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Home My WebLink AboutUpdate Of 1972 North Slope Transmission Study 1982 UPDATE OF 1972 NORTH SLOPE TRANSMISSION STUDY — | FEBRUARY 1982 <a UNITED STATES DEPARTMENT OF ENERGY ALASKA POWER ADMINISTRATION PROPERTY CF: Alaska Power Authority 334 W. 5th Ave. Anchorage, Alaska 99501 RECEIVED "np 1 UPDATE OF 7 1982 ALASKA POWER AUTHORITY 1972 NORTH SLOPE TRANSMISSION STUDY February 1982 UNITED STATES DEPARTMENT OF ENERGY ALASKA POWER ADMINISTRATION ABSTRACT This analysis updated the 1972 North Slope Transmission Study. High voltage power transmission lines to deliver power from Alaskan generating stations to the Pacific Northwest were analyzed within the broad concept of eventual power delivery to the Pacific Northwest, portions of Canada, and Southeast Alaska. Coal was determined to be the most likely resource for power generation and export as electric energy. Other energy resources were examined and found unavailable or too expensive. The specific case analyzed was a double circuit, HVDC system with capability of delivering 8,000 MW of electric power. Costs were estimated and economic analysis made of the project and several sensitivity analyses were made of alternative plans. Potential environmental impacts identified related to air and water quality, water supply, permafrost, and fish and wildlife resources. While the Pacific Northwest power demand could likely use the energy from the North Slope by the year 2000, costs of 11.2¢/kWh did not look economically attractive compared to energy at 5¢/kWh to 8¢/kwh generated in the Pacific Northwest. In addition, the $44 billion investment would be a major constraint to financing the project. Further studies did not appear warranted at this time. CONTENTS PART PAGE_NO. ABSTIRAG Tyarere ete etetefele)el<i« exelolotet oie) cle)sveieis leisiersisiors, 9) 91 s¥016/<1a'< s/ofele i ie IE NTRODU GION tererateterate ie tetoleioterorereleteleteleleverssaieteleleleraysvelaiors sieier= 1 PUD OSE iaiereteicisiels)o/eie lols loleloleie) oleic lolelolelejeleisielsioisicielssielslsrers 1 Background Of 1972) Study’ orc cicrcterereineiveieie one cieieioreie 1 Significant Evenits) Since 1972.35. 4nrsccercwieeeins 7 2s POTENTIAL GENERATION RESOURCES FOR BEEGTRIC POWER EXPORT <caemsriciiasicmincesie sie oc ccreiee 4s 9 COA re rererctelorotele ele le icvelel sere wisicieie eietsialolcis cee oleieisieieieleiclel sate 9 Natural Gas 10 HY CVOPOWE I a tereiotcleiciel oie eisiele eleieieiciss ll it Viste srorey 11 eto ote oierelelel efesieve le lenei o ster 13 WTI Ss. creterte re to rors rors: creret ne 610 (ote Lois o1 e) sowie 10re'e%e {o's (ole lei si sictei ae 13 TA dal Viera, «0:56 i515 ia12i nici alles fo16 6 (oraroterarayeiewreyors ets elo oeielesie 13 Resouycel ‘SUMMARY. <<): 6.5< cicisisici icin eioieiwn'e eiaieceeeisilies sc 13 35 PROGEGTBIEAN( 1oroioiefeleleselelereioisicleisisisieictateretela eiefereleloreloicielel yore 15 Steampllant; Description. screis:<s..0% 5 s100slic're' aisiels 0 ool 15 Transmission Line Description... 16 Transmission Technology 18 COSTS ae crstoreteleielstoleieim cle le oleielsicteicls ele oleloie wlelelel-Yele) )ereiee ele 20 Steampll ANt COS tS: sotescrsiya1 crepes 1010 (6 10 1cteloietsjsieie os 6 eie he 20 Caitital COStS ie reissers-ctero sets lo o(o10 Io olois) ot 101 n16/01 6 i019 20 Fixed Annual (Cosits\<<jjoocetereievcisisieicisisieleleleiloe sree 22 Operation and Maintenance Costs............... 22 Fan! Comts, Col ececacsssnevrertivibtsssesnssae 22 Transmission System CostsS........sccecsscssceses _ 23 Environmental Implications........ceccees ese eeeee 26 ECONOMIC Anal Sil Skarcrereseveteroyereie oie olel oFeieloleleleleleleereiele icicle) 32 GONSE MAT NES 31<)5- s1src lore elel ele vereieleleroiclelsi stole) sle1e)01 6 oi (elslerel 36 4, MARKEMABIISIT Yoyo cjeteretotoieteretoreloieieicieiereisrststc siatalelelalelera!eieleiererel= 37 Bis SUMMARN icteretetstereisyoisterelotcileielele) « ele lolefoicielelsisisisisisicio.6 cies cieiel ers 39 6. GUOSSARYiiveraretiotovelotoletetoiel)s1s) oracle (elelelerel oleielalstsicielelerslelelelele¥s\eis1 41 7. BiLBLTOGRAPHY, <5 <<< s0tefose: /<) 1a) torsisisieio\ala¥orei si sioie's's/e1s(e erclel eel 45 ii NUMBER “PAGE NO. 8. APPEND IE Xrsferetaporstetereyelat ol ari e%e7o1eIoiersiolo11e1s\0/6 ole foleioioleisleiels/eleisis] cio 49 A. ALASKA FACTOR AND GEOGRAPHIC INDEX................ 50 B. ESTIMATED ORIGINAL COAL RESOURCE OF ALASKA BY COALS FIELD Frsroperetererarstorsrstotsrereieioe oa tevetorsysieie(ote eJateteters 51 Cs ALASKA, RESERVES) =-"O1L Ss cisi0:< 010105 601s 0 s1e:5)010 coe sicicieioseie 52 DiSGESTPIMATIE TSUMMAR Vioyesoye ote leyetolal ele) ole ereleleloleielsielelere eleielelereleie pS E. TRANSMISSION LINE COST ESTIMATE...........ssceeeee 58 F. ESTIMATED ANNUAL FIXED CHARGES.............ccceee. 59 Gs (CORRESPONDENCE s5yo5a 5 ore ce rere oreretororss« « winter eicie) )eroieie 6 loloieic 60 FIGURES i TRANSMISSION ROUTES AND DISTANCES............... elereiere 2 (Ze CASES IT, TRANSMISSTONESYSTEM ‘eyerererere:0 210 ete teteFerolofeleroter=tololorey 3 St CASE, LI, TRANSMISSION SYSTEM <1. 3155010101 wrcieierereieeieisic «10 sioreis 4 4. CASE; Ts TRANSMISSION (SYSTEM 5\51510< <re1cte1srerarotsterere o/s ioieieisicla 6 Bis UNDEVELOPED HYDROELECTRIC RESOURCES OF ALASKA AFFECTED BY PUBLIC (DAW (9684.7 <oro 75151 s.c.510/0/njn'o aie 0\s1s)orer 5 2, 6s TYPICAL TOWER DESIGN + 800 KC (D.C.)............000 17 TABLES de EXAMPLES OF HIGH VOLTAGE DC TRANSMISSION SYSTEMS..... 19 oe SUMMARY OF COST ESTIMATES FOR NORTH SLOPE . POWERBUANIIS xyerere ara a\ore1= a \olatousicis/siaiclaisoisieis ress) s)olsislole isis sicr 21 Sis SUMMARY OF CASE 1 UNIT COSTS............cceseccceee as 24 4. SUMMARY OF TRANSMISSION SYSTEM INVESTMENT AND UNIT: COSTS onic. crooosereseterelor erase «6: 0.e efetezerol toleie. ils stele 25 iii 1. INTRODUCTION Purpose This analysis was made to evaluate the merits of further investigation of economic export of electric power from Alaska to the Pacific Northwest. The analysis was an update of Alaska Power Administration's (APA) 1972 North Slope Transmission Study (1972 study) 24/ that examined the possibility of using North Slope natural gas to generate electricity for transmission to Southcentral Alaska, British Columbia, Canada, and the lower 48 States. The basic concept of this analysis was similar to the 1972 study in that electric power would be generated on the North Slope and delivered to the Pacific Northwest by d.c. transmission line. Hydro, natural gas, and coal were evaluated as likely energy resources. Transmission technology was reviewed, costs updated, and costs of exporting energy resources as raw materials were compared. The time frame for this analysis was to the year 2000. Background of 1972 Study Three delivery plans--Cases I, II, and III shown in Figure 1--were examined in the 1972 study. This analysis considered only Case I, shown in Figure 2, which involved bulk transfer of electric energy from Alaska's North Slope to the Pacific Northwest through interconnection with + 800 kV d.c. transmission lines. While energy would be generated by burning natural gas in the 1972 study, this analysis was based on use of coal for the energy source. The natural gas pipeline from the North Slope to the lower 48 States was assumed to be in place before transmission lines could be in operation, and the natural gas would be committed to more valuable markets and not available for electric power generation. 22/ Case II, shown in Figure 3, was based on supplying electric energy to the Anchorage-Fairbanks (Railbelt) area from the North Slope. 1972 study conclusions were that the Railbelt area could be better served by local generation than by more remote North Slope generation. Since the 1972 study, considerable work has been done on energy supply alternatives for the Railbelt area. For example, the Susitna hydroelectric project proceeded to the advanced planning stage, construction of the Anchorage-Fairbanks Intertie was scheduled for 1982, and the Beluga coal field appeared on the verge of development for both electric power generation and export of bulk coal. Consequently, Case II no longer appeared logical and was not examined in detail in this analysis. #/Bibliographic reference 2861 Auenuer yy "Seay wo Boy .. North Slope e See eee, UNITED STATES DEPARTMENT OF ENERGY ALASKA POWER ADMINISTRATION ' NORTH SLOPE TRANSMISSION STUDY Ly TRANSMISSION ROUTES AND DISTANCES Wy, FAIRGANKS: Y U K O N i a —8OMlles Nee 491910 119_9_tp9 Big Dette . SCALE OF MILES qi ee 380Miles wmiteo stares Napa Cormacks “110 Miles ae a \ h TRANSMISSION D{STANCES MILES Re \ s70uanego a TE = CASE I (Export Line) North Slope Generation Site 10 Everett, Washington 2,240 CASEI (Railbelt Area) North Slope Generation Site to Anchorage vio Glennallen » 880 North Slope Generation Site to Belugo vio Healy 795 CASE I (Alasko, Y.T., B.C,, Everett Interconnections) North Slope Generation Site to Everet! via Fairbonks, Whitehorse, Dease Lake, Prince George . 2,240 Fairbonks 10 Beluga ‘vio Healy 345 2 ane TOTAL . a 585° & Altornate from Oeose Lake through Skeeno to Prince George 2,695 oY WASHINGTON \ 2861 Avenuep yay c ct! oc aR . fay North Slope Thermal Generation Site — 6) AC to OC Converter Station IB FAIRBANKS cmPrudhoe Bay UNITED STATES DEPARTMENT OF ENERGY ALASKA POWER ADMINISTRATION NORTH SLOPE TRANSMISSION STUDY CASE I TRANSMISSION SYSTEM YUKON ie | im ete TER RITORY 4 a . Le @ WHITEHORSE © OEASE LAKE BRITISH \ Two t BOO KVDC transmission lines, North Slope generation sile 1o Everett, Washington (2,240 miles) carne \ ae att . P ADC 10 AC Inverter Station D RMoYN EVERETT Prudhoe Bay North Slope Thermal Generation Site 2 7 ———————S=—=—=_ SCALE OF MILES SalIW OS Alternate routes Anchoroge- Fairbanks Intertic &» @Glennallen UNITED STATES DEPARTMENT OF ENERGY ALASKA POWER ADMINISTRATION NORTH SLOPE TRANSMISSION STUDY CASE II TRANSMISSION SYSTEM Figure 3 APA January 1982 Case III, shown in Figure 4, examined several plans of service’ to Alaska, Canada, and the lower 48 States through exchange, wheeling, and eventual displacement of Canadian power to the lower 48 States. Case III considered moving power to the lower 48 States the same as Case I but used large a.c. interconnected transmission lines. Nothing in Case III was found more attractive than in Case I for moving massive amounts of electric power to the lower 48 States. As a result, Case III was also not examined in detail in this analysis. Alaskan and Canadian hydro and thermal electric power projects constructed since 1972 and the major regional intertie studies conducted, together with projects and studies planned, could lead to eventual interconnection and should be considered. These were the principal findings identified in the 1972 study. 1. The North Slope natural gas resource of 26 trillion cubic feet could support an 8000-MW steamplant for 50 years. 2. Many environmental factors would need consideration, but none were of such significance as to make further study inappropriate. 3. No physical or engineering aspects would preclude the trans- mission system or energy generation using either steamplants or combustion turbines. Existing knowledge appeared to insure physical feasibility providing careful attention was given to foundation conditions and a few other critical areas. 4. Costs for Arctic construction were between 4 and 12 times lower 48 costs. The study used a maximum adjustment factor of 2.43. Investment costs for steamplants in the Arctic were estimated to be 0.36¢/kWh. Natural gas costs were unknown but assumed at 20 to 30 cents per million Btu (equivalent to oil at 3¢ to 4¢/gal.). Ss Export of bulk power to Everett, Washington, from the North Slope Case I was estimated at 0.8 to 0.9¢/kWh based on 1971 costs. This assumed an 8000-MW generation facility and twin 800 + kV d.c. circuits 2,240 miles long. The transmission accounted for 0.3¢/kWh. 6. Delivery of energy to the Anchorage and Fairbanks areas from the North Slope Case II appeared feasible at 0.7 to 0.8¢/kWh with transmission accounting for 0.3¢/kWh. However, moving natural gas to Fairbanks for generation and generation using other local thermal or hydro power sources appeared economically more favorable. 2861 Auenuer Ydy °o Clay Prudhoa Boy North Slope Thermal Generation () Site [NX @ FAIRBANKS 332 MW UNITED STATES DEPARTMENT OF ENERGY ALASKA POWER ADMINISTRATION NORTH SLOPE TRANSMISSION STUDY CASE III TRANSMISSION SYSTEM 400 40 00 120 40 SCALE OF MILES Dease Lake Y\e 840 Mw BRITISH \ So Alternate routes Dease Loke to Prince George intertie NK \ Sk princ® 730 MW GEORGE SKC OL UM BIA A. a_i ’ &\ Y\ EVERETT i) Fe Case III indicated a wide range of opportunities exi'sted for interconnected hydro-thermal power generation and transmission system facilities in Alaska, Yukon Territory, British Columbia, and the Pacific Northwestern states. 