Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
Report on the Fuel Supply Alternatives for Chugach Electric Association 1983
Report on the Fuel Supply Alternatives for Chugach Electric Association, Inc. Anchorage, Alaska Alaska 8 Chugach ach Cie ASSOCIATION, INC. 1983 82-182-4-004 Tea Sd ENGINEERS - ARCHITECTS - CONSULTANTS: MAL 607 Report on the Fuel Supply Alternatives Chugach Electric Association, Inc. Anchorage, Alaska Alaska 8 Chugach 1983 82-182-4-004 Burns & MSDonnell ENGINEERS - ARCHITECTS - CONSULTANTS Burns 2 M*Donneil ENGINEERS - ARCHITECTS - CONSULTANTS October 20, 1983 Board of Directors Chugach Electric Association, Inc. P.O. Box 3518 Anchorage, Alaska 99501 Chugach Electric Association, Inc. Fuel Supply Alternatives Final Report - Review Copy Project 82-182-4-004 Dear Members of the Board: In accordance with your authorization of January 19, 1983, we have performed a series of coordinated long-range generation and transmission planning stu- dies for Chugach Electric Association, Inc. These included studies on Power Requirements, Power Supply Planning, Power Cost, Transmission System and Fuel Supply Alternatives. This report presents the background, analyses and results of the evaluation of the Fuel Supply Alternatives. The purpose of this report is to investigate and identify the markets, avail- ability, and costs associated with the fuel supply alternatives available to Chugach Electric. The fuel types addressed in this report include natural gas, coal, fuel oil, refuse-derived fuel (RDF), wood, and peat. The economic information contained in this report was used to provide direction on the fuel-related aspects of the Power Supply Planning Study. Based upon the findings of this investigation, we have concluded that natural gas from the Cook Inlet Basin will remain to be Chugach Electric's principle source of fuel for the next several years. At projected requirements for south-central Alaska, existing Cook Inlet Basin natural gas supplies can meet demand for a few years past the year 2000. Estimates of undiscovered reserves, if discovered, would provide for a few more years’ requirements. Cook Inlet Basin natural gas reserves will, at some time, require supplemen- tation by other sources. North Slope natural gas is a potential supplemental source of natural gas. However, the timing and pricing of North Slope natural gas will be influenced by the world market for energy and by federal regula- tions, both of which are largely beyond Chugach Electric's control. Alternatively, natural gas generation could be supplanted by generation fired by coal or other combustible materials (wood, peat, RDF, etc.). In some cases 4800 EAST 63rd STREET, P.O. BOX 173, KANSAS CITY, MISSOURI 64141 e TEL: 816-333-4375 TWX: 910-771-3059 Board of Directors October 20,. 1983 Chugach Electric Association, Inc. -2- coal has a cost advantage over Cook Inlet natural gas on a delivered-cost/ heat-content basis which may lead to coal being able to compete with Cook Inlet natural gas on a mils per kilowatt-hour basis in the future. Chugach Electric is more restricted by coal-fired power plant planning and construc- tion times than by coal availability. Lead times of approximately seven years for the completion of a coal-fired power plant moves the first possible date for coal-fired generation to at least 1990 if planning was to begin immediately. The other fuel supply alternatives (wood, peat, RDF, etc.) currently offer no definitive economic advantage to Chugach Electric as fuel sources, however, they do warrant periodic review for future applications. Based on these conclusions it is recommended that Chugach Electric actively pursue the acquisition of additional Cook Inlet natural gas reserves from Enstar and the natural gas producers. It is further recommended that Chugach Electric monitor the development status and estimated costs for coal supplies that may become available as well as the proposed North Slope natural gas delivery systems. We wish to express our appreciation for this opportunity to serve Chugach Electric. We would like to acknowledge the excellent cooperation and support received from the Chugach Electric staff in the course of performing this study. We would be happy to discuss this report with you in detail at your convenience. Respectfully submitted, BURNS & McDONNELL Ya, N. A. Campbell, President 0K Matin C. K. Martin, P.E. Vice President Mark R. Griffith Mineral Economist NAC/CK M/MRG/ 311 TABLE OF CONTENTS Page No. SUMMARY OF FINDINGS AND RECOMMENDATIONS INTRODUCTION wcccccccccccccccccccccccccccccccccccccececeeecccces SUMMARY OF FINDINGS .cccccccccccccccccccccccccccccccccceveccccee Natural Gas ccccccccccccccccvccccccccccccccccscccceecccscees COAL coccccccccccccccccccccccccccc cece erscesccceceeeeeeecere Fuel OL1L cecccccccccecevcccccccccscveceveccccccscccccssseees Refuse-Derived Fuel wcccccccccccccccccccccccccccccccccccccce WO0d coccccccccccccccccccccccccccccccccecccccccccccccccccccs Peat cocccccccccccccccccccccccccccccccccecccccccccccccceccce CONCLUSIONS weccececccrccrcccerecnccncccccessesseseessssessecers RECOMMENDATIONS .cccescccccecvcrcccccccrecveccssccscsseesvesvecs ANNNNANNNNMN ' 1 6 ee oe Gh AMF UUW O PART I - INTRODUCTION PURPOSE ...... Occ c cere cc cccc cc cce ccc cc cee cecseceeseeeeeeeeeeeecs ! p= = I SCOPE cccccccccccecccccrcccccccccccccscecececesesevesesessseseees I- I COST cocccecccrccncccerecrccscresssccesssressesessesseesessesses PART II - COOK INLET NATURAL GAS INTRODUCTION .cccccccccce alotote?aiofererele ofc lore tore voleloxalerolaiele cforofolelevelotereroloreyo II-1 NATURAL GAS RESERVES ..ccccccccccccccccccccccccccccccccceccecees II-1 CHUGACH ELECTRIC'S CURRENT NATURAL GAS SUPPLIES .....eceeseeeees II-6 THE ENSTAR CONTRACTS .cccccccccccccccccccccccccccccecceccvcccces II-12 Enstar-Marathon cecccccccccccccccccccccccccscccccccccscccece II-12 Enstar-Shell ..cccccccccccccccccccccccvcccccccccccccceveseee II-17 RESERVE AVAILABILITY .cccccccccccccccccccccccccccccccescesvccces II-20 Review of Remaining Reserves ceeeccecccecccevccccesecccccses II-21 Review of Consumption of Cook Inlet Natural Gas ....eeeeeeee II-29 LONG-TERM PRICE CONSIDERATIONS ..ccccccccccccccccccccsccccsccses II-31 THE FUEL USE ACT EXEMPTION ..ccccccccccccccccccscccccees eisieroreroicre II-34 FEDERAL NATURAL GAS DECONTROL ..ccccccccccvcccccccsccvccvccscece II-36 PART III - NORTH SLOPE NATURAL GAS INTRODUCTION .cccccccccccccccccces seer cece cc ccc ccccccccscesceces III-1 NATURAL GAS RESERVES ..ccccccccccccccccccccccccsece ecccccccccccs III-1 DELIVERY SYSTEM DESCRIPTIONS .....-eeeeee Cece rcccccccccccccccere III-1 The Trans Alaska Gas System (AGS Stewie eee III-3 The Alaska Natural Gas Transportation System (ANGTS) ....... III-5 Gas Pipeline From North Slope to Fairbanks ...sessseeseeeees III-7 ESTIMATED COSTS .cvcccccccvencccccccsccccccccescccccsceccccccves III-8 Cost and Availability of Natural Gas for Tags ...seessceeeeee III-8 Cost and Availability of Natural Gas From ANGTS ...eeeeeeeee [ITI-10 SUMMALY ccccccccccccccceccvcccccscccccvcccsccccccsceccossoes § = IIIT-15 TC-1 PART IV - ALASKAN COAL INTRODUCTION .occccccccccccccccccccccce weve cc cece ne cencceeteene SUMMARY OF FIELDS .ccccccccccccccccccvccccecccccesceesesceescccs Nenana Field ..cccccccccccvcceecs ee eewcev cesses eee bese cesees Susitna Field, Beluga Field .ccrececcecccccsccccccsssssvvees Matanuska Field ceoccccccccccccccvcvcccvcvcccvecsccsevccccece Kenai Field cccccccccccccccccccvccccccccvcccccecccscesevcces Cook Inlet Field (Kenai Offshore Field) ..... eoccee eve: e-elersie 076 Northern Alaska Field .ccccrccccccccccccccccccevccccccvesves Other Alaskan Coal Deposits ceecececccccccccccccccccessscees RESERVES .ccccccccccvcce coc cccccccccccccccccccceces Ceebeuesseces LAND OWNERSHIP ...ccceccccvecces coerce cence ccercccseseecceecceee POTENTIAL COAL DEVELOPMENT ccc c cere cece cece eee en essence receees COAL AVAILABILITY AND COST .cccccccccccccccccccccccvcescveccene . Nenana Coal Field ..ccccecccccesecccccecvcves wcrc eccrccccccee Beluga Coal Field ..ccccceeeee Wilt) 01s are 0 016 bw esis iss 6 b 50's 010666 SUMMATY cocccececvcece ccc cc cccvccccccccccccs eer cvcccccccccs PART V - ALASKAN OIL RESERVES sccccccecvecccevccccccccecsevecccccsceccscccerececcceoes OIL PRICE PROJECTIONS .ccccccccccccccccccccccccesccccecceccccess Review of Projections ....ceceeeee ec ccccvcccccece epretaieleiece sate Fuel Oil Prices wesvcsccceecee cece ccccscccces eee cccccee eeceee PART VI - REFUSE-DERIVED FUEL AVAILABILITY AND USE .eccececccccccsccees See c cere ccc cecccccccecs COST wecccccccee eee ee eee ee ee eee ee ee ee ee PART VII - WOOD INTRODUCTION .cceccccecccccccccevccsccccecsceessesccsecesssveses WOOD FOR DIRECT POWER GENERATION .....eee- see cree creer ceseveees RESIDENTIAL HEATING .cccccccccccccccvcccccccccscccceesccsesccees COGENERATION .cccccccccccccccccccccccccccccccccescesesscessceses PART VIII - PEAT INTRODUCTION .occccccccccccccccccccsccsccccccccesveccesscessvees RESOURCES ceccccccccccccccccccveccscccece eee ecccccccces eacceee ee VIABILITY OF PEAT UTILIZATION ..ccececccecececcccccccccscsescces COST ESTIMATES .ecceccccccccccccccccecccscceccecsscscceees eseeee BIBLIOGRAPHY APPENDIX A - NOTATIONS TC-2 Table No. S-1 $-2 II-3 II-4 II-5 II-6 II-7 II-8 II-9 II-10 II-11 II-12 II-13 LIST OF TABLES Summary of Cook Inlet Basin Gas Price Assumptions ...... Summary of North Slope Gas Price Assumptions ...