191.7/21.6 506/ 17 COMMERCIAL 2,032.16) 234/ 4,009 BUSINESSES 276.6/31.1 1,428/ 17 INDUSTRIAL 620.9 9/ 5,367 USERS 85.2/9.6 49 ,694/ Dui FISHING 2,369.9 na_/_na VESSELS 320.6/36.1 na / na PUBLIC 100.0 8/ 800 BUILDINGS 13.8/ 1.6 8, 333/ na 6, 5172.-12 947/14 , 406 matin 888. 0/100.0 1,268/7 na % OF TOTAL & 100.0 incl in Diesel it / 1365 CANNERY 4507 na (self genera T Consumers 2 1980 retai 3 not availa KEA08/D4 Year: Scenario Maximum Demand (MW) Energy Usage (103 MwH) 1980 3.4 16.7 TABLE A-3 SUMMARY ELECTRICAL FORECASTS TO YEAR 2000* CITY OF CORDOVA 1985 1990 Low Mean High Low Mean High 4.1 $.0)) 5-7 5.0 5.8 8.3 18.5 22.0) 26.3 20.2 24.7 39.0 *not including heat (see Tables A-7, A-8, and A-9) 1995 Low Mean High 6.6 7.4 11.8 24.8 30.1 58.2 2000 Low Mean High 8.0 8.6 16.5 27.8 35.9 80.0 KEA08/D2 o ea ON eR Number & Type of Consumer: Residential AoOPWNre Unaccounted Power Average Consumption (KWH) Per Year Per Consumer . Residential . Small Commercial Large Commercial Large Commercial Public Lights, etc. Unaccounted Power OAnPwnr Total Energy (103 MwH): Maximum Demand (MW): Increase of 1% a year. Increase of 2% a year. Increase of 4% a year. Addition of 500 kW load. YEAR: Smal] Commercial (<50 kVA) Large Commercial (50 to 350 kVA) 7 8 Large Commercial (>350 kVA) Public Lights, etc. TABLE A-4 LOW ELECTRICAL LOAD FORECAST CITY OF CORDOVA 1980 1985 719 756 247 1 260 3 3 2 2 10% 10% 5,833 5,800 20,615 2 22,750 280,000 2 309,000 1,212,000 2 1,340,000 9,000 9,000 12% 10% 16.7 18.5 35473 4.1 1990 5,500 25,100 341,000 1,477,000 9,000 10% 20.2 5.0 1995 5,500 27,750 377,000 1,631,000 9,000 10% 24.8 6.6 4 2000 5,300 30,600 416 ,000 1,800,000 9,000 10% 27.8 8.0 Year: 1980 A. Number and Type of Consumers 1. Residential 2. Small Commercial (< 50 kVA) 3. Large Commercial (> 50 < 350 kVA) 4. Large Commercial (> 350 kVA) 5. Public Lighting, etc. 6. Unaccounted Loads (%) (city, plant & losse B. Average Consumption (kWh Per Consumer Per Year Residential Smal) Commercial Large Commercial Large Commercial Orpen Public Lighting, etc. C. Total Energy Consumption (103 x MHW) D. Maximum Demand (MW) Notes: wn 719 247 7 s) 12 ) 5,833 20,615 280,000 1,212,000 9,000 16.7 3.47 1981 740 2 252.14 11 6,000 20,615 297,000 * 1,212,000 9,000 17.5) 3.5 A growth rate of 3% is assumed during this period. A growth rate of 2% is assumed during this period. A growth rate of 1.5% is assumed during this period. 1982 763 257 11 6,000 21,000 306 ,000 1,220,000 9,000 18.2 3.6 1995 1996 1997 1998 1999 2000 942 952 961 971 981 991 323 328 333 338 343 348 13 14 14 15 16 7 5 5 5 5 5 5 6 6 6 6 6 6 12 10; 22) 10 10 10 10 5,800 6,000 6,000 6,000 6,000 6,000 24,500 25,000 25,500 26,000 26,500 27,000 450,000 463,000 477,000 490,000 506,000 521,000 520,000 1,550,000 1,582,000 1,610,000 1,646,000 1,680,000 9,000 9,000 9,000 9,000 3,000 9,000 30.1 31.0 31.8 33.0 34.5 35.9 7.4 7.6 7.9 8.1 8.3 8.6 4 Addition 1,000 kw, 1.6 MWh load of Chugach Fisheries to CE 10 11 Drop due to rising cost. Increase in transmission network. Decrease due to system improvements. Expansion of transmission network. Transmission line improvements. A growth rate of 1% is assumed during this period. Addition of a 600 kW, 1 MWh future customer. KEA08/D1 TABLE A-6 HIGH ELECTRICAL LOAD FORECAST CITY OF CORDOVA Year: 1980 1985 1990 1995 2000 A. Number & Type of Consumer: 1. Residential 719 1 834 966 1,120 1,298 2. Small Commercial (<50 kVA) 247 1 286 273 332 385 3. Large Commercial (50 to 350 kVA) 7 10 15 18 20 4. Large Commercial (>350 kVA) 3 4 6 8 10 5. Public Lights, etc. 2 4 6 8 10 6. Unaccounted Power 10% 10% 10% 10% 10% B. Average Consumption (KWH) Per Year Per Consumer 1. Residential 5,833 2 7,100 8,600 10,500 12,750 2. Small Commercial 20,615 2 25,000 30,500 37,100 45,000 3. Large Commercial 280,000 2 340,600 415,000 504 ,000 614,000 4. Large Commercial 1,212,000 2 1,475,000 1,794,000 2,183,000 2,656,000 5. Public Lights, etc. 9,000 9,000 9,000 9,000 9,000 6. Unaccounted Power 12% 10% 10% 10% 10% C. Total Energy (10° MWH): 16.7 26.3 39.0 58.2 80.0 D. Maximum Demand (MW): 3.4 3 5.7 8.3 11.8 16.5 1 3% increase every year. 2 4% increase in consumption. 3 6% increase + large loads (1 MW in 1983 for Chugach Fisheries & 350 kW per customer thereafter. ) TABLE A-7 LOW HEAT ENERGY FORECASTS TO YEAR 2000 CITY OF CORDOVA Year Population Heating 10° BTU 10° kWh 1980 2386 295.5 88.3 1981 2446 300.4 89.8 1982 2488 304.9 91.2 1983 2529 308.3 92.2 1984 2571 312.0 93.3 1985 2613 315.6 94.4 1986 2659 319.7 95.6 1987 2706 324.0 96.9 1988 2755 335.1 100.2 1989 2802 346.2 103.5 1990 2850 351.4 105.1 1991 2907 357.9 107.0 1992 2967 364.9 109.1 1993 3026 371.6 111.1 1994 3091 379.1 113.3 1995 3154 386.3 115.5 1996 3221 394.0 117.8 1997 3294 402.6 120.4 1998 3364 410.8 122.8 1999 3438 419.4 125.4 2000 3521 429.1 128.3 A-7 KEA08/A TABLE A-8 MEAN HEAT ENERGY FORECASTS TO YEAR 2000 CITY OF CORDOVA Year Population Heating 10° BTU 10° kWh 1980 2406 298.0 89.1 1981 2452 302.0 90.3 1982 2499 306.2 91.5 1983 2547 310.5 92.8 1984 2592 314.5 94.0 1985 2639 3185/7 95.3 1986 2703 325.0 97.2 1987 2760 330.5 98.8 1988 3208 384.4 114.9 1989 3289 392.8 117.4 1990 3338 397.3 118.8 1991 3433 407.2 121.7 1992 3495 413.3 123.6 1993 3566 420.4 12557 1994 3632 427.2 127.7 1995 3695 433.2 129.5 1996 3773 441.3 131.9 1997 3847 449.5 134.4 1998 3920 456.9 136.6 1999 3990 464.1 138.8 2000 4073 472.9 141.4 A-8 KEA08/A TABLE A-9 HIGH HEAT ENERGY FORECASTS TO YEAR 2000 CITY OF CORDOVA Year Population Heating 10° BTU 10° kWh 1980 2408 298.2 89.2 1981 2455 302.4 90.4 1982 2506 307.1 91.8 1983 2555 31155 93.1 1984 2607 316.3 94.6 1985 2649 319.9 95.6 1986 2688 323.2 96.6 1987 2799 335.2 100.2 1988 2928 350.8 104.9 1989 3285 392.3 1753 1990 3938 458.4 13754 1991 3992 464.6 138.9 1992 4006 466.3 139.4 1993 4065 473.1 141.4 1994 4166 478.1 142.9 1995 4254 486.0 145.3 1996 4332 492.8 147.3 1997 4406 499.0 149.2 1998 4479 505.1 151.0 1999 4549 510.8 152.7 2000 4616 516.1 154.3 A-9 KEA08/A High Estimate Year 2000 Population Esti Estimate of No.-ease) 10° BTU 4616 1378 (1.9% increase) % Incr/Gallons/10° BTU Diesel Fuel Residential ) Commercial ) Canneries ) Fishing Boats) Public Buildi) Heating Fuel #1 Fuel ) Propane Residential ) Commercial ) Gasoline Fishing ) Other Transpo) Aviation Gas ) Electric Genera) 10°MWH/10° BT3 Note? there 1 Increase 2 Not Appropria / / / / / / / / / / / / 108. 85. 114. 347. 20. 144. 10. 0. 116. 112. 39s 388. wr nN OoOfFOfLf OWOmn me BPH HERR He Zeer 9 ) 23 9 4 9 Ow PruouWw Fuel anneries, fishery related uses, closer to saturation and / 878,000 / 692,000 / 861,000 72,604 ,000 7 145,000 /1,198 ,000 124,000 4,000 / / / 950,000 / 991,000 7 345,000 /6,354,000 80.0/2054. / SSS Se SS ~SS ~N Ss SS ~ 121. 95. 118. 359. 20. 161. a 0. 120. 125; 43. 876. Pw e OoOPOhr ~wwoonmn B. resource costs oanowenvonvd vn wo w On DO FWD OUTLINE CARBON CREEK COAL TRANSMISSION OF CARBON CREEK ELECTRICITY HEALY COAL KATALLA OIL AND GAS INTERTIE WITH VALDEZ INTERTIED SMALL HYDRO POWER CREEK HYDROELECTRICITY CRATER LAKE HYDROELECTRICITY APPENDIX B RESOURCE COSTS PAGE B-1 B-7 B-8 B-9 B-10 B-11 B-13 B-15 APPENDIX B RESOURCE COSTS 1: CARBON CREEK COAL An estimation of the costs involved in mining the coals at Carbon Creek has been undertaken to enable comparison to other resources, as well as to other coals. Coals at Carbon Creek could be developed in the follow- ing fashion: 1) An initial exploration program would be required to determine overall feasibility and the areas to be mined, followed by a drill- ing program to prove reserves and determine the distribution and character of the coal. 2) Construction of a 38-mile access road from Mile 39 on the Copper River Highway would then take place. Construction equipment and materials would be brought in and camp facilities established. It should be noted that the construction of this road is mandatory for the establishment of a mining operation, and that a small scale operation such as the one proposed cannot economically build its own road. Other uses for the road such as the development of logging by Chugach Natives, Inc., may justify construction. 3) Development of the mine and mine-mouth power plant would overlap with construction of the camp. The mine itself would involve adits driven along the trend of coal stringers and lenses with raises or stopes when necessary to mine offshoots. Most equipment would operate from electricity provided by the power plant. The coal would be conveyed directly from the mine into a beneficiating system which would probably include sorting, crush- ing, screening, and drying. After drying, the coal could go directly into the power plant or into a stockpile. Note that to eliminate substantial transportation costs, a mine-mouth power plant with transmission lines to Cordova was decided on, rather than trucking the coal 77 miles to Cordova. Geology, terrain, climate and economics dictate that underground mining methods be employed. To extract 20,000 tons of coal in the first year APA25/f1 Baa: APPENDIX B RESOURCE COSTS of production, approximately 18 personnel would mine 96 tons of coal per day, five days per week, on a year round basis. Adits would be advanced on a slight uphill grade to allow drainage. Coal and the shale waste rock would be mined from the face with a coal cutting machine. A scoop tram would haul the coal to a truck which would take it to the mine conveyer for transport to the beneficiating plant and power plant or stockpile. Due to the inconsistency of the coal occurrences, several relatively short tunnels (6,000 to 8,000 feet) may be required over a 25-year period. Coal production per man per hour will be less than is common for most mines. The costing figures in the tables which follow are based on new equip- ment quotes from various Alaskan dealers and inflated values for certain underground machinery as quoted in Bottge's 1977 report (See Appendix E). Road construction, camp and mining development were roughly estimated based on current in-house projects with input from several engineers and construction managers. Mining methods and effective costs are hypothetical, as the actual deposits are not known. In general, costing was done conservatively at each stage so no contingency is added at the end. Exploration and drilling costs were based on a program that would encounter minimal weather problems and waste only a small percentage of the drill footage. APA25/f2 B-2 APPENDIX B RESOURCE COSTS TABLE B.1-1 SUMMARY ESTIMATES FOR COST OF CARBON CREEK COAL PER TON Development Costs A. Initial Exploration $ 271,000 Drilling Program to Prove Deposits 824,000 Cc. Road Construction ($200,000/mile x 38 miles) plus 6 Bridges @ $500,000 10,600,000 Dd. Initial Site, Camp and Mine Development 1,000,000 Mine Engineering and Construction 850,000 F. Contingencies 1,000,000 G. Environmental Allowance (10%) 1,400,000 Subtotal - Development Costs $15,945,000 Capital Costs A. Mining Equipment 1,280,000 B. Construction, Transportion and Road Maintenance Equipment (New Cost) 823,000 Cc. Beneficiation and Processing Equipment 150,000 D. Camp Facilities, (Temporary and Permanent) 944,000 Es Freight 100,000 Ps Total Interest on 25-Year Loan for Above at 8% 7,240,000 Subtotal Capital Costs $10 , 537,000 Total Fixed Costs $26 ,482 ,000 Subtotal Fixed Cost/ton Calculated over 25-year Life of Mine, Assuming 15,000 tons/year, Escalated to Total Production of 600,000 tons i in 25 Years $44.14/ton APA25/f3 B-3 Annual Operating Cost APPENDIX B RESOURCE COSTS A. Personnel (18 men, modified from Bottge 77) 760,000 B. Supplies 300,000 C. Depreciation and Maintenance 300,000 D. Insurance 80,000 E.. Fuel (excluding coal) 10,000 Fi. Continued Exploration 20,000 $1,470,000 Cost/ton calculated for 20,000 tons in first year; per ton cost per year $73.50/ton Transporation Cost A. Beneficiating Process, Handling to Plant Cost/ton 2.00/ton Subtotal Variable Costs/ton 75.50/ton Total _Cost/ton $119. 64/ton TABLE B.1-2 INITIAL GEOLOGIC RECONNAISSANCE PROGRAM TO OUTLINE TARGETS 2 Drillers, limited drilling (60 days, 2,000 feet) Project Geologist Geologist Cook Camp Rental Transportation Miscellaneous Costs Total APA25/f4 B-4 $120,000 31,000 28,000 5,000 25 ,000 60,000 2,000 $271,000 TABLE B.1-3 DRILLING PROGRAM TO PROVE RESERVES Drilling, Additional 10,000 feet @ $60/ft, APPENDIX B RESOURCE COSTS (80 Days Camp, 4 Drillers, 1 Mechanic) $600 ,000 1 Project Geologist, 120 days @ $350/day 42,000 2 Assistant Geologists, 120 days @ $200/day 36 ,000 Cook 6,000 Camp Rental, $70/day/man 56,000 Transportation 80,000 Miscellaneous Costs 4,000 Total $824 ,000 TABLE B.1-4 CAPITAL COST DETAILS CONSTRUCTION, TRANSPORTATION AND MAINTENANCE EQUIPMENT No. Description Cost 1 D-8 Full Cab, Ripper $252,000 1 End Dumps, 20 yd? 100,000 1 Fuel Truck 40,000 1 Front Loaders, 3 yd? 65,000 1 Grader, 14-G 152,000 1 4-wheel Drive Pickup 12,000 1 4-wheel Drive Crew Rig 12,000 1 Forklift 40,000 2 Crane, 13 ton 150,000 Total $823 ,000 APA25/f5 B-5 TABLE B.1-5 MINING EQUIPMENT Description Coal Drills, Cutting Machines, Scoop Trams, Supply Vehicles, etc. Ventilation System and Dust Facility Conveyor System Safety Equipment Fuel Storage Site Preparation Concrete Portal Total TABLE B.1-6 CAMP FACILITIES (Both Temporary (T) and Permanent (P) for up to 25 Men) No. Description Unit Cost 1 (T) Mobile Bunkhouse (6-8 men) $26,000 1 (T) Galley/Shower 48,000 a GP) Bunkhouse and Cookhouse (3,000 square feet) 500,000 mCP) Office (20 ft x 20 ft) 40,000 1 (P) Shop (60 ft x 60 ft) 300 ,000 2) ee) Storage building 15,000 Total APA25/f6 B-6 APPENDIX B RESOURCE COSTS Cost $700 ,000 150,000 150,000 80,000 100 ,000 50,000 50,000 $1,280,000 Extension $26 ,000 48,000 500,000 40,000 300,000 30,000 $944 ,000 APPENDIX B RESOURCE COSTS 2. TRANSMISSION OF CARBON CREEK COAL ELECTRICITY If a mine mouth power plant was built in the Carbon Creek area (about 15 miles northeast of Katalla) a transmission line approximately 63 miles in length would be required to deliver the electric power to the Cordova diesel plant vicinity. The route of such a transmission line would be mostly at elevations below 100 feet and would roughly parallel the road system that would connect the coal mining area to Cordova. About 37 miles of this road system already exists (a portion of the Copper River Highway). With a potential power requirement in Cordova of 30 to 50 Megawatts of peaking capacity by year 2000 a transmission line configuration of 138 kV with a 556.5 KCM ACSR conductor is necessary. It is estimated that such a line constructed in the location described above would cost about $150,000 per mile in today's dollars (1981). With the addition of substations at the generating plant ($800,000) and at Cordova ($800,000) the total transmission investment would be $11,050,000. Operation and maintenance of a transmission system in this location will pose no unusual problems for a utility familiar with Alaskan conditions. 3 HEALY COAL The Healy coal fields are located about 90 miles south of Fairbanks on the Parks Highway and are connected to Anchorage, Seward, and Whittier by the Alaska Railroad. The coal near Healy has been mined by the Usibelli Coal Company for over 25 years. While the coals of the Healy area are considerably lower in Btu content (8,000 + Btu/1b) than the Bering River coals, they are available in sufficient quantity now at a much lower cost than the cost estimated for development and use of Bering River coals.. Large reserves (in excess of 100 million tons) and a burgeoning market for coal should tend to keep this coal at competitive prices. APA25/f7 B-7 APPENDIX B RESOURCE COSTS Costs for delivery of Healy coal to Cordova are shown in the table below. It has been assumed that 20,000 tons of coal at 8,000 Btu/Ib would provide most of Cordova's electrical energy requirement in 1981. TABLE B.3-1 HEALY COAL COSTS Coal Purchase (1981) $23.00/ton Rail Freight to Whittier 9.72/ton Barge Freight to Cordova 7. 38/ton Handling (Docks and Stockpile) 4.00/ton Total $44.10/ton Coal purchase and rail freight costs were direct quotes. Handling costs were estimated based on capital costs for provision and operation of a facility that could load and unload loose coal from rail cars onto a barge. Barging costs were initially quoted; however, a review of the following method of operation shows that considerable savings are pos- sible by utilization of an Alaska based barge: costs are based on usage of an 8,000 ton barge with a 3,000 hp tug, delivered and returned to Seattle; it would require three trips to move 20,000 tons of coal; and each trip would be nearly 200 miles round trip, taking 28 hours. These costs are detailed in the following table: TABLE B.3-2 BARGING COSTS Barge Delivery and Return Time of 16 days x $6,500/day $104 ,000 28 hrs/trip x 3 trips @ $270/hr 22,680 40 hrs/trip Standby Time x 3 trips @ $175/hr 21,000 $147 ,680 Cost/ton for Barging = $147,680/20,000 tons = $7.38/ton APA25/f8 B-8 APPENDIX B RESOURCE COSTS 4. | KATALLA OIL AND GAS To explore and develop either old or new wells at Katalla would be very expensive. In either case, a heli-portable drill would be necessary with the capability of drilling, casing, logging, and cleaning, 6 to 10-inch diameter holes to depths of 1,000 feet. The cost for a single new well could be on the order of $300,000 to $500,000 with no guarantee of production. Without knowing the condition of the old wells, it should be assumed that re-entering an old well would be about the same cost. Currently, the City of Cordova uses 1.3 million gallons of fuel oil per year for electrical generation. By the year 2000, its needs are pro- jected to be 2.8 million gallons per year for electrical generation using the mean growth scenario. At the estimated production rates of 2 barrels per day (84 gallons) it can be quickly calculated that it would take 43 wells to produce enough fuel to supply current needs! Development costs would soar to 25 to 30 million dollars and the price of a single barrel of unrefined fuel would be $200.00 or more. Opera- tional expense, transportation and tariffs would add still further to the cost. Obviously, this approach is uneconomical. Even if convincing arguments could be made for potential of more productive new discoveries in the Katalla area, exploration costs would still run from 10 to 20 million dollars for geophysical work and drilling. There is little information on the local gas reserves occasionally found with Katalla oil. Local inquiry revealed that Katalla village used the natural gas directly from the wellhead for heating and lighting. The gas burned fairly easily, but noisily, in lanterns; the oi] was barreled and barged to customers. APA25/f9 B-9 APPENDIX B RESOURCE COSTS The following table summarizes rough estimates of costs which would be involved in development of oi] or gas as an energy source for Cordova. These estimates are based on work in the Barrow area for development of NPRA gas by Husky Oil engineers Robert Hall and Max Brewer, and discussions with Chat Chatterton of Rowan Drilling. TABLE B.4-1 KATALLA OIL AND GAS DEVELOPMENT COSTS a. Assumptions (1) (2) (3) (4) (5) APA25/f10 The reservoir rocks of the Katalla area are as highly deformed at depth as they are near the surface. In fact, the results of past drilling both at Katalla and in nearby areas along the Bering River bear this out. Deformation consists of tight folds and many associated faults. Traps therefore are expected to be small and dispersed. Production would depend on tapping a series of these small traps through a gridwork of wells. Production rates will be low. Some enhancement of production may be feasible using modern methods, but it is still unlikely that the needs of Cordova could be met with less than 15-20 wells. Compressor stations will probably be necessary to pump the Product to Cordova. The shallow depth of the reservoir and the many faults in the area will tend to decrease reservoir pressures. B-10 i/ APPENDIX B RESOURCE COSTS TABLE B.4-1 (Cont'd) b. Cost Estimates e Geophysical Exploration (seismic) and Geologic Analysis $ 2,500,000 t e Drilling of a trageted area from above study: 6 holes (2-4000' each) 4,600,000 e Well completion and testing (this is a very tenuous estimate, but assume 15 wells total will give the production necessary and that you have 100% success rate including the initial 6 wells!) 9,000,000 e Access and Physical Facility; port roads; buildings to house machinery for compressor separating facility and personnel; collecting system to wells. 