8. More detailed investigation of transmission systems to deliver energy generated from North Slope natural gas to the Pacific Northwest did not seem warranted at that time. Significant Events Since 1972 Several events since 1972 have affected resource availability, costs, and market conditions. The most significant event was a rapid increase in petroleum product costs beginning with the 1973 oi] embargo. For example, home heating oil in Juneau, Alaska, rose from 21¢/gallon in 1973 to $1.25/gallon in 1981--an increase of 600 percent, which was typical of oil price changes across the State and Nation. All of the State was affected. The Anchorage-Cook Inlet area, which has abundant natural gas resources, was affected the least by oil cost increase. Towns and villages dependent solely on oi] for heating and generation were impacted the most. The 800-mile oi] pipeline from the North Slope to Valdez was completed. With partial development of the Prudhoe Bay oil field, oi] tankers were transferring 1.5 to 2 million barrels per day to the lower 48 States by 1977. Oil pipeline construction provided experience in development of cold-region construction camps and support facilities, construction of gravel and snow roads, people and supply logistics, human and equipment efficiency rates, and new costs for doing business in the Arctic environment. This experience indicated construction in the Arctic was four times as costly as in the lower 48 States. Higher interest rates made overall project costs rise and made project financing more difficult. In December 1971 the Alaska Native Claims Settlement Act, P.L. 92-203 (ANCSA), authorized the transfer of public lands to Native villages and to regional Native corporations. In addition, up to 80 million acres of land were to be recommended for designation as National Forests, Parks, Wildlife Refuges, and Wild and Scenic Rivers. By the mid-1970's Federal land was set aside for a transportation corridor between Prudhoe Bay and Valdez. In December 1980 the Alaska National Interest Lands Conservation Act, P. L. 96-487 (ANILCA) finally designated National Interest Land for forests, parks, preserves, wildlife refuges, and wild and scenic rivers. The final settlement involved 101.4 million acres. ANILCA resulted in an increase in the percent of potential hydropower energy precluded from 12.9 percent to 80.5 percent. The Act precluded development of most of the "world class" hydroelectric power sites except the Upper Susitna River Basin projects and possibly the Yukon-Taiya project. ANILCA action precluded hydropower energy as an exportable resource. The effects of this Act were presented in APA's 1981 Analysis of Alaska National Interest Land Conservation Act Impact on Hydroelectric Resources. 24a/ Hydropower development activities in Alaska administered by the Alaska Power Authority were pursued vigorously beginning with creation of the Authority in 1976. At that time the State began investigating financing construction of several sites to serve towns in Southeast Alaska and along the Gulf of Alaska coast, studying many small sites throughout the State, and advancing feasibility studies of the Upper Susitna Project which would serve Anchorage and Fairbanks. The Susitna Project is in advanced stages of investigation. State appropriations for studies and construction during F.Y. 1982 were over $500 million while long-range authorizations were $5 billion. A single-circuit 345 kV transmission intertie between Anchorage and Fairbanks systems was designed and scheduled for construction in 1982. Initially the intertie would function to transfer energy between load centers and provide pooling reserve capacity. Ultimately, the line would become part of the system to deliver power from the Susitna hydroelectric project. Coal resources were under extensive study in 1981 for both bulk export and as an electric generation fuel source in the Railbelt area. Plans considered amount to several large-scale projects. 11/ 17/ 19a/ A natural gas pipeline from the North Slope to the lower 48 States was planned and in the final stages of financing in 1982. The 48-inch diameter pipeline would move the natural gas reserves to Alberta, Canada, where the line would branch to the San Francisco and Chicago areas. Construction was planned for the mid-1980's. Since the 1972 North Slope Study, British Columbia Hydro and Power Authority had constructed 5,700 MW of hydropower facilities and 300 MW of other generation. Their planned additions during the 1980's amount to 9,200 MW of hydropower and 2,700 MW of other generation, primarily coal-fired steam units. 30/ 31/ 2. POTENTIAL GENERATION RESOURCES FOR ELECTRIC POWER EXPORT Evaluation of electric power export from the State began with examination of resource availability and included comparison with other energy export methods such as gasline, oil line, or ships. Resources were discussed with known commitments. Export of energy was consistent with Alaska policy as long as it met tests for economic and environmental considerations and would not distract from availability of energy for in-State uses at a fair and equitable price. 32/ Coal In 1967 Alaska's coal resources were estimated at 130 billion tons with 120 billion tons, or 92 percent, located on the North Slope. A Table of coal resources by fields is in the Appendix. 2/ More recent studies place the coal reserve at 141 billion tons with 123 billion tons or 87 percent on the North Slope. Estimates of undiscovered coal have ranged from 477 to 4,077 billion tons (studies dated 1975, 1977, and 1980) assuming new depth limits and offshore resources under Cook Inlet. 15/ 19a/ The huge North Slope coal deposit appears to be a logical export resource. The Beluga (Susitna) and Nenana coal fields would be the most likely for early development and could supply local in-State as well as considerable The mine also had a contract to furnish 200,000 tons to Korea in 1982 and an eventual increase to 800,000 tons per year. Total in-State use amounted to approximately 800,000 tons in 1980. Two companies were active in the Beluga coal field--Placer-Amex and Diamond-Shamrock--each developing their coal leases to export to the oriental market. 5/ Each also considered furnishing coal supplies for local power generation. Diamond-Shamrock has a plan to export 13 million tons per year. This amounted to a 27-year supply based on published resources of 350 million tons for their lease. Placer-Amex studied a 54 thousand barrels per day methanol production plant and looked at producing coal for local _ generation (400-MW steamplant using 1.6 million tons per year). 11/ The Beluga (or Susitna) coal field with an estimated reserve of 2,395 million tons could support mining of 24 million tons per year for 100 years. As stated previously, in-State use during 1980 amounted to 0.8 million tons. A 1000-MW coal-fired steamplant would use 4 million tons per year at an 80 percent plant factor. To put the Beluga coal field in perspective, published reserve would last a 1000-MW steamplant 600 years assuming all the coal could be mined. North Slope coal--estimated to be 123 billion tons with 50 percent more heat content than Beluga coal--could supply a 1000-MW plant steamplant for 44,000 years. Because of the size of its resource, Northern Alaska (Colville and North Slope) would be the most likely area for long-term development. New technology for mining in a permafrost area would need to be developed, and costs would be significantly higher than for the South 48. 1/ 6/ The large quantity available should eventually make the coal use economically feasible. Mining on the scale to support a 24 million ton/year North Slope operation would be an immense undertaking approaching the scale of some of the largest mines in the United States. Added to this would be work under severe Arctic weather conditions. Needed facilities would include a whole transportation system for road and air travel, a town site for workers and support people, water supply and waste disposal systems, and an electric power system. Although there would be many problems in coal mining of this magnitude under such adverse climatic conditions, for the purpose of this analysis mining in the Arctic was considered to be possible. Natural Gas Alaska natural gas resources were estimated at 32.8 trillion cubic feet by the State Department of Natural Resources in 1981. Ejighty-eight percent, or 28.8 trillion cubic feet, was on the North Slope. A Table of the resource by fields is in the Appendix. Estimates of the natural gas resource including the likely undiscovered potential total 101.2 trillion cubic feet. 25a/ 25/ For purposes of this study, North Slope gas supply was assumed to be fully committed well before the year 2000. Alaska's local electric generation and domestic gas needs were assumed to be met from the Cook Inlet area or a smaller branch line to the Anchorage-Fairbanks area from export line. In addition the potential petrochemical plant being considered in Alaska would use liquid gasses from the North Slope in the Anchorage, Fairbanks, or Valdez areas. Amount of commercial energy available to the public is not known. : Cost of Alaska natural gas was uncertain. Wholesale cost of State royalty gas to Anchorage gas utilities was now relatively cheap at roughly 66¢/million Btu. Cost of gas to the major electric utility in the Anchorage area was around 30¢/million Btu--an equivalent oi] price of 8¢ and 4¢ per gallon respectively. Although new gas-well exploration was underway in the Cook Inlet area, the supply, quantity, and price to replace existing contracts ending during the next decade were uncertain. The proposed State royalty gas price was scheduled to increase to $2.39 per million Btu--equivalent to oi] at 34¢/gallon. Deregulation could significantly change the low price of natural gas to Alaska consumers. 11 Recent discussions of Alaska gas delivered in the South 48 placed the price around $9.00 to $10.00 per million Btu--equivalent to $1.24 to $1.38 per gallon for oil. 23/ 25b/ Prices in Alaska would be somewhat lower because of shorter transmission distance; however, availability of large quantities of cheap gas in Alaska appears to be drawing to a close. Alaska natural gas supply commitments, price structures, and higher value of the natural gas for other uses all led to the conclusion that it just didn't make sense to use natural gas supplies for large-scale, long-term electric power generation for export. Hydropower Possibilities of exporting hydropower from Alaska outlined in the 1972 study no longer exist. As a result of the December 1980 Alaska National Interest Land Conservation Act (ANILCA), most of the "world class" hydropower sites, with the exception of the Susitna River Project, have been precluded--Wood Canyon, Rampart, Woodchopper, and Holy Cross sites. These four sites total 13,6000 MW and 82,600 GWH estimated hydropower. Figure 5 shows hydropower sites prevented by the Act and the remaining sites. Results of an APA analysis indicated that 80.5 percent of the State's hydroelectric energy potential was foreclosed by the combined effect of ANILCA and existing National parks and monuments. 24a/ National parks and monuments existing before the Act eliminated 12.9 percent. Under ANILCA, new parks, monuments, preserves, and wild and scenic rivers added another 67.4 percent. Finally, an additional 0.2 percent was precluded by a three-year study that could lead to designation as Wild or Scenic. Remaining sites which could contribute to the State's near term power needs include the Susitna River and Chakachamna Lake Projects. Other sites allowed by ANILCA, such as Crooked Creek, Nuyakuk and Lake Iliamna, would likely have been precluded for environmental reasons. PaSsage of the Act would have little apparent near-term impact on hydroelectric projects under active consideration--Susitna and the smaller Terror Lake, Tyee, Bradley Lake and Black Bear. Long-term impacts were more extensive for all regions of the State except Southeast. The Southeast region has adequate undeveloped hydropower potential to meet need well after the year 2000. ANILCA essentially precluded hydro development in the Yukon and Northwest regions. The Southwest region would be able to meet their needs with hydropower through the year 2000 if both Tazimina and Kisaralik sites were determined to be developable. Engineering and economic feasibility studies are in process now, as well as land status clarification. The Southcentral region and Railbelt area would also have sufficient hydro resources to meet demands through the year 2000; however, estimated power demands exceed remaining resources. 2861 Avenagay yay S$ auNSIZ SOUTHWEST ranean 20 ANOODCHORM ERR 22 JUNCTION ISLAND 12 Font aiitct 23 | BIG DELTA 16 Genser} JOHNSON 18 Ae y ne JUSKASNA 12 Z + CATMEDRAL_BLUFFS 19 NOTE Numbers rater to projects fisted on “Summary of Naske Lower Priced Mydrowectie o WATANA 46 EVE. SABYON 43 WT Potentala”. yOLY CROSSE wanicpitia 40 YAGOD a EVEL 47 ‘ LANE 43 ER CHULITNA a9—>ff S KEETNA at oa, Low! ED CREEK 25 ‘SKWENTNA 38 WHISKERS 42 i 7 RYENTNA 36 UPPER a, fuds as @ te £ pets Sy crack a $ GER EOE 25 BY ee Swow 4g Sy8 (eS ALASKA POWER ADMINISTRATION —e Sites precluded by Alaska National Interest Conservation Act, Mi! Sites precluded by existing National ““*OCRS - Parks and Monuments. (C—] Sites precluded by 3 years: study under Wild & Scenic River Act, UNDEVELOPED HYDROELECTRIC RESOURCES OF ALASKA AFFECTED BY PUBLIC LAW 96-847 SUBREGIONS yEREEL DIVISION 87 tavkerncant FALLS $0 13 oi1 Use of oil for generation of electric energy for export would be unlikely. The resource has higher use as a portable liquid for distillation, and current world price was too high for new power generation. Price of Alaska crude oi] from the North Slope delivered to tidewater was $32 per barrel--equivalent to 76¢ per gallon refined. At $1 per gallon for refined fuel, basic cost per kilowatt hour for fuel alone would be roughly 7¢/kWh. In addition, the Fuel Use Law prohibited use of oil for electric generation except for peaking requirements. Wind For the purpose of this analysis, wind technology was not considered sufficiently advanced to be used as a basis for bulk power production and transport. If the technology comes, it could be of interest as a supplement to other sources. Tidal The best tidal power potential in Alaska has been identified as the Cook Inlet area, estimated at several thousand MW's. A recent study of Cook Inlet tidal resource and development alternatives prepared for the Governor's Office indicated that energy from even a partial development would not be available until the year 2000 at the earliest. The study identified 16 potential sites throughout Cook Inlet in Turnagain Arm and Knik Arm of the size to meet the Alaska Railbelt needs. Considerably more study would be needed to assess environmental implications and evaluate realistic resource export plans. 