+....+..- Coal Price Assumptions ceececeeseccccccccccrcesscceces oe Summary of Oil Price Escalation ccecceseccscceccsccccees Summary of Fuel Oil Prices ceecesccccecccrcccccvcseevece Estimate of Natural Gas Reserves in Alaska ...sseeseonee Preliminary Estimate of Economically Recoverable Undiscovered Natural Gas Resources in the Cook Inlet Basin cccccccccccccccrcccvvcscccccsesccsccccseces Summary of Chugach Electric's Current Fuel Sources ..... Price of Natural Gas Under Existing Beluga Field Supply Contracts cccccccccerccccccccccscccesccsvcsesees Estimated Price of Enstar Natural Gas to Chugach Electric cecceccccececccccccevecsccccccsscscees Natural Gas Delivery Commitment: Enstar-Marathon Contract cecccccccccccvccececcssssssseseceseseveseseees Natural Gas Price Adjustments Due to Quantity Reductions: Enstar-Marathon Contract ceccccccccccccccccccvecccseees Natural Gas Delivery Commitment: Enstar-Shell Contract cecccccccccccccccccccscscsevecvesesccsccccscces Possible Effect of Enstar-Shell Contract on Chugach Electric's Existing Beluga River Field Contracts ...... Estimated Cook Inlet Natural Gas Reserve Commitment Status cccccccccccvcccccccccccscscsscesesessscccscccces Corporate Interests in Cook Inlet Basin Fields with Connected Uncommitted Reserves sesrsecsececeeeccccecees Remaining Uncommitted Cook Inlet Basin Natural Gas ReServes cecececccccccccccessvevesccccseves Estimated In-State Consumption of Cook Inlet Natural Gas ..... occcccccccce Vee Ce RESWERD SC EeK wR eeeenese Page No. s-4 8-5 8-8 S-11 s-12 II-2 II-5 II-7 II-9 TI-11 II-13 II-15 II-18 II-21 II-25 II-25 II-27 Table No. Page No. II-14 Summary of Cook Inlet Basin Gas Price Assumptions ...... TI-32 III-1 Trans Alaska Gas System--Estimated Cumulative Cost Summary ceccccccceees eeeees Cece cccererevevreeveeee eoooee III-9 III-2 Prospective Trans Alaska Gas System Tariffs-Products Delivered to South-Central Alaska ........ coccccccceeee III-9 III-3 Summary of Alaska Natural Gas Transportation System Capital Costs secesecceccervccrecccrveecesseveevnee eee III-12 III-4 Cost Components of Alaska Natural Gas Transportation GAS cocvcccercccccvccccrcccccccscccccccosesescccescesss III=12 TII-5 Estimated Price Performance for Alaska Natural Gas Transportation System Gas at Fairbanks ......seeeeeeee- ITI-14 TII-6 Summary of North Slope Gas Price AnalysiS ...sssseeeeee .- ITII-16 Iv-1 Alaska's Coal Resources ....ee.- Fae] alalisiere sells s[els-e aia'sewsiele] |] LV =o IV-2 State of Alaska Coal Leases ...seeeeeeseeeee secccccceses IV=10 IV-3 State of Alaska Conversion to Lease Applications ....... IV-1 Iv-4 Coal Analysis - Nenana Field - Usibelli Coal Mine, Inc. cecccccccccccccvccccevccccvecvccesvccccesees IV-17 IV-5 Usibelli Coal Mine, Inc., Coal Price Data .......... eoee IV-17 IV-6 Coal Freight Rates in Alaska ccccensecncscscces conswenen || LVI 9 IV-7 Coal Analysis - Beluga Field - Diamond Chuitna PLOJECE cocccccccccccccccsccscscvccccccccccccccccsscces LV=22 IV-8 Coal Analysis - Beluga Field - Placer-Amex Leases ....-. IV=-24 IV-9 Beluga Field Coal Price Data ...ceseccscccceccvecsecvees IV-26 IvV-10 Coal Analysis - Beluga Field - Mobil Oil Leases ........ IV-27 IV-11 Summary of U.S.G.S. Analyses of Alaskan Coal - Healy Quadrangle ..cccccccccccccccsccccccccscscccccsees IV=28 Iv-12 Summary of U.S.G.S. Analyses of Alaskan Coal - Kenai Quadrangle ...cecceevccvceeeee eee serccccs eee iorsts IV-29 IV-13 Summary of U.S.G.S. Analyses of Alaskan Coal - Seldovia Quadrangle ..scccceeccccscescccccsece eocccceee ILV-30 TC-4 Table No. Page No. IV-14 Summary of U.S.G.S. Analyses of Alaskan Coal - Utukok River Quadrangle ....... ec ccrcccrevcccvesecccses LV=50 IV-15 Coal Price ASSUMptiONS .eseereecereccccrcececeeseseesees LV=52 v-1 Estimated Alaskan Oil Reserves ceccccccccesecccecccseces Va2 V-2 Annual Alaskan Oil Production wecccccececcccccccvccccece v-4 vV-3 Alternative Crude Oil Price Paths weccccccecccccccrseeee V9 v-4 Summary of Fuel Oil Prices ceccccecccccccccccccccvcceees V=16 VIII-1 Summary of Alaska Peat Commercial Feasibility .......... VIII-3 VIII-2 Price of Peat Based Fuels cevecccccccscccccsccccscccvece VIII-7 VIII-3 Power Generation Costs from Peat cesecccsccecececeeceeee VIII-7 TC-5 Figure No S-1 IT-1 II-2 III-1 Iv-1 IV-2 VIII-1 LIST OF FIGURES Estimated Projected Fuel Prices weccvescccecccrccccceces Cook Inlet Natural Gas and Oil Fields .eccecceeeeseveeee Summary of Cook Inlet Natural Gas Reserves ....eeeeeeeeee Pipeline Delivery Systems eccccccescvescccccccccvccvccce Major Alaskan Coal Fields .ecccccccecccccccccecccesccces Beluga Coal Field Coal Lease Areas .ecceccccccsevcece eee Potential Alaskan Fuel Peat Occurrences * ee ke TC-6 a) Page No. S-2 II-3 II-28 TII-2 IV-3 IV-13 VIII-2 Summary of Findings and Recommendations SUMMARY OF FINDINGS AND RECOMMENDATIONS INTRODUCTION Alaska possesses large quantities of all major fossil-fuel energy resources. Many of these energy resources are located at considerable distances from their point of use, making them wumeconomical for development or requiring large capital investments +o move the product to market (e.g., North Slope oil and gas). Many resources are unexplored and will remain that way until world energy prices and demand can support the costs and risks associated with the development of these resources. Chugach Electric is most concerned with those energy resources that are available to the south-central region of Alaska. This region has experienced considerable exploration and development of its energy resources and stands to benefit from plans for the future development of North Slope natural gas. Fuel supply alternatives considered in this report are natural gas, coal, oil, refuse-derived fuel (RDF), wood and peat. The last two of these fuels exhibit little potential as power generation fuels for sometime to come. However, Chugach Electric will have to remain aware of these fuels as they could become the fuel for small-scale power generation facilities (through either direct combustion or biomass gasification) that may request to sell electricity to Chugach Electric under Public Utility Regulatory Policy Act regulations. The findings regarding the price and availability of each fuel are summarized below. The estimated future prices for natural gas, fuel oil and coal are presented in graph form on Figure S-1. 