2,500,000 e Pipeline, 40 miles x $20/foot 12,000,000 e Distribution within Cordova (3,000 people) 3,000,000 TOTAL 33,600,000 NOTE: There is a very high risk factor involved in gas exploration in the Katalla area. 5. INTERTIE WITH VALDEZ A transmission intertie between Cordova and Valdez could provide for an exchange of electrical energy and capacity and also provide connection to a series of potential hydro sites that exist in the region between the two communities. APA25/f11 B-11 APPENDIX B RESOURCE COSTS Table B.5-1 shows projected surplus MWh at Valdez from the Solomon Gulch hydroelectric project and the proposed Pressure Reducing Turbine (PRT). The cost or even availability of this "surplus" energy to Cordova is not known at this time, but will have a major impact on the feasibility of the intertie alternatives. An agreement pending approval of the respective voting members, has been reached between Copper Valley Electric Association and the City of Valdez for the City to take over the power utility for Valdez. The actual disposition of energy from Solomon Gulch hydroelectric project will not be determined until the agreement is approved or disapproved. Additionally, the PRT concept was discussed with Alyeska Pipeline Service Company during design and construction of the Trans- Alaska Pipeline and Alyeska even provided valves in the pipe for installing a PRT system; however, current estimated cost of energy from Solomon Gulch and the PRT varies from 1¢ to 12¢ per kWh depending on many factors which have not yet been determined. To illdstrate the sen- sitivity of this cost on those alternatives in which surplus energy is a part of the scenario, two different economic analyses were developed. If a transmission intertie could be made feasible, there would be a substantial benefit to both communities immediately and increasing benefits as hydro sites along the route are developed. The following preliminary analysis is intended to provide a reconnaissance level estimate of parameters and costs to provide a basis for considering a more in-depth study if feasibility seems attainable. APA25/f12 B-12 \ APPENDIX B RESOURCE COSTS TABLE B.5-1 PROJECTED SURPLUS MWH AT VALDEZ (to nearest 100 MWH) YEAR HYDRO_MWH PRT_MWH TOTAL SURPLUS MWH 1981 =O= =0> == 1982 9,400 -0- 9,400 1983 2,300 12,500 14,800 1984 1,300 12,500 13,800 1985 1,900 12,500 14,400 1986 7,400 16,600 24,000 1987 6,200 15,300 21,500 1988 4,900 14,200 19,100 1989 3,500 13,000 16,500 1990 2,100 12,500 14,600 1991 600 12,500 13,100 1992 =0- 11,400 11,400 1993 =0> 9,700 9,700 1994 =0= 7,900 7,900 1995 =0= 6,000 6,000 1996 -0- =0= => 1997 =0= -0- =0= 1998 =0= =0= =05 1999 =0= =0= Os 2000 =0= =0= =0= APA25/f13 B-13 APPENDIX B RESOURCE COSTS 6. INTERTIED SMALL HYDRO A preliminary estimate of cost for the three transmission routes des- cribed previously in Section IV, "Energy Resource Alternatives," for 50 MW transfer capability is: Route (1): $57,300,000 Route (2): $12,220,000 Route (3): $35,000,000 A more in-depth description of how these estimates were developed is presented in Appendix C. It is clear that Route (2) is the most viable alternate based on the assumptions made. Studies of possible single wire ground return (SWGR) electric lines have been made which show potential benefits for transmission systems under some conditions. There is a small demonstration project operating today using this principle and successfully delivering electricity from Bethel to Napakiak. The project is also demonstrating a single phase to three phase state-of-the-art converter which is in use supplying three phase power to the BIA school in Napakiak. Construction costs for the line to Napakiak were found to be about one third of the cost of conventional construction. The transmission system of Route (2) could obtain substantial savings in the line costs by using this SWGR concept. Without an in-depth analysis it will be assumed that the overhead line costs can be reduced by one- fifth and that the single phase substations will cost 70% of the three phase equivalent. To these costs will be added the estimated single phase to three phase conversion costs. This SWGR concept is thus esti- mated to cost $12,120,000 for Route (2). The SWGR concept appears worth more in-depth consideration. APA25/f14 B-14 APPENDIX B RESOURCE COSTS Transmission Route (2) passes within easy reach of a number of potential hydroelectric sites. It is estimated that these hydro sites could be developed at an overall cost of about $5,000 per kW. A reconnaissance level estimated overall cost to develop these hydro-power sites is $5,000 per kW installed. It is difficult to refine the estimated cost anymore than what is given without actually visiting each site. However, even though increasing the estimated cost per kW by 50 percent, to $7,500, would change the relative year 2041 economic ranking of the Intertie alternatives and the coal generation with Healy coal alternatives, it would not change the recommendation that these alternatives be considered for more indepth feasibility studies. A brief summary of the estimated capacity and corresponding estimated cost for the hydroelectric sites follows. These sites are listed in order from Cordova towards Valdez. (a) Sheep River Lakes Lake 2026 1200 kW Installed Capacity 4,200 MWh Prime and 5,260 MWh Average Cost: $6,000,000 Lake 1022 - 1200 kW Installed Capacity 3,720 MWh Prime and 5,000 MWh Average Cost: $6,000,000 Lake 649 - 4000 kW Installed Capacity 12,360 MWh Prime and 17,660 MWh Average Cost: $20,000,000 APA25/f15 B-15 (b) (d) (e) (fF) (g) APA25/f16 Lake Dead Lake Lake 1488 - off Beartrap Bay 6700 kW Installed Capacity 21,940 MWh Prime and 29,260 MWh Average Cost: $33,500,000 Creek - Gravina River Tributary 15,500 kW Installed Capacity 50,200 MWh Prime and 66,960 MWh Average Cost: $77,500,000 1975 - above Dead Creek 2,200 kW Installed Capacity 4,240 MWh Prime and 9,420 MWh Average Cost: $11,000,000 1878 - above Fidalgo Creek 5,000 kW Installed Capacity 11,390 MWh Prime and 22,780 MWh Average Cost: $25,000,000 Fidalgo Creek - Run-of-River Plant 5,000 kW Installed Capacity 0 MWh Prime and 10,000 MWh Average Cost: $25,000,000 Silver Lake - Duck River 12,000 kW Installed Capacity 49,450 MWh Prime and Average Cost: Hydro Site - $60,000,000 Transmission Line - _ 3,240,000 $63,240,000 B-16 APPENDIX B RESOURCE COSTS APPENDIX B RESOURCE COSTS 7. POWER CREEK HYDROELECTRICITY A run-of-river hydroelectric development at Power Creek could possibly be developed in two stages: a first stage of 6600 kW and a second stage of 6000 kW capacity. Estimated cost for the first stage is $21,600,000 (about $3300/kW) and for the second stage is $12,300,000 (about $2100/kW). The dam would be near stream Mile 3.0 (upstream of Ohman Falls) and the powerhouse would be at about Mile 2.0. The Corps of Engineers has test drilled two dam sites and will test the third (Ohman Falls) this year. If drilling at this third site shows potential, a final report will be prepared and Federal funds will be requested to begin specification work. Apparently the Power Creek project will be abandoned by the Corps if drilling proves this Ohman Falls site unsuitable. Excessive depth to bedrock and seepage elimin- ated the previous sites investigated on Power Creek. Figure B.7-1 shows the relation of first stage Power Creek power to Cordova's recent loads. This figure clearly shows the need for other base load power for much of the year when flows are quite low. 8. CRATER LAKE HYDROELECTRICITY The small watershed of Crater Lake, proximate to Cordova, could provide about 435 kW of prime power and 3,800 MWh per year. A small dam to raise the lake level about 10 feet, would offer the possibility of totally regu- lated flows, rather than run-of-river type flows. The power plant would require a small penstock (less than 12 inches in diameter) for the high head, easy access plant. Discharge toward Orca would permit the project fulfilling the dual purposes of hydropower and water supply for the cannery at Orca; discharge to Eyak Lake faces topographical problems. The Corps of Engineers plans to install a gauge on the outflow from Crater Lake in the summer of 1981. Actual installed capacity would be 800 to 900 kW at a cost estimated at roughly $3500 per kw. APA25/f17 Bs17 KW 10; FEB MAR | APR MAY | JUN | JUL MONTH AUG | SEP OcT CITY OF CORDOVA POWER CREEK VS. DEMAND FIGURE B7-1 NOV | DEC C. energy technology profiles APPENDIX C.1 INTRODUCTION OUTLINE C.1 INTRODUCTION C.2 EXPLANATORY NOTES C.3 ENERGY TECHNOLOGY PROFILES Ca3z. Current Petroleum Technology C.3.1.1 Diesel-Electric Generation C.3.1.2 Oi] Heating (ee Er4 Hydroelectric Technologies C.3.2.1 Hydroelectric Generation C.3.2.2 Electric Heating C323 Electrical Transmission Interties C354 Coal Technologies C.3.4.1 Coal-Fired Steam-Electric Generation C.3.4.2 Coal and Wood Heating C2355) Conservation Technologies C.3.5.1 Diesel Lube 011 Recycling C.3.5.2 Diesel Waste Heat Utilization C.3.5.3 Steam Cogeneration C.3.5.4 Conservation C.3.6 Wind Energy Conversion Systems (WECS) Gida7 Heat Pumps apa26/h1 (ela APPENDIX C.1 INTRODUCTION C.1. INTRODUCTION The energy technology profiling effort involves the development of a consistent set of site specific assumptions to provide a truly com- parable data base. Although at least several data sources are available for each technology, the data generally is quite variable (often based on incompatible assumptions) and, perhaps more important, does not apply to systems of the size or nature which would be utilized in Cordova in particular. Data discrepancies for the so-called alternative energy technologies are also strongly influenced by the simple lack of exper- jence in constructing and operating facilities utilizing these tech- nologies. The technology profiles which follow are an attempt to provide a consis- tent, appropriate data base relevant to Cordova's energy needs to the year 2000. We are engineers, not visionaries, and unforeseen progress in the more developmental technologies could cause radical need for reassessment of these technologies. We can reasonably expect little of such progress until at least 1985 and, most likely, after 1990. These profiles are in conformance with the recommended APA format. apa26/h2 C.1-2 APPENDIX C.2 EXPLANATORY NOTES C.2. EXPLANATORY NOTES Several explanatory notes apply to the profiling effort in general 1. Factors that cause differences in electrical generating plant capital costs per kW include: project scope regulatory requirements local cost variations plant size single versus multiple unit plants construction time interest rates 2. The availability factor is used as a measure of reliability and is the percentage of time over a specified period (typically one year) that the power plant was available to generate electricity. Credit for availability is given if the plant is shut down for any reason. 3. Net Energy as used here is typically referred to as the “heat rate" in the case of electric generation and is expressed as the ratio of Btu in to kWh out in this case. For direct heat application cases, this ratio is Btu in to Btu out. apa26/ml1 C.2-1 C.3.1.1 APPENDIX C.3.1.1 DIESEL-ELECTRIC DIESEL-ELECTRIC GENERATION (A) General Description 1) 2) Thermodynamic and engineering processes involved In the diesel engine, air is compressed in a cylinder to a high pressure. Fuel oil is injected into the compressed air, which is at a temperature above the fuel ignition point, and the fuel burns, converting thermal energy to mechanical energy by driving a piston. Pistons drive a shaft which in turn drives the generator. Current and future availability Diesel engines driving electrical generators are one of the most efficient simple cycle converters of chemical energy (fuel) to electrical energy. Although the diesel cycle in theory will burn any combustible matter, the practical fact of the matter is that these engines burn only high grade liquid petroleum or gas, except for multi-thousand horsepower engines which can burn heated residual oil. Diesel generating units are usually built as an integral whole and mounted on skids for installation at their place of use. (B) Performance Characteristics 1) apa26/d1 Energy output a) Quality - temperature, form In addition to electricity, diesel generators produce two kinds of capturable waste heat: from the cooling water and from the exhaust. The cooling water normally is in the 160-200°F range, but it can be 250°F or higher with C2331 iL APPENDIX C.3.1.1 DIESEL-ELECTRIC slight engine modification. Engines today are usually run at the cooler temperatures because of design simplic- ity, simpler operating routines, and first cost economy. The exhaust heat in a diesel is of higher temperature and consequently more easily used than the cooling water heat, but higher initial costs and increased operating complexities are encountered when attempting to recover energy from the exhaust gases. b) Quantity Typically 30% of the fuel energy supplied to a diesel- electric set is converted to electricity, 30% is trans- ferred to cooling water, 30% is exhausted as hot gas, and 10% is radiated directly from the engine block. Typical Alaska diesel installation range from about 50 to 2500 kW. c) Dynamics - daily, seasonal, annual Diesel units are typically base loaded ( not subject to dynamic variations). 2) Reliability a) Need for back-up Proper installation and maintenance allow continuous loading. b) Storage requirements Tanks located nearby the power plant. apa26/d2 C.3,51.162 APPENDIX C.3.1.1 DIESEL-ELECTRIC 3) Thermodynamic efficiency e Typically 17-31% overall plant efficiency without heat recovery. 4) Net energy e 11,000 - 20,000 Btu/kWh (C) Costs 1) Capital e $400/kW (AVEC) e $265-530/kW (Bristol Bay 1979 $ X 1.32 for units up to 500 kW) e $220/kW (Cordova bid) 2) Assembly and installation $400/kW (AVEC) $230-690/kW (Bristol Bay 1979 $ X 1.32) $950/kW (Kake capital and installation) $220/kW (Cordova Estimate) 3) Operation a 4-8% of investment per year (Bristol Bay operation) 4) Maintenance and replacement e 2% of investment per year (Bristol Bay maintenance) e $7.44/MWH (THREA records, maintenance) 4 9.4% of investment per year (replacement at 7% for 20 years) e $150,000 in salaries + $7/MWH (Cordova estimate) apa26/d3 Cc3e 1-3 5) APPENDIX C.3.1.1 DIESEL-ELECTRIC Economies of scale Diesel electric units range from around 1 kW to around 2.5 MW. (D) Special Requirements and Impacts 1) 2) 3) 4) apa26/d4 Siting - directional aspect, land, height A 1000 kW unit is typically skid mounted, is about 8 feet high, 6 feet wide, and 18 feet long. The unit requires foundation, enclosure, and provision for cooling and combustion air. Resource needs a) Renewable N/A b) Non-renewable No.2 diesel fuel is typically used for stationary installations. Construction and operating employment by skill Construction can be done with supervised typical local labor and equipment. Operation requires operator/mechanics. Environmental residuals The composition of the exhaust is a function of the air-fuel ratio and the hydrogen-carbon ratio of the fuel. Residuals include: carbon dioxide, carbon monoxide, hydrogen, and traces of nitrogen oxides and unburned hydrocarbons. C.3.1.1-4 5) APPENDIX C.3.1.1 DIESEL-ELECTRIC Health or safety aspects Fuel tanks require spill protection, often difficult in remote installations. Major consideration is potential impact from such spills. (E) Summary and Critical Discussion 1) 2) 3) apa26/d5 Cost per million BTU or kWh (fuel & lube oi] costs only) 10-11¢/kWh (Kotzebue and Bethel) 22-25¢/kWh (Small Villages) 17¢/kWh (Cordova residential) 11¢/kWh (Cordova commercial) Resources, requirements, environmental residuals per million BTU or kWh e From 0.07 to 0.12 gallons of fuel per kWh. * Environmental residuals per million Btu: N/A. Critical discussion of the technology, its reliability and its availability Diesel units are typically stocked by several manufacturers and, as such, have relatively short lead times for use. While this technology is a widely used application, lack of qualified operators and availability of spare parts have posed problems in Alaska. C.3.1.1-5 C.3.1.2 APPENDIX C.3.1.2 OIL HEATING OIL HEATING (A) General Description 1) 2) Thermodynamic and engineering processes involved An oil burner is a mechanical device for preparing fuel oi] to combine with air under controlled conditions for combustion. Two methods (atomization and vaporization) are used for the preparation of fuel oi] for the combustion process. Air for combustion is supplied by natural or mechanical draft. Ignition is generally accomplished by an electric spark or pilot flame. Operation may be continuous, intermittent, modulating, or high- low flame. Current and future availability Long history of practice in Cordova. The majority of residential burner production (over 95%) is of the high pressure atomizing gun burner type. Substantial numbers of other types of burners are still in operation, but only a few of these types are currently in production. (B) Performance Characteristics 1) APA26/J1 Energy output a) Quality - temperature, form Space heat or hot water for hydronic space heating systems. C.3.1.2-1 APPENDIX C.3.1.2 OIL HEATING b) Quantity Residential heating burners typically operate in the 0.5 to 3.5 gallon per hour range. No. 2 fuel oi] is generally used, although burners in the residential size range can also operate on No. 1 fuel oi] Output ratings of 64,000 - 150,000 Btu/hour are typical. c) Dynamics - daily, seasonal, annual Available whenever fuel oi] is available. 2) Reliability a) Need for back-up None usually required. b) Storage requirements Requires fuel storage tanks. 3) Thermodynamic efficiency About 70%. 4) Net energy About 1.4 units in for 1.0 units out. APA26/J2 C.3.1.2-2 APPENDIX C.3.1.2 OIL HEATING (C) Costs 1) Capital A typical residential unit costs on the order of $800-1000 for air heating units. 2) Assembly and installation About equal to 2 to 3 times the capital cost. 3) Operation Negligible, as this is performed by the homeowner. 4) Maintenance and replacement Easily maintained; units have a typical 10-20 year life. 5) Economies of scale Not appropriate. (D) Special Requirements and Impacts 1) Siting - directional aspects, land, height Needs to be isolated from flammable materials 2) Resource needs a) Renewable None. APA26/J3 G€.3.1:2=3 3) 4) 5) APPENDIX C.3.1.2 OIL HEATING b) Non-renewable Fuel oil. Construction and operating employment by skill Installed by local services; operated by residents. Annual inspection of burner equipment is recommended to assure good adjustment and operating condition. Environmental residuals Carbon dioxide, carbon monoxide, hydrogen, and traces of nitrogen oxides and unburned hydrocarbons. Health or safety aspects Fuel tanks require spill protection. Units must be located a safe distance from flammable materials. (E) Summary and Critical Discussion 1) 2) APA26/J4 Cost per million Btu or kWh Fuel oi] now costs about $13.00 per million Btu taking into account heating efficiency. Resources, requirements, environmental residuals per million Btu or kWh Requires 7.25 gallons per million Btu. Environmental resi- duals per million Btu not available. C.3.1.2°4 APPENDIX C.3.1.2 OIL HEATING 3) Critical discussion of the technology, its reliability and its availabiltiy The technology is commercially available, reliable, and pro- vides most of Cordova's heating needs. The rising cost of fuel oi] is, however, making this tech- nology less and less desirable. APA26/J5 C33 3152-5 APPENDIX C.3.2.1 HYDROELECTRIC C.3.2.1 HYDROELECTRIC GENERATION (A) General Description Ls APA/26/B Thermodynamic and engineering processes involved In the hydroelectric power development, flowing water is directed into a hydraulic turbine where the energy in the water is used to turn a shaft, which in turn drives a gener- ator. In their action, turbines involve a continuous trans- formation of the potential and/or kinetic energy of the water into usable mechanical energy at the shaft. Water stored at rest at an elevation above the level of the turbine (head) possesses potential energy; when flowing, the water possesses kinetic energy as a function of its velocity. Current and future availability Hydroelectric developments in the United States, as of January 1978, totaled 59 million kilowatts, producing an estimated average annual output of 276 billion kilowatt hours according to the U.S. Department of Energy (DOE). Hydropower provides about 10% of Alaska's electric energy needs. Developments range in size from over a million kilowatts down to just a few kilowatts of installed capacity. Hydropower is a time proven method of generation that offers unique advantages. Fuel cost, a major contributor to thermal plant operating costs, is eliminated. Another advantage of hydropower developments is that they last much longer than do other plant types. Hydropower develop- ments are, however, initially costly and require around 5 years of lead time, from reconnaissance to start-up. Licen- sing procedures, particularly for smaller projects, are being streamlined. Streamlining licensing procedures can signifi- cantly reduce the amount of lead time needed to bring a pro- ject on-line. Gass 2 ioL APPENDIX C.3.2.1 HYDROELECTRIC (B) Performance Characteristics a Energy output a) b) Quality - temperature, form Hydropower provides readily regulated electricity. Water quality is not affected. A slight temperature differen- tial may exist between discharge water and the receiving waters. The effect of the temperature change on spawning salmon normally requires investigation. Quantity Approximately 60% of the energy stored in the water will result in saleable electricity. The remaining 40% will be lost in the water conduit, turbine, generator, station service, transformers, and the transmission line. Typical installed capacities in Alaskan power plants range from 1-20 Mw. Dynamics - daily, seasonal, annual Hydropower plants can be base loaded and/or peak loaded. In smaller installations, the operating mode may be adjusted seasonally, depending on the availability of water and the demand for electricity. (2 Reliability a) APA/26/B Need for back-up The reliability of the hydroplant itself is very high. The transmission lines are often routed through very rugged terrain and are consequently subject to a variety of natural hazards. Repairs to damaged lines can usually C3 2a 2 (C) Costs 1 APA/26/B b) APPENDIX C.3.2.1 HYDROELECTRIC be accomplished relatively quickly. It is customary to provide sufficient installed diesel generation capacity to provide emergency electricity to the utility's custom- ers in the event that the transmission line or the power- plant should go down. The amount of backup required can be reduced by building an alternate transmission line. Storage requirements A reservoir is usually used to store water except for run-of-river plants. Typical reservoirs will range in size from a few acres to several hundred acres. Thermodynamic efficiency Not appropriate. Net energy Approximately 4800 kWh/installed kW will be generated annu- ally. Saleable energy will be about 10% less when station service, transformer, transmission line and other losses are included. Capital $14,000/kW installed Lake Elva near Bristol Bay (feasibility estimate) $1,800/kW installed - Solomon Gulch near Valdez $50,000/kW installed (reconnaissance estimate) $5,000/Kw installed for hydro along Cordova-Valdez intertie route $3,500/kW installed for Crater Lake $3,300/kW installed for Power Creek first stage Caseeus3 APPENDIX C.3.2.1 HYDROELECTRIC Assembly and installation See above. Operation Operation and maintenance costs are normally combined when evaluating a hydropower development. Maintenance and replacement Operation and maintenance costs for a hydroelectric develop- ment normally depend on the size of the installation and the method of operation. Most large installations (76,000 kW) will be attended full-time while many of the smaller installa- tions are operated remotely and visited only occasionally for maintenance. Estimated annual operation and maintenance cost for large installations is $100.00 + $7.00/kW. For small plants the estimated cost is $25,000 + $7.00/kW. Annual replacement cost for a hydroelectric plant with 50- year economic life is $3.00 per kW installed. Economies of scale The cost per kW installed generally decreases for larger installations. Further economics of scale can be realized when the operation of several smal] hydropower developments can be integrated. (D) Special Requirements and Impacts ay APA/26/B Siting - directional aspect, land, height C7332. 