26a/ Resource Summary The only available economical energy resource of significant size for export appeared to be coal from the North Slope. Most of the potential hydropower sites have been precluded by ANILCA. Natural gas on the North Slope was committed for transport to the South 48 via the pipeline which was in the advanced planning stages in 1982. An amount of gas equal to the original 26 trillion cubic feet would need to be discovered to support an 8,000-MW powerplant. In addition, a determination would have to be made about whether the gas was more valuable for use in the South 48 or for burning on the North Slope and shipping south as electricity. Tidal power would need considerable more investigation to determine if it would be a realistic resource to consider for export. Wind power generation in Alaska doesn't appear to have significant advantage over similar generation in the South 48 where the long transmission line would not be needed. Generation using oi] seemed the most expensive and unlikely. Environmental implications and other constraints were discussed in Part 3. 15 3. PROJECT PLAN Basic project facilities for Case I of the 1972 Study included generation stations on the North Slope and transmission to the Everett, Washington, area. This analysis considers coal-fired steamplants rather than natural gas-fired steamplants. The 1972 study and this analysis both used the same 800 + kV d.c. double circuit transmission system. Steamplant Description The plan for the generating facilities would be for a total installed capacity of 8,000 MW. The assumption was made that the plants would be located in one complex 40 to 60 miles inland from the Arctic Ocean where bedrock could be found for foundations. As many of each plant's components as possible would be preassembled in the South 48 in the largest assemblies possible for barging to the North Slope. Large, complex plant components such as boilers and air cleaning equipment would require major on-site assembly. The 1972 Study based steamplant design and costs on technology practiced in the 1960's. The standard plant gave little attention to flue gasses and used a "once through" water circulation system to cool the condensers. Large steamplants subsequently constructed would be more sophisticated and relatively more costly. Environmental protection would require expensive treatment of flue gas to remove sulphur, particles, and noxious gasses. Cooling water would be handled differently to avoid damage to living things in the receiving water and protect the quality for downstream users. Flue gas scrubbers and other standard air quality protection equipment would be assumed to be required. In addition, water consumption in the arctic would need to be minimized because of low precipitation and other supply and disposal problems. The Wyodak steamplant_in Wyoming, in an area of low rainfall, has cold weather extremes (-40° F) approaching Arctic conditions. A North Slope steamplant cooling water method could be patterned after the proven mechanical dry cooling system technology used at the Wyodak plant. 4/ 3/ Water consumption is 200 gallons per minute for the 330-MW plant. Proportionally an 8000-MW North Slope steamplant would use 24 times as much or 4800 gallons per minute (11 cubic feet per second). Because of the remoteness, complete support facilities would be needed for the steamplant and coal mining both during construction and for operation of permanent facilities. Construction was assumed to require eight years but could stretch out to 15 years because of the size of the project. Steamplant construction and mining operations were not examined closely, but as an example of the size of the operation--based on Beluga study estimates--the steamplant could require 2500 operation and maintenance employees requiring a town of 5000 to 7500. 5a/ To produce 24 million tons of coal per year, 4600 to 7000 employees would be needed. Mining techniques under Arctic conditions--yet to be developed-- could significantly adjust these employment figures. 6/ Many of the workers could commute from Fairbanks and Anchorage which would require an extensive air and road transportation system. Airports, water, sewage and electrical systems along with some local government facilities would be needed. Transmission Line Description Case I of the 1972 Study shown on Figure 2 evaluated the concept of delivering large blocks of power to the Pacific Northwest using direct current systems and was examined in detail. The same plan was used in this analysis and consisted of two parallel, bipolar d.c. transmission lines at + 800-kV d.c. Each line was 3,605 kilometers (2,240 miles) long, and each had capacity to deliver 4,000 MW of power to the BPA Monroe Substation southeast of Everett, Washington. Figure 2 shows location concept, and representative d.c. transmission line tower design is shown on Figure 6. Tower design was refined slightly but was almost identical to the plans used in the 1972 study. The transmission plan, capacity, design, and bulk power transmission concept were reviewed by BPA. 27/ The transmission route generally followed existing and planned roads and railroads so no added costs were assumed for access roads. A service road suitable for 4-wheel drive vehicles was planned along those portions of the route where soil conditions permit. The service road would be used for construction, operation, and maintenance. For permafrost areas such primitive service roads would be suitable only where soil conditions are ideal. For frost-susceptible soils and suspected high ice content permafrost, the assumption was made that overland access for both construction and 0& would be limited to winter transport on frozen soils. Helicopters would be used extensively. The d.c. transmission estimate assumed design criteria of 1.5 inches of ice and eight pounds wind loading with standard weight steel transmission towers. This was based on the finding that more stringent design would likely be required for only relatively short segments in critical areas. The estimate was for a transmission line passing over 50 percent mountainous and 50% rolling terrain. Tower foundations in permafrost areas would require a departure from normal practice. Careful attention to foundations and full use of existing Arctic design construction skill would be essential to insure physical feasibility. An a.c. to d.c. converter using existing proven technology would be located near the powerplant and similar-sized equipment located near Everett, Washington, to convert the energy back to alternating current. oH = s = | —}> j tog} i343 a zg Ze a <| ee : alr 7 . = 8 als B als = “5 w he : oO r | S 2h + =e) SSB SEEKEKK KKK | : + " nw UNITED STATES DEYARTMANT GF EXRAGY BOANEVILLE POWER ADMINISTRATION ff HZACCUARTEAS, POATLAND, CREGCH } System voltage and conductor configurations were selected using rule-of-thumb methods by BPA and rough approximations made of line capabilities and losses. Power system analyses such as power flow and stability studies have not been made. Estimated transmission losses were 7.2% at design capacity. Terminal buses and switching arrangements at each end would permit transmitting full capacity (less additional line losses) with one line out of service, thus the dual lines would provide a high degree of system reliability. Transmission Technology The 800-kV d.c. capacity was actually greater than any in service but was well within limits of available technology. Extensive a.c. systems existed at 500-kV, and major Canadian and U.S. lines were operational at 735-kV and 765-kV. The U.S.S.R had an 1150-kV transmission line due for energization in 1983, 34/ and Bonneville Power Administration (BPA) has a 1200-kV test facility which has been energized since 1976. 28/ Parallel advances in high voltage direct current (HVDC) technology have also been made. HVDC systems utilizing mercury arc and thyristor valve systems were in service with a voltage range of 50-kV to + 533-kV. Systems capable of 6000 MW at + 600-kV and + 750-kV were under construction in Brazil and Russia. The U.S.S.R. had a 30 GW + 1500-kV d.c. system in the planning stages. 35/ Table 1 gives some examples from recent literature on existing and planned large transmission lines. Transmission of electric energy over a long distance was well suited to HVDC technology. Consultations with BPA led to the conclusion that the 1972 Study Case I premise that + 800-kV d.c. lines for the 3,605-kilometer (2,249-miles) distance would be well within capabilities of existing technology. 27/ Transmission distances are illustrated on Figure 1. Case II distances and loads are well within capabilities of existing a.c. transmigsion technology. Individual line segments of Case III range from 260 up to 550 miles. Again, loads and distances fell within existing a.c. capability. Present a.c. technology would be suitable for Case II and Case III plans, while d.c. circuits would be less costly pending future development of less expensive terminals and an economical method of tapping d.c. lines for intermediate loads. Circuit breakers for use in d.c. lines are in the development stage. BPA, EPRI, and the Division of Electric Energy System of USDOE jointly sponsored a project to develop a d.c. circuit breaker rated + 500-kV, 2000 amperes. 29/ The circuit breaker would be ready for testing in two to three years and would be installed in the PNW-PSW Intertie System. Use of a d.c. circuit breaker would increase the reliability of the d.c. lines by allowing sectionalizing at intermediate points for system faults or schedules maintenance. It would also allow tapping of a line to serve intermediate loads. Table 1 Examples of High Voltage DC Transmission Systems mes Nominal Year Voltage Length Capacity Project Country Energized kv Km MW Comments Gotland-Swedish Mainland Sweden 1954/70 150 96 30 Cross Channel Great Britain 1961 + 100 65 160 and France Volgograd-Donbass Soviet Union 1962/65 + 400 470 720 Konti-Skan Denmark & Sweden 1965 250 180 250 Sakuma Japan 1965 125 300 50/60 Hertz Tie New Zealand New Zealand 1965 + 250 609 600 Sardinia-Italian Mainland Italy 1967 200 413 200 Vancouver Pole 1 Canada 1968/69 + 260 74 312 Pacific Northwest-Pacific United States 1970 + 400 1362 1440 Upgrade to + 500-kV, 2000 MW Southwest Intertie ~ Nelson River Bipole 1 Canada 1973/77 + 450 890 1620 Kingsnorth Great Britain + 266 82 640 Eel River Canada 80 320 Asynchronous Tie Skagerrak Denmark & Norway 1976/77 + 250 240 500 David A. Hamil United States 1977 50 100 Asynchronous Tie Cabora Bassa~Apollo Mozambique ~ 1977/79 + 533 1414 1920 South Africa Vancouver Pole 2 Canada 1977/79 - 280 14 370 Square Butte United States 1977 + 250 749 500 Shin-Shinano Japan 1977 125 300 50/60 Hertz Tie Nelson River Bipole 2 Canada 1978 + 250 930 900 cu United States 1979 + 400 710 1000 Hokkaido-Honshu Japan 1979 125 168 150 Final Stage: + 250-kV, 600 M USSR-Finland Soviet Union- 1981 + 85 1070 Asynchronous Tie Finland Inqa~Shaba Zaire 1981 + 500 1700 560 Final Stage: + 500-kV, 1120 Acaray Paraguay-Brazil 1981 26 50 50/60 Hz Tie Itaipu Brazil 1983/85 + 600 806 6300 Durnrohr Austria 1983 183 550 Asynchronous Tie Ekibastuz~Centre Soviet Union 1984 + 750 2400 6000 Cross Channel 2 Great Britain- 1984 + 270 68 2000 France Nelson River Bipole 3 Canada + 1990 + 500 930 2000 1/ Incorporating HVDC Power Transmission Into System Planning. A symposium sponsored by the U. S. Department of Energy, March 24-27, 1981, Phoenix, Arizona. 61 In summary, available transmission technology could handle the' distance and loads contemplated in the case studies. Development of d.c. circuit breakers would provide for greater reliability and flexibility and would allow the development of d.c. transmission networks. Costs Costs were presented for the generating and transmission system described previously. Alaska prices were used where available, but most of the costs were prepared for South 48 conditions and adjusted to Alaska conditions. An Alaska geographical adjustment factor was derived for this analysis based on a survey of factors used by three military services, two engineering firms, and two oi] companies with operations on the North Slope. A summary of data is presented in Appendix A. The assumption was made that as many modular assemblies as possible would be fabricated in the South 48 States. Primary items causing large increases were itemized. Labor 0 Overtime 0 Travel for importation from Anchorage and the South 48 0 Camps including meals, support personnel, facilities, water, sewer and electric supplies Oo Cold weather labor inefficiencies Equipment 0 Increased running time and fuel 0 Special lubricating and servicing requirements Material 0 Extra handling and storing 0 Transportation barging in summer; trucking year around ° Special steel and insulation requirements Steamplant Costs Costs for an 8000-MW coal-fired steamplant were estimated based on recent studies. Table 2 presents a summary of steamplant costs--$32.5 billion capital investment, or $4,065/kW. Capital Costs--Most cost experience was from the lower 48 States and needs adjustment to reflect Alaska price levels and construction conditions. Two studies for smaller plants have been prepared for Alaska conditions. A 1977 Golden Valley Electric Association (GVEA) study for a TABLE 2. SUMMARY OF COST ESTIMATES FOR NORTH SLOPE POWERPLANTS Coal-Fired Steam Turbines Plant size, MW 1,000 8,000 Unit size, MW 500 500 Number of units 2 6 Annual generation, KWH x 102 7 56 Investment, millions of dollars 4,065 32,520 Investment cost, $/KW 4,065 4,065 Annualized investment cost 2/ Annual capital cost, million dollars 406.5 352520 $/KW 406.5 406.5 ¢/KWH 1/ 6.3 6.3 Annual operation and maintenance costs, exclusive of fuels million dollars 38.75 310.0 $/KW 38.75 38.75 ¢/KWH 1/ 0.6 0.6 Total annual cost, excluding fuel 445.3 3,562.0 Unit energy costs exclusive of fuels, cents/KWH 6.9 6.9 Fuel costs, cents/KWH Fuel cost of $2/mmBtu 2.2 22 Energy cost including investment, 0&M and fuel, cents/KWH 9.1 9.1 1/ Assumed 80 percent annual plant factor less 7.2% losses for 52 billion kWh at the market. 