2 a = = bo 4 & w ° ira Qa 1982 1984 1986 1988 1990 1992 1994 1996 YEAR _- NO. 2 FUEL OIL __ TAGS PHASE | ANGTS NW PIPELINE <—_____ TAGS PHASE I -o8— ENSTAR . ——+______- ANGTSS SECREST & SWIFT NEW BELUGA RIVER = NENANA COAL eooe’*Se ss BELUGA COAL EXISTING BELUGA RIVER 1998 2000 2002 2004 Figure S-1 ESTIMATED PROJECTED FUEL PRICES (CURRENT $ - 1983 - 2002) SUMMARY OF FINDINGS Natural Gas Natural gas occurs in numerous gas fields in the Cook Inlet Basin and currently serves as Chugach Electric's principle source of generation fuel. Generation units located at Beluga will continue to be served primarily by contracts with producers in the Beluga River field. The costs associated with this field are summarized in Table S-1. The existing contracts are currently priced at 40.206 per Mcf plus approximately $0.03 Alaska production tax and are estimated to increase at 3.2 percent per year. Using, as an indicator, the contract recently signed between Enstar and Shell, new contract prices will be approximately $2.32 per Mcf plus an estimated Alaska production of $0.11 per Mcf and is estimated to increase at 7.3 percent per year. The current price of Enstar natural gas is $1.60 per Mcf, and is estimated to increase at 10.1 percent per year. In the future Chugach Electric may be able to receive natural gas from either of the two proposed projects for transporting North Slope natural gas to market. Estimated projections of North Slope natural gas prices are summarized in Table S-2. The Alaska Natural Gas Transportation System (ANGTS) would be a pipeline for transporting gas from the North Slope to the lower-48 United States. The pipeline would go through the Fairbanks area before proceeding down the Tanana River valley to Canada. Natural gas tapped from the pipeline at Fairbanks could be used to generate electricity at a site near Fairbanks and then be supplied to Chugach Electric's service territory. ANGTS, if completed, would make North Slope gas available to the Fairbanks region in 1990 at a cost of $6.30 to $8.27 per Mcf (1983 dollars), increasing at a rate of 2.1 to 2.5 percent per year through the year 2002. Table S-1 SUMMARY OF COOK INLET BASIN GAS PRICE ASSUMPTIONS ($/Mcf) Existing Beluga New Supplies weer River Contracts! Beluga River? Enstar? 1983 .2362 2.43 1.60 1984 -2403 2.50 1.72 1985 .2403 2.58 1.80 1986 2445 2.80 2.40 1987 2445 3.04 2.68 1988 .30 3.29 2.95 1989 30 3.57 3.35 1990 31 3.87 3.77 1991 31 4.17 4.12 1992 32 4.48 4.41 1993 .32 4.82 5.41 1994 .33 5.17 6.62 1995 33 5.56 7.10 1996 34 5.98 7.48 1997 34 6.43 7.95 1998 _ 6.91 8.28 1999 _ 7.42 8.97 2000 _ 7.99 9.64 2001 _ 8.59 10.52 2002 _ 9.23 11.28 1 Includes $.03/Mcf for Alaska production tax. 2 Includes 4.7 percent for Alaska production tax. 3 For study purposes, it is assumed that the cost of natural gas for new units is equal to the ‘‘Enstar’’ costs after 1992. s4 Year 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2001 2001 2002 SUMMARY OF Table S-2 NORTH SLOPE GAS PRICE ASSUMPTIONS (Current $ Per MMBtu) Alaska Natural Gas Transportation System? Secrest and Swift 10.02 9.82 9.64 9.52 9.42 9.38 9.37 9.39 9.46 9.55 9.69 9.86 10.07 (at Fairbanks) Northwest Pipeline 1 price details are shown on Table III-5. 7 Prices shown are averages of the ranges shown in Table III-2. 13.14 12.79 12.56 12.33 12.13 11.99 11.92 11.87 11.88 11.93 12.04 12.19 12.37 $5 Trans Alaska Gas System? Phase | 7.84 8.32 8.82 9.35 9.91 10.51 11.14 11.80 12.51 13.26 14.06 14.90 15.80 (at Nikishka) Phase III 6.51 6.90 7.31 7.75 8.22 8.71 9.23 9.79 10.37 11.00 11.66 12.35 The other proposed North Slope natural gas project is the Trans Alaska Gas System (TAGS). In this system natural gas would be transported by pipeline from the North Slope to a tidewater port facility in south-central Alaska. The gas would be liquified and loaded onto liquified natural gas (LNG) tankers for export. The system is scheduled for completion in phases from 1990 to 1994. Some of the gas may be available for in-state use. The liquefaction process may produce, as a byproduct, a low-Btu “waste gas" which could also be used for power generation. The quantity and quality of the waste gas that may be available will be dependent upon the design of the liquefaction process plant. Due to the uncertanties surrounding the waste gas, no price information has been developed for it. TAGS, if completed, would make North Slope gas available at a tidewater location on Cook Inlet at a price of $4.67 to $7.91 per Mcf (1983 dollars). The Powerplant and Industrial Fuel Use Act of 1978 (Fuel Use Act) was developed by Congress to conserve domestic oil and natural gas resources through encouragement of fuel substitution and by restricting the construction of new oil and gas-fired power plants. Permanent exemptions are available under Section 2.2 of the Act; however, the filing of the required exemption petitions can be a time-consuming and expensive procedure. A special Alaska Exemption to allow the construction of natural-gas-fired power plants has been recently signed into law as part of the 1983 Department of the Interior Appropriations Bill (H.R. 7356). As a result of the Alaska Exemption, any Alaskan utility can receive permanent exemptions to allow the construction of natural-gas-fired power plants, and the S-6 use of natural gas as a fuel in these power plants. There are two major restrictions contained in the Alaska Exemption: o The exemption petition must be accepted by the Economic Regulatory Agency by December 31, 1985. o Natural gas for new power plants receiving a permanent exemption under the Alaska Exemption cannot come from the Prudhoe Bay Unit. Coal The two coal fields which to date have received the most commercial interest are the Nenana field near Healy and the Beluga field on the west side of Cook Inlet. Coal price information is summarized on Table S-3. The only active coal mining operation in the state of Alaska is the mine operated by Usibelli Coal Mine, Inc., in the Nenana field. Due to a recently announced export contract commitment, this company has removed itself from consideration as a potential fuel supplier until after 1985. In 1986-87, approximately 1 million tons of coal per year may be available at $19.80 to $22.25 per ton. The cost of transporting the coal by rail is approximated by the equation: Freight Rate ($/ton) = (2.49 Ln distance (miles)) - 4.68 In the Beluga field there are two major commercial ventures under consideration. The Diamond Chuitna Project, a joint-venture between Diamond Shamrock and Chuitna Coal Company is planned to be developed for 5 to 15 million tons per year of export coal. Diamond Chuitna is also willing to consider production S-7 Table S-3 COAL PRICE ASSUMPTIONS (1983$) Price F.0.B. Mine Freight? Coal Source Power Plant Site ($/ton) ($/ton) Nenana North Site 21.03 5.06 Nenana South Site 21.03 8.51 Beluga Mine-Mouth 20.93 NA® 1 Based on discussions with producers in the coal field areas. 2 Estimated by Burns and McDonnell. 3 Escalation is the average compound rate of increase. The escalation factors were: Coal (f.0.b. Mine) Rail Freight 1983-85 7.6% 8.1% 1985-90 8.1% 8.6% 1990-2002 7.1% 7.6% 4 estimated heat content is 7850 Btu per pound. 5 Estimated heat content is 7750 Btu per pound. 7 NA — Not Applicable. S-8 ($/ton) 26.09 29.54 20.93 Delivered ($/MMBtu) 1.664 1.884 1.35° Average Escalation? (1983-2002) 7.5% 7.5% 7.4% levels of one, two or three million tons per year to supply a mine-mouth power plant. This could be developed either in conjunction with, or independent of, the large export coal operation. Based on preliminary discussions with the two commercial ventures, the Diamond Chuitna Project has a lower estimated price and should be used for further planning. This coal is available for $18.60 to $23.25 per ton (1983 dollars) at a heat content of 7,750 Btus per pound. Cost escalation for coal at the mine is estimated to be 0 to 2 percent per year in real terms, with 1 percent used as a base case for the values in Table S-3. Rail transportation costs are estimated to escalate at 1.5 percent per year in real terms. Table S-3 illustrates that when underlying inflation is included, the coal prices are estimated to increase at annual rates of 7.4 to 7.5 percent. The other potential commercial operation in the Beluga field is a joint-venture between Placer Amex, Inc.,and the Cook Inlet Regional Corporation. This would be a 5-million-ton-per-year operation exporting either coal or liquid synthetic fuels derived from coal. These Beluga field ventures are driven by the potential for exporting coal (or coal products) to the Pacific Rim countries such as Japan, Korea, and the U.S. Pacific Northwest. Supplies of coal for a mine-mouth power plant could be a natural extension of either project as the Beluga field is reasonably close to the existing Beluga power plant, thereby simplifying many considerations, such as transmission line routing and infrastructure development. Development of strip-mining operations as well as a generating plant located at mine-mouth will require in-depth environmental studies. The Diamond Chuitna s-9 Project sponsors have initiated preliminary environmental investigations; however, these studies have not been