1-4 APA/26/B APPENDIX C.3.2.1 HYDROELECTRIC A suitable site for any hydropower development must, of course, be found. Requirements include an adequate water supply and a reasonable proximity to the load center (consumers). Site preparation for a hydropower development involves modification of the existing terrain and results in changes in both the topography (cuts and fills), and in the natural or existing drainage pattern. The project boundary (the outer limits of the land directly affected by the project) may encompass several hundred acres. The impacts of a hydropower develop- ment cover a wide spectrum. They affect man, vegetation, wildlife, and fisheries. The special advantage of a hydro- power development is that it is effectively non-polluting. Resource needs a) Renewable Water. b) Non-renewable Some of the construction and maintenance resources (such as steel and lube oi1) are non-renewable resources. Construction and operating employment by skill Construction of a hydropower development requires the employ- ment of both highly skilled individuals experienced in the design and construction of this type of project and less experienced individuals who usually come from the local work- force. Operators of hydroplants are often local diesel power plant operators who receive a minimal amount of additional training to qualify them to work as hydroplant operators. C23 ..2- 1-5 APPENDIX C.3.2.1 HYDROELECTRIC Environmental residuals None Health or safety aspects Public safety, legal liabilities, insurance, and land use issues must be addressed prior to construction of a hydropower development. (E) Summary and Critical Discussion 1. APA/26/B Cost per million Btu or kWh See Appendix B for cost per kWh. Resources, requirements, environmental residuals per million Btu or kWh. N/A. Critical discussion of the technology, its reliability and its availability. Hydroelectric power generation is a well established technol- ogy. Each project, and many of its components, are "custom" design jobs. Because of this and because of the large scale and the long lead time associated with a project, hydropower is a capital intensive investment with high field exploration costs. Few utilities alone can afford to provide long term and interim financing. The State of Alaska, the Rural Electrifi- cation Administration, and others provide assistance to util- ities to bring worthwhile projects forward. Hydroplants can be remotely operated from a central station. An operator is usually stationed at the power plant to take care of routine maintenance. Safety of hydropower develop- C.3.2.1-6 APA/26/B APPENDIX C.3.2.1 HYDROELECTRIC ments has long been a concern of the Federal and State govern- ments. Criteria for safe design and operation of hydropower developments are well established and major failures are very rare. The hydraulic turbine, and its component parts, is designed and are built to exacting specifications and is extremely reliable; the turbine has a useful life of upwards of 30 years. C.3.2.1-7 PRECIPITATION & RUNOFF WATER STORAGE RESERVOIR WATER CONDUIT GENERATOR POWER TAILWATER HYDROELECTRIC POWER DEVELOPMENT DIAGRAM HYDRAULIC TURBINE TAILRACE FIGURE C.3.2.1-1 C..3..2.2 APPENDIX C.3.2.2 ELECTRIC HEATING ELECTRIC HEATING (A) General Description 1) 2) Thermodynamic and engineering processes involved Electricity is passed through resistance wiring and gives off heat in encountering such resistance. The heat is transferred to air or water. Current and future availability Electric heat is clean, noiseless, easily controllable and relatively efficient. Electric heat is recognized as a sound means of heating buildings where heat losses are held to a sound, economical level and the cost of electricity is not prohibitive. (B) Performance Characteristics 1) APA26/C Energy output a) Quality - temperature, form Heat or hot water for space heating applications. b) Quantity 3413 Btu in per kWh out. Typical residential furnaces are of capacities in the range of 20,000 to 120,000 Btu per hour. Crs .2en 2) 3) 4) (C) Costs 1) APA26/C APPENDIX C.3.2.2 ELECTRIC HEATING c) Dynamics - daily, seasonal, annual Available whenever there is electricity. Reliability a) Need for back-up Typically, none. b) Storage requirements None. Thermodynamic efficiency So far as the conversion of electric energy into heat is concerned, all types of electric resistance heaters are equally efficient. They all produce 3413 Btu per kilowatt-hour of electrical energy used. From a thermodynamic efficiency standpoint, electric heaters are 100 percent efficient. However, different types of heaters differ in effectiveness; the effectiveness is determined by the means used to transfer the heat generated into the area that is to be heated. Net energy Overall, say about 1.02 units in to 1.00 unit out. Capital About $800-1000 for a central home unit. C23. 2.122 2) 3) 4) 5) APPENDIX C.3.2.2 ELECTRIC HEATING Assembly and installation About equal to capital cost. Operation A function of the cost of electricity. Maintenance and replacement Virtually maintenance free; replacement life estimated to be 20 years. Economies of scale Not appropriate. (D) Special Requirements and Impacts 1) APA26/C Siting - directional aspect, land, height In typical residential installations, a metal casing, in the same configuration as conventional baseboard along walls, contains one or more heating elements placed horizontally. The vertical dimension is usually less than 9 inches, and projection from wall surface is less than 3.5 inches. Units are available from 1 to 12 feet long with ratings from 100 to 400 watts per foot of length and are designed to be fitted together to make up any desired continuous length or rating. C232 2./2-3 APPENDIX C.3.2.2 ELECTRIC HEATING 2) Resource needs a) Renewable Hydroelectricity is currently the only cost effective renewable resource. b) Non-renewable Fossil fuels used for electrical generation. 3) Construction and operating employment by skill Simple to install and effectively automatic. 4) Environmental residuals None. &) Health or safety aspects None. (E) Summary and Critical Discussion aL) Cost per million Btu or kWh Cost is a function of the cost of electricity. The most economical electric heating systems from an operating standpoint are of a decentralized type, with a thermostat provided on each unit or for each room. This permits each APA26/C C.3.2.2-4 2) 3) APA26/C APPENDIX C.3.2.2 ELECTRIC HEATING room to compensate for heat contributed by sources auxiliary such as sunshine, lighting, and appliances. This arrangement also gives a better diversity of the power demand due to noncoincidence of electric load from all units of an install- ation. Manual switches are often provided to permit cutting off heat or reducing temperature in rooms when not in use. When such operation is practiced, consideration should be given to provide extra time for warm-up. Resources, requirements, environmental residuals per million Btu or kWh A function of the resource used to generate electricity. See appropriate Appendix C profiles. Critical discussion of the technology, its reliability and its availability In summary, a simple list of some of the benefits and advant- ages of electric heat includes the following: Dependable No fuel deliveries No fuel storage problems Clean No venting required No oxygen consumption Individual room-by-room control Quiet Easy to install Space-saving ooo omUmUCODWUmUUCODWUUCOUUCUCOUUCUCOUUCUCUCOUCUCO "Flameless" C.352.255 C.3.3 APPENDIX C.3.3 INTERTIES ELECTRICAL TRANSMISSION INTERTIES (A) General Description 1) apa26/w1 Thermodynamic and engineering processes involved Electric transmission is the most efficient and low cost means of delivering useful energy (except heat) to homes and community enterprises. The outdoor, overhead, open-wire line is the least costly and least resource consuming electric line that exists. The typical open-wire overhead electric line consists of supporting structures that carry the electrical conductors (3 wires for 3 phase current) at a safe height in air that also provides the insulation required. A single wire ground return (SWGR) transmission system can best be described as single-phase, single wire transmission system using the earth as a return circuit. SWGR is not a new technology; thousands of miles of line have been in successful operation for more than thirty years, mostly outside the United States (India, New Zealand, Australia, Canada and in areas of the USA during World War II.) The SWGR lines suggested here are point-to-point connections with a carefully established grounding system at each end point. The single wire configuration can be designed for minimum cost by utilizing high-strength conductors that require a minimum number of structures and still retain the standards for high reliability. C.3.3-1 2) APPENDIX C.3.3 INTERTIES Current and future availability Conventional transmission interties serve the lower 48 and major Alaskan population centers. Technology is well known. A demonstration project to supply Bethel central station electricity by SWGR to the village of Napakiak, a distance of 8.5 miles, is presently in operation. This project has provided a demonstration of the technical and cost feasibility of the SWGR system in small scale Alaska situations. European single phase systems exist in the 70 MW range. (B) Performance Characteristics 1) apa26/w2 Energy output a) Quality - temperature, form Electricity b) Quantity SWGR transmission to about 70 MW; conventional trans- mission above 70 MW. Electric lines deliver quantities of energy that are approximately proportional to the square of the voltage of the circuit. For example, this means that an elec- trical transmission line of 138 kV rating could be expected to deliver 30 times as much power as a 25 kV line. Cx32352 2) 3) 4) (C) Costs ae apa26/w3 APPENDIX C.3.3 INTERTIES c) Dynamics - daily, seasonal, annual Available whenever the electrical generating source is. Reliability a) Need for back-up Transmission line reliability generally exceeds 99 per- cent. Diesel generators, currently installed in Cordova, would provide back-up should the transmission line be temporarily out of service. b) Storage requirements None required or applicable. Thermodynamic efficiency Not appropriate. Net energy Line loss typically does not exceed 3-5% of gross energy transfer. Capital A preliminary estimate of cost for the three transmission routes previously described for 50 MW transfer capability in the conventional mode is: Route (1) Submarine, 38, 60 Hz, 138 kV, 81 mi. 4 s/c Cables @ $650,000/mi. $52,650,000 2 terminals @ $250,000) ea. 500,000 C.3.3-3 APPENDIX C.3.3 INTERTIES 3 mi. overland @ $150,000/mi. 450,000 Compensation (90 MVAR) 2,100,000 Substations (100 MVA) 1,600,000 Total $57,300,000 Route (2) Overland, 38, 60 Hz, 138 kV 59 mi. 556.5 KCM ACSR equiv. @ $180,000/mi. $10,620,000 Compensation 0 Substations 1,600,000 Total $12,220,000 Route (3) Overland, 38, 60 Hz, 230 kV 130 mi. 795 KCM ACSR equiv. @ $240,000/mi. $31,200,000 Compensation (40 MVAR) 1,400,000 Substations (@ 1.5 x 138 kV) 2,400,000 Total $35,000,000 The construction cost breakdown for "normal" transmission lines, j.e., transmission lines with relatively short spans (<1,500 feet) and wheeled or tracked vehicle access is about 50% labor and equipment and 50% materials. It is envisioned that the short section of over- Jand line needed for Route (1) and the transmission line from the Carbon Creek coal plant to Cordova, discussed elsewhere in this report, would be of this type construction, at an estimated cost of $150,000 per mile - $75,000 per mile labor and equipment, and $75,000 per mile materials. It is estimated that the overall material costs for the Route (2) intertie will be the same since the transmission lines are carrying the same amount of energy. However, the labor and equipment costs will be higher because of different construction techniques. apa26/w4 C.3.3-4 APPENDIX C.3.3 INTERTIES The construction techniques for the Route (2) intertie are envisioned as helicopter supported operations with line structures and footings modified for such equipment. Because of the mountainous terrain, it is anticipated that there will be many long spans which could reduce the number of structures per mile and right-of-way clearing and thus the costs associated with each. It is estimated that labor and equipment costs for this type of construction will be 40% higher than "normal" or $105,000 per mile. This gives an estimated total construction cost of $180,000 per mile. The transmission system of Route (2) could obtain substantial savings in line costs by using this SWGR concept. Without an in-depth analysis, it will be assumed that the overhead line costs can be reduced by one-fifth and that the single phase substations will cost 70% of the three phase equivalent. To these costs will be added the estimated 18 to 3f conversion costs. This SWGR concept would then cost as follows: Route (2) 18, 60 Hz SWGR 161 kV 1-G, 59 mi. 1590 KCM ACSR @ $144,000/mi. $8,500,000 Compensation 0 Substations (100 MVA) 1,120,000 Converters 16/38, 60 Hz, for 1/3 of 50 MW 2,500,000 Total $12,120,000 2. Assembly and installation see above 3. Operation negligable 4. Maintenance and replacement Annual maintenance cost for transmission lines is estimated to be $200 per mile. apa26/w5 i228 APPENDIX C.3.3 INTERTIES Annual replacement cost estimated to be 1% of the capital investment. (D) Special Requirements and Impacts 1) 2) 3) apa26/w6 Siting - directional aspect, land, height The physical dimensions of electric lines are determined primarily by the voltage of the line which requires that sufficient air space between wires exist to prevent costly electric losses through energy leaks and provide safe clear- ances above ground, other structures, vehicles, flora and fauna. Electric lines that can be placed underground or carried at lesser spacings than open-wire lines must replace the insu- lation provided by the air with other non-conducting materials of equivalent electrical strength and smaller dimension. Insulated electric cables typically use a rubber or plastic compound or a high-grade paper saturated with insulating oil. Insulated electric cable transmission lines are typically much more costly (5 to 40 times) than open-wire lines. Resource needs Transmission of electrical energy generated from either renew- able or non-renewable resources. Construction and operating employment by skill For a transmission intertie from Cordova to Valdez, highly skilled professional construction labor supervisors will be required to direct locally available personnel. Operational employment consists chiefly of qualified maintenance personnel. C.3.3°6 4) 5) APPENDIX C.3.3 INTERTIES Environmental residuals Right-of-way clearing is the major impact in forested areas; some soil disturbance is required during installation. Health or safety aspects Current aspects are widespread in acceptability. The use of the earth as the return circuit for SWGR would in no way create an operating system with lesser safety than those now accepted. (E) Summary and Critical Discussion 1) 2) 3) apa26/w7 Cost per million BTU or kWh Not appropriate Resources, requirements, environmental residuals per million Btu or kWh. Not available. Critical discussion of the technology, its reliability and its availability. Conventional three phase transmission is well proven and extremely widely used. The successful construction and operation of the SWGR trans- mission line between Bethel and Napakiak has proven the tech- nical feasibility of the SWGR concept in Alaska. Additional operation of the line should prove the reliability of the line design, enhance potential user confidence and encourage addi- tional construction. Materials used in the construction of C.3.3-7 APPENDIX C.3.3 INTERTIES the line are, for the most part, standardized distribution and transmission line hardware. Materials are generally available from manufacturers within a reasonable time period. apa26/w8 G.3.3=8 C.3.4.1 APPENDIX C.3.4.1 COAL-ELECTRIC COAL FIRED STEAM-ELECTRIC GENERATION (A) General Description 1) 2) Thermodynamic and engineering processes involved Coal is ground to roughly less than 2 inch diameter chunks and mechanically loaded onto a boiler grate after which it is combusted in the boiler to heat incoming water to steam. The steam is then expanded in a turbine which drives a generator to produce electricity. Figure 3.1.1-1 shows a basic steam power cycle. Current and future availability Steam plants account for the majority of electrical generation in the United States today. Although steam plants can accomo- date a wide range of loads, U.S. economies of scale indicate that the cost per unit increases sharply in sizes below about 50 MW. It should be noted that European coal-steam generation units are employed in the less than 10 MW range. (B) Performance Characteristics 1) apa26/al Energy output a) Quality - temperature, form Electricity C73542151 2) 3) 4) apa26/a2 APPENDIX C.3.4.1 COAL-ELECTRIC b) Quantity Typically 5-50 MW; rarely as small as 1 MW (1000 kW). c) Dynamics - daily, seasonal, annual Coal fired steam plants are typically used for base power without respect to time of year. Reliability a) Need for back-up 65% capacity factor b) Storage requirements Typical storage is sufficient supply for 90 days of operation. For village areas, up to 9 months worth of coal storage may be required to guarantee continuous supply irrespective of weather. Thermodynamic efficiency up to 33% Net energy 9,500 - 17,500 Btu/kWh C.3..4: 152 APPENDIX C.3.4.1 COAL-ELECTRIC (C) Costs (1980 $) 1) 2) 3) 4) 5) apa26/a3 Capital e $1350/kW (Kotzebue 5000 kW, 1980) e $1700/kW installed (Cordova 5 MW) e $2100/kW installed (Carbon Creek 5 MW) Assembly and installation e $770/kW (Kotzebue 5000 kW) e See above for Cordova and Carbon Creek Operation e $450 ,000/year (Kotzebue 2500 kW and 5000 kW) e $360 ,000/year (Cordova) e $450,000/year (Carbon Creek) Maintenance and replacement e 2% of investment per year (Bristol Bay maintenance) e 2.5% of investment per year (Cordova maintenance) e 9.4% of investment per year (replacement @ 7% for 20 years). Economies of scale Economies of scale favor larger scale plants, particularly with respect to coal handling facilities. (Upcoming plants in the lower 48 are typically of 500 MW size.) Economies in operator requirements also favor large plants. C.3.4.1-3 APPENDIX C.3.4.1 COAL-ELECTRIC (D) Special Requirements and Impacts 1) 2) 3) 4) apa26/a4 Siting - directional aspect, land, height Coal plants require space for storage of fuel, typically a 3 to 9 month supply. If the plant is sited at the mine, handling and storage requirements are lessened; storage of a month's fuel is adequate. Resource needs a) b) Renewable N/A Non-renewable Typical Alaskan coal ranges from 6500 to 15,000 Btu per pound. Construction and operating employment by skill Requires highly skilled construction and operation personnel. Environmental residuals Solid wastes: include slag, bottom ash, scrubber sludge. Gaseous wastes: NOY, SO, Current environmental requlations regarding sulfur diox- ide emissions from conventional coal-steam plants gener- ally require abatement processes which significantly increase the cost of such plants. C.3.4.1-4 5) APPENDIX C.3.4.1 COAL-ELECTRIC Health or safety aspects Coal fired plants emit the following, as yet unregulated, atmospheric pollutants: toxic and carcinogenic trace elements, radionuclides, and organic and metal-organic compounds. Considerations include impact of transport and storage of fuel, risk of spontaneous combusion, and coal pile run off. (E) Summary and Critical Discussion 1) 2) 3) apa26/a5 Cost per million BTU or kWh e 20.3¢/kWh (Kotzebue 2500 kW busbar cost in 1984). Resources, requirements, environmental residuals per million BTU or kWh e For coal at 10,000 Btu per pound and plant at 17,500 Btu/kWh, 1.8 pounds of coal are needed per kWh. NO, emissions are about 0.15 Ibs/million Btu. SO, emissions are about 0.067 1bs/million Btu. Particulate emissions are about 0.006 lbs/million Btu. Solid wastes are about 10% of fuel burned. Critical discussion of the technology, its reliability and its availability In general, the conventional boiler-fired steam turbine system is the most economic and technologically developed system available to the power industry. Operational economics require a minimum plant size of 5 MW, however. Lead time is signifi- cantly longer than for diesel or gas turbine installation. C.354-1<5 STEAM HEADER ce EXHAUST GASES OuT TURBINE = | | | v | | | ASH BOILER ouT COAL IN GENERATOR CONDENSER CONDENSATE DIAGRAM OF RUDIMENTARY STEAM POWER PLANT FIGURE C.3.4.1-1 C.3.4.2 APPENDIX C.3.4.2 COAL AND WOOD HEATING COAL_AND WOOD HEATING (A) General Description 1) 2) Thermodynamic and engineering processes involved A mechanical stoker is a device that feeds coal or wood into a combustion chamber. It provides a supply of air for burning the fuel under automatic control and, in some cases, incorporates a means of removing the ash and refuse of combustion automa- tically. Coal and wood can be burned more efficiently by a mechanical stoker than by hand firing because the stoker provides a uniform fuel feed rate, better distribution in the fuel bed, and positive control of the air supplied for combustion Current and future availability Commercially available and widespread in use, particularly in the Eastern United States. (B) Performance Characteristics 1) APA26/K1 Energy output a) Quality - temperature, form Hot air for space heating or hot water for hydronic space heating. b) Quantity Residential units are typically sized in the 75,000-150,000 Btu per hour range. C.3.4.251 APPENDIX C.3.4.2 COAL AND WOOD HEATING c) Dynamics - daily, seasonal, annual Available whenever the coal or wood supply is available. 