2/ Based on 10 percent annual cost. Including interest at 9 percent, depreciation, and interim replacements. 2 150-MH plant had a January 1981 indexed cost of $2,200.00 per kW. A 1979 study for Placer Amex, the lease holder in the Beluga Coal Field, showed an investment cost for a 400-MW plant of about $2,300.00 per kW adjusted to January 1981 price base. The cost estimate for this study was based on a 1977 Washington Public Power Supply System (WPPSS) for the Pacific Northwest that involved several types of plants and qualities of coal. The basic cost for a two-unit 1,000-MW plant in operation during mid-1976 was about $680 per kW including scrubbers. The basic cost was adjusted from mid-1976 to October 1981 using the Engineering News Record construction cost trend which increased the cost 49 percent. A geographic factor of 1.9 was used to adjust Pacific Northwest costs to the Anchorage-Cook Inlet area and another factor of 2.1 to North Slope conditions. Unit costs became $1936 per kW in the Anchorage-Cook Inlet area and $4065 kW for the North Slope. The $1936/kW was comparable to the $2200/kW and $2300/kW estimates for smaller scale plants examined for the Beluga and Healy areas. Since the basic steamplant cost included interest during construction, the indexed cost would be the investment cost. Investment cost for an 8000-MW steamplant would be $32.5 billion. Fixed Annual Costs--Amortization was based on 9 percent for repayment of principal and interest, with an additional 0.35 percent for interim replacements. The total fixed annual cost was 9.81 percent of the investment--rounded to 10 percent. Operation and Maintenance Costs--The annual Operation and Maintenance (0&M) costs at October 1981 price level were $310 million. Costs were based on a detailed estimate of personnel, supplies, and equipment for a 400-MW coal-fired steamplant in the Cook Inlet area--indexed from December 1978 to October 1981 using the Cost of Living Index and further adjusted to 8000 MW. 11/ The number of people involved in direct operation and maintenance would be about 2,500. This assumed 1D percent economy of scale for personnel compared to a 2,000-MW plant. 12/ Fuel Costs, Coal--Fuel costs were based on using the huge coal resource on the North Slope. Coal underlays most of the western part of the North Slope and a large finger extends east beyond the oil pipeline. Assuming that a steamplant could be located on or near the Brooks Range foothills where a rock foundation exists, only a few miles transportation from mine to plant would be required. A 1980 study by the Department of Energy examined the possibility of using North Slope coal near tidewater from the western shore of the North Slope in the Kukpowruk area. 8/ A five million ton per year export plan was estimated to have a mine price of $0.97 to $1.05 million Btu, a transportation cost of $0.83 to $0.93 per million Btu, resulting in a total cost at the port of $1.81 to $1.99 million Btu. 18/ Although the 23 transportation distance was short, transportation accounted for roughly half of the net cost. For purposes of this study, the cost of $2 per million Btu was used--equivalent to $48/ton based on 12,000 Btu per pound of coal. Transmission System Costs Bonneville Power Administration furnished unit costs for the d.c. transmission components based on Pacific Northwest costs. 27/ These were adjusted to reflect higher labor and transportation costs for Alaska and Northern Canada construction. Two d.c. voltage levels, + 800-kV and + 1200-kV, were examined as well as a radial 2-line 1100-kV a.c. system with intermediate switching stations and 30 percent series compensation. Higher levels of compensation could be required to maintain system stability during faulted conditions, but the 2-line 1100-kV a.c. system was the most economical a.c. alternative for the distance and power level involved. The studies indicated that the two single-circuit + 800-kV d.c. system would be preferred. The two-circuit + 1200-kV d.c. system has lower transmission line losses, but the overall cost was higher. The + 1200-kV d.c. right-of-way was wider and the towers were taller, presenting more visual and environmental impacts. Table 3 summarized cost estimates for + 800 kV d.c. system and derives unit costs. A sample calculation sheet with itemized costs and overhead is included in the Appendix. Table 4 presented a summary of investment costs and the resulting unit cost of energy delivered to Everett, Washington. Rough estimates of clearing costs were derived based on Pacific Northwest cover types and required width of rights-of-way. Clearing costs were considered minor and therefore omitted for the line between the North Slope and Fairbanks. For this same reach of line, costs were increased to account for tower foundations in permafrost areas. Forty percent of the line from Fairbanks south was estimated to require clearing. Costs for converter stations to convert the energy from a.c. to d.c. and back to a.c. were included. The cost estimate includes a microwave communication system for messages and control of operations. Costs were not included for facilities to deliver energy to load centers in the Washington area. Costs for right-of-way were not included. The line would follow the transportation corridor from Prudhoe Bay to Delta Junction south of Fairbanks. State and private land would be involved for approximately 180 miles between Delta Junction and the Alaska-Canadian border. Right-of-way costs were not addressed. TABLE 3. SUMMARY OF CASE 1 UNIT COSTS Unit Costs of North Slope-Everett, Washington + 800-kV d.c. Transmission System Item Conductors Towers Gnd. wire, Insul., Hardware & Misc. Right-of-Way Clearing Service Roads Surveys & Design Circuit Breaker AC-DC Converter - Terminals Communications Terminal Operation Designation 6-Thrasher ACSR 128.9 Tons/mi. 1/2" EHS Steel Acquisition Average Non-permafrost areas only 525-kV HVDC Repeaters every 40 miles Terminal Maintenance Line Operation Line Maintenance Cost per Unit $161,700/mi. $236 ,405/mi. $219 ,165/mi. No cost assumed $12,350/acre $8 ,885/mi. $1,200,00 each $55/kW $250,000 + $625 ,000/100mi. $500,000/yr. $500 ,000/yr. $125/mile/yr. $324/mile/yr. Cost Basis 1981 Pac. N.W. 1981 Pac. N.W. 1981 Pac. N.W. 1981 Pac. N.W. Alaska 1981 Pac. N.W. 1981 Pac. N.W. 1981 Pac. N.W. 1981 Pac. N.W. 1981 Pac. N.W. TABLE 4. SUMMARY OF TRANSMISSION SYSTEM INVESTMENT AND UNIT COSTS North Slope - Pacific Northwest (Everett, Washington) 2,240 Miles Two circuits, + 800-KV DC Sixbundle Thrasher Conductors per Pole Load at Market = 8,000 MW @ 80% Load Factor Less 7.2% Losses. Energy at Market = 52.0 x 10 KWH $ Million Construction Cost (1981 price basis) Transmission line, terminals, communications 8,996.3 Interest During Construction IDC = Cost x 9% x 5 yr 2,024.2 2 : 17,020.5 Total Investment, Rounded 11,000 Annual Cost Repayment of principal and interest 9% interest, 35-year period = 9.46% 1,040.6 Replacements 14.6 Operation and maintenance Tae Total Annual Cost 1,062.4 Annual Capacity Cost for Transmission $1,062.4 million $132.80/KW 8,000,000 KW Annual Energy cost for Transmission $1,062.4 million 8,000 MW x 80% load factor x 8,/60hr/yr - 7.2% losses " $1,062.4 million 52.0 billion KWH = 2.04¢/KWH Use 2.1¢/KWH 25 Environmental Implications Large thermal electric generating plants would involve a broad range of environmental changes in Alaska and major new related transmission systems would present significant environmental challenges. Both beneficial and adverse environmental changes are probable, but additional information would be necessary to provide specific design criteria to minimize adverse environmental effects. Such large generating plants and transmission systems were examined in this section, and major environmental effects were identified that might result from construction and operation. Affected Environment Generating plants. and related transmission systems would affect the Interior and North Slope areas of the State--vast expanses of land under the influence of arctic and sub-arctic climates. Interior - North of the coastal forests climate becomes more severe. The area between the southcentral coast and the Alaska Range is a mountainous area dissected by several long, narrow river valleys including the Matanuska, Susitna, and Copper. Lands along the rivers tend to be forested, and extensive grassy rangeland is found along the southern slopes of the Alaska Range. Discontinuous permafrost is present throughout. The area between the Alaska and Brooks Ranges is characterized by a continental climate. Rainfall is generally about 20 inches annually but may be as ljttle as eight inches in some areas. Winter gemperatures may drop to -50°F; summer temperatures may rise to nearly 90°F. The interior is primarily a broad plateau periodically intersected by mountains and ranging from flat marshy lands along meandering rivers to gently rolling forested hills. The Yukon and Kuskokwim Rivers and their tributaries constitute the main river systems draining the area, and most of the land here is underlain by permafrost. Forests cover much of the lands along the river valleys with great expanses of marsh and tundra in the lake-dotted plains. : North Slope - This is the area of the North Slope oil] and natural gas discovery, major reserves of coal, and the Arctic National Wildlife Range. The area encompasses 81,000 square miles of lands draining into the Chukchi and Beaufort Seas. The southern border of the area is located in the northern terminus of the Pacific Rocky Mountain system--the Brooks Range, which forms a 100-mile band of steep, canyoned ridges. To the north the land becomes gently rolling foothills which gradually flatten into the broad tundra-covered coastal plains. Seas are wholly or partially ice-covered all year; precipitation is scant, and winds may be strong. 27 The entire costal plain is underlain by permafrost except under lakes and rivers. Because permafrost prevents water percolation and evaporation is slight, the plain becomes dotted with ponds and lakes in the spring camouflaging the fact that this area is essentially a desert. The coast supports populations of seal, walrus, whale, and polar bear; but fish in these waters are unusually small for their age, and modest numbers of shellfish are found here. Plant life in the area is primarily confined to tundra with high brush at higher elevations. Balsam poplar and Alaskan willow are the only species at these latitudes, and small stands of these occur, reaching a height of 35 feet and a 5-inch diameter. Environmental Consequences Various major environmental impacts might be expected from construction and operation of the proposed generating plants and related transmission facilities. While lack of project facility location precludes exact determination of environmental impacts, potential impacts equal or exceed construction and operation of the Alaska oil pipeline. The extent of impacts depends on their effect on human activities, values, and the human environment. Analysis therefore included consideration of related individual components to help identify major impacts. Climate .- While additional data would be needed to determine if energy developments would affect Alaska's climate, available information indicated that there would be minor effect on a regional basis, but potential exists for local change. Air Quality - Emissions from coal-fired electric powerplants of the size being considered have potential for major environmental impacts. For the 16 500-MW plants considered, daily emissions were estimated based on a lower quality of coal at the 860-MW Emery powerplant in Utah as follows. 21/ Estimated Emissions Tons/day Sulfur dioxide (S0,) 850 Nitrogen dioxide (R0,) 650 Particulates 50 These figures give only a rough magnitude of materials involved. There would also be ozone, trace elements, and radioactive elements which were not estimated. This magnitude of emissions could present difficulty in meeting National and State New Source Performance Standards and ambient air quality standards. While the latest advances in dry cooling towers would be used, plants would still put an estimated 6,900,000 gallons of water vapor into the air each day. With the regular deep air inversions on the North Slope during winter months, this could result in more than 29,000 tons of ice fog daily. Additional ice fog would come from houses, vehicles, and other equipment. Surface activities during summer months, particularly if strip mining is used, would expose soils to wind erosion that would affect air quality to some extent. Topography - Major impact could come from land subsidence on thousands of acres iF underground mining is employed. Open pit mining would create a pit 750 feet deep and cover an area of roughly 3,800 acres. Depending on coal seam configuration, land for waste disposal could require two to four times the excavated pit area. Land form would be changed on several hundred acres in the construction of plants and related facilities while some impact could also be expected for the transmission facilities corridor from access construction and erosion. 