completed to the point where any conclusions regarding environmental compliance could be reached. Therefore, for this fuel alternatives evaluation it has been assumed that a strip-mining operation and an associated mine-mouth power plant can be developed within environmental regulatory requirements. Fuel Oil Refined petroleum products are produced in the Cook Inlet area and are available to Chugach Electric primarily as a standby or peaking fuel. Since oil will probably continue to be available to Chugach Electric only at a price considerably higher than that for natural gas, it probably will never be utilized as a baseload fuel. An oil price analysis has been included in this report as oil will continue to play a major role as a standby fuel. Perhaps more importantly, the price of oil will have a substantial impact on the general level of economic activity in Alaska, thereby affecting Chugach Electric's future electrical energy demand. Also, oil prices are used as an index for price adjustment in natural gas supply contracts recently secured by Enstar. Numerous oil price escalation possibilities are presented in Table V-3 of this report. Low-, medium-, and high-escalation cases for crude oil were abstracted and are presented in Table S-4. For the purposes of evaluating price adjustments for new Cook Inlet Basin natural gas contracts, the estimated base case escalation for crude oil was assumed to match the anticipated escalation for distillate (No. 2) fuel oil. Distillate and residual (No. 6) fuel oil price information is presented in Table S-5. S-10 Table S-4 SUMMARY OF OIL PRICE ESCALATION Scenarios Time Period Low Medium High 1982—1985 -15.9% -3.4% -3.0% 1985—2000 -2.1 +1.4% +3.7% 1982—2000 -4.1% +0.6% +2.6% S-11 Table S-5 SUMMARY OF FUEL OIL PRICES No. 2 Fuel Oil! No. 6 Fuel Oil? Year Cents/Gallon $/MMBtu $/Barrel $/MMBtu 1983 87.49 6.30 27.004 4.35 1984 89.9 6.48 30.19 4.87 1985 92.5 6.67 33.76 5.45 1986 100.4 7.24 36.92 5.95 1987 108.9 7.85 40.37 6.51 1988 118.1 8.52 44.15 7.12 1989 128.2 9.24 48.28 7.79 1990 139.1 10.03 52.79 8.51 1991 149.5 10.78 56.68 9.14 1992 160.7 11.59 60.87 9.82 1993 172.7 12.45 65.36 10.54 1994 185.7 13.39 70.18 11.32 1995 199.5 14.38 75.36 12.15 1996 214.5 15.47 80.92 13.05 1997 230.5 16.62 86.89 14.01 1998 247.8 17.87 93.30 15.05 1999 266.3 19.20 100.18 16.16 2000 286.3 20.64 107.58 17.35 2001 307.7 22.19 115.51 18.63 2002 330.7 23.84 124.03 20.00 4 Price projection based on estimates for crude oil prices from DCED, 1983, p. D-3. ? Price projection based on estimates from DCED, 1983, p. F-2, for refined petroleum products. ‘ Average price No. 2 fuel oil at Tesoro’s and Chevron’s Anchorage terminals as of June, 1983. 4 Representative price for large volume annual contract sales, as provided by Tesoro. S-12 Refuse-Derived Fuel The utilization of fuel derived from municipal solid waste or refuse-derived fuel (RDF) as a power plant boiler fuel is commercially feasible only in areas where relatively large quantities of refuse are generated. Anchorage is the only municipality within Chugach Electric's service territory which generates sufficient volumes of municipal waste to fuel a power plant boiler. Based on Anchorage's 1982 refuse levels, it may be possible to fuel approximately 10 MW of generation capacity with Anchorage's municipal solid waste. Tf))|@))|\'solid= waste-burning power plant were to be developed in Anchorage, it is reasonable to assume that this project would be initiated by the municipality of Anchorage. In fact, the Anchorage Department of Solid Waste Services has contracted for engineering studies to assess the feasibility of developing such a plant, the preliminary results of which are expected to be available in mid-1983. Ifa plant is developed, Chugach Electric might be requested to purchase energy from, or to participate in, the plant since Chugach Electric serves much of the suburban Anchorage electrical requirements. Wood Although Alaska has a substantial timber resouce, past studies have shown that harvesting wood for power generation is commercially feasible only in comparison to the alternative of power generation with diesel fuel in isolated areas. In several instances, however, wood waste from Alaskan mill operations is utilized as a power generation fuel. Wood in this form has some future potential in providing Chugach Electric with power generated by wood manufacturing operations or to at least offset some of these operations’ electrical requirements that would otherwise be fulfilled by Chugach Electric. S-13 Quantity and quality estimates have been developed for the current Alaska Resources Corporation (ARC) power production project at Haines. Based on the percent residue of hog fuel (sawmill waste) available, total logging costs, and hog fuel conversion costs, the use of hog fuel at Haines costs approximately $1.53/MMBtu in January 1983 dollars. This cost figure indicates that cogeneration of electricity fron hog fuel can be economic at wood mills; however, all operating mills are outside Chugach Electric's service territory. Peat Alaska has tremendous resources of peat, which can be thought of as low-grade, young coal. Deposits are located throughout the state, including the Cook Inlet area. Due to the relatively high cost of peat collection and preparation in comparison to other more readily available fuels, current peat research interest has been limited to its potential uses for space heating fuel or the development of a peat-derived fuel for export. Feasibility studies of the commercial prospects for peat utilization for energy production indicate that peat is not cost-competitive with coal and it may be assumed that peat resources will not be developed before coal. Based on a 1980 study (Ekono, 1980), cost estimates for various peat harvesting-processing operations range between approximately $1.90 to $5.10/MMBtu expressed in 1983 dollars. S-14 CONCLUSIONS Based upon the findings of this investigation, as summarized above, the following fuel supply-related conclusions have been reached: 3. For the next several years, Cook Inlet Basin natural gas will remain to be Chugach Electric's principal source of generation fuel. Distillate (No. 2) fuel oil is the only other generation fuel source available to Chugach Electric for the next several years. Due to its premium price (when compared to Cook Inlet Basin natural gas), its use will be limited to standby and peaking uses. Alaskan coal supplies begin to play a role as potential fuel sources only after 1985. The current Nenana field producer has committed virtually all of its production capacity, and has expressed no interest in considering an expansion of its production capacity until after 1985. The lower-cost prospective Beluga field producer has stated that it could be producing coal for a mine-mouth power plant three years after a definite commitment. However, Chugach Electric is more restricted by power plant construction times than by coal availability. Lead times of 6 to 7 years for the completion of a coal-fired power plant are not unusual. This moves the first possible date for coal-fired generation back to a 1989-1990 time frame. S-15 4. The Cook Inlet Basin natural gas reserves appear to be adequate for at least the next 20 years. At projected requirements, existing Cook Inlet Basin natural gas supplies can meet demand for a few years past the year 2000. The Division of Geological and Geophysical Surveys’ (DGGS) estimated undiscovered reserves, if discovered, would provide for a few more years' requirements. Cook Inlet Basin natural gas reserves will, at some time, require supplementation by other sources. Likely candidates for providing this supplement are North Slope natural gas or fuel oil. Alternatively, natural gas-fired generation could be supplanted by generation fired by coal or other combustible materials (wood, peat, RDF, etc.) or by noncombustion generation from sources such as hydro or solar power. The timing and selection of the combination of generation fuels which will supplant Cook Inlet Basin natural gas will be dictated by economics and regulatory actions which do not now exist. Coal-fired generation appears to be a likely candidate for supplanting base-load natural gas-fired generation in south-central Alaska. In some cases, coal already possesses a cost advantage over Cook Inlet Basin natural gas on a delivered-cost/heat-content basis. This advantage may, at some time, lead to coal being able to compete with Cook Inlet Basin natural gas on a mills-per-kilowatt-hour basis. S-16 7. North Slope natural gas appears to be a likely candidate for supplanting Cook Inlet Basin natural gas in the future. As Cook Inlet Basin natural gas reserves dwindle, it is likely that North Slope natural gas will become part of south-central Alaska's natural gas supply. The timing and pricing of North Slope natural gas will be influenced by the world market for energy and by federal regulations, both of which are largely beyond Chugach Electric's control. 