2) Reliability a) Need for back-up None usually required. b) Storage requirements Storage is required. A one month supply for a large residential unit run continuously is on the order of 5 tons. 3) Thermodynamic efficiency About 25% (hand fired) to about 70% (automated). 4) Net energy About 1.4 to 4.0 units in to 1.0 units out. (C) Costs 1) Capital About $1200-1500 per unit. 2) Assembly and installation About equal to two to three times capital costs. APA26/K2 C.354. 222 3) 4) 5) APPENDIX C.3.4.2 COAL AND WOOD HEATING Operation Negligible cost as operation is provided by the resident. Stokers for residential operation are usually screw fed under- feed types, and are designed for quiet, automatic operation. Maintenance and replacement Useful life is 10-20 years with simple maintenance. Soot deposits on flue surfaces of a boiler or heater act as an insulating layer over the surface, reducing heat transfer to the water or air. Soot can also clog flues, reduce the draft, and prevent proper fuel selection and combustion. Soot accum- ulation can be held to a minimum by proper burner adjustment and periodic cleaning. Economies of scale Not appropriate. (D) Special Requirements and Impacts 1) 2) APA26/K3 Siting - directional aspects, land, height Fuel storage is the major siting impact. The burner should be isolated from flammable material. Resource needs a) Renewable Wood. C.3.4.2-3 3) 4) 5) APPENDIX C.3.4.2 COAL AND WOOD HEATING b) Non-renewable Coal. Construction and operating employment by skill Installed by locally available services; operated by the homeowner. Environmental residuals Carbon dioxide, carbon monoxide, soot, ash, oxides of nitro- gen, and sulfur oxides. Health or safety aspects Fuel should be sheltered to prevent runoff from precipitation. Units must be located a safe distance from flammable mater- jals. (E) Summary and Critical Discussion 1) 2) APA26/K4 Cost per million Btu or kWh Carbon Creek coal at $120/ton and 12,000 Btu/pound costs $7.00 per million Btu; Healy coal at $45/ton and 8,000 Btu/pound costs $4.00 per million Btu, taking into account heating efficiency. Wood costs were not available. Resources, requirements, environmental residuals per million Btu or kWh. Requires 83.3 pounds of Carbon Creek coal or 125 pounds of Healy coal per million Btu; for dried wood at a nominal 8000 Btu/pound, 125 pounds per million Btu are required. Environmental residuals for coal and wood, based on boiler firing to produce steam for electrical generation, are as follows. C.3.4.2-4 COAL: WOOD 3) APA26/K5 APPENDIX C.3.4.2 COAL AND WOOD HEATING NOy emissions are about 0.15 lbs/million Btu. SOy emissions are about 0.067 1bs/million Btu. Particulate emissions are about 0.006 Ibs/million Btu. Solid wastes are about 10% of fuel burned. NOy emissions are about 0.25 - 1.18 lbs/million Btu. SOy emissions are about 0.07 - 0.18 lbs/million Btu. Particulate emissions are about 0.02 1lbs/million Btu. Residual ash from wood-firing is not classified as a hazardous waste; firing wood actually decreases the amount of solid waste in the environment. Critical discussion of the technology, its reliability and its availability The technology is commercially available and reliable. Implementation of coal technology in Cordova is dependent upon the availability of Carbon Creek or Healy coal at prices noted for power production. Although dry wood (at about 8000 Btu/pound) has about the same potential heat content as Healy coal, most wood is naturally sufficiently moist to reduce this heat value by 40 to 50 percent. In addition to the moisture content, the relative volume to weight ratio of wood is disadvantageous as compared to coal, with consequent increased gathering, transportation, and handling energy requirements. There has been a noticeable shift in Cordova in the last two years from heating oi] to wood stoves. It has been reported that the main restriction on wood harvesting in the Chugach National Forest is that the land available has C.3.4.2-5 APPENDIX C.3.4.2 COAL AND WOOD HEATING been "selected" by Eyak Village Corporation and Chugach Natives, Inc. Wood gathering by permit or fee might be allowed after title has been fully transferred to the Native groups. APA26/K6 C..3.4.2-6 APPENDIX C.3.5.1 LUBE OIL RECYCLING C.3.5.1 DIESEL LUBE OIL RECYCLING (A) General Description 1) Thermodynamic and engineering processes involved Commercially available units automatically remove water, rust, dirt, and other contaminants from used diesel lubricating oil. This recycled oi] is then mixed at one part oil to 20 parts diesel fuel. 2) Current and future availability Currently scheduled to be employed in Cordova (B) Performance Characteristics 1) Energy output a) Quality - temperature, form Oi] at about 130,000 Btu/1b. b) Quantity A function of the size and number of diesel units. c) Dynamics - daily, seasonal, annual Can be made to operate continuously. apa26/el C235 551—1 APPENDIX C.3.5.1 LUBE OIL RECYCLING 2) Reliability a) Need for back-up In the event of breakdown, pure diesel fuel is utilized. b) Storage requirements Typically 40 gallons. 3) Thermodynamic efficiency N/A 4) Net energy N/A (C) Costs 1) Capital About $4000 for a powerplant size unit. 2) Assembly and installation Portable. 3) Operation Not available. apa26/e2 Cys sos? APPENDIX C.3.5.1 LUBE OIL RECYCLING 4) Maintenance and replacement Not available. 5) Economies of scale A typical unit is rated at 6 gallons per minute. (D) Special Requirements and Impacts 1) Siting - directional aspects, land, height Needs about four square feet of floor space, stands about four feet high. 2) Resource needs a) Renewable None. b) Non-renewable Used diesel lubricating oil. 3) Construction and operating employment by skill Easily installed and virtually automatic in operation. 4) Environmental residuals Rust, dirt, sediment, dirty water. apa26/e3 C.3.5:1-3 5) APPENDIX C.3.5.1 LUBE OIL RECYCLING Health and safety aspects Negligible. (E) Summary and Critical Discussion 1) 2) 3) apa26/e4 Cost per million Btu or kWh Not available. Resources, requirements, environmental residuals per million Btu or kWh Unavailable. Critical discussion of the technology, its reliability and its availability Due to increased fuel costs and the lack of adequate means to dispose of used lubricants, this reliable, commercially avail- able technology is becoming increasingly more widely used. Tests by diesel engine manufacturers have found no noticeable difference in performance or life for engines run on the blended mixture as compared to those run on straight diesel fuel. The blended fuel seems to deliver better cold weather performance with less freeze-up as compared to #2 diesel fuel. C.3.5. 1-4 CxsaSa2 APPENDIX C.3.5.2 WASTE HEAT DIESEL WASTE HEAT UTILIZATION (A) General Description 1) 2) Thermodynamic and engineering processes involved The present use of fossil fuels to produce electricity is far less than 100 percent efficient. For example, an average diesel generator burns fossil fuel and produces electrical output equivalent to about 30% of the fuel burned; the energy represented by the remaining 70% of the fuel appears as unused or "waste" heat. Such heat most often appears as hot exhaust gas, tepid to warm jacket water (about 180°F), hot air from exhaust, and direct radiation from the machine. Diesel waste heat can be recovered from engine cooling water and exhaust (as shown in Figure C.3.5.2-1), or either source separately. The waste heat is typically transferred to a water-glycol circulating system in Alaskan applications. The heated circulating fluid can be used for space, water, or process heating. Current and future availability Practice in Alaska is growing as a result of sharp increases in cost of diesel fuels. Recovery of jacket water heat only is most common in Alaska and is shown in Figure C.3.5.2-2. (B) Performance Characteristics 1) apa26/s1 Energy output a) Quality - temperature, form Cooling water is typically 160-200°F. Exhaust heat varies with engine speed and load and ranges from about 300 to 600°F. C2335. 2=1, TO REMOTE FROM REMOTE HEAT LOOP “HEAT LOOP EXHAUST GAS EXPANSION HEAT RECOVERY — SILENCER ee eae A | R pola esr F ie 0 Ww — (THERMOSTATIC BOOSTER CONTACTOR PUMP JACKET WATER & EXHAUST WASTE HEAT RECOVERY SYSTEM FIGURE C.3.5.2-1 ENGINE THERMOSTATIC JACKET WATER WASTE HEAT RECOVERY SYSTEM FIGURE C.3.5.2-2 kW 500 750 1000 2000 2500 kWh/year 1,752,000 2,628,000 3,504,000 7,008,000 8,760,000 APPENDIX C.3.5.2 WASTE HEAT b) Quantity All of the cooling water heat, about half of the exhaust heat, and all of the radiation can be usefully captured if space heat needs are in economic proximity. Table C.3.5.2-1 indicates the annual recoverable waste heat for various diesel unit sizes and generating efficien- cies (ie. kWh/gal and heat rates in Btu/kWh) and assumes that one-third of the fuel heat is recoverable. TABLE C.3.5.2-1 WASTE HEAT AVAILABILITY? 10° Btu/year Available at Indicated Generating Efficiency 14 kWh/gal 12 kWh/gal 10 kWh/gal 8 kWh/gal (9,900 Btu/kWh) (11,500 Btu/kWh) (13,800 Btu/kWh) (17,250 Btu/kWh) 5,756 6,716 8,059 10,074 8,634 10,074 12,089 15,111 11,512 13,432 16,118 20,148 23,024 26 ,864 32,236 40,296 28,780 33,580 40,295 50,370 1 Assumes 138,000 Btu/gallon fuel, 0.40 load factor apa26/s4 C.3.5.2-4 2) 3) 4) (C) Costs 1) apa26/s5 APPENDIX C.3.5.2 WASTE HEAT c) Dynamics - daily, seasonal, annual Waste heat is available whenever its diesel generation source is in operation. Reliability a) Need for back-up Heat recovery systems require a back-up heat source in case of system shutdown. This is typically provided by heaters that existed prior to installation of the recovery system and were consequently idled by it. b) Storage requirements Waste heat is generally utilized as it is recovered; storage of heat is currently atypical. Thermodynamic efficiency N/A Net energy N/A Capital Costs of waste heat recovery and utilization systems are greatly influenced by the specific area served. In response to local interest, three example systems specific to Cordova are presented following; the first two examples presented and three others are treated in detail in Final Report, Power Plant Site Investigation, Cordova, Alaska by Robert W. Retherford Associates (1980). C23354255 APPENDIX C.3.5.2 WASTE HEAT Table C.3.5.2-2 lists the facilities discussed in the examples and their estimated annual heating oi] consumption values TABLE C.3.5.2-2 HEATING OIL USE ESTIMATED ANNUAL HEATING OIL FACILITY USE, GALLONS?, 2 des Reluctant Fisherman Motel 36,000 2. Morpac, Inc. (Cannery) 71,000 3. North Pacific Processors (Cannery) 106 ,000 4. St. Elias Ocean Products (Cannery) 131,000 5. City Hall 13,000 6. B. Korn Pool 27,000 7. Domestic Water Heating 255, 000% 8. Hospital 18,000 9. Elementary School 20,000 1 Rounded to nearest 1000 gallons 2 1979 values except for hospital and elementary school which are 1980 values 3 Does not currently exist. apa26/s6 C2355. 2-6 APPENDIX C.3.5.2 WASTE HEAT Only a portion of the steam requirement of the canneries can be supplied by the waste heat recovery systems under discussion. Based on use of the existing power plant site, steam would be supplied only to North Pacific and St. Elias canneries. Heating that could potentially be supplied to the City's water mains depends upon the plan selected. We have assumed an increase in water mains temperature of 10°F, and that 50% of all water used is heated before being used. The 50% figure is conservative, even in summer. It has been stated that many residents keep faucets running during the winter to help prevent freezing of water lines; although it is most difficult to derive a "value" for the water thusly wasted, a higher water mains temperature would greatly decrease that area of waste. Based on conservative assumptions, then, the annual amount of equivalent annual energy to heat the water mains is about 255,000 gallons of fuel oil.? Since the City water system is not now heated, any waste heat introduced into the water system would not directly replace fuel. However, it would indirectly displace fuel in that less energy in the form of electrical or oil heating of water would be used by individual consumers. Al] consumers would benefit to some extent because of savings in water heating and fewer problems with freezing of water mains and taps. 1 Assuming further, 1,500,000 gallons of heated water heated at 65% efficiency using 138,000 Btu/gallon fuel oil. apa26/s7 C23 555257 EXAMPLE 1 Waste heat recovery equipment installed in the existing power apa26/s8 APPENDIX C.3.5.2 WASTE HEAT plant would serve to provide: Steam generation to serve the sustained year-round levelized load of two canneries. (The peak steam loads of each cannery would continue to be served by their existing steam boilers. ) Buried insulated steam lines would be routed underground to connect to the existing mains in each plant. No condensate return lines are to be provided. Space heating by use of pumped hot water mains to serve the motel, the Community Center building and the swimming pool. These facilities are all heated by compatible hot water heating systems. Heating of the City's cold water mains to raise the temper- ature from an average of 40°F up to about 50°F to reduce fuel consumption by all water users north of the power plant which would include all three canneries except during their two-month seasonal peak. An allowance is included in this alternate for a limited amount of recon- figuration of the water system to circulate heated water through some portions of the water system south of the power plant. The existing diesel generation plant would be provided with heat exchangers for waste heat recovery from engine jacket cooling water systems and from the engine exhaust systems The existing jacket-water systems would be manifolded together and connected to a cooling water loop containing a heat recovery heat exchanger, thus providing a supply of heating water up to approximately 190°F maximum. This heat recovery loop would be connected to a new air cooled heat radiator circuit for standby cooling of the engine jacket water during emergency periods. Gz32552=8 APPENDIX C.3.5.2 WASTE HEAT An exhaust gas waste heat recovery boiler would have an intake manifold to collect exhaust gases from the three largest diesel units. The exhaust gas boiler would boost the heating water supply temperature to 240°F and the surplus heat remaining would generate 150 psi steam for delivery to the canneries. Plant auxiliaries would include a make-up water treatment unit. A buried, insulated steam main would be routed to two canneries, with no condensate return piping. Parallel to the steam main in the same trench would be heating water supply and return mains for space heating large oil users in the community. The low temperature heating water would supply a heat exchanger so that the municipal cold water main would be heated from 40°F to 50°F under year-round average conditions. This alternate would require an investment of $1,900,000 for heat recovery equipment, would displace 76,000 gallon per year of fuel for space heating, 189,000 gallons per year of fuel oil for steam heat at canneries, and can supply heat to the City water system equivalent to 195,000 gallon of fuel oil per year. EXAMPLE 2 The heat recovery aspects of this example are similar to Example 1. However, the heat produced would be used to heat only the City water system rather than to heat commercial loads. During the winter months the temperature of 1 million gallons per day could be increased from 37°F to 56°F, and during the summer 2 million gallons per day could be warmed from 45°F to 54°F. Since the City water mains are relatively near the power plant, investment in heat distribution facilities would be much less than for other alternates. This alternate would require an investment of about $160,000 and would supply heat equivalent to 255,000 gallons of oil per year to the City water system. apa26/s9 C.3.5.2-9 2) 3) 4) 5) APPENDIX C.3.5.2 WASTE HEAT EXAMPLE 3 A simple heat recovery system utilizing only a portion of heat recoverable from existing diesel jacket water heat would provide hot water for space heating the hospital and elementary school in Cordova. Cost for this system is estimated to be $270,000; fuel oi] displaced is about 38,000 gallons per year. Assembly and installation See above. Operation Not available. Maintenance and replacement e 2% of capital investment per year (maintenance) e 9.4% of investment per year (replacement at 7% for 20 years) Economies of scale Small systems may be as beneficial economically as very large systems because required equipment is less sophisticated and consequently less costly. Cost of redundancy requirements is typically lower (per unit recovered) in smaller systems, also. (D) Special Requirements and Impacts 1) apa26/s10 Siting - directional aspect, land, height Should be immediately adjacent to diesel engine. C.3.5-2=10 APPENDIX C.3.5.2 WASTE HEAT 2) Resource needs a) Renewable Waste heat, according to the Third Law of Thermodynamics, is a continually increasing resource (a "self-renewing" resource). b) Non-renewable Does not increase non-renewable resource requirements above the already established diesel fuel usage for generation. 3) Construction and operating employment by skill Jacket water heat recovery systems are installable and oper- able by local personnel qualified for similar work with diesel generators. 4) Environmental residuals Environmental residuals are those associated with diesel generation. 5) Health or safety aspects No negative health or safety aspects except those associated with the heat source. (E) Summary and Critical Discussion 1) Cost per million Btu or kWh See (C) above. apa26/s1l 6.3.5,2°11 APPENDIX C.3.5.2 WASTE HEAT 2) Resources, requirements, environmental residuals per million Btu or kWh These items are whatever is attributable to diesel generation. 