20/ Soils - Productivity of about 20,000 acres of soil would be lost or reduced as a result of plant, mine, and associated facility construction. In addition, some of the transmission corridor lands--depending on location and design--would also be lost. Any area disturbed, particularly in permafrost areas, has potential for major impact through soil erosion due to permafrost degradation resulting from removal of the insulating vegetative cover. Vegetation - Construction of the generating plants and related facilities would disturb or eliminate vegetation from several hundred acres of land. The town site for powerplant and mining employees would also change several hundred acres. Emissions would have potentially major impacts on vegetation as identified in the 1972 study--particularly long-term nitrogen and sulfur concentrations. Vegetative change in turn could affect wildlife habitat and soil stability. Water - Development of the generating plants and related facilities will place significant demands on water resources. The generating plant requirements using best technology were estimated at 6,900,000 gallons per day or 7,900 acre-feet per year. Other water requirements would be associated with underground mining, plant and transmission facility construction and operation, and an associated town of several thousand employees. Satisfying water requirements of this scale could be difficult dependent on facility location because available water in these northern latitudes is severely limited in many cases. Sewage disposal and maintenance of water quality could likewise present major problems. 29 Waste Heat - Waste heat could be beneficial in warming local waters and increasing productivity. Wildlife - Principal impacts on wildlife resources would probably be loss or change in habitat and reduction of species numbers through additional hunting and fishing by the population influx. Depending on facility location, impacts could be possible on critical habitat and/or endangered species. Scenic Resources - Construction of the generating plants and facilities would have impact on the scenic resources--the extent of which would depend on design and location. Operation of the plants and mining would also add to visual impacts through emission plumes and vegetative disturbance and removal. Visually the generation plants and most of the transmission facilities would be prominent industrial intrusions on a wilderness-type landscape. Two rows of towers with a height of 135 feet on a 320-foot right-of-way would present visually prominent features above adjacent vegetation and would have a rigid unnatural appearance compared to the natural landscape. Minerals - Twenty-four million tons of coal would be mined each year for 35 years for the generating plants. This represents only 0.7 percent of the known coal reserves of the North Slope. Depending on the type of mining used, an additional 5 to 50 percent of coal would remain in the mines as unrecoverable. Deposits of sand and gravel could be used in construction and operation, and many mineral resources would be used to make project materials. Land Use - Roughly 20,000 acres of land would be used by the powerplant, mining operation, and townsite. The mine would be expected to use most of the area with the largest variable depending on the amount of space needed for mine waste disposal, and ash disposal would require 1000 to 1500 acres. Switchyards would use 100 to 200 acres. Area for a townsite, water storage, sewage disposal, an airport, extensive road system, and related community and recreational facilities would be ~ included. Transmission facilities would require 87,000 acres of land. Human Resources - Population would increase significantly, particularly on the North Slope. A new townsite on the North Slope for a population of 10,000 to 14,000 might be expected. 11/ 12/ 21/ Estimated Population Total Workers Population Mining 4,600 - 7,000 5,000 - 9,000 Plant & Facility Construction 10,000 11,000 Operation and Maintenance 2,500 5,000 30 Social impacts could occur as a result of lifestyle differences between the new population and present residents. Human Health and Safety - In addition to the hazards to health and safety inherent in coal mining and generation plant and transmission facility construction and operation encountered in the contiguous states, the Arctic climate of the North Slope and Interior Alaska presents additional hazards of long-term freezing temperatures. Under certain weather conditions, noise could be a problem near transmission facilities. Market Area - Electricity generated by the plants would be transmitted to the contiguous states and would impact the Pacific Northwest area. Magnitude was not predicted, but impacts would be anticipated in residential, commercial, and industrial use with potential for growth. With this growth would go increased employment and demand for goods and services. Severity and significance of impacts would depend on local situations, but they would be expected for the life of the plants. Mitigating Measures Measures could be taken to mitigate or reduce adverse impacts to the human environment. Measures suggested were considered to be in addition to those required by State and Federal law and regulation. Mining - Mine and related transportation system layout should be done to recover the maximum amount of coal from the mine and to minimize adverse impacts on fish and wildlife and their habitat, water and vegetative resources, air quality, and permafrost. Sufficient studies should be made to identify and locate critical natural resources and alternatives to avoid them. Mining should be based on arctic techniques. Any strip mining should include restoration and revegetation. Generating Plants - Early study should be made of potential generating sites to identify alternative locations that avoid critical wildlife habitat and endangered species and minimize adverse impacts on other resource values. Plant layout and design should compliment local _ landform, and arctic technologies should be used in all equipment design. Transmission Facilities - These facilities should be located to minimize conflict with present and planned land uses and preserve the natural landscape. To the extent compatible, joint use of corridors should be made. Unavoidable Adverse Impacts Some impacts could not be avoided completely should the generating plants and transmission facilities be constructed and operated. 31 Air Quality - Discharge of pollutants such as particulates, sulfur dioxide, nitrogen oxides, trace and radioactive elements, and coal mine, auto, truck, and aircraft emissions to the atmosphere would be unavoidable. Water vapor discharge to the atmosphere during periods of inversions in winter would produce ice fog. Extent of impacts would depend on plant and facility location, equipment design, and dispersal patterns. Topography - Landform would be changed where developments occur. Extent of impact would depend on development location and facility layout and design. Coal mining could present important impacts depending on mining methods. Underground mining could result in land subsidence while strip mining could cause permafrost degradation and subsequent erosion. Soils - Impacts to soils would be in the form of loss of soil productivity and erosion from disturbance and permafrost degradation. Impacts could be significant in local mining and facility development areas. Vegetation - Loss of vegetation would occur with facility development areas, and potential would exist for loss from emissions. Water - Construction and operation of the plants and transmission facilities would require water supplies for both consumptive and non-consumptive purposes. Depending on location of use, impacts on fish and wildlife, vegetative resources, and historic subsistence uses could be critical. Wildlife - Wildlife habitat would be reduced and harvest of wildlife populations would increase. Critical species and habitat could be involved depending on location of facility developments. . Cultural and Paleontological - Impacts to these resources would occur, but amount and significance of loss could not be predicted. Scenery - Impacts on scenic resources from intrusion of industrial © facilities into wilderness-type lands could be significant. Minerals - Mining and use of coal would be unavoidable, and coal used would be irreplaceable. Use of local sand and gravel would reduce reserves accordingly, and depending on location, use could create secondary impacts on fish and wildlife, soils, vegetation, and permafrost. Land Use - Use of 50,000 acres of land for mining, generating plants, and transmission facilities would be unavoidable. On the basis of expected plant life, acreage could be considered irreplaceable. Human Health and Safety - The majority of the population involved would be newly placed in a remote, arctic environment which would subject them to additional hazards from extended freezing temperatures. Market Area - Unavoidable impacts would include increased air pollution and pressures on public services due to increased commercial and industrial activities. Magnitude of these impacts could not be determined. Alternatives Major environmental impacts would also result from alternative energy resource use and export. Coal Export - Export would eliminate the need for the generating plants, new communities, and electric transmission facilities. All environmental impacts related to such construction would be eliminated from Alaska. Coal transportation facilities would be necessary, and impacts from them could be significant, depending on location and design. A town of several thousand people to support the mining effort would still be needed. Natural Gas - Generation with natural gas on the North Slope would be similar to that outlined in the 1972 study. Emission impacts, depending on location and plume patterns, would still be present but significantly smaller than for coal generation. Sulfur oxides would be reduced significantly. Export of gas by pipeline would raise potential for major impacts on natural resources, again depending on location, design, construction, and operation. Hydropower - While several "world class" hydropower potentials exist in Alaska--Wood Canyon, Rampart, Wood Chopper, and Holy Cross, recent Federal land legislation has precluded their development. Oil - Generation of electric energy from 0i1 would involve a set of environmental impacts similar to generation using natural gas: emissions, ice fog, generating plants, transmission lines, and facility construction in arctic areas in addition to whole new communities. Tidal - Tidal electric energy generation would be in the Cook Inlet area and would create significant impacts on scenery and fish and wildlife resources. Economic Analysis Economic analysis was made for a Federal financing method. Several sensitivity analyses were made to show effects of various other financing methods, coal prices, and inflation. 33 The following tabulation presents investment costs and costs per kilowatt-hour for steamplant generation on the North Slope and transmission to Everett, Washington, derived on Tables 2 and 4. Energy cost includes deduction of 7.2% transmission losses. Annual Investment Cost Energy Cost $ Billion $ Billion ¢/KWH Steamplant, 8000 MW 32.5 3.56 6.9 Fuel 1.12 2.2 Transmission Two + 800-kV d.c. lines 11.0 1.06 2.1 43.5 5.74 11.2 Cost estimates were on 1981 price levels. The annual costs included interest at 9% for Federal type of financing, depreciation, interim replacements, and operation and maintenance. For economic analysis purposes, a project repayment period of 35-years was selected. Eighty percent of project investment was in the steamplant, d.c. converter terminals, and communication equipment and had a 35-year life. The other 20 percent of the investment was for the transmission line which had a 50-year life. There would be some salvage value of the transmission line which could be included in economic analysis but would account for only 6 percent of the investment cost. Sensitivity Analysis When private financing of North Slope generation and transmission was tested against the Federal financing method, cost of energy delivered to the market increased from 11.2¢ per kWh to 20.1¢ per kWh. The primary reason for the 80 percent increase was an interest rate assumption of 14 percent instead of 9 percent, and an additional 6 percent for taxes. A tabulation of estimated annual fixed charges for generation facilities is included in the Appendix for comparison with other financing methods and interest rates. The State of Alaska had three methods of financing energy projects. 1. 0 percent interest with full payment of operation, maintenance and replacement (OM&R) costs. 2. 10 percent of the investment cost in annual payments, or OM&R costs, whichever is greater. 3. 5 percent interest with full payment of OM&R. Under the first method there would be little or no incentive for Alaska to subsidize over $40 billion of construction and forego all capital return on the investment with a small amount of royalty from coal development as the only benefit to the State. The other two financing methods would produce these costs. Energy Cost ¢/kWh Federal Financing State Financing Basic Case 10% of investment 5% interest 9% interest f or OM&R plus OM&R 11.2 10.5 ! 