8. RDF-fired generation may become available to Chugach Electric in the 1980s. This will be dependent upon actions taken by the Municipality of Anchorage. 9. The other fuel supply alternatives evaluated in this report--peat and wood--currently offer no definitive economic advantage to Chugach Electric as fuel sources. These potential sources warrant periodic review for future applications. In particular, cogeneration of electricity from wood waste at wood mills that may be operated in Chugach Electric's service territory may occur. RECOMMENDATIONS Based upon the findings of this investigation and the conclusions reached, Burns & McDonnell recommends that Chugach Electric: 1. Activity pursue the acquisition of additional Cook Inlet Basin natural gas reserves from the Beluga River field. S-17 Investigate the potential for working with Instar and with natural gas producing companies to acquire additional dedicated natural gas reserves in other Cook Inlet Basin natural gas fields. Periodically monitor the development status and estimated costs for coal supplies that may become available from the Nenana, Beluga, or other coal fields. Periodically monitor the development status and cost associated with the proposed North Slope natural gas delivery systems. * eee 8-18 Part | - Introduction PART I INTRODUCTION PURPOSE In December 1982, Burns & McDonnell was retained by Chugach Electric Association, Inc. (Chugach Electric), to perform a series of studies on its power requirements, power supply planning, transmission system and fuel supply alternatives. This document is Burns & McDonnell's report on its evaluation of Chugach Electric's fuel supply alternatives. The purpose of this report is to: o Investigate the current markets for alternative fuel supply sources for Chugach Electric; o Determine availability and reliability of existing fuel supply sources; and o Determine the costs associated with each fuel supply source. SCOPE This report includes cost and availability information on the following fuels: o Natural gas; o Coal; o Fuel oil; o Refuse-derived fuel; o Wood; and o Peat. I-1 In addition to cost and availability information, this report includes discussions on the major projects proposed to bring many of the fuel supply alternatives to the market place. COST DATA Cost estimates and cost projections in this report are expressed in both current and constant dollars. Current dollar cost projections incorporate the assumed underlying general rate of inflation. Constant dollar cost projections do not include the assumed underlying general rate of inflation. The assumed underlying general inflation rate for this study, as well as Burns & McDonnell's studies for Chugach Electric on power requirements, power supply planning, and transmission planning, is 6.5 percent for the 1982-1985 period, 7.0 percent for the 1985-1990 period, and 6.0 percent thereafter. These values are from the Alaska 1983 Long Term Energy Plan, Working Draft (DCED, 1983). ene eee I-2 Part Il - Cook Inlet Natural Gas PART II COOK INLET NATURAL GAS INTRODUCTION Virtually all of Chugach Electric's nonhydroelectric power is generated by the combustion of natural gas, and all of this natural gas is produced from natural gas fields located in the Cook Inlet Basin. Part II of this report identifies Chugach Electric's current sources of natural gas; other supplies of natural gas; current consumption; and the availability of uncommitted Cook Inlet Basin reserves. NATURAL GAS RESERVES Alaskan gas reserves as of January 1, 1982 amounted to a total of over 32.6 trillion cubic feet (see Table II-1). The Prudhoe Bay field alone accounts for over 88 percent of the total Alaskan gas reserve. It is the Prudhoe Bay field which is usually referred to as "North Slope Natural Gas" in the evaluation of alternative means for developing and transporting this large gas reserve, although there are other fields in the North Slope Province. The major projects under consideration for the transportation of North Slope natural gas, and its potential impact upon Chugach Electric's fuel supply alternatives, are discussed in Part III. The remainder of Alaska's natural gas reserves occurs in numerous fields in the Cook Inlet Basin (see Figure II-1). Of the nearly 3,600 billion cubic feet (Bef) of natural gas in the Cook Inlet Basin, only 121 Bcf is classified as II-1 Table Il-1 ESTIMATE OF NATURAL GAS RESERVES IN ALASKA (as of January 1, 1982) Field Reserves (Bcf) North Slope Oil and Gas Province Prudhoe Bay 28,778 Kuparuk River 206 East Barrow 12 South Barrow ll Subtotal 29,007 Cook Inlet Basin Oil and Gas Province Beaver Creek 240 Beluga River 742 Birch Hill? 11 Falls Creek! 13 Granite Point 26 Ivan River! 26 Kenai 1,109 Lewis River! 22 McArthur River 90 Middle Ground Shoal 14 Nicolai Creek! 17 North Cook Inlet 951 North Fork? 12 Sterling 23 Swanson River? 259 Trading Bay 13 West Foreland! 20 West Fork 6 Subtotal 3,594 TOTAL GAS RESERVES 32,601 7 Fields not currently in production, i.e. ‘‘shut-in'’. 2 Primarily injected gas used for pressure maintenance. Source: Alaska Oil and Gas Conservation Commission, 1981 Statistical Report, p. 24. W-2 Moquawkig a Alb J OBirch Hill Goa River Redoubt Shoal Queaver Creek Ss west Fork o Oreerine OLDOTNA O Falls Creek Figure II-1 ONorth Fork D COOK INLET NATURAL GAS : AND OIL FIELDS 1-3 "shut-in" (currently unavailable). The remainder is currently available for production and utilization. Part II reviews the distribution system for the Cook Inlet Basin natural gas, and the quantity of this gas not yet committed for sale through long-term contractual agreements. Natural gas "reserves" are estimated from the results of exploration and development drilling of gas fields in regions of current commercial interest. In the description of the resource base of any mineral commodity, it is generally assumed that there are proven "reserves" that have been developed in the areas that are easiest to access and are relatively close to markets, and more broadly defined "resources" that may be discovered during future exploration. Resources are estimated by identifying geological conditions favorable for the occurrence of undiscovered natural gas reserves. Natural gas resources are estimated to be 40,000 to 200,000 Bef in the Arctic Slope Region (which includes Prudhoe Bay), and 7,000 to 50,000 Bef in the South Central Region of Alaska (which includes Cook Inlet Basin). For the entire state, natural gas resources are estimated to be between 174,000 and 560,000 Bcf (Booz-Allen & Hamilton, 1982, p. II-7 ff). The wide range of the estimates is a reflection of the uncertainty inherent in estimates based solely on the geologic favorability for the occurrence of natural gas in a region. The Division of Geological and Geophysical Surveys (DGGS) of the Alaska Department of Natural Resources has recently released a preliminary estimate of the undiscovered economically recoverable natural gas resources of the Cook Inlet Basin. Their findings are summarized in Table II-2. In their report to the Alaska Power Authority, DGGS states that the expected (or average) amount of II-4 / Table II-2 PRELIMINARY ESTIMATE OF ECONOMICALLY RECOVERABLE UNDISCOVERED NATURAL GAS RESOURCES IN THE COOK INLET BASIN Probability That Actual Quantity Gas Resource (BCF) Is at Least The Given * Economically Value (%) In Place Recoverable 99 470 000 95 930 220 90 1,240 430 75 1,980 930 50 3,070 1,760 25 4,380 2,780 10 5,840 4,040 5 6,930 4,900 z 9,060 6,830 Average 3,360 2,040 Source: DNR (DGGS), 1983, Attachments B and C. US economically recoverable undiscovered natural