3) Critical discussion of the technology, its reliability and its availability Waste heat capture can provide significant savings in overall fuel use. Waste heat utilization, however, is not free, even though there may not actually be a direct charge for the heat. The equipment for utilizing this heat requires a sizeable capital investment and is feasible only when the cost for associated equipment is less than the cost of the fuel saved. The critical point of any efforts to evaluate waste heat recovery is that point at which the equivalent annual cost of recovering heat will be less than the cost of generating heat by other means. Low grade waste heat cannot be transported very far for its actual resale value. apa26/s12 Gass Ssenne C.3.5.3 APPENDIX C.3.5.3 COGENERATION STEAM COGENERATION (A) General Description 1) 2) APA26/f1 Thermodynamic and engineering processes involved Cogeneration involves use of some of the steam used to drive turbines for heating or industrial process loads. Two types of specialized steam turbines are used: back-pressure turbines and extraction turbines. In the back-pressure turbines, the exhaust steam is employed for some heating process, and the turbine work may be a by- product. If all the exhaust steam is condensed in heat- absorbing apparatus and returned to the system, the thermal efficiency of the system may be over 90 percent. With extraction turbines, partly expanded steam is extracted for external process use at one or more points. The turbines may be either condensing or noncondensing. Extraction tur- bines are usually designed to sustain full rated output, with or without extraction, and are provided with automatic regu- lating mechanisms to deliver steam from the extraction points at constant pressure, as long as there is sufficient power load to permit the necessary flow. Current and future availability Cogeneration is employed worldwide. Ces aS -k APPENDIX C.3.5.3 COGENERATION (B) Performance Characteristics 1) 2) 3) APA26/f2 Energy output a) Quality - temperature, form Steam b) Quantity Based on heating requirements and turbine design. c) Dynamics - daily, seasonal, annual Available whenever steam is passed through the turbine. Reliability a) Need for back-up Cogeneration systems are typically utilized with no back-up. Capacity factor is 70%. b) Storage requirements None, other than fuel storage for the boiler. Thermodynamic efficiency Can exceed 90%, particularly if the heat loads are the basis of steam sizing, rather than electrical loads. C3359. 372 APPENDIX C.3.5.3 COGENERATION 4) Net energy 4700 Btu/kWh (typical) (C) Costs 1) Capital $730/kW (California) 2) Assembly and installation Not available. 3) Operation Not available. 4) Maintenance and replacement Not available. 5) Economies of scale Economic in the 1-7 MW range representative of Cordova. The economies of scale should have a decided effect upon the unit cost of larger coal burning, steam producing facilities in the area of fuel transportation and coal terminal facili- ties. There should be ample economic incentives to create large cogeneration facilities and thereby gain the advantage of lower unit costs per pound of steam. APA26/f3 C.3.5.3-3 APPENDIX C.3.5.3 COGENERATION (D) Special Requirements and Impacts 1) Siting - directional aspect, land, height Steam turbines require about 3000 square feet of associated plant space. See also Appendix C.3.4.1 2) Resource needs a) Renewable None. b) Non-renewable Fuel used to fire boilers; coal is considered for use in Cordova. See also Appendix C.3.4.1. 3) Construction and operating employment by skill Requires highly skilled construction and operation personnel. 4) Environmental residuals See Appendix C.3.4.1. 5) Health or safety aspects See Appendix C.3.4.1. APA26/f4 C.3)553-4 APPENDIX C.3.5.3 COGENERATION (E) Summary and Critical Discussion 1) 2) 3) APA26/f5 Cost per million Btu or kWh Not available. Resources, requirements, environmental residuals per million Btu or kWh See Appendix C.3.4.1. Critical discussion of the technology, its reliability and its availability The technology is well established, reliable, and commercially available. Many of the small cogeneration systems for industry use combustion turbines; steam turbine cogeneration is widely practiced at the 10 MW level in the Scandanavian countries. Most applications involve small systems. This is due largely to the fact that industrial steam loads are small and the economics of cogeneration systems are usually optimized by sizing the system to closely meet industrial process steam requirements. Electrical generation is usually not the factor determining the choice of size for the turbine. Economics also determine the choice of prime mover (i.e., combustion vs. steam turbine), but other factors such as the ratio of the industrial customer's heat to power requirement are important determinants of equipment selection. Because combustion turbines have heat to power ratios similiar to most industrial loads, they have become the major option for pro- posed cogeneration applications. However, when the ratio is lower, steam turbines are normally indicated. Fifty percent fuel savings are typically possible with conven- tional turbines when modified for cogeneration-based district heating. C.355-3=5 C.3.5.4 Section C.3.5.4 CONSERVATION CONSERVATION (A) General Description 1) 2) Thermodynamic and engineering processes involved Conservation measures for the 13 villages considered here are mainly classified as "passive". Passive measures are intended to conserve energy without any further electrical, thermal, or mechanical energy input. Typical passive measures are insu- lation, double glazing or solar film, arctic entrances and weather stripping. Energy conservation characteristics of some passive measures degrade with time, which must be con- sidered in the overall evaluation of their effectiveness for an intended life cycle. Current and future availability Passive measures are commercially available and increasing in use all over the United States due to the rapidly escalating cost of energy. (B) Performance Characteristics 1) APA26/L Energy output a) Quality - temperatures, form No energy output per se; rather a reduction of energy types input. b) Quantity See above. C.3.5.4-1 Section C.3.5.4 CONSERVATION c) Dynamics - daily, seasonal, annual Passive conservation measures "operate" year round. 2) Reliability a) Need for back-up None required. b) Storage requirements None required. 3) Thermodynamic efficiency Not appropriate. 4) Net energy Not appropriate. (C) Costs 1) Capital Residential installations run from several hundred to several thousand dollars. 2) Assembly and installation See above. APA26/L C.3.5.4-2 Section C.3.5.4 CONSERVATION 3) Operation None. 4) Maintenance and replacement Effectively maintenance free; 10-15 year life. 5) Economies of scale Amenable and appropriate to single dwellings or large indus- trial complexes. (D) Special Requirements and Impacts 1) Siting - directional aspect, land, height No special requirements. 2) Resource needs a) Renewable Solar insolation. b) Non-renewable Materials used for conservation modes employed. 3) Construction and operating employment by skill Can often be installed by the resident; locally specialized services (for example, insulation skills) may be employed. No operation required. APA26/L C5355;54=3 4) 5) Section C.3.5.4 CONSERVATION Environmental residuals None. Health or safety aspects None except care should be taken to assure proper air change rates for occupant health. (E) Summary and Critical Discussion 1) 2) 3) APA26/L Cost per million Btu or kWh Not available. Resources, requirements, environmental residuals per million Btu or kWh Not available. Critical discussion of the technology, its reliability and its availability Residences generally require the availability of energy at all times. Before 1973, the cost of energy was 3 to 10% of total annual expenses; now that percentage has soared to perhaps 40%. Although some dynamic measures (notably solar energy) merit consideration in this class of structure, the prime emphasis should be on passive energy conservation measures. As a whole, this market is not geared to sophisticated or costly equipment or to any measure that requires special operating or maintenance procedures or attention. Generally, simplicity and low cost, with moderate energy benefits, should be pursued. C.3.5.4-4 APA26/L Section C.3.5.4 CONSERVATION As far as commercial and industrial facilities are concerned, dynamic conservation measures may often warrant consideration, but major energy savings are achieved in: (1) restructuring the manufacturing process or reclaim energy that in the past has been wasted, and/or (2) modifying the timing cycle of the process to reduce energy usage during idling or other nonpeak energy- use-periods. Both commercial and industrial building classes have experi- enced substantial energy cost increases since 1973. In addi- tion, an even more serious problem has arisen: the unavaila- bility or curtailed supply of fuels. This situation adds an urgency to energy management goals because of the threat it poses to required operating patterns. Interest in multifuel capability and nondepletable energy resources will increase rapidly because of this: The State of Alaska has high interest in energy conservation by weatherization (passive conservation), particularly for residences. The State has a $5,000, 5% loan program for upgrading residences for conservation of energy. Figure C.3.5.4-1 following shows the impact of construction types of fuel savings. C.3.5.4-5 SQUARE FEET AREA OF DWELLING IN 100 4 5 6 7 8 9 10 " 12 13 14 100 GALLONS OF OIL CONSUMED/ YEAR 20 2i 22 23 RESIDNTAL ENERGY CONSUMED FOR VARIOUS SIZES AND TYPES OF CONSTRUCTION CITY OF CORDOVA FIGURE C-3.5.4-1 24 C356 APPENDIX C.3.6 WECS WIND ENERGY CONVERSION SYSTEMS (WECS) (A) General Description 1) 2) apa26/ql Thermodynamic and engineering processes involved No thermodynamic process is involved with the use of wind power for generation of electrical energy. The process relies on wind flowing over an air foil assembly to create differential pressure which results in rotation of the assembly around the fixed axis to which it is attached. Power from the wind is transmitted through the connection shaft and accompanying gear box to an electrical generator. (See Figure C.3.6-1). Three types of generators are presently in use with wind energy systems. These are the DC generator, the AC induction generator and the AC synchronous generator. Of the three types the AC induction generator is the most widely used: an induction generator is not a stand-alone generator and must be connected to an external power system of relatively constant frequency and voltage to operate properly. Current and future availability Availability of small size units in the 1.5 kW to 20 kW range is good. Larger units in the 100-200 kW range are currently undergoing tests in both the government and private sector and should be commercially available in the near future. Demonstra- tions of multi-megawatt sizes are in process, although major problems have been recently encountered. Crsr6=1 HIGH SPEEDO SHAFT BRAKE INDUCTION GENERATOR SECONDARY PITCH ACTUATOR CRANK SECONDARY PITCH CONT ACTUATOR PILLOW BLOCK BEARING AFT PRIMARY PITCH BEARING CONT ACTUATOR COWLING ROTOR GEAR BOX THRUST BEARING STRONGBACK TOWER VERTICAL SHAFT INBOARD PROFILE WIND TURBINE GENERATOR FIGURE C-3.6-1 APPENDIX C.3.6 WECS (B) Performance Characteristics 1) Energy output a) Quality - temperature, form Electricity b) Quantity Annual kWh output for following machine sizes for average annual wind speed of 12 mph: 1.5 kW 3,120 kWh 18 kW 20,000 kWh 45 kW 50,000 kWH c) Dynamics - daily, seasonal, annual Output of WECS dependent on seasonal wind flow patterns. 2) Reliability a) Need for back-up In general, except for the small, single dwelling wind systems, wind power generation is not a stand alone system. Diesel or another form of back-up generation must be provided for days the wind does not blow with sufficient velocity to produce energy from the WECS. apa26/q3 C2356=3 APPENDIX C.3.6 WECS b) Storage requirements Battery storage or, possibly, pumped hydro can be used for storage; both constitute considerable expense. Today the concensus is that the most cost effective way to use wind power is in a utility grid to displace fuel only when the wind blows and not to try to store the wind energy. 3) Thermodynamic efficiency N/A 4) Net energy N/A (C) Costs 1) Capital Machine size Cost $/kW 1.5 kW $ 7,000! $4,667 18 kW 19,000 1,054 45 kW 38,000 843 1 Includes cost of conversion equipment. apa26/q4 C.3.6-4 APPENDIX C.3.6 WECS 2) Assembly and installation 1.5 kW - $ 8,600 18 kW - $11,000 45 kW - $21,000 3) Operation 1.5 kW - N/A 18 kW - N/A 45 kW- N/A 4) Maintenance and replacement Unit Size Maintenance Replacement? Total 1.5 kW $2400 $1470 $3870 18 kW $3100 $2820 $5920 45 kW $3800 $5570 $9370 2 Depreciation, 20 years at 7% 5) Economies of scale Economies of scale likely favor installation of large cen- tralized wind generators over the small individually owned wind generators. The total installed WECS instantaneous output should not exceed 30 percent of the total system load. apa26/q5 C.3.6-5 APPENDIX C.3.6 WECS (D) Special Requirements and Impacts 1) 2) 3) 4) apa26/q6 Siting - directional aspect, land, height Siting requires the selection of a location with an average annual wind speed in excess of 10 mph. Height of the mounting tower will vary depending on location and machine size, but will generally exceed 30 feet in height. Resource needs a) Renewable Average annual wind speed in excess of 10 mph. b) Non-renewable N/A Construction and operating employment by skill Certain aspects of construction (foundation work and tower installation) could be performed by unskilled labor under close supervision. An operator would not be required as WECS are designed to operate unattended. Environmental residuals Little environmental impact is anticipated when operating only a few machines within a small geographic area. C.3.6-6 5) APPENDIX C.3.6 WECS Health or safety aspects Public safety, legal liabilities, insurance and land use issues must be addressed prior to installation of a utility owned and operated WECS. (E) Summary and Critical Discussion 1) 2) apa26/q7 Cost per million BTU or kWh The 1981 cost per kWh for the various system sizes is as follows. 1.5 kW - $1.21/kWh 18 kW - $0.29/kWh 45 kW - $0.18/kWh These costs can be misleading as they are for secondary (inter- ruptable) energy, not prime power. These figures are not comparable to firm energy costs, but rather should only be used for comparison with cost of fuel displaced. No allowance is made for cost of back-up power. See Figure C.3.6-2, WECS versus Diesel Generation, to deter- mine the breakeven cost at which an 18 kW WECS becomes economically competitive with diesel generation. Resources, requirements, environmental residuals per million BTU or kWh N/A C.3.6-7 1.00 DIESEL GENERATION AT 6 KWH/GAL = 5 075 ed — - z FE DIESEL a GENERATION 8 AT 12 KWH/GAL. 3 0.5 z 60% ($0.43/KWH ) BREAKEVEN FUEL COSTS (TYPICAL) WECS UTILIZATION 80% ($0.32/KWH) an 100 %($ 0.26/KWH) 0.25 = 0 1 2 3 4 5 6 7 DIESEL FUEL COST IN $/GALLON (1) UTILIZATION FACTOR IS DEFINED AS THE PERCENTAGE OF AVAILABLE ELECTRICAL ENERGY PRODUCED BY THE wecs WECS WHICH IS ACTUALLY UTILIZED. vs DIESEL GENERATION 18 KW INDUCTION GENERATION FIGURE C-3.6-2 3) apa26/q9 APPENDIX C.3.6 WECS Critical discussion of the technology, its reliability and its availability. Wind power suffers from one obvious disadvantage: the inter- mittent and fluctuating nature of wind. A small utility must install sufficient primary generation at additional costs to meet demands on those days when the wind does not blow with sufficient velocity to produce rated output of the WECS. Besides the fickleness of local wind conditions, technical, environmental, and social problems must be addressed. Tech- nical and social barriers that must be dealt with include power system stability; voltage transients, harmonics; fault- interruption capability; effects on communications and TV transmissions, public safety; legal liabilities and insurance, and land use issues. (C3326=9) Co3e7 APPENDIX C.3.7 HEAT PUMPS HEAT PUMPS (A) General Description 1) 2) Thermodynamic and engineering processes involved A heat pump extracts heat from a source at a low temperature and rejects it to a sink at a higher temperature by input of mechanical and electrical work. The heat pump basically operates much like a refrigerator or air conditioner: it utilizes coils and a refrigerant that soaks up heat energy in changing from liquid to gas, then gives up the heat to indoor air. Figure C.3.7-1 shows a heat pump schematic diagram. Current and future availability Heat pumps have been in existence for more than 100 years. The U.S. DOE projects market growth through the year 2000 at 2 percent per year. (B) Performance Characteristics 1) apa26/U1 Energy Output a) Quality - temperature, form Heated air. b) Quantity 1.5 to 2.5 units of heat for each heat unit of electricity used. c) Dynamics - daily, seasonal, annual C5357 =1 FROM HEAT SOURCE HOT AIR TO BUILDING ioe — EXPANSION VALVE REJECT HEAT COOL AIR FROM BUILDING EVAPORATOR CONDENSER ("SOURCE") ("SINK") HEAT PUMP FOR BUILDING HEATING FIGURE C.3. 7-1 APPENDIX C.3.7 HEAT PUMPS Heat pumps are more efficient at higher heat source temperatures. To satisfy heating requirements at times of maximum demand, most installations use supplementary electric resistance heaters. The point at which additional heat is supplied is known as the “balance point" and is pre-set for each installation based on pump characteristics and location variables. 2) Reliability a) Need for back-up See "Dynamics" above. b) Storage requirements None. 3) Thermodynamic efficiency Depending on the heat source temperature, a heat pump supplies 150 to 250 percent as much heat energy as the electrical energy it uses. 4) Net energy 1.0 kWh in 5,120 to 8,532 Btu out. (C) Costs 1) Capital $3,200. apa26/U3 C.357=3 2) 3) 4) 5) APPENDIX C.3.7 HEAT PUMPS Assembly and installation Not available Operation $430/year Maintenance and replacement Maintenance cost included in operation Replacement cost is 9.4% of investment per year based on 20 year life and 7% discount. Economies of scale Commercial units range in capacity from less than 10,000 Btu/hour to over 10 million Btu/hour. (D) Special Requirements and Impacts 1) 2) apa26/U4 Siting - directional aspect, land, height Units for home use are compact and occupy a similar amount of space as an air conditioning unit. Units are installed immediately adjacent to the user building and require space internally and externally. Resource needs a) Renewable If the heat source is heated water, the heat can be provided by renewable or non-renewable resources. If the heat source is air, the resource is renewable. C.3.7-4 3) 4) 5) APPENDIX C.3.7 HEAT PUMPS Electricity from renewable or non-renewable resources is required for operation. b) Non-renewable. See above. Construction and operating employment by skill Can be installed by local heating services. Operation is basically automatic. Environmental residuals. Environmental residuals are those attributable to the resources used for heating and electricity. Health or safety aspects. Operation is safe and without negative health impacts. Resources used for heating and electricity have impacts discussed in the appropriate energy technology profiles. (E) Summary and Critical Discussion 1) 2) apa26/U5 Cost per million Btu or kWh e From 40 to 70 percent of the cost of equivalent electric heating to which must be added the cost of heat source provision. Resource requirements, environmental residuals per million Btu or kWh e Whatever is attributable to the electrical and heat sources used. C.3.7-5 3) apa26/U6 APPENDIX C.3.7 HEAT PUMPS Critical discussion of the technology, its reliability and its availability At least 15 domestic manufacturers produce commercially reliable heat pumps. The most common units use air as a heat source; water heat source heat pumps are most generally based on groundwater heat, but operate more efficiently with heated water and are currently being actively promoted by major manufacturers. Use in Alaska is expected to increase as more information on local heat pump applications is disseminated. The Alaska Power Administration has been conducting and evaluating air and water source heat pumps in Juneau for the last two years and reports efficiencies of electrical use by heat pumps to by 2.5 to 2.6 times as high as resistive electrical heating. C.3.7-6 D. economic analyses - details APPENDIX D ECONOMIC ANALYSES - DETAILS The following parameters were used in the economic analyses for electrical generation plans which follow. All costs are 1981 values. Planning Period ° 1981 to 2000 Economic Analysis Period ° 1981 to 2041 Economic Life ° Diesel - 20 years ° Waste Heat -20 years ° Transmission and Intertie - 30 years ° Hydroelectric - 50 years ° Coal Plant - 30 years Investment Costs presented are constructed plant or "turn-key" costs. They include costs for designing and constructing the projects. They do not include such costs as finance charges, administration costs, land acquisition fees and permit fees. 0 Diesel: $430/kW ° Intertie: - Transmission line and substations = $12,220,000 - Hydroelectric plant at $5,000/kW. Power Creek Hydro: $3,300/kW. Crater Lake Hydro: $3,500/kW. Healy Coal Plant: $1,700/kW. Carbon Creek Coal: Power Plant @ $2,100/kW Transmission line and substations $11,050,000 ooo 0 apa26/Z1 APPENDIX D ECONOMIC ANALYSES - DETAILS ° Diesel: Base = $1.23/gallon for 13 kWh/gal. Cost escalated @ 3.5% per year. Healy Coal: $0.0225/pound for 0.58 kWh/pound. Carbon Creek Coal: $0.0600/pound for 0.88 kWh/pound. Hydro: No fuel costs. Surplus Energy: 1¢/kWh and 6.25¢/kWh. ooo 0 Operation and Maintenance - Annual oO Diesel: $150,000 + $7.00/MWH. 0 Healy Coal: $360,000 + 2.5% of investment ° Carbon Creek Coal: $450,000 + 2.5% of investment. 