8.6 Steamplants in the Arctic would have a higher likelihood of cost variation than if located elsewhere. Several items were not specifically quantified in this study. 0 Capital cost of the town to support the steamplant and the mine, including the homes and community support systems such as roads, water and sewer systems, and an airport. (The town would be as large or larger than the potential new capital with construction costs double those of the Anchorage area.) 0 A pilot steam plant to verify the appropriate technology for arctic operation. Oo Interest during construction if the schedule extends beyond building all 16 units at the same time. Inflation during construction and interest for 12 years instead of six to eight years could easily add 50% to total cost. 0 Cost of upgrading the highway to the North Slope to provide access for construction and operation of the steamplant, coal mine, and the town. 0 Development of large modular components for the steamplant and related barges and handling equipment. For purposes of sensitivity analysis, if the cost of the steamplant on the North Slope was increased 25 percent to cover the above contingency items, capital cost would increase from $32.5 billion to $40.7 billion. Overall cost of energy delivered to Everett, Washington, would increase from 11.2 to 12.6 cents per kilowatt hour. Another comparison would assume coal shipped from the Alaska Beluga coal field to the Pacific Northwest and burned in steamplants costing only 25 percent of the steamplant cost on the North Slope. Coal prices delivered to the Pacific Northwest and at the mine mouth on the North Slope would be approximately the same based on two separate studies. 17/ 18/ The long transmission line would be eliminated with a resulting cost of 35 roughly 4¢/kWh in the Pacific Northwest (comparable to the recently completed Boardman plant: in Oregon). This price would be roughly one third the price of the North Slope energy option. Coal prices were estimated at $2 per million Btu ($48 per ton) which is equivalent to 2.2¢/kWh after transmission losses. If the cost of mining turned out to be $4 or $8 per million Btu, the resulting energy cost would be 4.3¢ or 8.6¢/kWh considering losses. Year around coal strip mining in the Arctic is not a proven technology, and cost variation should be expected. Final determination of the amount of royalty and world demand for coal could add further variations to the price. The distance of the mine from the steamplant, the coal transportation method, and method of mining are all variables that can not be identified without considerably more study, and these factors could highly influence the fuel cost. The construction costs are on a 1981 price level. To get an estimate of the annual cost and the capital required in terms of year 2000 prices, the following tabulation presents costs escalated 5 percent per year for 19 years (253 percent). 1981 2000 Price Level Investment Investment Annual $ billion $ billion $ billion ¢/kWh Steamplant 32.5 82.1 9.0 17.3 Fuel 2.8 5.4 Transmission 11.0 27.8 Qld, 5.2 3.9 109.9 14.5 7.9 The investment cost by the year 2000 would be about $110 billion and cost about 28¢/kWh wholesale delivered to the Pacific Northwest. For comparison, 1981 estimated cost of the natural gas pipeline from the North Slope to the South 48 was roughly $30 billion, while the cost of the North Slope steamplant.and related transmission system was over $43 billion. The North Slope steam project would exceed by 40 percent the capital investment of the pipeline which has been claimed the most costly project in the world. The amount of electric energy delivered to the Pacific Northwest from the steamplant would be roughly equivalent to electric energy generated in the Pacific Northwest by using gas from the pipeline. Available energy would be increased two or more times if natural gas were used for space heating and other higher value uses instead of fuel for electric power generation. This economic analysis does not include costs for upgrading the Pacific Northwest transmission system to distribute the energy. Reserve generation capability would also need to be provided for short-term power 36 line outages and times when 80 percent of the total generation capability on the North Slope might not be available due to routine maintenance and emergencies. Any reserve generation was assumed to be installed in the Pacific Northwest where the cost would be cheaper than on the North Slope. Costs for reserve generation were not included in this analysis. Constraints A project of the immense magnitude contemplated could be faced with these constraints. °O 0 Climatic--from the effects of long-term freezing temperatures. Environmental--in terms of Arctic health and safety hazards, permafrost, air and water quality standards, available water supplies, waste disposal, and scenic, fish and wildlife values. Economic--from the standpoint of available capital for investment and feasibility. Federal Land Actions--in terms of land use and development. Technological State-of-the-Art--on the basis of Arctic coal mining technology. Transportation--in terms of land and air access. 37 4, MARKETABILITY The power market area for the export case would be the Pacific Northwest and the interconnected systems including the Pacific Southwest and possibly Canada. The wholesale price of the energy in 1981 terms would be 11.2¢/kWh delivered to the low voltage side of the d.c. converter station near Everett, Washington. Bonneville Power Administration's assessment, shown in Appendix G, indicated that there appeared to be sufficient incremental Pacific Northwest energy demand between 1981 and the year 2000 to require an additional 8,000-MW resource to cover either the load growth or to replace an equivalent resource if the imported energy is economical. 27/ The projected price of energy in the Pacific Northwest from coal-fired steamplants, at a 1980 price level, ranged from roughly 5¢ to 8¢/kWh-- Bonneville estimates. Fuel accounted for about 1¢/kWh. In the 1970's energy from nuclear and coal generation facilities cost 1.5¢/kWh to 2¢/kWh. The Boardman steamplant in Oregon, started in the 1970's and completed in 1980, had an energy cost of 4.0¢/kWh. North Slope generation was estimated at 11.2¢/kWh at 1981 price levels. Cost figures from this preliminary study indicated no real likelihood that power from the North Slope could be delivered to the Pacific Northwest at an attractive price. j 5. SUMMARY From time to time consideration has been given to the Northern latitudes as a source of energy for the lower 48 States. This analysis considered a set of those energy export potentials. Early export schemes contemplated vast hydroelectric developments. Subsequently, the 1972 North Slope Transmission Study (1972 study) examined options for exporting electric power from the North Slope using natural gas-fired generation. The 1972 study considered three cases of delivery of power from the North Slope to: (I) the Pacific Northwest, (II) the Railbelt area of Alaska, and (III) a system interconnecting Alaska, Canada, and the Pacific Northwest. Several significant events have occurred since 1972 that would affect the 1972 study findings. These included rapid increase in oil prices, proposed construction of a large natural gas line from the North Slope to the lower 48 States, and legislation which precluded most of the hydropower development in Alaska. Because of these changes and continued interest in export of electric power from Alaska to the Pacific Northwest, this analysis was made to update the 1972 study. Alternative energy resources in Alaska were reviewed to determine which would be available for export as electricity. Coal deposits on the North Slope comprised 90 percent of the State coal resource and appeared the most logical long range export resource available. The Beluga and Nenana coal fields were the most likely for early development for local electric generation and for bulk shipment to the lower 48 and the Orient. Electricity export using generation from natural gas, hydropower, oil, wind, and tidal power did not seem promising. The project plan was similar to the 1972 study except that in this analysis energy was generated from coal instead of natural gas. An 8,000 MW mine-mouth steamplant would be constructed on the North Slope. Energy would be delivered to a substation near Everett, Washington, by two parallel + 800 kV direct-current transmission lines. The steamplant would be sited as close as possible to the mine to minimize transportation of the 24 million tons of fuel needed annually. Several sensitivity analyses were made to demonstrate the effect of private financing, State financing, a 25 percent increase in steamplant costs, a variation in fuel costs, and the impact of inflation. These were the major findings of the study. 0 Coal resources on the North Slope were considered to be the most likely energy source to generate electric power for export from Alaska. 39 Investment cost for steamplants on the North Slope was calculated to total $33 billion--roughly four times as costly as in the lower 48 States. Transmission system costs would be $11 billion, while annual cost was estimated to be $5.8 billion--all resulting in an energy cost of 11.2¢/kWh delivered to the Pacific Northwest. Marketability of project energy was examined by comparing the 11.2¢/kWh for North Slope energy delivered to the current Pacific Northwest price of 5¢ to 8¢/kWh for coal-fired and nuclear generation in the same market area. Although the Pacific Northwest demand for a block of energy this size might exist by the year 2000, the 11.2¢/kWh does not appear economically attractive. Technology of large scale coal mining in the Arctic would need considerable study and definition before a serious proposal could be made to export energy from steamplants in the Arctic. Price of mine-mouth coal could exceed costs considered in this study due to handling frozen coal, mining in permafrost, and maintenance of a town with a population of 10,000 to 14,000. This analysis re-confirmed 1972 study findings that a + 800 kV direct current transmission system would be feasible from an engineering standpoint, appropriate and near optimum size. There would be potential environmental impacts on air and water quality, water supplies, permafrost, and fish and wildlife resources. Principal constraints to the project identified were the immense magnitude of the project, severe cold climate limitations, detrimental environmental impacts, size of capital investment and economic feasibility, Federal land restrictions to use and development, lack of Arctic coal mining technology, and lack of air and land transportation access. . The magnitude of problems associated with large-scale coal mining in deep permafrost conditions would dictate careful examination before any serious attempts at mining. The price of coal could be higher than considered in this analysis due to problems associated with a world class 24 million ton/year mine, handling frozen coal, stripmine revegetation or backfilling an underground mine, in addition to development and maintenance of a town with a population of 10,000 to 14,000 in the Arctic. Further studies did not appear warranted. a. C. ANCSA ANILCA APA B.C. Hydro Bipolar d.c. transmission system BPA Btu Converters EPRI Gigawatt (GW) GVEA HVDC Indexed cost 41 6. GLOSSARY Alternating current Alaska Native Claims Settlement Act, Public Law 92-203, December, 1971. Alaska National Interest Lands Conservation Act, Public Law 96-487, December 2, 1980. Alaska Power Administration, U. S. Department of Energy British Columbia Hydro and Power Authority A direct current transmission line with two conductors, one charged positive and the other charged negative. Bonneville Power Administration, U. S. Department of Energy British thermal unit Equipment that converts a.c. to d.c. or d.c. to a.c. Direct current Extra high voltage. A term used to describe electrical equipment or transmission lines usually referring to volatage over 500 kV. The capacity for performing work. the electrical energy term generally used is kilowatt-hours and represents power (kilowatts) operating for some time period (hours). Electric Power Research Institute One billion watts, a unit of electric power Golden Valley Electric Association High voltage direct current An indexed cost is a ratio of costs from one time compared to another time. Costs may also be ratioed from one geographical area to another. N Inverter Kilovolt (kV) Kilowatt (kW) Kilowatt-hour (kWh) Load Load factor Megawatt (MW mmBTU oan Peaking Capacity Plant factor PNW-PSW Intertie System Scrubber South 48 See converter One thousand volts, a unit of electric potential difference. One thousand watts, a unit of electric power. One thousand watt-hours or the amount of energy involved with 1-kilowatt demand over a period of 1 hour. The amount of power needed to be delivered at a given point on an electric system. The ratio of the amount of energy used or produced over a period of time compared to the amount that could have been produced if the peak amount had been used or produced over the same period of time. One million watts, a unit of electric power One million Btu Operation and Maintenance The amount of installed electric generation capability needed to meet the largest demand on a specific day or a specific time of the year. The ratio of the amount of energy a plant produced compared to the amount it could produce operating at 100 percent of the peak all year around. The high voltage d.c. power line ; intertieing the Pacific Northwest to the Pacific Southwest. A mechanical and chemical system used to clean sulphur dioxide and other chemicals from a steamplant smoke stack. The 48 contiguous states--excludes Alaska and Hawaii. Steamplant Subsidence Terminal buses Transmission system Twin circuit transmission system USDOE Wheeling WPPSS 1972 Study 43 A coal-fired electric generating plant using steam to turn the turbine and generator. The lowering of land due to the withdrawal of coal or water from underground. A common connector between several circuits at a swtichyard or d.c. terminal converter. The towers and electrical cables that move the electric energy between two or more points. Two separate transmission lines starting at the same point and serving the same end points. They may or may not use the same right-of-way. United States Department of Energy Transmission through the facilities of one entity electric power owned by another entity. Washington Public Power Supply System North Slope Transmission Study of 1972 Se 5a. 6. iS 12. 