gas in the Cook Inlet Basin to be 2,000 Bcf. This would be a substantial addition to the 3,600 Bcf of proven reserves. However, the DGGS data also shows that there is a chance that considerably less natural gas would be discovered. CHUGACH ELECTRIC'S CURRENT NATURAL GAS SUPPLIES Chugach Electric's principal source of natural gas is a series of three contracts with Atlantic Richfield Company (ARCO), Shell Oil Company, and Standard Oil Company of California (Chevron) to supply natural gas from the Beluga River field to the Beluga generating station. The natural gas supplies for Bernice Lake, International and Knik Arm are obtained from Enstar Natural Gas Company (Enstar), formerly the Alaska Gas and Service Company. The Mstar natural gas is supplied under a tariff filed with the Alaska Public Service Commission (APUC). A summary of Chugach Electric's current fuel sources is found in Table II-3. Chugach Electric's natural gas supplies can be categorized as either "contract" (Beluga station) or "tariff" (Bernice Lake, International and Knik Arm stations). There are a number of differences between these two types of supplies. Contract natural gas is purchased under the authority of a supply agreement between the producer and the consumer. In the contract, the minimum and maximum flows of gas are established, and a quantity of gas is committed for the exclusive use of the consumer. The contract also sets the price of the gas, and the means by which the price will be adjusted. II-6 Table II-3 SUMMARY OF CHUGACH ELECTRIC’s CURRENT FUEL SOURCES Fuel Sources = Capability (mw)? Primary Stand-by Beluga 356.9 Natural Gas—Contract None Bernice Lake 83.9 Natural Gas—Tariff Fuel Oil Cooper Lake 17.2 Hydro N.A. International 48.2 Natural Gas—Tariff Fuel Oil Knik Arm 14.0 Natural Gas—Tariff None Total 520.2 N.A. — Not Applicable. I Net actual capacity available at 0°C from information received from Chugach Electric. -7 In Chugach Electric's contracts for gas from the Beluga River field, the gas can be delivered, in total, at rates varying from 55,000 to 60,000 thousand cubic feet (Mcf) per day, or 20,075,000 to 21,900,000 Mcf (20.075 to 21.9 Bef) per year. In years prior to 1982, this range of delivery rates had been lower. The total contract commitment is for 373 Bef of natural gas, of which approximately 142 Bef had been consumed by the end of 1982. The contracts establish a base price of $0.162 per Mcf in 1973, subject to a series of price adjustments, summarized on Table II-4. This price is subject to proportional adjustment when the heat content of the natural gas varies from 1,000 Btu per cubic foot. This price would have furthermore been subject to the price for Beluga River field natural gas paid by Pacific Alaska LNG (PALNG). However, PALNG appears to no longer be a project of substance, and the potential effect of its costs on Chugach Electric's prices has not been included in this report. This gas is subject to Alaska's production tax which, for gas, is the greater of 10 percent of the sales price, or $0.064 per Mcf. The effective tax rate is adjusted according to the economic limit factor (ELF). The ELF is designed to reduce the production tax on the gas from a producing property as the production rate decreases towards the point where marginal production costs are just covered by marginal revenues. The production tax for Chugach Electric's existing Beluga River Field contracts should be $0.064 per Mcf, subject to ELF. Current production taxes are about $0.03 per Mcf on the average presumably due to the impact of the ELF. This value could vary over the remaining life of Chugach Electric's contract; however, for the purposes of this study, it was assumed to remain at $0.03 per Mcf, which is about 47 percent of its normal value. If the same ELF applied to the production of new gas from the Beluga II-8 aan Table II-4 PRICE OF NATURAL GAS UNDER EXISTING BELUGA RIVER FIELD SUPPLY CONTRACTS Contract Price? Year ($ Per Mcf) 1973 0.1620 1974 0.1620 1975 0.1620 1976 0.1620 1977 0.1834 1978 0.1864 1979 0.1920 1980 0.1962 1981 0.1962 1982 0.2003 1983 0.2062 1984 0.2103 1985 0.2103 1986 0.2145 1987 0.2145 1988-1989 0.2700 1990-1991 0.2800 1992-1993 0.2900 1994-1995 0.3000 4 These prices would not be effective if the PALNG project were to proceed. The prices are subject to the Alaska Production Tax, estimated to be 3¢ per Mcf in this case. Source: Chugach Electric's existing gas supply contracts with Arco, Chevron and Shell. 1-9 River field, then the effective production tax rate would be 4.7 percent of the price of any gas priced at $.64 per Mcf or higher. When the price of the gas is below $.64 per Mcf, then the $.03 per Mcf tax yields more revenue to the state than the 4.7 percent tax. Tariff natural gas is supplied to Chugach Electric by Enstar, a natural gas pipeline company. Enstar's function is to purchase gas at the well head from the producing companies, transport the gas through its pipeline system, and sell the gas to the eventual consumers. In the past, Enstar has purchased natural gas from producers in the Kenai and West Fork Field, and from the state of Alaska in the North Cook Inlet Field. This latter purchase is “royalty gas," representing Phillips Petroleum's "in-kind" payment of natural gas production royalties to the state of Alaska. Enstar has recently entered into supply agreements with Shell Oil Company for 220 Bcf of natural gas from the Beluga River field and with Marathon Oil Company for 250 Bcf of natural gas from the Kenai, Beaver Creek or Trading Bay fields. The price Chugach Electric pays for Enstar gas will be equal to Enstar's weighted average cost of acquiring natural gas, plus Enstar's costs for pipelines and overhead. Secrest and Swift (1982, p. 2.24) have estimated the volumes of gas Enstar will have to deliver through the year 2000. The price information they have developed is now out of date, as the two latest Enstar natural gas supply agreements were executed after their report was issued. However, their volume requirements can be used to estimate the average cost of Enstar natural gas, as delivered to Chugach Electric. This analysis is shown in Table II-5. These annual costs for Enstar natural gas are accurate only at the II-10 LLll Table 11-5 ESTIMATED PRICE OF ENSTAR GAS TO CHUGACH ELECTRIC (current $) Kenni & West! Marathon Contract? Fork Fields (nutu-Field) Supplemental Gas? Subtotal ‘Shell-Enstar Contract Cost i#/met Cost (#/mett Cost i#/men Cost ($/meft Tout Quantity Cost. © Quantity Wellhead = Deliv. Prod. Quantity Welhesd Prod. Quantity Ave. Quantity Welthesd Prod. Requirements Availability Surplus Price Your feet/y) —(8/met) —tbel/yr)_ Cot Foe Tox Tout —tbef/yr_ Cost Tax Tout —tbet/yr) Cost Transmission? Tots — tbet/yr)_ Cost Tax Transmission Total __ (bef/yi fbct/yr)_—Mbet/y) s/c 1983 26.84 0.68 2.32 0.23 2.55 2.32 23 2.55 34.84 iu 49 1.60 ° 2.32 ou 0 273 34.84 34.84 0.0 1.60 1984 a7 0.72 2.39 0.24 2.63 ° 2.39 24 2.63 36.11 1.20 52 172 ° 2.39 oun 32 2.82 36.11 36.11 00 1.72 1985 28.44 0.77 2.46 0.25 2m o 2.46 25 2m 37.44 1.24 56 1.80 o 2.46 0.12 M4 2.92 37.44 37.44 00 1.80 1988 26.28 0.82 2.67 os 3.38 ° 2.67 27 2.94 40.28 um 60 231 5.0 2.67 0.13 36 3.16 39.00 45.28 6.28 2.40 1987 26.28 0.88 14.0 2.90 0.33 3.67 ° 2.90 29 3.19 40.28 64 2.49 10.0 2.90 0.14 39 3.43 39.59 50.28 10.69 2.68 1988 25.12 0.94 3.14 0.36 3.97 ° 34 3 3.45 40.12 69 2.76 10.0 3.14 0.15 a 3.70 37.43 50.12 12.69 2.95 1989 22.84 1.01 341 st 0.39 431 o 341 M 3.75 38.84 73 3.10 15.0 341 0.16 Mm 4.01 38.60 53.84 15.24 3.35 1990 20.76 1.08 3.70 56 0.43 4.69 o 3.70 37 38.76 79 355 15.0 3.70 0.17 a7 434 39.84 53.76 13.92 3.77 1991 20.76 114 19.0 3.98 60 0468 5.04 o 3.98 40 39.76 84 3.84 20.0 3.98 0.19 50 467 41.45 59.76 18.31 412 1992 20.76 1.21 19.0 4.28 6s 049 5.42 ° 4.28 43 39.76 89 au 20.0 4.28 0.20 53 5.01 43.14 59.76 16.62 4a 1993 11.25 1.29 27.0 4.60 70 053 5.83 o 4.60 46 38.25 94 5.43 20.0 4.60 0.22 56 5.38 44.90 58.25 13.35 5.41 1994 o - 27.0 4.94 13 0.57 6.26 o 494 49 27.00 1.00 7.26 20.0 4.94 0.23 59 5.76 46.74 47.0 0.26 6.62 1995 o - 27.0 5.31 80 6.72 1.66 5.31 53 5.84 28.66 1.06 1.73 20.0 5.31 0.25 63 19 48.66 48.66 00 7.10 1996 o - 16.0 3m 86 723 19.55 5.7 ST 6.28 35.55 67 1.12 7.83 15.0 3.71 0.27 67 50.55 50.55 7.48 1997 ° - 12.0 6.14 93 on 778 25.52 6.14 6 6.75 37.52 708 (1.19 