0 Intertie and Transmission line: $200/mile ° Hydroelectric Plant: = < 6,000 kW: $25,000 + $7.00/kW = > 6,000 kW: $100,000 + $7.00/kW Replacement - Annual Diesel: 2% of investment Coal Plant: 4% of investment Intertie and Transmission: 1% of investment Hydroelectric Plant: $3.00 per kW ooo 0 Analyses ° Per APA regulations. apa26/Z2 DEMAND — KW ENERGY — MWH EXISTING DIESEL KW ADDITIONAL SOURCES - KW UNIT 1 UNIT 2 UNIT 3 DIESEL INVESTMENT (000) DIESEL EQUIV AN COST (000) GALLONS DIESEL FUEL (000) COST PER GALLON DIESEL FUEL COST (000) DIESEL O&M COST (000) DIESEL REPLACEMENT (000) ANNUAL COSTS PRES WORTH ANNUAL COST ACCUM PRES WORTH DEMAND — KW ENERGY — MWH EXISTING DIESEL KW ADDITIONAL SOURCES — KW UNIT 1 UNIT 2 UNIT 3 DIESEL INVESTMENT (000) DIESEL EQUIV AN COST (000) GALLONS DIESEL FUEL (000) COST PER GALLON DIESEL FUEL COST (000) DIESEL O&M COST (000) DIESEL REPLACEMENT (000) ANNUAL COSTS PRES WORTH ANNUAL COST ACCUM PRES WORTH TABLE D-1 DIESEL GENERATION ONLY RECONNAISSANCE STUDY OF ENERGY REGUIREMENTS AND ALTERNATIVE: ECONOMIC ANALYSIS 1981 1982 1983 1984 1985, 3,500 3,600 4,700 4,900 5,000 16,900 18,000 20,500 21,200 22,000 5,000 5,000 5,000 5,000 5,000 7 - - - 2,500 = a = = 1,075 72 1,300 1,384 1,576 1,630 1,692 1.23 1527 1.32 1.36 1.41 1,759 1,933 2,288 2,438 2,624 263 276 294 298 304 43 43 43 43 65 2,070 2,252 2,625 2,779 3,065 2,070 2,186 2,474 2,543 2,723 2,070 4,256 4,730 9,273 11,996 1992 1993 1994 1995 1996 6,800 7,000 71200 71400 71600 27,700 28,900 29,500 30,100 31,000 5,000 5,000 5,000 5,000 5,000 S 2,500 2,500 = 2,500 2,500 2,500 2,500 2,50 i - - 1,075 = 72 72 TZ 145 145 2,130 2,222 2,269 2,315 2,384 1.80 1.86 1.92 1.99 2.06 4,217 4,546 4,792 5,068 5,402 344 352 357 361 367 65 65 65 86 86 4,693 5,035 5,286 5,660 4,000 3,394 3,531 3,400 3,742 3.851 32,886 36,417 40,017 43,759 47,610 S FOR CORDOVA 1986, 72 1,676 1.46 2,692 303 65 3,132 2,702 14,4698 1997 71900 31,800 5,000 2,500 2,500 145 2,445 2.13 53.729 373 B86 6,333 3,947 51,557 1987 Si, 300 22,300 5,000 2,500 72 1,715 1.51 2,849 306 65 3,292 2,757 17,455 1993 8,100 33,000 5,000 2,500 2,500 145 2,538 2.21 6,170 381 B46 6,782 4,103 55.660 1988 5,400 23,300 5,000 2,500 72 1,792 1.56 3,075 Bis 65 3,525 25866 20,321 1999 8,300 34,500 5,000 2,500 2,500 145 2,453 2.28 6,654 392 B86 71277 4,275 59,935 1989 5,400 23,800 72 1,830 1.62 3,261 317 65 3,715 2,933 23,254 2000 8,400 35,900 5,000 2,500 2,500 145 2,761 2.36 73168 401 86 7,800 4,448 64,382 1990 72 1,899 1.63 3,509 323 65 3,969 3,042 26,296 2001 THRU 2041 8,600 35,900 5,000 2,500 2,500 145 2,761 2.36 75168 401 B86 7,800 104,144 168,527 1991 6,000 26,000 a2 1,999 1.74 3,826 332 65 4,295 3,196 29,492 DEMAND — KW ENERGY — MWH EXISTING DIESEL KW ADDITIONAL SOURCES — KW SURPLUS SILVER LAKE MWH - DIESEL MWH - HYDRO HYDRO/INTERTIE INVESTMENT EQUIV AN COST (000) O&M COST (000) REPLACEMENT (000) SURPLUS ENERGY COST (000) DIESEL INVESTMENT (000) DIESEL EQUIV AN COST (000) GALLONS DIESEL FUEL (000) COST PER GALLON DIESEL FUEL COST (000) DIESEL O&M COST (000) DIESEL REPLACEMENT (000) ANNUAL COSTS PRES WORTH ANNUAL COST ACCUM PRES WORTH DEMAND — KW ENERGY - MWH EXISTING DIESEL KW ADDITIONAL SOURCES - KW SURPLUS SILVER LAKE MWH — DIESEL MWH — HYDRO HYDRO/INTERTIE INVESTMENT EQUIV AN COST (000) O&M COST (000) REPLACEMENT (000) SURPLUS ENERGY COST (000) DIESEL INVESTMENT (000) DIESEL EQUIV AN COST (000) GALLONS DIESEL FUEL (000) COST PER GALLON DIESEL FUEL COST (000) DIESEL G&M COST (000) DIESEL REPLACEMENT (000) ANNUAL COSTS PRES WORTH ANNUAL COST ACCUM PRES WORTH TABLE [D-2A DIESEL PLUS INTERTIED SURPLUS PLUS SILVER LAKE HYDRO (SURPLUS ENERGY COST $.0625/KWH) RECONNAISSANCE STUDY OF ENERGY REGUIREMENTS AND ALTERNATIVES FOR CORDOVA ECONOMIC ANALYSIS 1981 1982 1983 1984 1935 1986 1987 3,500 3,600 4,700 4,900 5,000 5,100 5,300 146,900 18,000 20,500 21,200 22,000 21,800. 22,300 5,000 5,000 5,000 5,000 5,000 5,000 5,000 = = 3,400 3,200 3,300 5,000 4,900 14,900 18,000 5,600 71400 7,000 = 800 ~ 14,900 13,800 14,300 21,800 21,500 = - 12,220 - = = - = ~ $22 622 622 G22 622 - - 12 12 12 12 12 oo = 12 12 12 12 12 « = 931 B62 B94 1,362 1,343 1,300 1,384 431 569 533 om 62 1.23 1.27 1.32 1.36 1.41 1.46 1.51 1,759 1,933 626 S51 B34 = 103 268 276 89 102 99 10 56 43 43 43 43 43 1 43 2,070 2,252 2,335 2,504 2,516 2,019 2,191 2,070 2,186 2,201 2,292 2,235 1,742 1,835, 2,070 4,254 6,457 8,749 10,984 12,726 14,561 1992 1993 1994 1995, 1996 1997 1998 6,800 7,000 71200 7400 7,600 7,900 8,100 27,700 28,900 29,500 30,100 31,000 31,800 33,000 2,600 2,200 1,800 1,400 - - - 12,000 12,000 12,000 12,000 12,000 12,000 12,000 27,700 28,900 29,500 30,100 31,000 31,800 33,000 3,080 3,080 3,080 3,080 3,080 3,080 3,080 196 196 196 196 196 196 196 43 43 438 43 36 36 36 WAZ 606 494 375 = 7 = 1.80 1.86 1.92 1.99 2.06 2.13 2.21 ' ' ' ' t ' 4,036 3,930 3,818 3.4699 3,312 3,312 3,312 2,916 2,756 2,600 2,445 2,126 2,064 2,004 27,247 30,003 32,603 35,048 37,174 39,238 41,242 1988 5,400 23,300 5,000 4,400 4,200 19,100 622 12 12 1,194 323 1.54 554 79 43 2,516 2,046 16,607 1999 8,300 34,500 3,312 1,945 43,187 1989 5,600 23,800 5,000 3,800 7,200 16,600 622 12 12 1,038 S54 1.62 PET 100 43 2,814 2,221 18,828 2000 8,600 35,900 3,312 1,889 45,076 1990 5,800 24,700 5,000 3,300 10,100 14,600 622 12 12 912 777 1.68 1,436 121 43 3,158 2,420 21,248 2001 THRU 2041 8,600 35,9700 3,312 44,221 89,297 1991 6,000 26,000 3,000 12,000 26,000 63,240 3,080 196 43 819 4,143 3,083 24,331 DEMAND — KW ENERGY — MWH EXISTING DIESEL KW ADDITIONAL SOURCES - KW SURPLUS SILVER LAKE MWH - DIESEL MWH — HYDRO HYDRO/INTERTIE INVESTMENT EQUIV AN COST (000) O&M COST (000) REPLACEMENT (000) SURPLUS ENERGY COST (000) DIESEL INVESTMENT (000) DIESEL EQUIV AN COST (000) GALLONS DIESEL FUEL (000) COST PER GALLON DIESEL FUEL COST (000) DIESEL O&M COST (000) DIESEL REPLACEMENT (000) ANNUAL COSTS PRES WORTH ANNUAL COST ACCUM PRES WORTH DEMAND ~— KW ENERGY — MWH EXISTING DIESEL KW ADDITIONAL SOURCES - KW SURPLUS: SILVER LAKE MWH — DIESEL MWH — HYDRO HYDRO/INTERTIE INVESTMENT EQUIV AN COST (000) O&M COST (000) REPLACEMENT (000) SURPLUS ENERGY COST (000) DIESEL INVESTMENT (000) DIESEL EQUIV AN COST (000) GALLONS DIESEL FUEL (000) cOST PER GALLON DIESEL FUEL COST (000) DIESEL O&M COST (000) DIESEL REPLACEMENT (000) ANNUAL COSTS PRES WORTH ANNUAL COST ACCUM PRES WORTH TABLE D-2B DIESEL PLUS INTERTIED SURPLUS PLUS SILVER LAKE HYDRO (SURPLUS ENERGY COST $.01/KWH) RECONNAISSANCE STUDY OF ENERGY REQUIREMENTS AND ALTERNATIVES FOR CORDOVA ECONOMIC ANALYSIS 1981 1982 1983 1984 1985, 1984 1987 3,500 3,600 4,700 4,900 5,000 5,100 5,300 16,900 18,000 20,500 21,200 22,000 21,800 22,300 5,000 5,000 5,000 5,000 5,000 5,000 5,000 = = 3,400 3,200 3,300 5,000 4,900 16,900 18,000 5,600 7,400 7,000 = 800 = - 14,900 13,800 14,300 21,800 21,500 = - 12,220 = = = a ea 622 622 622 622 622 = = 12 12 12 12 12 = 12 12 Le 12 12 * = 149 138 143 218 215 1,300 1,384 431 569 533 = 62 1.23 1.27 1.32 1.36 1.41 1.46 1.51 1,759 1,933 626 ssi 834 = 103 268 276 89 102 99 10 Sé 43 43 43 43 43 1 43 2,070 2,252 1,553 1,780 1,765 875 1,063 2,070 2,186 1,464 1,629 1,568 755 890 2,070 4,256 5,720 7,349 8,917 9,672 10,562 1992 1993 1994 1995 1996 1997 1998 6,800 7,000 7,200 7,400 7,600 7,900 8,100 27,700 28,900 29,500 30,100 31,000 31,800 33,000 2,600 2,200 1,800 1,400 - - = 12,000 12,000 12,000 12,000 12,000 12,000 12,000 27,700 28,900 29,500 30,100 31,000 31,800 33,000 3,080 3,080 3,080 3,080 3,080 3,080 3,080 196 196 196 196 196 196 196 43 43 43 43 34 36 36 114 97 79 60 - - = 1.80 1.86 1.92 1.99 2.06 2.13 2.21 3,438 3,421 3,403 3,384 3,312 3,312 3,312 2,484 2,399 2,317 2,237 2,126 2,064 2,004 20,213 22,612 24,929 27,164 29,292 31,354 33,360 1988 5,400 23,300 5,000 4,400 4,200 19,100 622 12 12 191 323 1.56 554 79 43 1,513 1,230 11,792 1999 8,300 34,500 12,000 34,500 3,080 196 3,312 1,945 35,305 1989 5,600 23,800 5,000 3,800 7,200 16,400 622 12 12 1466 ss4 1.62 987 100 43 1,942 1,533 13,325 2000 8,600 35,900 12,000 35,900 3,080 196 3,312 1,889 37,194 1990 5,600 24,700 5,000 3,300 10,100 14,600 622 12 12 146 Tia 1.68 1,436 121 43 2,392 1,833 15,158 2001 THRU 2041 8,400 35,900 12,000 35,900 3,080 196 3,312 44,221 81,415 1991 6,000 26,000 3,000 12,000 26,000 63,240 3,080 196 48 131 3,455 2,571 17,729 DEMAND - KW ENERGY — MWH EXISTING DIESEL KW ADDITIONAL SOURCES - KW POWER CREEK CRATER LAKE MWH - DIESEL MWH — HYDRO HYDRO INVESTMENT (000) HYDRO EQUIV AN COST (000) HYDRO O&M COST (000) HYDRO REPLACEMENT (000) DIESEL INVESTMENT (000) DIESEL EQUIV AN COST (000) GALLONS DIESEL FUEL (000) COST PER GALLON DIESEL FUEL COST (000) DIESEL O&M COST (000) DIESEL REPLACEMENT (000) ANNUAL COSTS PRES WORTH ANNUAL COST ACCUM PRES WORTH DEMAND — KW ENERGY — MWH EXISTING DIESEL KW ADDITIONAL SOURCES ~— KW POWER CREEK CRATER LAKE MWH — DIESEL MWH - HYDRO HYDRO INVESTMENT (000) HYDRO EQUIV AN COST (000) HYDRO O&M COST (000) HYDRO REPLACEMENT (000) DIESEL INVESTMENT (000) DIESEL EQUIV AN COST (000) GALLONS DIESEL FUEL (000) COST PER GALLON DIESEL FUEL COST (000) DIESEL O&M COST (000) DIESEL REPLACEMENT (000) ANNUAL COSTS PRES WORTH ANNUAL COST ACCUM PRES WORTH 1981 3,500 16,900 5,000 2,070 2,070 2,070 1992 6,800 27,700 5,000 6,600 800 3,400 24,300 IS6 ive 22 261 1.80 517 74 43 1,789 1,292 17,949 1982 3,600 18,000 5,000 2,252 2,186 4,256 1993 7,000 28,900 5,000 6,600 800 3,500 25,400 956 177 22 269 1.86 sso 74 43 1,822 1,278 19,227 TABLE D-3 LOCAL HYDRO PLUS DIESEL RECONNAISSANCE STUDY OF ENERGY REQUIREMENTS AND ALTERNATIVES FOR CORDOVA ECONOMIC ANALYSIS 1983 4,700 20,500 5,000 6,600 3,700 16,800 21,780 847 146 20 285 fc2 414 76 43 1,546 1,457 5,713 1994 7,200 29,500 5,000 6,600 800 3,600 25,900 956 177 22 277. 1.92 ses 75 43 1,858 1,265 20,492 1984 4,900 21,200 5,000 6,600 3,900 17,300 B47 146 20 300 1.36 449 77 43 1,582 1,448 7161 1995, 7,400 30,100 5,000 6,600 800 3,800 26,300 956 177 22 292 ed 639 77 43 1,914 1,265 21,757 1985, 5,000 22,000 5,000 6,600 800 2,700 19,300 2,800 956 177 aoe 208 1.41 323 69 43 1,590 1,413 8,574 1996 7,600 31,000 5,000 6,600 800 3,900 27,100 956 a7 22 300 2.06 680 we 43 1,955 1,255 23,012 1986 5,100 21,800 5,000 6,600 800 2,800 19,000 936 477 22 215 1.46 345 70 43 1,613 1,391 9,965 1997 7,900 31,800 5,000 6,600 800 4,000 27,800 VSG 177 22 308 2.13 722 73 43 1,998 1,245 24,257 1987 5,300 22,300 5,000 6,600 800 2,900 19,400 956 l7z ze 223 1.51 370 70 43 1,638 1,372 11,337 1998 8,100 33,000 5,000 6,600 800 4,200 28,800 956 177 22. 323 2.21 7385 79 43 2,062 1,248 25,505 1983 5,400 23,300 5,000 6,600 800 3,000 20,300 956 ie 22 231 1.56 396 71 43 1,665 1,354 12,4691 1999 8,300 34,500 5,000 6,600 800 4,700 29,800 956 177 pr 361 2.28 905 83 43 2,186 1,284 26,789 1989 5,600 23,800 5,000 6,600 800 3,100 20,700 956 77 22 238 1.62 424 72 43 1,694 1,337 14,028 2000 8,600 35,900 5,000 6,600 800 6,100 29,800 956 177 a 469 2.36 1,218 93 43 2,509 1,431 28,220 1990 5,800 24,700 5,000 6,600 800 3,200 21,500 956 177 22 246 1.468 455 72 43 1,725 1,322 15,350 2001 THRU 2041 8,600 35,900 5,000 6,600 800 6,100 29,800 IS6 w77 22 469 2.36 1,218 93 43 2,509 33,500 61,720 1991 6,000 26,000 5,000 6,600 800 3,300 22,700 956 B2e 22 254 1.74 436 73 43 1,757 1,307 16,657 DEMAND — KW ENERGY — MWH EXISTING DIESEL KW ADDITIONAL SOURCES - KW UNIT 1 UNIT 2 UNIT 3 MWH - DIESEL MWH - COAL COAL INVESTMENT (000) COAL EQUIV AN COST (000) TONS OF COAL COST PER TON COAL FUEL COST (000) COAL O&M COST (000) COAL REPLACEMENT (000) DIESEL INVESTMENT (000) DIESEL EQUIV AN COST (000) GALLONS DIESEL FUEL (000) COST PER GALLON DIESEL FUEL COST (000) DIESEL O&M COST (000) DIESEL REPLACEMENT (000) ANNUAL COSTS PRES WORTH ANNUAL COST ACCUM PRES WORTH DEMAND — KW ENERGY — MWH EXISTING DIESEL KW ADDITIONAL SOURCES - KW UNIT 1 UNIT 2 UNIT 3 MWH — DIESEL MWH — COAL COAL INVESTMENT (000) COAL EQUIV AN COST (000) TONS OF COAL COST PER TON COAL FUEL COST (000) COAL O&M COST (000) COAL REPLACEMENT (000) DIESEL INVESTMENT (000) DIESEL EQUIV AN COST (000) GALLONS DIESEL FUEL (000) COST PER GALLON DIESEL FUEL COST (000) DIESEL O&M COST (000) DIESEL REPLACEMENT (000) ANNUAL COSTS PRES WORTH ANNUAL COST ACCUM PRES WORTH HEALY COAL GENERATION RECONNAISSANCE STUDY OF TABLE D-4 ENERGY REGUIREMENTS AND ALTERNATIVES FOR CORDOVA ECONOMIC ANALYSIS 1981 3,500 16,900 5,000 2,070 2,070 2,070 1992 6,800 27,700 5,000 5,000 5,000 27,700 867 23,822 45 1,072 735 680 3,415 2,467 25,138 1982 3,600 18,000 5,000 + 2,252 2,186 4,256 1993 7,000 28,900 5,000 5,000 5,000 28,900 867 24,844 45 1,118 735 680 3,461 2,427 27,565 1983 4,700 20,500 5,000 5,000 20,500 8,500 434 17,422 45 793 S73 340 2,151 2,028 6,284 1994 7,200 29,500 5,000 5,000 5,000 29,500 867 25,378 45 1,142 735 680 1.92 3,485 2,373 29,938 1984 4,900 21,200 5,000 5,000 21,200 434 18,222 4s 820 S73 340 1.36 10 1 2,178 1,993 8,277 1995, 7,400 30,100 5,000 5,000 5,000 30,100 8467 25,8389 45 1,165 735 680 be 10 1 3,508 2,319 32,257 1985, 5,000 22,000 5,000 5,000 22,000 434 18,911 4s 851 573 340 1.41 2,209 1,963 10,240 1996 7,600 31,000 5,000 5,000 5,000 31,000 847 26,667 45 1,200 735 680 3,543 2,274 34,531 1986 5,100 21,800 5,000 5,000 21,800 434 18,756 45 844 573 340 1997 71900 31,800 5,000 5,000 5,000 31,800 867 27,356 45 1,231 735 680 1987 5,300 22,300 5,000 5,000 300 22,000 434 18,911 4s 851 S73 340 23 1.51 38 Ss2 43 2,331 1,952 14,091 1998 8,100 33,000 5,000 5,000 5,000 33,000 867 28,378 45 1,277 738 680 3,620 2,190 38,948 1988 5,400 23,300 5,000 5,000 1,300 22,000 434 18,911 4s 851 573 340 100 1.56 iva Ss? 43 2,472 2,010 16,101 1999 8,300 34,500 5,000 5,000 5,000 34,500 867 29,667 45 1,335 735 680 2.28 10 1 3,678 2,160 41,108 1989 5,400 23,800 5,000 5,000 1,800 22,000 434 18,911 45 851 573 340 138 1.62 246 63 43 2,550 2,013 18,114 2000 8,600 35,900 5,000 5,000 5,000 35,900 867 30,867 45 1,389 735 680 3,732 2,128 43,236 1990 5,800 24,700 5,000 5,000 2,700 22,000 434 18,911 45 851 573 340 208 1.68 384 69 43 2,694 2,065 20,179 2001 THRU 2041 8,600 35,900 5,000 5,000 5,000 35,900 867 30,867 45 1,389 7385 680 3,732 49,829 93,065 1991 6,000 26,000 5,000 5,000 5,000 26,000 8,500 867 22,356 4s 1,006 735 680 3,349 2,492 22,671 DEMAND — KW ENERGY — MWH EXISTING DIESEL KW ADDITIONAL SOURCES — KW UNIT 1 UNIT 2 UNIT 3 MWH - DIESEL MWH — COAL COAL INVESTMENT (000) COAL EQUIV AN COST (000) TONS OF COAL COST PER TON COAL FUEL COST (000) COAL O&M COST (000) COAL REPLACEMENT (000) DIESEL INVESTMENT (000) DIESEL EQUIV AN COST (000) GALLONS DIESEL FUEL (000) COST PER GALLON DIESEL FUEL COST (000) DIESEL O&M COST (000) DIESEL REPLACEMENT (000) ANNUAL COSTS PRES WORTH ANNUAL COST ACCUM PRES WORTH DEMAND — KW ENERGY — MWH EXISTING DIESEL KW ADDITIONAL SOURCES - KW UNIT 1 UNIT 2 UNIT 3 MWH - DIESEL MWH - COAL COAL INVESTMENT (000) COAL EQUIV AN COST (000) TONS OF COAL COST PER TON COAL FUEL COST (000) COAL O&M COST (000) COAL REPLACEMENT (000) DIESEL INVESTMENT (000) DIESEL EQUIV AN COST (000) GALLONS DIESEL FUEL (000) cosT PER GALLON DIESEL FUEL COST (000) DIESEL O&M COST (000) DIESEL REPLACEMENT (000) ANNUAL COSTS PRES WORTH ANNUAL COST ACCUM PRES WORTH 1981 3,500 16,900 5,000 1992 6,800 27,700 5,000 an +000 5,000 27,700 1,976 15,792 120 1,895 974 1,282 4,138 4,434 43,682 1982 3,600 18,000 5,000 18,000 2,252 2,186 4,256 1993 7,000 28,900 5,000 5,000 5,000 28,900 1,976 16,475 120 1,977 974 1,282 6,220 4,362 48,044 TABLE D-S CARBON CREEK COAL GENERATION RECONNAISSANCE STUDY OF ENERGY REGUIREMENTS AND ALTERNATIVES FOR CORDOVA ECONOMIC ANALYSIS 1983 4,700 20,500 5,000 5,000 20,500 21,550 1,270 11,4683 120 1,402 Wiz 862 4,257 4,013 8,269 1994 7,200 29,500 5,000 5,000 5,000 29,500 1,976 16,817 120 2,018 974 1,282 6,261 4,264 52,308 1984 4,900 21,200 5,000 5,000 1,200 1,270 12,083 120 1,450 712 862 4,305 3,940 12,209 1995 7,400 30,100 5,000 5,000 5,000 30,100 1,976 17,158 120 2,059 974 1,282 6,302 4,166 56,474 1985, 5,000 22,000 5,000 5,000 22,000 1,270 12,542 120 1,505 712 862 1.41 10 4,360 3,874 16,083 1996 7,600 31,000 5,000 5,000 5,000 31,000 1,976 17,667 120 2,120 974 1,282 2.06 10 1 6,363 4,084 60,558 1986 5,100 21,800 5,000 5,000 21,800 1,270 12,425 120 1,491 712 862 4,346 3,749 19,832 1997 7,900 31,800 5,000 5,000 5,000 31,800 1,976 18,125 120 2,175 974 1,282 2.13 10 1 6,418 4,000 64,558 1987 5,300 22,300 5,000 5,000 300 22,000 1,270 12,542 120 1,505 712 B62 23 1.51 38 52 43 4,482 3,753 23,585 1998 3,100 33,000 5,000 5,000 5,000 33,000 1,976 18,808 120 2,257 974 1,282 2.2 1 Bore 6,500 3,933 63,491 1988 5,400 23,300 5,000 5,000 1,300 22,000 1,270 12,542 120 1,505 Iie B62 100 1.56 172 Ss? 43 4,623 3,759 27,344 6,603 3,879 72,370 1989 5,600 22,800 5,000 5,000 1,300 22,000 1,270 120 1,505 712 B62 138 1.62 246 43 4,701 3711 31,055 2000 8,600 35,900 5,000 5,000 5,000 35,900 1,976 20,467 120 2,456 974 1,282 b,699 3,820 74,190 1990 5,800 24,700 5,000 5,000 2,700 22,000 1,270 12,542 120 1,505 712 862 208 1.68 384 67 43 4,845 3.713 34,768 2001 THRU 2041 8,600 35,9700 5,000 5,000 5,000 35,900 1,976 20,467 120 2,456 974 1,282 6,699 89,444 165,634 1991 6,000 26,000 5,000 5,000 5,000 26,000 10,500 1,976 14,817 120 1,778 974 1,282 6,021 4,480 39,248 AVAILABLE — KW ENERGY — MWH EXISTING DIESEL KW ADDITIONAL SOURCES - KW SURPLUS DEAD CREEK SILVER LAKE LAKE 1483 LAKE 649 LAKE 1878 MWH — DIESEL MWH — HYDRO PLUS SURPLUS HYDRO/INTERTIE INVESTMENT EQUIV AN COST (000) O&M COST (000) REPLACEMENT COST(000) SURPLUS ENERGY COST (000) DIESEL INVESTMENT (000) DIESEL EQUIV AN COST (000) GALLONS DIESEL FUEL (000) COST PER GALLON DIESEL FUEL COST (000) DIESEL O&M COST (000) DIESEL REPLACEMENT (000) ANNUAL COSTS PRES WORTH ANNUAL COST ACCUM PRES WORTH AVAILABLE - KW ENERGY — MWH EXISTING DIESEL KW ADDITIONAL SOURCES - KW SURPLUS DEAD CREEK SILVER LAKE LAKE 1483 LAKE 649 LAKE 1878 MWH — DIESEL MWH - HYDRO PLUS SURPLUS HYDRO/INTERTIE INVESTMENT EQUIV AN COST (000) O&M COST (000) REPLACEMENT COST(000) SURPLUS ENERGY COST (000) DIESEL INVESTMENT (000) DIESEL EQUIV AN COST (000) GALLONS DIESEL FUEL (000) COST PER GALLON DIESEL FUEL COST (000) DIESEL O&M COST (000) DIESEL REPLACEMENT (000) ANNUAL COSTS PRES WORTH ANNUAL COST ACCUM PRES WORTH 1981 5,000 16,900 5,000 2,070 2,070 2,070 1992 40,800 145,345 2,600 15,500 12,000 6,700 4,000 145,345 20,000 8,171 604 127 Yiz2 9,614 6,946 54,719 TABLE D-é6A ELECTRIC HEATING BY INTERTIED HYDRO SURPLUS ENERGY COST $.0625/KWH) RECONNAISSANCE STUDY OF ENERGY RE@UIREMENTS AND ALTERNATIVES FOR CORDOVA ECONOMIC 1982 1983 1984 5,000 §,400 8,200 18,100 20,400 21,200 5,000 5,000 5,000 - 3,400 3,200 18,100 5,400 7,400 - 14,800 13,800 - 12,220 - - 622 622 - iz 12 - 12 12 - 925 862 1,392 431 569 1527, 1.32 1.36 1,945 426 a51 276 10 10 43 43 43 2,264 2,250 2,412 2,198 2,121 2,207 4,268 6,389 8,596 1993 1994 40,400 40,000 44 143,645 141,845 151 2,200 1,800 1 15,500 15,500 15 12,000 12,000 12 6,700 6,700 & 4,000 4,000 4 - - 5 143,645 141,845 151 - - 25 8,171 8,171 9 604 604 127 127 606 494 1.86 1.92 9,508 91396 10 61669 6,398 6 61,388 47,786 74 ANALYSIS 1985 1986 18,800 20,500 64,595 74,195 3,300 5,000 15,500 15,500 64,595 74,195 77,500 = 3,634 3,634 221 el so 59 900 1,500 1.41 1.46 4,913 5,413 4,276 4,669 12,872 17,541 1995 1996 +600 43,200 °333°«145,333 1 >400 e +500 15,500 +000 12,000 +700 6,700 7000 4,000 7000 5,000 7333 «145,333 1 7000 = 7143 95143 664 664 142 142 375 = 1.99 2.06 +324 9,949 7825 6,386 9611 80,997 1987 20,400 71,695 4,900 15,500 71,695 3,634 221 59 1,344 5,257 4,402 21,943 1997 43,200 45,333 15,500 12,000 6,700 4,000 5,000 45,333 9,143 664 142 9,949 6,200 87,197 1988 31,900 118,745 4,400 15,500 12,000 118,745 63,240 6,092 405 95 1,194 7,785 6,330 28,273 1993 43,200 145,333 15,500 12,000 6,700 4,000 5,000 145,333 9,143 664 142 994d 6,019 93,216 1989 1990 31,300 37,500 116,145 136,185 3,800 3,300 15,500 15,500 12,000 12,000 “ 6,700 116,145 136,185 ae 33,500 6,092 7,394 405 S51 9S 115 1,031 912 1.62 1.63 7622 8,972 6,017 6,876 34,290 41,166 iver 2000 43,200 43,200 145,333 145,333 15,500 15,500 12,000 12,000 6,700 6,700 4,000 4,000 5,000 5,000 145,333 145,333 95143 9143 664 664 142 142 2.28 2.36 9,949 994? 5,844 5,674 99,060 104,734 1991 37,200 134,685 3,000 15,500 12,000 6,700 134,685 7,394 551 115 819 8,879 6,607 47,773 2001 THRU 2041 43,200 145,333 15,500 12,000 6,700 4,000 5,000 145,333 9,143 664 142 9,949 132,837 237,571 AVAILABLE ~— KW ENERGY — MWH EXISTING DIESEL KW ADDITIONAL SOURCES — KW SURPLUS BEAD CREEK SILVER LAKE LAKE 1488 LAKE 649 LAKE 1878 MWH - DIESEL MWH - HYDRO PLUS SURPLUS HYDRO/INTERTIE INVESTMENT EQUIV AN COST (000) O&M COST (000) REPLACEMENT COST(000) SURPLUS ENERGY COST (000) DIESEL INVESTMENT (000) DIESEL EQUIV AN COST (000) GALLONS DIESEL FUEL (000) COST PER GALLON DIESEL FUEL COST (000) DIESEL O&M COST (000) DIESEL REPLACEMENT (000) ANNUAL COSTS PRES WORTH ANNUAL COST ACCUM PRES WORTH AVAILABLE — KW ENERGY ~ MWH EXISTING DIESEL KW ADDITIONAL SOURCES — KW SURPLUS DEAD CREEK SILVER LAKE LAKE 1486 LAKE 649 LAKE 1878 MWH - DIESEL MWH - HYDRO PLUS SURPLUS HYDRO/INTERTIE INVESTMENT EQUIV AN COST (000) O&M COST (000) REPLACEMENT COST(000) SURPLUS ENERGY COST (000) DIESEL INVESTMENT (000) DIESEL EQUIV AN COST (000) GALLONS DIESEL FUEL (000) COST PER GALLON DIESEL FUEL COST (000) DIESEL O&M COST (000) DIESEL REPLACEMENT (000) ANNUAL COSTS PRES WORTH ANNUAL COST ACCUM PRES WORTH 1981 5,000 14,900 5,000 2,070 2,070 2,070 1992 40,800 145,345 2,600 15,500 12,000 6,700 4,000 145,345 20,000 8,171 604 pkey 114 1.80 9,016 6,514 47,590 TABLE D-6B ELECTRIC HEATING BY INTERTIED HYDRO (SURPLUS ENERGY COST $.01/KWH) RECONNAISSANCE STUDY OF ENERGY REGUIREMENTS AND ALTERNATIVES FOR CORDOVA ECONOMIC ANALYSIS 1. 