45 7. BIBLIOGRAPHY Coal Assessment of the Feasibility of Utilization of the Coal Resources of Northwestern Alaska for Space Heating and Electricity, Phase Il. Prepared for Alaska Power Authority by Dames & Moore, June 30, 1981. Barnes, Farrell F. Coal Resources of Alaska. Geological Survey Bulletin 1242-B. Washington: U.S. Government Printing Office, 1967. Barnes, Farrell F. Geology and Coal Resources of the Beluga-Yentna Region Alaska. Geological Survey Bulletin 1202-C. Washington: U.S. Government Printing Office, 1966. Bartz, John A. and Maulbetsch, John S. “Are Dry-Cooled Power Plants A Feasible Alternative?" Mechanical Engineering, October 1981, pp. 34-41. Beluga Status Report September 1979. Placer Amex Inc., 1979. The Alaska Economic Report. October 15, 1981. Bottge, Robert G. Coal as Fuel for Barrow, Alaska: A Preliminar Study of Mining Costs. Open File Report OFR 88-77. U.S. Department of the Interior, Bureau of Mines, 1977. Burnham, John B., comp. The Impact of Increased Coal Consumption on the Pacific Northwest. Battelle for Department of Energy (Springfield: NTIS), March 1978. Burnham, John B., comp. A Preliminary Assessment of the Health and Environmental Effects of Coal Utilization in the Pacific Northwest. (Comment Draft) Battelle for Department of Energy. October 1977. Cost Study for a 400 MW Coal Fired Power Plant, North Foreland Area Cook Inlet, Alaska. EBASCO, March, 1979. Hat Creek Thermal Power Project, Highlights of the Environmental Impact Statement. Vancouver, B.C.: B. C. Hydro, May 1981. 13. 14. 15): Whe 18. 19. 19a. 20. (al eee 235 Hesse, Gerhard, and Augustine, P.R. "Wyodak: A Milestone’ in Dry Cooling" Power Engineering, August 1980, pp. 66-69. Olsen, Marvin, and others. Beluga Coal Field Development: Social Effects and Management Alternatives. Battelle for Department of Energy (Springfield: NTIS), May 1979. Rao, P. Dharma, and Wolff, Ernest N., eds. Focus on Alaska's Coal '75. Proceedings of the Conference held at the University of Alaska, Fairbanks October 15-17, 1975. Anchorage: Mineral Industry Research Laboratory, 1975. Swift, W.H., Haskins, J.P., and Scott, M.J. Beluga Coal Market Stud Prepared by Battelle for the Division of Policy Development and Planning, Office of the Governor, State of Alaska, December 1980. Transportation and Market Analysis of Alaska Coal. U. S. Department of Energy. Seattle: Office of the Regional Representative of the U.S. Secretary of Energy, 1980. Wahrhaftig, Clyde, and others. The Coal-Bearing Group in the Nenana Coal Field, Alaska. Geological Survey Bulletin 1274-D. Washington: U.S. Government Printing Office, 1969. Sanders, Robert B. Coal Resources of Alaska. October 1980. Environment Environmental Criteria For Electric Transmission Systems. United States Department of the Interior, United States Department of Agriculture, 1970. Final Environmental Statement, EMERY POWER PLANT. Bureau of Land Management, 1977. Gas Pipeline Chronology of Major Events, Alaska Natural Gas Transportation System. Office of the Federal Inspector, Alaska Natural Gas Transportation System, Updated through November 6, 1979. Oil and Natural Gas The Current State of the Natural Gas Market. An Analysis of the Natural Gas Policy Act and Several Alternatives, Part l. DOE/EIA-0313. Energy Information Administration Office of Oil and Gas, U. S. Department of Energy. December 1981. 25a. 25b. 26a. 24. 24a. 24b. Ue 28. 29. 30. Slr 47 Van Dyke, William D. A Report to the State of Alaska, Jay S. Hammond, Governor, and to the Department of Natural Resources, Robert E. Leresche, Commissioner. Proven and Probable Oil_and Gas Reserves, North Slope, Alaska. September 25, 1980. Oil and Gas Resources of Alaska. Alaska Department of Natural Resources, Division of Geologic and Geophysical Surveys. July 1981. Erickson, G. H. Natural Gas and Electric Power: Alternatives for the Railbelt. Legislative Affairs Agency, Alaska State Legislature. March 1981. Water Cook Inlet Tidal Power Study. Prepared for the Office of the Governor by Acres American. December 1981. Alaska Power Administration North Slope Transmission Study. U. S. Department of the Interior, Alaska Power Administration, 1972. Alaska Power Administration. Analysis of Alaska National Interest Land Conservation Act Impact on Hydroelectric Resources. May 1981. Preliminary Evaluation of Wind Energy Potential--Cook Inlet Area Alaska. Battelle for Alaska Power Administration. June 1980. Bonneville Power Administration Bonneville Power Administration. Correspondence between Bonneville Power Administration and Alaska Power Administration. December 1981. 1979 Annual Report. Bonneville Power Administration, U.S. Department of Energy. Transmission Line Reference Book HVDC to +600 kV, Electric Power Research Institute and Bonneville Power Administration. B.C. Hydro Annual Report 1980/81. British Columbia Hydro and Power Authority. Annual Report 1979/80. British Columbia Hydro and Power Authority. Policies, Office of the Governor 32. Policy Analysis Paper No. 80-16. Alaska Energy Issues, Options for State Action. Prepared by Office of the Governor, Division of Policy Development and Planning. November 1, 1980. Transmission Technology 34. Electrical Review, June 5, 1981. 35. Electrical Review Vol. 209 Nol., July 3, 1981, Page 5. Related Material Alaska Water Assessment Summary Report. Alaska Water Study Committee, 1977. Buck, Eugene H., ed. Comprehensive Bibliography and Index of Environmental Information for the Beluga-Susitna, Nenana and Western Arctic Coal Fields, Volume III. Anchorage: Arctic Environmental Information and Data Center, 1979. Comparative Assessment of Health and Safety Impacts of Coal Use. U.S. Department of Energy, Assistant Secretary for Environment, Office of Technology Impacts, Technology Assessments Division. Springfield: NTIS, March 1980. Rutledge, Gene, and others. Alaska Regional Energy Resources Planning Project, Phase 2 Coal, Hydroelectric and Energy Alternatives, Volume I, Beluga Coal District Analysis. U.S. Department of Energy, 1980. 8. APPENDIX 49 APPENDIX A ALASKA FACTOR AND GEOGRAPHIC INDEX Agencies and corporations were contacted to determine what cost factor adjustment would be reasonable for comparing construction costs in Anchorage and the South 48 the North Slope area. States to Ratio of Prudhoe or Barrow to Wn. D.C. Anchorage Barrow Anchorage Corps of Engineers Applicable to construction on site for buildings, roads, airports, 1970. 1.0 Ler au 1.0 2a Zail 1980 10 1.9 U.S. Coast Guard & Navy 1.03 Medi 35) Design Manual 1973 1.0 Zot eu Oil Company #1 Prudhoe O&M 1981 1.0 un a2 Oil Company #2 So. 48 Prudhoe So. 48 construction & barging of large modules to Prudhoe and 10 20) t03)-0 hookup on site, 1981. 0 lies WSitouces 19) Consultant #1 Barrow & Prudhoe 1978 Construction 1.0 2254 2.54 1978 O&M 1.0 1.80 Seattle 0) 13 a3 Consultant #2 Barrow 1981 0 1.92 1.92 Alaska Power Administration So. 48 Remote ~ Barrow Study, 1977. near Barrow ] 4.0 3 Ank “T.0** all rely Mode el Mean 22) Best data & most likely 2.2 (Consultant #1 & Oil Co. #2) 0&™ only (Consultant #1 & Oil Co. #1) 220 Prudhoe sites only (Consultant #1, Oil Co. #1 & #2) ne, Use factor of 1.9 for South 48 adjustment to Alaska for heavy construction. Use factor of 2.0 for 0&M adjustment between Anchorage and Prudhoe Bay. Use average factor of 2.1 for adjustment between Anchorage and Prudhoe Bay. * Assumed at 1.3 from consultant #1. **Based on Corps of Engineer index of 1.9 for on-site construction in Alaska. APPENDIX B TABLE A-1 ' ESTIMATED ORIGINAL COAL RESOURCE OF ALASKA By Coal Field (Million Short Tons) Subbituminous Coal Field Bituminous and Lignite Total Northern Alaska 19,292 100 ,905 120,197 Nenana - 6,938 6,938 Jarvis Creek - 77 77 Broad Pass - 64 64 Matanuska 137 - 137 Susitna (Beluga) - 2,395 2,395 Kenai (Homer Dist.) - 318 318 Total Original Coal Resources 19,429 110,697 130,126 Source: Barnes, Farrell F., "Coal Resources of Alaska," U.S. Government Printing Office, Washington, D.C., 1967. i2 APPENDIX C ALASKA RESERVES -- OIL Latest estimates for oil reserves for Alaska by fields January 1, 198] Beaver Creek -------------- 1 MM STB Granite Point ------------- 35 Kaparuk River ------------ 448* MacArthur River ----------- 91 Middle Ground Shoal ------- 33 Prudhoe Bay ------------- 7,819 Swanson River ------------- 22 Trading Bay ---------------- 5 Totals 8,454** Several minor oi] fields on the North Slop have not been defined by drilling and reserve values are not available. ALASKA RESERVES -- GAS Latest estimates for gas reserves for Alaska by fields Million Cubic Feet Beaver Creek --------------- 239 Beaver Creek (AG) ---------- ] Beluga River --------------- 760 Birch Hill ----------------- 11 Falls Creek ---------------- 13 Granite Point (AG) --------- 26 Ivan River ----------------- 26 Kenai ---------------------- 1,215 Kuparuk River -------------- 206 Lewis River ---------------- 22° McArthur River ------------- 71 Middle Ground Shoal -------- 17 Nicolai Creek -------------- 117 North Cook Inlet ----------- 1,001 North Fork ----------------- 12 Prudhoe Bay (AG) ----------- 28,831 South Barrow --------------- 24 Sterling ------------------- 23 Swanson River -------------- 265 Trading Bay ---------------- 10 West Foreland -------------- 20 West Fork ------------------ 6 Totals 32 ,846 *Estimate from Arco Testimony, March 25, 1981 **Statistical Report 1980, Alaska Oi] and Gas Commission Source: Qi] and Gas Reserves and Resources for Alaska. 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NULLS: Vv 3LVOHD°9°R / 80% Jd = WONSS AN3YYNI LIZMIG AX 008 —e *9¥ONT WELSAS 4O ATO 21SN03U° AQNLS NOISSIMSNVUL 3407S HLYON ; A=C9ET-XL20N 183°" i Ee = “ests , sen fenc1eajele' ese eJ0.2 eisieeicie sje'ee'e, clelee 8 AYVHHAS JivuT ISA : é ae 1s 3 SSS a 2 \ iene —————— _ NORTH SLOPE. TRANSHESS TON STUDY = ITEH NO. ITEH QUANT. me = —— ~ 70510 CLEARING. _ 15.50 = ~—-—. 70620 ACCESS ROAD CONSTRUCTION 52.80 —~——" CLASS 2. . a _.. 70660 IMPROVE EXISTING ROAD 52.80 a _ 70750 EROSION CONTROL. = 38.80 a (EACH ACRE OF R/W) 70850 BRUSH CONTROL. SS 15.50 a ° ete (EACH ACRE OF R/W CLEARED) 70950 ACCESS ROAD IMPROVEMENT. = 1.00 ~ 70960 GRASS SEEDING BY. HAND OR BY._ 2200 DRILL 72410 CRUSHED AGG. FOR AR*S 3INCH-_ 390.00 == SUBTOTAL Se eee 2. TOTAL . = Se SS ee LLE ARS. UGCTALL 0 es > EST. NO. TX-1363-V PAGE..2.. -- CONTRACT CONSTRUCTION 8PA CONSTRUCTION. UNIT MATERIAL LABOR MATERIAL LABOR. ACRE 22480 = STA 17580 STA 9870 ACRE "620. ACRE "B50. MILE “~150_ HILE 750... cuyD 4810 = 54740 2370 54740 “2370 tapas saree ni aea ed aaa cetaieaes ns aes 0 . = a = ease 8, m oe a, ee == Se — . = E - E « ———<—- o - Se “CONSTRUCTION DETAIL = === NORTH SLOPE. TRANSHI SS 10N STUDY . : EST. NO. TX-1363-V PAGE 3. Ar —— -—~ ——— —— ccc wee, CONTRACT CONSTRUCTION BPA CONSTRUCTION eee ITEH i : . a NOs. = ITEM QUANT. UNIT MATERIAL LABOR MATERIAL LABOR _ TOWER AWD STEEL FOUNDATIONS © —— ———_ Se —_—_——- 74210 TOWER STEEL 257.80 TONS ce OA AILO —— se meemmememee oes 74310 TOWER STEEL ERECTION _ 257680 TONS 227,900 Paani: se (500 TONS AND UP ) = ea ee CONDUCTOR rai - . == Saaeee= * 80476 6 THRASHER CONDUCTOR — "1.00 MILE ee 2724005 OSS” ——CGNDUCTOR STRINGING, BUNDLED, SaCee SSS SS SS SS SS qererseereper cnr ent abe Geen enee TEEN TESTS OF Sensors ee CS —FO2526 STRINGING, 6 THRASHER 1.00 MILE 51,000 pumemetens CONDUCTOR HAROWARE STEEL - c a Se Se _————— —__* 86625 CONDUCTOR HARDWARE =” 1.00 MILE. 32000. ———T TNS ULA TORS amar ts TSO 1WSICATORs 66 kIP O-C ~~" §060.00 EACH cee" "217580 ——— VIBRATION DAHPERS | —— ———— —— call enter te vwemmee fee eases nn te eee —____¥ 68601 VIBRATION DAMPERS & SPACERS® 1.00 MILE . 