8.27 15.0 6.14 0.29 a 52.52 52.52 795 1998 ° - - - - - 39.58 6.60 66 7.26 7.2600 (1.26 8.52 15.0 6.60 ost 1 54.58 54.38 8.28 1999 ° - ° - - - - 46.72 7.09 n 7.80 780 (1.33 9.13 10.0 7.09 0.33 co) 36.72 36.72 8.97 2000 o - ° - - - - 48.94 7,63 16 8.39 8390 (14 9.80 10.0 7.63 0.96 84 58.94 58.94 9.64 2001 ° = ° = = os eo 61.30 82 9.02 902 1.50 10.52 ° - - - - 61.30% 61.30 00 10.52 2002 ° - o - - - - 63.75 88 9.69 969 = 1.59 11.28 o - - - - 63.75° 63.75 00 11.28 | Prices based on Secrest and Swift, 1982, p. 2.24, escalated to 1983 dollars: subtraction, Shell and Marathon Contract Quantities from Total, subject through 1985. Total committed Kenai gas assumed to be 251.52 bef. based on 312.0 bet remaining commitment on 12/31/80 (Secrest and Swift, 1982, p. A 10) and 1981 and 1982 use of 30.85 bef and 29 63 bef. 5 percent. Quantity found by 4 minimum take of 26.28 bet/yr respectively (Secrest and Swift, 1982, p. 2.24). By 1990, 52.77 bct of reserves remain. The 1990 projected production rate is maintained until the reserves run out in 1993, 2 Gas Purchase Contract, Marathon Oil Company and Alaska Pipeline Company’ December 16, 1982. “Premium deliverability fee’ of $0.35 per mcf has been added starting in 1986, subject to escalation + supplemental delivery fees,” including 10 percent Alaska production tax 4 Gas transmission charge of $0.49 per Mcf derived from Enstar’s APUC filing of April 8. 1983, 5 --Gas Purchase Contract, Shell Oil Company. Seller. and Alaska Pipeline Company, Buyer," December 17. 5 prices based on prices in Enstar Shell and Enstar-Marathon contracts. without “premium 1982. Gas transmission charge of $0.30 per mcf is an estimate from a communication with Robert Mohn, APA. “Premium deliverability fee” of $0 35 per mcf has not been included. 5 secrest and Swift, 1982, project total Enstar requirements only to the year 2000. Projected totals for 2001 ‘and 2002 were calculated by extrapolating (rom the 2000 projection. using the average annual rate of growth projected during 1990-2000 (4.0 percent). Also note that total quantity demanded will be sensitive to price Total quantity in this table has not been adjusted (or differences between Burns & McDonnell’s and Secrest and Swift's calculated prices annual total availability levels shown. In several years, Enstar's natural gas availability, based on contract data, is estimated to exceed the requirements estimated by Secrest and Swift. Secrest and Swift's requirements estimates include Enstar's deliveries to electric utilities for use in gas-fired power plants. In their estimate, electric utility demand accounts for approximately 33 to 39 percent of Enstar's requirements. If the surplus available gas is not needed, the take-or-pay provisions of Enstar's supply contracts will be activated, resulting in prices higher than those shown in Table II-5. The treatment of Cook Inlet Basin long-term natural gas prices is discussed in more detail in the "Long-Term Price Considerations" section of this part. THE ENSTAR CONTRACTS In December, 1982, the Alaska Pipeline Company, a subsidiary of Enstar, entered into separate natural gas purchase agreements with Marathon Oil Company and Shell Oil Company. Of all of the Cook Inlet Basin gas contracts, these are of greatest interest to Chugach Electric because of their potential for impacting Chugach Electric's cost of gas from Enstar, as well as its upcoming negotiations with Chevron and Atlantic Richfield Company (ARCO). These two contracts have committed an aggregate of 470 Bef of Cook Inlet Basin natural gas through the year 2000. Enstar-Marathon The Enstar-Marathon gas purchase contract is for natural gas produced from the Kenai, Beaver Creek and Trading Bay fields. Deliveries are scheduled to commence in 1983. The annual delivery commitments are presented in Table II-6. Marathon has committed itself to a total delivery of 250 Bcf of natural gas, II-12 Year 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 NATURAL GAS DELIVERY COMMITMENT: Table II-6 ENSTAR—MARATHON CONTRACT Annual (Mcf per year) 8,000,000 9,000,000 9,000,000 14,000,000 14,000,000 15,000,000 16,000,000 18,000,000 19,000,000 19,000,000 27,000,000 27,000,000 27,000,000 16,000,000 12,000,000 Total Commitment: 250,000,000 Mcf. Contract Quantity Average Daily Rate (Mcf per day) 21,918 24,657 24,657 38,356 38,356 41,096 43,836 49,315 52,055 52,055 73,973 73,973 73,973 43,836 32,877 Source: ‘‘Gas Purchase Contract, Marathon Oil Company and 1-13 Alaska Pipeline Company, ’’ December 16, 1982, p.10. Swing Rate (Mcf per day) 26,000 32,000 35,000 100,000 110,000 120,000 130,000 133,000 130,000 130,000 125,000 115,000 95,000 60,000 35,000 subject to numerous restrictions in Article V of the gas purchase contract. The “average daily rate” on Table II-6 was calculated by dividing the annual commitment by 365 days per year (defined as "daily contract quantity" on page 25 of the Enstar-Marthon Contract). The "swing rate" is taken from the contract, and refers to the maximum daily take in each year. This contract is primarily a “take-or-pay" contract, although Enstar has the ability to reduce its purchase commitment if competitors capture part of its market, or by allowing a substantial price increase (an indirect “buy out" of its contract). Under paragraph 3 of Article V, Enstar can reduce its annual purchase commitment in direct proportion that Enstar's customers increase their purchases of natural gas from sources other than Instar. This would appear to be an infrequent event, as Enstar is typically the sole provider of natural gas to the customers it serves. Enstar can buy out up to 30 percent of its annual contract commitments by accepting the price adjustments shown in Table II-7. Enstar's decision to reduce its annual contract commitment for a given contract year must be declared by April 1 of the preceeding year. The amount by which the annual requirement is reduced is defined to be the "released quantity." The released quantity is then released for Marathon's use or sale to other parties. Marathon has the right, however, to extend, at its option, the term of the contract and recommit the released quantity to Enstar. The means by which this extension would be effected is not specified. Neither is the price at which it would be sold, although it would be reasonable to assume that it would be the adjusted price calculated in Article XI of the contract. Enstar does not appear to receive any TI-14 Table II-7 NATURAL GAS PRICE ADJUSTMENTS DUE TO QUANTITY REDUCTIONS: ENSTAR—MARATHON CONTRACT Reduction in Annual Quantity Price Increase (percent) __(percent) 0 to 10.0 5.6 over 10.0 to 20.0 12.5 over 20.0 to 30.0 21.4 Source: ‘‘Gas Purchase Contract, Marathon Oil Company and Alaska Pipeline Company,’’ December 16, 1982, p.12. 1-15 credit against the price of the recommitted gas, in spite of having accepted the higher gas price when the gas was released. Enstar also does not appear to have the option to refuse the delivery of the recommitted gas. The pricing provisions are contained in Article XI of the contract. The base price of the natural gas is $2.32 per Mcf. This price is subject to adjustment on every January 1, starting in 1984, according to changes in the posted price of No. 2 fuel oil relative to its posted price on January 1, 1983. The posted price will be that price for No. 2 fuel oil f.o.b. the Tesoro Refinery at Nikiski, Alaska. This price was 96.3 cents per gallon on January 1, 1983. By March 1, 1983, it had fallen to 93.3 cents per gallon. By the end of June, 1983, the posted price stood at 85.3 cents per gallon. As long as Marathon remains committed to delivering the applicable annual contract quantities and maintains a minimum deliverability value referred to as the "swing factor," the adjusted price is subject to a "premium deliverability charge" of $0.35 per Mcf, starting in 1986. The swing factor equals the ratio obtained by dividing Marathon's daily delivery capacity by the daily contract quantity in effect for that year. The minimum swing factors needed to allow Marathon to charge the premium deliverability charge are 2.5 for 1986-1989, 2.25 for 1990, and 2.0 for each year thereafter. The projected price path for the Enstar-Marathon contract is shown on Table II-5. This is based on the "DCED-1983 Energy Plan" oil