1982 1983 5,000 8,400 18,100 20,400 5,000 5,000 - 3,400 18,100 5,400 = 14,800 - 12,220 - 622 - 12 - 12 - 148 1,392 431 1.27 1562 1,945 626 276 10 43 43 2,264 1,473 2,198 1,388 4,268 5,656 1993 1 40,400 40, 143,445 141, 2,200 1, 15,500 15, 12,000 12, 6,700 4, 4,000 4, 143,445 141, 8.171 g, 604 127 97 1.86 2,999 a, 6.312 6, 53,902 60, 1984 1985-1986 8,200 18,800 20,500 21,200 64,595 74,195 5,000 - - 3,200 3,300 5,000 - 15,500 15,500 7,400 - - 13,800 64,595 74,195 - 77,500 - 622 3,434 3,634 1z 221 221 12 59 59 138 144 240 569 - - 1.346 1.41 1.46 851 - - 10 - - 43 - - 1,683 4,057 4,153 1,545 3,405 3,582 7,201 10,806 14,388 994 1995 1996 000 44,400 43,200 845 151,333 145,339 1 800 1,400 - 500 15,500 15,500 000 12,000 12,000 700 6,700 4,700 000 4,000 4,000 - 5,000 5,000 845 151,333 145,339 1 - 25,000 - 171 9,143 9,143 604 664 664 127 142 142 79 60 = ve 1.99 2.06 981 10,009 9,949 116 6.617 386 018 66,635 73,021 1987 20,400 71,695 4,900 15,500 71,695 3,634 med Ss? 215 4,128 3,457 17,845 1997 43,200 45,333 15,500 12,000 6,700 4,000 5,000 45,333 9,143 664 142 9,949 6,200 79,221 1988 31,900 118,745 4,400 15,500 12,000 118,745 63,240 6,092 405 aS 191 6,782 5,514 23,359 1998 43,200 145,333 15,500 12,000 6,700 4,000 5,000 145,333 95143 664 142 9,949 6,019 85,240 1989 1990 1991 31,300 37,500 37,200 114,145 136,185 134,485 3,800 3,300 2,000 15,500 15,500 15,500 12,000 12,000 12,000 - 6,700 6,700 116,145 136,185 134,485 - 33,500 - 6,092 75394 75394 405 S51 S51 95 iis 115 165 146 131 1.62 1.68 1.74 6,756 8,206 8,191 5,333 6,289 6,095 28,692 34,981 41,076 1999 2000 2001 THRU 2041 43,200 43,200 43,200 145,333 145,333 145,333 15,500 15,500 15,500 12,000 12,000 12,000 4,700 45700 6,700 4,000 4,000 4,000 5,000 5,000 5,000 145,333 145,333 145,333 9,143 9,143 9,143 664 664 664 142 142 142 2.28 2.36 2.36 9,949 2,949 9,949 5,844 5,674 132,837 91,084 96,758 229,595 TABLE D-7 DIESEL GENERATION WITH WASTE HEAT RECONNAISSANCE STUDY OF ENERGY REQUIREMENTS AND ALTERNATIVES FOR CORDOVA ECONOMIC ANALYSIS 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 DEMAND -- KW 3,500 3,600 4,700 4,900 5,000 5,100 5,300 5,400 5,400 5,800 6,000 ENERGY -- MWH 16,900 18,000 20,500 21,200 22,000 21,800 22,300 23,300 23,800 24,700 26,000 EXISTING DIESEL - KW 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 ADDITIONAL SOURCES ~ KW UNIT 1 - - - - 2,500 2,500 2,500 2,500 2,500 2,500 2,500 UNIT 2 - - - - - - - - - - - UNIT 3 - - - - - - - - - - - DIESEL INVESTMENT (000) - - - - 1,075 - - ~ - - - DIESEL EQUIV AN COST (000) - - - - 72 72 72 72 72 72 72 GALLONS DIESEL FUEL (000) 1,300 1,384 1,576 1.630 1,692 1,676 1,715 1,792 1,830 1,899 1,999 COST PER GALLON 1.23 i. 27 1-2 1.36 1.41 1.46 inst 1.56 1.42 1.68 1.74 DIESEL FUEL COST (000) 1,759 1,933 2,288 2.438 2,624 2,692 2,849 3,075 3,261 3,509 3,826 DIESEL O&M COST (000) 268 276 294 298 304 303 306 213 317 323 332 DIESEL REPLACEMENT (000) 43 43 43 43 65 65 65 65 65 65 45 DIESEL ANNUAL COST (000) 2,070 2,252 2,625 2,779 3,065 3,132 3,292 3,525 3,715 35969 4,295 WASTE HEAT INVESTMENT (000) - - 1,900 - - - - - - - - EQUIV AN COST (000) - - 127.8 127.8 127.8 127.8 127.8 127.8 127.8 127.8 127.8 O&M COST (000) - - 47.5 47.5 47.5 A735 47.5 47.5 47.5 47.5 47.5 REPLACEMENT COST (000) - - 38.0 38.0 38.0 38.0 38.0 38.0 38.0 38.0 38.0 GALLONS DIESEL DISPLACED (000) - - 460 440 440 460 460 460 460 460 460 DOLLAR VALUE (000) - - (606) (627) (649) (672) (696) (720) (745) (771) (798) WASTE HEAT AN COST (000) - - (393) (414) (436) (459) (483) (507) (532) (558) «= (S85) NET ANNUAL COST (000) 2,070 2,252 2,232 2,365 2,629 2,473 2,809 3,018 3,183 3,411 3,710 PRES WORTH AN COST (000) 2,070 25186 2,104 2,164 2,336 2,306 2,952 2,454 2,513 2,614 2,761 ACCUM PRES WORTH AN COST (000) 2,070 4,256 6,360 $524 10,860 13,166 15,518 17,972 20,485 23,099 25,860 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 THRU 2041 DEMAND -- KW 7 6,800 7,000 7,200 7,400 7,400 7,900 8.100 8,300 8,400 8,400 ENERGY -~ MWH 27,700 28,900 29,500 30,100 31,000 31,800 23,000 34,500 35,900 35,900 EXISTING DIESEL - KW 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 ADDITIONAL SOURCES — KW UNIT 1 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 UNIT 2 - - - 2,500 2,500 2,500 2,500 2,500 2,500 2,500 UNIT @ C - = = = = = - - - DIESEL INVESTMENT (000) - - - 1,075 - - - - - - DIESEL EQUIV AN COST (000) 72 72 72 145 145 145 145 145 145 145 GALLONS DIESEL FUEL (000) 25130 2.222 2.269 2,315 2,384 2,445 2,538 2,653 2,761 2,761 COST PER GALLON 1.80 1.86 1.92 1.99 2.06 2.13) 2.21 2.28 2.36 2.36 DIESEL FUEL COST (000) 4,217 4,546 4,792 5,068 5,402 5,729 4,170 6454 7,148 71168 DIESEL O&M COST (000) 344 352 357 361 347 373 381 392 401 4o1 DIESEL REPLACEMENT (000) 65 6s 65 86 86 Bb 86 86 a6 a6 DIESEL ANNUAL COST (000) 4,698 5,035 5,284 5.440 46,000 6,333 6,782 7,277 7,800 71800 WASTE HEAT INVESTMENT (000) - - - - - - - - - - EQUIV AN COST (000) 127.8 127.8 127.8 127.8 127.8 127.8 127.8 127.8 127.8 127.8 O&M COST (000) 47.5 47.5 47.5 47.5 47.5 47.5 47.5 47.5 47.5 47.5 REPLACEMENT COST (000) 38.0 38.0 38.0 38.0 38.0 38.0 38.0 38.0 38.0 38.0 GALLONS DIESEL DISPLACED (000) 460 440 460 440 460 460 460 440 440 460 DOLLAR VALUE (000) (826) (855) (885) (916) = (948) = (981) (1,015) (1,051) (1,088) (1,088) WASTE HEAT AN COST (000) (413) (642) (472) (703) (735) (768) (802) (838) (875) (875) NET ANNUAL COST (000) 4,085 4,393 4,414 4,957 5,265 5,565 5,980 6,439 6,925 4,925 PRES WORTH AN COST (000) 2,951 3,081 3,142 3,277 35379 3,468 3,418 3,782 3,949 92,461 ACCUM PRES WORTH AN COST (000) 28,911 31,892 35,034 38,311 41,490 45,158 48,776 52,558 56,507 148,968 E. bibliography APPENDIX E BIBLIOGRAPHY Coal Resources Averitt, P.; Coal Resources of the United States; U.S. Geological Survey Bulletin 1412; 1975. Barnes, F.F., A Review of the Geology and Coal Resources of the Bering River Coal Field; U.S. Geological Survey Circular 146; 1951. Barnes, F.F.; Coal Resources of Alaska; U.S. Geological Survey Bulletin 1242-B; 1967. Bottge, R.G.; Coal as an Energy Source for Barrow, Alaska; U.S. Bureau of Mines Report for the Alaska Power Authority; 1977. Coal Fields, Alaska; University of Alaska M.I.R.L Report No. 31; 1973. Cooper, H.M., et al; Analysis of Alaska Coals; U.S. Bureau of Mines Tech. Paper 682; 1946. Hankinson, F.C.; Petrographic Evaluation of Coking Potential of Selected Alaskan Coals and Blends; University of Alaska M.I.R.L. Report No. 35/1965: Howell, S.B.; Cost Study: Chignik Bay Coal Field; U.S. Bureau of Mines Internal Report; 1979. Janson, Lone; The Copper Spike; Northwest Alaska Publishing Co. ; Anchorage; 1975. U.S. Geological Survey Miscellaneous Geologic Investigations Map 1-308; 1969. apa26/01 E=1 APPENDIX E BIBLIOGRAPHY Kennedy, Andrew; Report on Field Examination of the 33 Cunningham Alaska Coal Entries; U.S. Congress, Investigation of the Department of the Interior and of the Bureau of Forestry; 1910. Martin, G.C.; Geology and Mineral Resources of Controller Bay Region, Alaska; U.S. Geological Survey Bulletin 335; 1908. McGee, D.L., and O'Conner, Kristina M.; Mineral Resources of Alaska and State of Alaska, DNR, Division of Geological and Geophysical Surveys Open File Report 51; 1976. Miller, D.J.; Geology at the Site of a Proposed Dam and Reservoir on Power Creek near Cordova, Alaska; U.S. Geological Survey Circular 136; 1951. Miller, D.J.; Geology of the Katalla District, Gulf of Alaska Tertiary Province, Alaska; U.S. Geological Survey, Open File Report 206; 1961. Miller, D.J., Payne, T.G., Gryc, George, with Annotated Bibliography by U.S. Geological Survey Bulletin 1094; 1969. Plafker, George; Geologic Map of the Gulf of Alaska Tertiary Province, Alaska; U.S. Geological Survey Miscellaneous Geologic Investiga- tions Map 1-484; 1967. from Bering River Field, Alaska; University of Alaska M.I.R.L Report No. 21; 1959. natives for Kotzebue; Alaska Power Authority; 1980. Robert W. Retherford Associates; Bristol Bay Energy and Electric Power Potential, Phase 1; U.S. Department of Energy; 1979. apa26/02 E-2 APPENDIX E BIBLIOGRAPHY Carbon Creek) Area of the Bering River Coal Field; U.S. Geological Survey General Report; 1976. 0i] and Gas Resources Publications: American Petroleum Institute; “Reserves of Crude Oi], Natural Gas Liquids and Natural Gas in the United States and Canada as of December 31, 1968"; American Gas Association and Canadian Petroleum Association; V. 23, p. 31; 1969. U.S. Department of Interfor Bureau of Mines, Informational Handout 19201974; 1975. Dolton, G.L., et. al.; Estimates of Undiscovered Recoverable Resources of Conventionally Producible Oil and Gas in the United States; U.S. Geological Survey Open File Report 81-192; 1981. Gates, G.0., Grantz, Arthur and Patton, W.W., Jr.; Geology and Natural Gas and Oi] Resources in Alaska; Natural Gases of North America, Edited by B.W. Beebe and F. Curtis; Amer. Assoc. Petrol. Geolo- gists Memoir 9, V. 9, p. 3-48; 1968. Grantz, Arthur; "Petroleum and Natural Gas - Southern Alaska"; Mineral and Water Resources of Alaska; U.S. Congress, Senate Committee on Interior and Insular Affairs, 88th Congress, 2nd Session, Committee Prit., p. 44-62; 1964. apa26/03 E-3 APPENDIX E BIBLIOGRAPHY Gryc, George; "Summary of Potential Petroleum Resources of Region I United States - Their Geology and Potential; ed. by I.H. Gram; Amer. Assoc. Petrol. Geol. Memoir 15, V. 1, p. 55-67; 1971. LeMay, W.J.; "A Perspective on Alaska's Oi] Potentials"; Oi1 and Gas Journal; V. 67, No. 8., p. 114-120; 1969. Region, Alaska; U.S. Geological Survey Bulletin 335; 1908. McConkey, W., Lane, D., Quinlan, C., Rahm, M., and Rutledge, G.; Alaska's Energy Resources: Inventory of Oil, Gas, Coal, Hydro- electric and Uranium Resources; Vol. I and Vol. II; 1977. Miller, D.J., Payne, T.G., and Gryc, George; Geology of Possible Petroleum Provinces in Alaska; with annotated bibliography by E.H. Cobb; U.S. Geological Survey Bulletin 1094; 1959. Moore, Billy J.; "Tables on Alaskan Gases"; Analyses of Natural Gases; U.S. Department of Interior Bureau of Mines; p. 4-8; 1975. State of Alaska, Department of Natural Resources, Division of Geological and Geophysical Surveys; Estimated Speculative Recoverable 1974. U.S. Department of Interior Bureau of Mines; Alaska 1/250,000 Scale Quadrangle Map Overlays Showing Exploratory Oi] and Gas Well File Report 69-73 (updated yearly); 1973. apa26/04 E-4 APPENDIX E BIBLIOGRAPHY U.S. Department of Interior Bureau of Mines; Minerals, Fuels, Geology-- mission for Alaska; Volume 4: Inventory Report - Southcentral Region and Volume 6: Inventory Report - Southcentral Region; edited and assembled by Arctic Environmental Information and Data Center; 1974. U.S. Department of Interior Geological Survey; Oil and Gas Regions and Provinces, State of Alaska USA; Resources Appraisal Group, Branch of Oi] and Gas Resources for U.S.G.$. Circular 725; 1974. Personal Communications: Brewer, Max, Director, National Petroleum Reserve Development for Husky 0i1 Co., Anchorage. Chatterton, C.V., President, Rowan Drilling Co., Anchorage. Mangus, Martin, Petroleum Geologic Consultant, Anchorage. McMullin, Robert, Geologist, U.S. Geological Survey, Anchorage. Geothermal Resources Forbes, R.B.; Geothermal Energy and Wind Power, Alternate Energy Sources for Alaska; Alaska Energy Office and Geophysical Institute, Univer- sity of Alaska; p. 144; 1976. Godwin, L.H.; Classification of Public Lands Valuable for Geothermal Steam and Associated Geothermal Resources; U.S. Geological Survey Circular 647; p. 18; 1971. McConkey, W., Quinlan, C., Rutledge, G., Lane, D., and Rahm, M.; Alaska's Energy Resources: Findings and Analysis; Alaska Division of Energy and Power Development; p. 244; 1977. apa26/05 E-5 APPENDIX E BIBLIOGRAPHY McFadden, W.A., Jr., Wanek, A.A., and Callahan, J.E.; Alaska Geothermal Resources Minutes #1; Minutes of Mineral Land Classification Board; 1971. McFadden, W.A., Jr., Wanek, A.A., and Callahan, J.E.; Alaska Geothermal Resources Minutes #2; Minutes of Mineral Land Classification Board; 1971. Miller, T.P.; Distribution and Chemical Analyses of Thermal Springs in Alaska; U.S. Geological Survey Open File Report; 1972. Miller, T.P., Barnes, F., and Patton, W.W., Jr.; Geologic Setting and Chemical Characteristics of Hot Springs in Central and Western Alaska; U.S. Geological Survey Open File Report; 1972. Miller, T.P., and Barnes, Ivan; Potential for Geothermal Energy Develop- ment in Alaska--Summary; Circum-Pacific Energy and Mineral Resources Mem. 25, A.A.P.G.; 1976. Muffler, L.J.P.; Assessment of Geothermal Resources of the United States; U.S. Geological Survey Circular 790; 1978. Ogle W.E.; Geothermal Energy Possibilities in Alaska; Consultant, Anchorage, Alaska; 1974. U.S. Code of Federal Regulations; Title 43, Public Lands, Sect. 3200, Geothermal Leasing, Part 2310, Withdrawals. U.S. Congress; Geothermal Steam Act, Public Law 91-581; 84 Stat. 1566; 1970. Waring, G.A.; Mineral Springs of Alaska; U.S.Geological Survey Water Supply Paper 492; 1917. apa26/06 E-6 APPENDIX E BIBLIOGRAPHY White, D.F., and Williams, D.L.; Assessment of Geothermal Resources of the United States; U.S. Geological Survey Circular 726, p. 155; 1975. Energy Technologies Alaska Department of Commerce and Economic Development; Jobs and Power for Alaskans; July 1978. Alaska Division of Energy and Power Development, Department of Commerce and Economic Development; Minimizing Consumption of Exhaustible Energy Resources through Community Planning and Design; Final Report for U.S. Energy Research and Development Administration; Anchorage; October 1977. Alaska OCS Socioeconomic Studies Program; Northern Gulf of Alaska Petroleum Development Scenarios, Local Socioeconomic Impacts; for Bureau of Land Management Alaska Outer Continental Shelf Office; Technical Report No. 33; October 1979. Anonymous; "Energy from Biomass"; EPRI Journal; December 1980. Anonymous; "Photovoltaic Review"; IEEE Spectrum; February 1980. ASHRAE; Handbook of Fundamentals; Amercian Society of Heating, Refriger- ating, and Air-Conditioning Engineers, Inc.,; New York; 1977. ASHRAE; 1980 Systems; American Society of Heating, Refigerating, and Air-Conditioning Engineers, Inc.; New York; 1980. ASHRAE; 1979 Equipment; American Society of Heating, Refrigerating, and Air-Conditioning Engineers, Inc.; New York; 1979. apa26/07 E-7 APPENDIX E BIBLIOGRAPHY Berman, Ira M., and Schmidt, Philip S.; "Fuel Cells and Coal-Derived Fuel"; Power Engineering; October 1980. Black, Theodore W.; "PP&L Test Power from the Wind"; Power Engineering; July 1979. 1955. Baumeister, Theodore, Avallone, Eugene A., and Baumeister III, Theodore, Editors; Marks' Standard Handbook for Mechanical Engineers; Eighth Edition; McGraw-Hill Book Company; New York; 1978. Ecodyne Industrial Waste Treatment Division; 1977. Budwani, Ramesh H.; "Power Plant Capital Cost Analysis"; Power Engineering; May 1980. Bueche, Arthur M.; "Energy Conservation, Efficiency, and Substitution"; EPRI Journal; December 1980. California Energy Commission; Commercial Status: Electrical Generation and Nongeneration Technologies; Staff Draft; September 1979. California Energy Commission; Electricity Tomorrow: 1981 Final Report Summary; February 1981. California Energy Commission, Nontraditional Energy Technologies: Issues and Actions; Staff Report; December 1980. California Energy Commission; Volume 1: Technical Assessment Manual, Electrical Generation, Version One; Staff Draft with Appendices; September 1979. apa26/08 E-8 APPENDIX E BIBLIOGRAPHY Canter, Larry W. and Hill, Loren G.; Handbook of Variables for Environ- mental Impact Assessment; Ann Arbor Science Publishers, Inc.; Ann Arbor, Michigan; 1979. Comtois, Wilfred H.; "Economy of Scale in Power Plants"; Power Engineer- ing; August 1977. Creager, W. P., and Justin, D.; Hydroelectric Handbook; Second Edition; John Wiley & Sons, Inc.; New York; 1950. Davis, C. V., and Sorensen, K. E., Editors; Handbook of Applied Hydraulics; Third Edition; McGraw-Hill Book Company; New York; 1969. Denesdi, L,; “Fuel Savings with Turbines Modified for District Heating"; Power Engineering; February 1980. Earting, J. P., and Seifort, R. D.; Solar Energy Resource Potential in Alaska; University of Alaska Institute of Water Resources; 1978. Edison Electric Institute; Electric Heating and Cooling Handbook; New York; 1966. Inc.; Framingham, Massachusetts; 1980. Geothermal Resources Council; Direct Utilization of Geothermal Energy: A Technical Handbook; Special Report No. 7; 1979. Gilles, Theodore C.; "Air-to-Air Heat Pumps"; Plant Engineering; April 3, 1980. Godfrey, Robert Sturgis, Editor-in-Chief; Building Construction Cost Data 1980; Robert Snow Means Company, Inc.; 1979. apa26/09 E-9 APPENDIX £ BIBLIOGRAPHY Golden, Jack; Quellette, Robert P.; Saari, Sharon; and Cheremisinoff, Paul H.; Environmental Impact Data Book; Ann Arbor Science Publishers, Inc.; Ann Arbor, Michigan; 1979. Hanks, David J.; "Heat Pumps"; Specifying Engineer; February 1981. Harkins, H. L.; "Applying Cogeneration to Solve Tough Energy Problems"; Specifying Engineer; December 1979. Lihach, Nadine; "Lifting Hydro's Potential"; EPRI Journal; December 1980. Merritt, F. S., Editor; Standard Handbook for Civil Engineers; Second Edition; McGraw-Hil? Book Company; New York; 1976. Niess, Richard C.; "High Temperature Heat Pumps Can Accelerate the Use of Geothermal Energy"; Commercial Uses of Geothermal Heat; Geothermal Resources Council Special Report No. 9; June 1980. Norelli, Patrick; "Industrial Heat Pumps"; Plant Engineering; August 21 and September 18, 1980. Olds, F. C.; "Coal Resources and Outlook"; Power Engineering; October 1979. Reeder, John W., Coonrod, Patti L., Bragg, Nola I., Denig-Chakroff, Dave, and Markle, Donald R.; Alaska Geothermal Implementation Plan; Draft for U.S. Department of Energy; July 1980. Robert W. Retherford Associates; Alternate Energy Study: Angoon, Alaska; Preliminary Report for State of Alaska Division of Energy and Power Development; Anchorage; November 1980. apa26/010 E-10 APPENDIX E BIBLIOGRAPHY natives for Kotzebue; for Alaska Power Authority; Anchorage; June 1980. Robert W. Retherford Associates; Bristol Bay Energy and Electric Power Potential Phase 1; for U.S. Department of Energy; Anchorage; December 1979, Robert W. Retherford Associates; Final Report: Power Plant Site Inves- tigation, Cordova, Alaska; for Cordova Electric Cooperative; February 1980. Robert W. Retherford Associates; Lower Kuskokwim Single Wire Ground Return Transmission System Phase I Report; for State of Alaska, Department of Commerce and Economic Development; June 1980. Robert W. Retherford Associates; Transmission Intertie Kake-Petersburg, Alaska: A Reconnaissance Report; for Alaska Power Authority; Anchorage; October 1980. Robert W. Retherford Associates; Waste Heat Capture Study for State of Alaska; Anchorage; June 1978. R. W. Beck and Associates; Investigation of Alternative Solid Waste Management Systems; for City of Cordova; October 1979. Schweiger, Robert G.; "Burning Tomorrow's Fuels"; Power; February 1979. Singh, Ram Bux; Bio-Gas Plant; Mother's Print Shop; Hendersonville, North Carolina; 1975. Stoner, Carol Hupping, Editor; Producing Your Own Power; Rodale Press, Inc.; Emmaus, Pennsylvania; 1976. apa26/011 E-11 APPENDIX E BIBLIOGRAPHY Technical Publishing; Plant Engineering Directory and Specifications Catalog; 1980. U.S. Army Corps of Engineers; Feasibility Studies for Small Scale Hydro Additions; 1979. U.S. Army Corps of Engineers; Hydropower Computer Model; 1981. United States Department of Commerce, National Oceanic and Atmospheric Administration Environmental Data Service; Monthly Normals of Temperature, Precipitation and Heating and Cooling Degree Days 1940-1970 for Alaska. U.S. Department of Energy and FERC; Hydroelectric Power Evaluation; 1979. United States Department of Labor; Dictionary of Occupational Titles; Fourth Edition; 1977. University of Alaska Institute of Social and Economic Research; Electric Power in Alaska 1976-1995; August 1976. University of Oklahoma Science and Public Policy Program; Energy Alter- natives: A Comparative Analysis; Federal Energy Administration; Washington, DC; May 1975. - Yould, E. P.; "The Alaska Hydropower Resource"; Alaska Business Trends; Alaska Pacific Bank Corporation. Young, Arthur and Company; A Discussion of Considerations Pertaining to Rural Energy Policy Options; State of Alaska Department of Commerce and Economic Development, Division of Energy and Power Development; April 1979. apa26/012 E-12 F. comments CITY OF CORDOV Phone: (907) 424-3237 or 424-3238 Box 1210 602 Railroad Ave. CORDOVA, ALASKA 99574 “The Friendly City” peor Warren Eyneart, P.E. Robert W. Retherford International Engineering Co. 813 "D" Street Anchorage, AK 99501 Dear Mr. Enyeart: I am writing to provide some comments and guidelines for preparation of the final report of the Cordova Alternate Energy Study. I have reviewed the various comments received on the draft and feel they are very reasonable. In particular, I would like to call your attention to the Power Authority's comment No. 9, which stressed the need to prepare alternative plans. Several of your proposals (local hydro) could work in conjunction with continued diesel generation, but the draft did not discuss the capital costs or O & Mof such plans. One area that needs more discussion is waste heat recovery from the existing plant. The "Power Site Selection Study, Cordova" by Retherford, discussed this in detail. The use of the waste heat for manufacturing electricity ‘or sale for heating homes should be addressed in more detail. In accordance with past paractices of the Alaska Power Authority, you should include each agency's comments and specifically address them in an Appendix