9 23790' ee Fe emo ter ; . Fe tere eee men GD wee ——_ tHGW' SF COUNTERPOTSE FOR STEEL OB oie oO (\_____92403_CONTINUOUS W/ COUNTERPOISE ee, 2000 WILE | 4420 4550 oo . . oO 1-172" STEEL GH "CONSTRUCTION CLEANUP = aimcains en —~"""94990 CLEANUP 1.00 4. SS CONSTRUCTION OETAIL “MISCELLANEOUS SHALL ITEKS “YARD STORAGE EXPENSE 09 15.0% = = P e r——_ rere E = w Se tee — a ee ie ed nies = 7 bt eee é —_——- - ms ee i nn eet rent 8 ee eter tee nee a come 09: a: ary cee ST Oe Sst — —— m cme sermeneaeemennet se +0 ary meen, == = _..., CONTRACT CONSTRUCTION BI o ESTs NOs TX-1363-V PAGE 4. BPA CONSTRUCTION 18240 2 (301560 795290 160. inate —36700_. ===. — ., 27520 = = __ 301560 —*859 680 __180 _ = =a i = a ry = SI 5 H nome sw ere see ee om * aw eS ae TX-1363-V NORTH SLOPE Tse sia ‘STUDY —— 2 f0as8L a STRUCTURES — SiGe Gincorr sree Re acer eee reoareeces es CONDUCTOR - seroma Bees = ————— VOLTAGE — 2 800 KY Dincer aennemr TONS /HILE = 2839 t92s/qe (Fon Two Ammee aiee3)™ - = PER HILE BREAKDOWN : . ee ; MILES OF LINE? 1.0000 oe —. ,. CONTINGENCIES 0400 = ____SURVEY cove b41500000 _ ees poe eaere tren “3620.00 ree Saeco 7 == 7 Ea = a == = _ «DEST GN . Cy _. MATERIAL _859550.00 - — . RAND OO ce cp eect nen ee = CLEARING & AR*S 67580.00 — = CONSTRUCTION _— _357220.00 a _ UT REKOVAL e000 ee, —— —— — ee ———$ Seer rs eesvcor ss er co 5s Sacto —$$——$ SUBTOTAL ~ 1302120.00 j / ; Sa —___... .._ INDTRECT OH & ROUNDGUT 67410.00 = eoStgoe qe “HSEA GeHe _ 40470200 © = GROSS COST PER HIL 410000.00 © —— , ; = “| _ (cost OF LOSSES. PER MILE nee no Se eee mee eee wee eres ne = wo oan cree cower aaare PES a . = . * res ewes on ow . aren —-. we te — ——-— — —__— etn snes es cere oe eee ses eee see cem mime . « ‘ . : tee ——— - a ae on qd XIGNadd¥ —_—_— nt te ee cre ene mmm emt net teremenswowee sey prem ——— — re ‘ ' od o N nr eee Hote emma eee - o - . TRANSMISSION LINE COST ESTIMATE APPENDIX E North Slope to Fairbanks (450 mi.) Million Dollars A.C. - D.C. Converter Terminal 8,000,000 kW x $55/kW = Microwave Oe Sry tkaz5 pO $250,000 + (450 mi.) ($625,000) = 0525 2.81 100 mi. Transmission Line Materials, Labor, Overhead for Towers, Conductors, Construction, Access Roads, Special Foundations, Design, Surveys, etc. 450 mi. x $1.41 x 10° Subtotal Indexed Cost: 4.0 x 1,077.6 = 4,310.4 Fairbanks to Dease Lake (810 mi.) Transmission Line 6 810 mi. x $1.41 x 10 Microwave Communications 730 mi. x $625,000 mi. Subtotal Indexed Cost: 2.5 x 1,147.2 = 2,868.0 Dease Lake to Everett, WA (980 mi.) A.C. - D.C. Terminal 8,000 MW x $55/kW Microwave Communications 980 mi. x $625,000 TOO mi. Transmission 6 980 mi. x $1.41 x 10 Subtotal Indexed Cost: 1.0 x 1,827.9 = 1,827.9 Total Construction Cost North Slope to Fairbanks Fairbanks to Dease Lake Dease Lake to Everett, WA Investment Cost Construction Cost 440 3.1 634.5 1,142.1 Saul 1,147.2 440 6.1 1,381.8 3827:29 ve COoOw Noa aj Oo . wo 7 oie oVyNW COO oof mC ow mw oO Mw 1T,020.5 $11,000 ESTIMATED ANNUAL FIXED CHARGES - GENERATION FACILITIES Private Financing Cost of Money Depreciation (Sinking Fund) Interim Replacements Insurance Federal Income Taxes Miscellaneous Federal Taxes State & Local Taxes Totals Municipal and Other Public Non-Federal Financing Cost of Money Depreciation/Amortization (Sinking Fund) Interim Replacements Insurance Taxes (In Lieu of and Miscellaneous Federal) Totals REA Cooperative Financing (Composite Interest) Cost of Money Depreciation/Amortization (Sinking Fund) Interim Replacements Insurance Taxes (In Lieu of and Miscellaneous Federal) Totals Federal Financing 7 Cost of Money Depreciation/Amortization (Sinking Fund) Interim Replacements Insurance Taxes Totals Conventional Steam Plants 35-Yr. Life 14.00% 0.14 0.35 0.25 3.32 0.10 2.47 20.63 5.00% lel APPENDIX F 9.00% 0.46 0.35 0.25 0.75 6S APPENDIX G CORRESPONDENCE Letter to Honorable Terry Stim son from Alaska Power Administration. April 9, 1981. Confirming APA will update the 1972 study. Letter from Bonneville Power Administration to Alaska Power Administration. December 31, 1981. Transmitting costs and technical review. Bonneville Power Administration memorandum on marketability of energy from North Slope Transmission Study, December 22, 1981. DOE FORM AD.9 (12-77) CONCURRENCES ATG. SYmeou (2) April 9, 1981 Honorable Terry Stimson Alaska Senate Pouch V Juneau, AK 99811 ATG. SYMBOL, Dear Senator Stimson: INITIALS /si8. Don Shira and I enjoyed the opportunity to meet with you on April 1 and 2 concerning the Northwest Power Grid concepts. I wanted to confirm that we will provide an update of the transmission plans and costs in our 1972 North Slope Transmission Study, particularly since the cost data in that report is over 10 years old. The update should be available by late fall or early winter 1981. INITIALS/SIa. In the meantime, I believe the ballpark figures which we presented on April 2 are reasonable planning numbers for the high voltage, direct current concept. This is the case I of the 1972 report with 8,000 MW of transmission capacity between Alaska and the Northwest and an initial cost of about $6.2 billion plus costs of compensation to Canada for their participation. The figure does not include an allowance for future inflation. RTG. SYMBOL INITIALS /S16. We agree with comments from representatives of the Rand Corporation that there is substantial risk of underestimating the difficulty and the costs of such a plan at this stage of investigation. This is probably less of a risk for transmission system estimates than for powerplants, pipelines, and roads because of the nature of the construction activity. Transmission lines are just not as sensitive to local geologic and climatic conditions as the other work. INITIALS /si6. inrriats/sic. At the same time, there is very little likelihood that detailed inves- tigations would result in lower costs for these systems. The larger problem is of course the power source or sources. As in- dicated in our notes, the cost of providing 8,000 MW of generating YNITIALS/ Sia. capacity on the North Slope is likely at least four times the cost of a transmission system to deliver the power to the Pacific Northwest. 7 OFFICIAL FILE COPY 2 Based on this and the discussions on April 1 and 2, it doesn't appear prudent to initiate detailed studies of the bulk power export concept. Again, we really appreciated the opportunity to participate in the meeting. Sincerely, Robert J. Cross Administrator bee: Marvin Klinger, BPA RJCROSS/nt Department of Energy Bonneville Power Administration ; i P.O. Box 3621 Sraed hei Portland, Oregon 97208 In reply refer to: EOF DEC 3 1 1981 Mr. Donald L. Shira, Director Department of Energy Alaska Power Administration, Planning Division P.O. Box 50 Juneau, Alaska 99802 Dear Mr. Shira: When we met in my office on September 23, 1981, it was agreed that the Bonneville Power Administration (BPA) would undertake a review of the North Slope Transmission Study related to the Case I Study . The review would “TneTude an evaluation of bulk power transmission directly to the Pacific Northwest and an assessment of state of the art transmission technology. BPA would provide updated transmission system costs and power marketing data. The transmission system should be capable of delivering 8,000 MW of power from North Slope to BPA's Monroe Substation southeast of Everett, Washington, a distance of 3,605 kilometers (2,240 miles). As agreed, two DC voltage levels, + 800-kV and + 1200-kV, were examined. A radial 2-line 1100-kV AC system with intermediate switching stations and 30 percent series compensation was also considered. Higher levels of com- pensation may be required to maintain system stability during faulted condi- tions. We feel this is the most economical AC alternative for the distance and power level involved. Our studies indicate that a 2 X + 800-kV DC system would be preferred. The 2X + 1200-kV DC system has lower transmission line losses but the overall cost is higher. The + 1200-kV DC right-of-way is wider and the towers are taller, presenting more visual and environmental impacts. Drawings TD-3357, TD-3358, and TD-2915-D (enclosed) show the relative dimensions of the DC and AC towers. An AC system would be more costly than either DC alternative. Our present worth analysis using 7-3/8 percent interest rate indicates that the two line + 800-kV DC system would be the most economical. Loss savings is referenced to the the 1100-kV AC plan. The results of this economic ana- lysis are shown below: 4 2 Comparative Costs of AC and DC Systems (In Billions) 1100-kV AC + 800-kV DC + 1200-kV DC Present Present Present Investment Worth Investment Worth Investment Worth 1981 $ 1981 1981 $ 1981 1981 $ 1981 13.85 6.32 8.49 3.69 11.28 4.95 Loss Savings .03 L/ 7 Net Present Worth 6.32 3.66 4.78 1/ Based on current value of losses used by BPA We also made preliminary payout studies based on Table 13 of your report and the 9 percent interest rate that you have suggested. The + 800-kV DC and + 1200-kV DC transmission system costs (including losses) would be 20.5 mills/kWh and 24.4 mills/kWh, respectively. Copies of the BPA estimate Nos. TX-1363-V and TX-1363-W for the DC transmis- sion lines are enclosed. The per mile costs shown are for 2 parallel transmis— sion lines. No estimates were made of the PNW transmission system additions that would be required to deliver the electric energy to load centers. It is expected that the BPA 500-kV grid would need reinforcing. Tabulations of current typical costs for AC transmission lines as well as AC and DC terminal equipment are also enclosed for your information. The enclosed draft of the technology section has been revised to reflect the current state of DC transmission development. Table and figure numbers have been left blank. Responses to other questions raised during our meeting are: rs DC Circuit Breakers - A joint project to develop a 500-kV DC breaker is being sponsored by BPA, DOE, and EPRI. The develop- mental work is expected to be completed in two to three years, with the device to be tested in the Pacific Northwest-Pacific Southwest DC transmission line. 65 2. BC Hydro - We suggest you contact BC Hydro directly about its future development plans. 3. Electrolysis - If parallel oil or gas pipelines have proper cath- odic protection, no problems are envisioned. Any remedial meas- ures on existing pipelines would require investigation as part of the project. Our cost estimates do not include costs for these measures. 4. Satellite Communications - It is BPA's understanding that satel- lite communication is not adequate for high speed relaying. It would be all right for other uses. 5. Environmental - The HVDC line will have similar visual and elec- trical problems as AC; however, the electric field effect is some- what different. There should be no adverse environmental effects if care is taken during construction. Enclosed for your refer- ence is a BPA publication, "Electrical and Biological Effects of © Transmission Lines: A Review". The power marketing information you requested is provided in the attached internal memorandum from Edward Sienkiewicz, Power Manager, to Marvin Klinger, Assistant Administrator for Engineering and Constructrion. If we can be of further help, please let me know. Sincerely, (OUcen G redhhe Jor D. E. Perry, Director Division of System Engineering Enclosures in2ville Power Administration . Department of Energy BPA 16 e : DEC 22 1981 UNITED STATES GOVERNMENT ply mY op Memorandum Marv Klinger, Asst. Administrator for Engineering & Construction - E )M pOR raward Sienkiewicz, Asst. Administrator (dali F for Power Management - P wect: North Slope Transmission Study: As suggested by your memo of September 18, Power Management staff attended the September 23 meeting with Alaska Power Administration personnel concerning an updating of the 1972 North Slope Transmission Study. In response to the questions on marketability in Don Shira's memo of September 11, the following is submitted for consolidation with your material and transmittal to APA. Q. What would be the market for this size of a resource in your area by the year 2000? A. The load-resource forecast for the Pacific Northwest currently is affected by some uncertainties which in turn would place qualifications on the need for a resource such as North Slope generation. The regional forecast of the rate of load growth has been declining now for 8 years.s The Northwest Regional Forecast of June 1981 projected an annual growth rate of 3.2%. More recent analyses based on a regional econometric model indicate the rate may be closer to 2%. In the face of the declining forecasts and the recently enacted Regional Act which assigns priority to conservation, renewable resources, and cogeneration over all other resources, the need for additional generating resources is subject to considerable public discussion and controversy. As a result of such scrutiny and some financial difficulties, the construction of two large thermal baseload plants has been postponed; and the plants are being mothballed, with completion deferred indefinitely. The sunk costs in such regional resources would tend to place North Slope generation at an even greater economic disadvantage than does the very distant transmission. Additional competition lies in the substantial investment by Pacific Northwest utilities in Montana and Wyoming coal deposits. In spite of uncertainties in the forecast and the declining load projections, there appears to be sufficient incremental Pacific Northwest energy demand between now and the year 2000, even with the lower growth rates, to require an additional 8,000-MW resource either to cover the load growth or to replace an equivalent resource if economically warranted. Q. What price of energy would be marketable in the Pacific Northwest by the year 2000 (in terms of 1981 dollars)? A. Our response to this question is in terms of generation cost, assuming that energy will be priced accordingly. We interpret the question to seek the price of energy in today's dollars, i-e., not inflated to 2000. While INEVILLE POWER ADMINISTRATION, PORTLAND, OREGON BPA 1100 REV MAR 1 67 Pacific Northwest coal-fired and nuclear generation in the 1970's were closely grouped in cost from 15-19 mills/kWh, the Boardman coal plant installed in 1980 cost 40 mills/kWh. Projected costs of coal-fired resources during the 1980's, deflated to the 1980 price level, range from 43-81 mills/kWh. One possible addition to the report would be a discussion of potential benefits from storage interchange between systems should the State of Alaska, or any other developer, proceed with a program to develop hydro. CECancilla:bja (WP-PR-0145R) ce: S. Montfort - PRT R. Lamb — PRC N. Freeman - PRI J. Hornor - P Official File - PR RARY COPY PROPERTY OF: Alaska Power Authority 334 W. 5th Ave. Anchorage, Alaska 99501