in the final report. Although, I realize it may require some delay in printing the final report, I would like you to provide three copies of the final draft of the report for the City of Cordova, Cordova Electric Cooperative and Alaska Power Authority for review and approval prior to printing 75 copies of the final report. We will comment within five (5) working days after receiving the final draft so you may continue close to schedule. Very truly yours, cc: Doug Bechtel - CEC Brent Petrie - APA UNITED STATES DEPARTMENT OF COMMERCE National Oceanic and Atmospheric Administration Nattonal Marine Fisheries Service P.O. Box 1668 Juneau, Alaska 99802 April 10, 1981 a Mr. Warren L. Enyeart, P.E. Project Manager International Engineering Company, Inc. 813 "D" Street P.O. Box 6410 Anchorage, Alaska 99502 Dear Mr. Enyeart: We have received your letter of February 27, 1981, requesting our comments on the Draft Reconnaissance Study of Energy Requirements and Alternatives for Cordova. We have reviewed the Draft Report and have no comment to offer at this time. Thank you for the opportunity to comment. Sincerely, = Reber W. McVey / ine€tor, Alaska Region \ Ur. Perry Lovett, City Manager City of Cordova P.O, Sox 1230 Cordova, AX 99574 Dear Mr. Lovett: Here are our comments on the draft Reconnaissance Study of Hydropower Sites Near Cordova, Alaska, as requested by Mr. Enyeart from the Robert W. Retherford Division of International Engineering Company, Inc. The study appears to be logically presented, comprehensive and the supporting information well documented in the appendix. It points out that the resources for electric power in the area are very limited. Recommendations as to further study include: the local identified hydro alternatives; an intertie to Valdez (with the possibility of developing suall hydroelectric potentials along the routing); and a small scale coal-fired steamplant, We certainly agrea with the recommendations for further study of the local hydros and the interconnection. However, we feel that the recogmenda- tion to study the potential of using a small scale coal-fired steamplant should be given lower study priority. This is primarily due to the cost uncertainties associated with small steamplants. We note that the study identified wood use for space heating as a possible alternative to oil. This may have a significant impact on the future use of oil, and we suggest that ia future studies, it be analyzed in wore detail. The projected yearly peak demand and energy use estimated in the study is generally gomewhat lower than our agency estinated in conjunction with Corps of Engineers studies for Power Creek, However, it 1s of tha Sane general magnitude, and the variation does not appear significant, np The cost of $300,000 to $400,600 for a feasibility study of the 435-ki Crater Lake hydropower site scens high to us. We appreciate the opportunity to comment. Sincerely, Robert J. Cross Adninistrator cc: Eric Yould, Alaska Power Authority Robert W. Retherford Associates DCOTSCHALL: ws Mr. Warren Enyeart, P.E. all Robert W. Retherford Division International Engineering Company 813 D Street Anchorage, Alaska 99501 Dear Mr. Enyeart: Your Draft Report: Reconnaissance Study of Energy Requirements and Alter- natives For Cordova is generally comprehensive and thorough. However, we feel the following points should be cleaned up or addressed in the final report: a Intertie to Valdez. Your costs for intertie route #2 for 59 miles over very rugged country at $12.2 million seemed questionable when compared to the 63 mile Cordova to Carbon Creek line (much less rugged country and 37 miles of existing road access) at $11,050,000. Bob Retherford's explanation at the public meeting pointed out that very different con- struction techniques would be used for each line. Some additional explanation in the text of the possible construction technique for intertie route #2 would help clarify this seeming inconsistency. Intertie route 3 also includes smaller hydro sites in addition to the large hydro potential at Woods Canyon, Cleve, and Million Dollar. Such smaller projects may be more suitable for a Cordova-Valdez market and should be discussed at a recon level. They might include Cleave Creek, Tiekel River, Van Cleve Lake, Heiden Canyon (Lowe River headwaters), Brown Creek, and an unnamed creek in T.10S. R. 5W, Copper River Meridian. Based on comments received and the recon flight of intertie route #2, we suggest you reexamine the proposed costs for a detailed feasibility study and make sure it is sufficient for necessary engineering and geotechnical feasibility studies. We also suggest you double check the estimate for feasibility studies of the coal fired plants, to make sure it will pro- vide for the necessary environmental studies in addition to engineering and economic feasibility studies. There was considerable discussion at the public meeting that the Valdez area may not have a significant surplus of power even with the pressure reducing turbine and Allison Creek hydro project in place. This needs to be clarified in the final report as it affects the viability of the intertie. In addition, other benefits of an intertie such as the shar- ing of reserves and increasing reliability should be discussed. Mr. Warren Enyeart, P. E. April 6, 1981 Page 2 Ref. pp. IV-5 Crater Lake is described as possibly offering "a 435 KW prime" hydroelectricity plant. We understand "prime power" from a hy- droelectricity plant as synonomous with continuous power. Continuous power from a hydroplant is generally defined as the power available from a plant on a continuous basis under the most adverse hydraulic (low flow) conditions. When one considers the very small watershed of Crater Lake, it seems that the 435 kW of prime power and 38,000 MWh per year for Crater Lake generation (p. B-15) is an error. Figure 4 "Projected Yearly Elec- trical Consumption, City of Cordova" shows only 16,000 MWh of total consumption for the year 1980. Crater Lake surely cannot generate more than twice the present yearly consumption of Cordova. Ref. pp.IV-16. Heat Pumps. This section should be expanded so that the lay reader knows what heat pumps are, how they work, and their availability for Cordova. The Alaska Power Administration has been conducting a demon- stration and evaluation of air and water source heat pumps in Juneau for the past two years. According to a verbal presentation by Bob Cross in Juneau on March 28, 1981, their data show the heat pumps to be 2.5 to 2.6 times as efficient in use of electricity as resistive electric space heat- ing. You should check with the Alaska Power Administration on this. Heat pumps may be more economic heating alternative for Cordova than resistive electric space heating or heating oi] and, if so, should be described more fully under technology alternatives (Chapter V) and energy technology pro- files (Appendix C). Ref. pp. IV-3. Item 3 Intertie with Valdez. This paragraph states that the Valdez area surplus is expected to decrease by 6% per year and refers the reader to Figure 11 in Chapter VI. However, Figure 11 shows a straight line of Valdez area surplus for 1983-1990. This should be corrected. Fur- thermore, Figure 12 does not match up with Figure 11, i.e., the Figure 12 surplus shows about a 15 MW surplus vs. 9 MW surplus on Figure 11, and the addition of Dead Creek shows a 25 MW peak capacity on Figure 12 vs. a 15 MW peak on Figure 11. Reference Chapter IV. Wood as a space heating fuel deserves expanded men- tion since many people in Cordova mentioned that there had been a noticeable shift in the last two years from heating 011 to wood stoves. For lack of a better figure, I suggest you use estimates provided by the U. S. Forest Service in Ken Kilborn's comment. Furthermore, I was told by a local re- sident, whose name I cannot recall, that the main restrictions on wood harvesting in the nearby Chugach National Forest were due to the fact that the land was selected by Eyak Village Corporation and Chugach Natives, Inc. They indicated that wood gathering by permit or fee might be allowed after title had been transferred to the Natives. While it seems obvious that wood alone cannot provide for Cordova's energy needs it seems like it may continue to be a viable option for several years on an individual basis. Mr. Warren Enyeart, P. E. April 6, 1981 Page 3 9. Chapter VI. This portion does present a series of plans to meet Cordova's energy requirements, but is not in complete conformance with "Alaska Power Authority Reconnaissance Study Regulations" which were provided to you at the beginning of the contract. The following excerpts from the reconnais- sance study regulations should be used as guidelines in preparing the analysis and format for Chapter VI. (c) In order to allow comparative analysis of alternative power sources the authority in conducting a reconnaissance study will, to the extent applicable, use the following standard criteria and measures: (1) a "base case" plan will be developed that would meet the forecasted electric power requirements of the community or region and that would result from a continuation of present practices in the community or region and/or from a reliance on liquid fossil fuel generation modes. The "base case” plan will serve ‘as a basis for comparing alternative plans. (2) other alternatives, either aig or in combina- be i ee: te into two or more plans each of which sted requirements. To the extent possible e formated to provide a common level of reli- period will be anning period is NY year and pli ” i ‘ ‘represen e esti yf money, the present worth. t 0 sig i Wafning period wil edias of " w Rajustneng for ya vic . ) ra y will be establ : thority 7 various eon thalt : uated to formate ‘the’ diesel option. Wou ertied hydro) be in con place it as a separate also be a suitable plan capacity? Mr. Warren Enyeart, P. E. April 6, 1981 Page 4 Please refer to your firm's recent draft report on Thirteen Western Alaska Villages, Chapters 6 and 7, for a format for presentation of base case and alter- native plans... The Cordova report seems to have all the necessary numbers for preparation of such plans but some revision in the presentation format would be helpful. Please feel free to contact me if you have any questions on the above com- ments. All comments which you have received on the draft should be included in an appendix in the final report. Sincerely, as FOR THE EXECUTIVE DIRECTOR 7 $ o - . Brent N. Petrie Project Manager file STAVE Ol ALASIMN [oem DEPART MENT OF FISH AND GAME OFFICE OF THE COMMISSIONER | ‘SuNcaU, ALASKA 09801 March 27, 1981 City of Cordova P.O. Box 1210 Cordova, Alaska 99574 Attention: Mr. Perry Lovett, City Manager Gentlemen: Re: Draft Report: Reconnaissance Study of Energy Requirements and Alternatives for Cordova The Alaska Department of Fish and Game has reviewed the above referenced study and offers no specific comments. We request, however, the opportunity to review any subsequent studies or reports regarding energy related projects for Cordova. If you have any questions, please do not hesitate to contact us. Sincerely, ZI Y Specie ff lle. William G. Demmert, Jr., Ed.D / Deputy Commissfoner Program Management (907) 465-4100 cc: C. Yanagawa qatesaia VALDEZ Fle 2722 TATITLEK 4, (a 0 ps “ee, wee CORDOVA EYAK Mies, 99, CHENEGA 2 o SEWARD March 16, 1981 ENGLISH BAY PORT GRAHAM Mr. Brent Petrie, Project Manager Alaska Power Authority , 333 West .4th Avenue, Suite 31 Anchorage, Alaska 99501 Dear Mr. Petrie: I have reviewed your Draft Report: Reconnaissance Study of Energy Requirements and Alternatives for Cordova. Unfortunately, I will not be able to attend the March 19.meeting on this report in Cordova, so the following remarks summarize my reaction to this draft. ‘ Chugach Natives, Inc., is the Alaska Native regional corporation for the area encompassed in this study. For a myriad of reasons our corporation has yet to receive the entitlement of some 377,000 acres of land promised to us under the Alaska Native Claims Settlement Act of 1971. Once this transfer is completed, Chugach will be primarily a natural resources company. A considerable amount of the land which Chugach will eventually receive title to will be located in the general vicinity of Cordova. Lands currently under consideration for transfer to Chugach include several of the small potential hydro-electric sites located between Cordova and Valdez which were mentioned in this study, along with the Bering River coal field area and the Katalla oil and gas area. We readily admit that in pure economic terms. neither the Bering River coal field nor the Katalla oil and natural gas resources justify development solely for local use. However, as a natural resources com- pany, Chugach has begun and intends to continue pursuing the development of these resources for non-local consumption.. For instance, negotiations are actively underway with a number of major domestic and foreign companies concerning the development of the Bering River coal field at this time. If any of these negotiations reach fruition, and development of the field Chugach 903 West No:thern Lights Blvd., Suite 201, Anchorage, Alaska 99503, Phone (907) 276-1080 Natives, Inc. Mr. Brent Petrie Mareh Lo, LYS1 Page Two is determined to be feasible, then the economics of utilizing a portion of the coal for local use are altered radically. What had heretofore been an uneconomical energy resource, given the high capital costs and the low demand, would suddenly become a very viable energy alternative. Therefore, in general we do not disagree with your conclusions, based on the assumptions given. But somewhere in your study you should provide the latitude for a scenario such as that sketched above for the Bering River coal field. Such latitude would lend more credibility to your report under a wider variety of future energy scenarios for Cor- dova. Also, one specific statement which should be corrected in your final report is where you state on page III-3 that the Eyak Native Village Coop owns Chugach Alaska Fisheries. This should read that Chugach Alaska Fisheries, Inc., is a wholly-owned subsidiary of Chugach Natives, Inc. : Chugach looks forward to a continuing involvement in Cordova's energy affairs. Sincerely, CHUG. INC. NATIVES, Director of Lands and Natural Resources cc: Perry Lovett Doug Bechtel DEPARTMENT OF THE ARMY ALASKA DISTRICT. CORPS OF EN REPLY TO ATTENTION OF: NPAEN-PL-R Mr. Perry Lovett City Manager JLAEEA POW AES P.O. Box 1210 Cordova, Alaska 99574 Dear Mr. Lovett: Thank you for providing us the opportunity of reviewing the Draft Report: Reconnaissance Study of Energy Requirements and Alternatives for Cordova. We do not have the expertise to comment on most of the alternatives presented but would like to furnish the following comments on the hydropower alternative: 1. Reference Section IV, paragraph 1.a. Besides environmental problems, the Million Dollar, Cleve and Woods Canyon projects should be excluded because they are too large for the Cordova market. However, other sites in the Copper River area might be included. These are Tiekel River, Sheep Creek and Cleve Creek. 2. Reference Section IV, paragraph 1.b. The Corps' investigations to date on Power Creek indicate that a 6,000 kw run-of-river project may be feasible. We are also studying the possibility of a storage project at the same site at Ohman Falls. Other sites on Power Creek have been ruled out due to the extreme depth to bedrock. 3. Reference Section IV, paragraph ].c. The recent Corps' study for Valdez shows that there would be no surplus energy at Valdez until after the Solomon Gulch project is completed and that even if the pressure reducing turbine is installed in the Trans Alaska pipeline, the Valdez-Glennallen area will need additional power in 1990 for the winter peak demands. It should be mentioned that a pressure reducing turbine is only a short range energy source since the supply of oi] from the North Slope is limited. The intertie proposal should be studied, to determine the feasibility of the numerous sites along the intertie route, and other benefits from an intertie such as balancing energy demands. 4. Reference Figure 7. Silver Lake and Simpson Creek could be added to Route 2. Route 3 Intertie could have projects tied into it such as Cleve Creek, Tiekel River, Sheep Creek and Van Cleve Lake. NPAEN-PL-R Mr. Perry Lovett 20 MAR i981 5. Reference Section IV, paragraph 1.d. For Crater Lake it should be mentioned that the cannery at Orca has a water right of one cfs. A dual purpose project of water supply and hydropower should be recommended. 6. Reference Section VIII page | and Figure 13. The second stage for Power Creek is still under study. The cost of $5,000/kw to develop smal] hydropower sites along the intertie line and $11,200,000 for the SWGR line appear to be low for this terrain. 7. Reference Appendix B, page B-15. Discharge from Crater Lake to Eyak Lake is more difficult due to adverse topography. It should discharge toward Orca. Our estimates indicate the cost for this project is higher than the $3,500 stated. Other than these comments, the Draft Report is very good. We are still planning to drill the site on Power Creek this summer and also install a gage on the outflow from Crater Lake. We hope to discuss this with you when you come to the harbor bid opening next month. If we can be of further assistance, please do not hesitate to contact Mr. Ken Hitch of our Planning Branch at 752-3461. Sincerely, /7S/ HARLAN E. MOORE HARLAN E. MOORE Chief, Engineering Division Copy Furnished: - Brent Petrie + Alaska Power Authority _-* 7596790 U.S. DEPARTMENT OF AGRICULTURE SPEED MEMO MESSAGE (WRITE CONCISE MESSAGE. SIGN AND FORWARD PARTS 1 AND 3 TO ADDRESSEE. RETAIN PART@2.) basp Vato &, Piatra tice frganrwmd tn Wood dey fr pre hati Ue Prod rel tol lice Xo POOR 1009 Srrele Po yen. Rdetrrmmmns) thy Lyocul B HL ore that to 17,100 Wellin BtaS /yeu nd? of desis riuthigned pn hh h—9: Cored ee C4 g hel) bo mented Ow (Page U-/ TIt@ vr coi QD radinake lucde ah ‘ = a Lowery flemse “of 30008 e600 Cages 0-5 coutel cmsr— Urol dee. > = 9 abel. 77/26: brevet Ate en Cale wooed Pees ey a payee gee eee MAATe B® Bee lyove! Aft Ort , SIGNATURE a ee REPLY (USE THIS-SPACE FOR REPLY. SIGN AND DATE. RETURN PART 3 TO SENDER. RETAIN PART 1) RECEIVED [AAR 13 1981 i ALASKA POWER oso ITY SIGNATURE DATE 4626 2728, Phone: (907) 424-3237 CITY OF CORDOVA” h “ay or 424-3238 Box 1210 602 Railroad Ave. Vv CORDOVA, ALASKA 995748 “The Friendly City” iS Q Warren Enyeart, P.E. 3l® Project Manager Robert W. Retherford Assoc. Box 6410 Anchorage, AK 99502 Dear Mr. Enyeart: I thought the public hearing went well with several good comments and suggestions. Some areas that I feel should be tightened up and developed are: 1. Check projected planning budget costs for Valdez intertie. Several comments that budget costs are low. I agree that we don't want inflated costs--only best realistic estimated possible. 2. Coal fire plant. There should be planning budget costs for a new plant--5, 10, 15, 20 year estimated costs of operation and coal costs with consideration of the Healy, Beluga and Bering River Fields as sources. 3. Coal for heating. Same resources for residential and industrial heating--costs and availability of coal. Both of these should address the environmental conditions you brought up on rain runoff from the stockpile. 4. Copper River Run of River. What are the probabilities, problems, costs and environmental concerns (fish, etc.). 5. Pressure reducing turbine. There should be a more definite statement about the present and future plans for this project. Who will do it, when and how will power be utilized. 6. Discussion of statement that Valdez will be power-lean by 1984. 7. Dead Creek. What is environmental position, fish spawning stream, land ownership, costs, etc. A good vigorous discussion of this subject is certainly warranted. 8. ALPETCO. What are the probabilities of this project being built in Valdez. Effect on power needs. page 2 9. Ownership map of lands near Katella, Bering River Coal Fields and patented natural gas fields. The frank discussion of these issues are necessary before we take dead aim at selecting one or more items for a detailed feasibility study. We look forward to reviewing your interpretation of these items. Very truly yours, Perry B- al ager cc: Brent Petrie, APA Doug Bechtel, CEC M/S 443 13 MAR 1989 Perry Lovett, City Manager City of Cordova P. 0. Box 1210 Cordova, Alaska 99574 Subject: Draft Report: Reconnaissance Study of Energy Requirements and Alternatives for Cordova Dear Mr. Lovett: Thank you for giving us the opportunity to review the above draft study. We have no comments on the study, though we thought it was quite well done and interesting. We would appreciate the opportunity to review future feasibility studies which may be prepared on any of the hydroelectric or coal-fired power plant alternatives since we could have a role in the federal permits which may be required for such facilities. Please feel free to contact either myself or Judi Schwarz of my staff if you have any questions, We can be reached at (206) 442-1285. Sincerely yours, Elizabeth Corbyn, Chief Environmental Evaluation Branch cc: Warren L. Enyeart “ Yatarnational Engineering Company JSchwarz:bIm 03-13-81 TEWilson PROPERTY OF: Alaska Power Authority 334 W. 5th Ave. Anchorage, Alaska 99501 LIERARY COPY