price projections on Table V-4. The contract (Article X) specifies that the heat content of the gas shall fall between 950 and 1,050 Btu per cubic foot. Should the heat content be outside II-16 this range, Enstar has the right to refuse acceptance of the gas for as long as the heat content is outside the range. Enstar is not guaranteed that the 250 Bcf of natural gas is available for delivery. Should Marathon ever determine that the natural gas available for delivery is less than contract commitment, then the contract commitment is to be reduced without any compensation to Enstar (Article IV). Enstar-Shell The gas purchase contract between Shell Oil Company and Enstar commits 220 Bcf of Beluga River field natural gas to deliveries between 1986 and 2000. The annual contract quantity commitments are presented in Table II-8. The Shell reserves are its share of the approximately 660 Bcf of natural gas that had been committed previously to the PALNG Project. This field is not connected to Enstar's natural gas transmission system, so a natural gas pipeline must be constructed before gas deliveries commence in 1986. Chevron and ARCO each control one-half of the remaining 440 Bef of natural gas that had originally been dedicated to PALNG. Shell has calculated the swing rate by approximately doubling the average daily contract delivery rate. The ratio between the swing rate and the average daily rate is the "swing factor" in the Enstar-Shell contract. This is different than the definition of "swing factor" in the Enstar-Marathon contract. In Article 5.2 of the Enstar-Shell contract, Enstar can request Shell to increase the swing factor. If Shell complies with this request, and the swing II-17 Year 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 NATURAL GAS DELIVERY COMMITMENT: Table Il-8 ENSTAR-SHELL CONTRACT Annual (Mcf Per Year) 5,000,000 10,000,000 10,000,000 15,000,000 15,000,000 20,000,000 20,000,000 20,000,000 20,000,000 20,000,000 15,000,000 15,000,000 15,000,000 10,000,000 10,000,000 Contract Quantity Total Commitment: 220,000,000 Mcf Average Daily Rate (Mcf Per Day) 13,699 27,397 27,397 41,096 41,096 54,795 54,795 54,795 54,795 54,795 41,096 41,096 41,096 27,397 27,397 Source: ‘‘Gas Purchase Contract, Shell Oil Company, Seller, and 11-18 Alaska Pipeline Company, Buyer,'’ December 17, 1982, p.11. Swing Rate (Mcf Per Day) 25,000 50,000 50,000 80,000 80,000 110,000 110,000 110,000 110,000 110,000 80,000 80,000 80,000 50,000 50,000 factor is increased to 2.5 or more, a premium deliverability fee of $.35 per Mcf will be added to the adjusted base price of the fuel. The premium deliverability fee in the Enstar-Shell contract is activated at the option of Enstar, while this fee in the Enstar-Marathon contract is an option reserved for Marathon. The base price of the Enstar-Shell natural gas is $2.32 per Mcf. This is subject to adjustment according to changes in the posted f.o.b. price of No. 2 fuel oil at the Teroso Refinery in Nikiski, Alaska. This price was 96.3 cents per gallon, the same as the January 1, 1983 price used in the Enstar-Marathon contract. Adjustments will occur on every January 1, based on the percentage change between the posted price on the previous November 1, and the posted price on November 1, 1983. The projected price path for the Enstar-Shell contract is shown on Table II-5. This projection is based on the "DCED-1983 Energy Plan" oil price projections on Table V-4. The contract (Article VI) specifies that the heat content of the gas shall fall between 950 and 1,050 Btu per cubic foot. Should the heat content be higher than 1,050 Btu/cubic foot, Enstar has the option to refuse acceptance of the gas. Should the heat content fall below 950 Btu per cubic foot, Enstar may refuse acceptance of the gas or may continue to purchase it at a reduced price. The reduced price is determined by multiplying the current contract price by a factor which has the actual heat content for its numerator and 950 Btu per cubic foot for its denominator. Whenever Enstar refuses natural gas deliveries on a heat-content basis, Shell's total contract commitment is reduced by a similar . quantity. II-19 Like its Marathon counterpart, the Enstar-Shell contract is basically a "take-or-pay" contract, with commitment reductions allowed only in the case of loss of customers to competing natural gas pipelines, or through an indirect buy out in the form of a price increase. The relationship of the price increase with respect to the reduction in Enstar's contractual commitment is essentially the same as that presented in Table II-7. Unlike the Enstar-Marathon contract, the Enstar-Shell contract might have a detrimental effect upon Chugach Electric's existing Beluga River field contracts. Article V of the existing Beluga River field contracts provides for an alternative price adjustment mechanism if Chugach Electric purchases Beluga River field natural gas from a “third party." It is not clear if Enstar would qualify as a "third party," in the context of the existing Beluga River field contracts. This is the same price adjustment mechanism that would have come into effect if the PALNG project were to proceed. Based upon the estimated projected price for the Enstar-Beluga contract, the price for the current Beluga River field contracts would increase substantially. This effect is shown on Table II-9. By 1995, the contract price would be $5.40 per Mcf, as opposed to the $0.30 per Mcf as now provided for. RESERVE AVAILABILITY There are two ways of evaluating the availability of the remaining reserves of natural gas in the Cook Inlet Basin, both of which are discussed below. One way is to review all of the remaining reserves and identify those which are most likely to be available for future consumption by Chugach Electric. Such an analysis will identify target areas for natural gas acquisition. II-20 Table II-9 POSSIBLE EFFECT OF ENSTAR-SHELL CONTRACT ON CHUGACH ELECTRIC’S EXISTING BELUGA RIVER FIELD CONTRACTS Natural Gas Price Existing Contracts (¢/Mcf) If Enstar-Beluga Gas Is Yeor Current —Purchesed _ 1983 -2062 1.21 1984 -2103 1.25 1985 .2103 1.28 1986 -2145 1.36 1987 .2145 1.45 1988 .27 3.38 1989 .27 3.62 1990 28 3.87 1991 .28 4.13 1992 .29 4.42 1993 .29 4.72 1994 30 5.05 1995 .30 5.40 This is based on an Enstar-Shell contract price of $2.62, including $0.30 for delivery, escalated at 2.9% for 1983-85 and 6.9% thereafter, and Chugach purchasing the Beluga River gas from the existing contracts at 60,000 Mcf per day. This does not include the effect of production tax, estimated to be the greater of $.03 per Mcf or 4.7 percent of the price. H-21 The second method of evaluation is to review the anticipated consumption of Cook Inlet Basin natural gas to determine when these reserves would be exhausted. Such an analysis is sensitive to assumptions made on future consumption and ignores additions made to reserves by new discoveries. However, it can be instructive by giving a sense of the size of the remaining known reserves. Review of Remaining Reserves As presented previously, there are approximately 3,600 Bcf of recoverable natural gas reserves in the Cook Inlet Basin, and perhaps 2,000 Bef of undiscovered economically recoverable resources. The DGGS estimate of undiscovered resources, while serving as an indication of potential long-term supplies, is not useful for developing reserve acquisition plans for the near future. The commitment status of the Cook Inlet Basin's known reserves is shown in Table II-10. The uncommitted reserves have been tabulated in terms of retaining or releasing the PALNG commitments. Without PALNG, uncommitted reserves are estimated to be 1,875 Bef. It appears that the PALNG project has only a very low probability of occurring, as it was never able to obtain all the gas reserves it needs, and a significant portion of its previous contract commitments has been resold to Enstar. Of the currently producing Cook Inlet Basin fields, the uncommitted reserves are: CHU4. FSA II-22 Table II-10 ESTIMATED COOK INLET NATURAL GAS RESERVE COMMITMENT STATUS (AS OF JANUARY 1, 1982; Bcf) Uncommitted Pacific Tokyo Reserves Chugach Collier Alaska Gas SOCAL, Recoverable Electric Carbon & LNG Tokyo ARCO With Without Reserves! Enstar? Assoc. AMP&L Chemical Assoc. Electric Rental PALNG PALNG Beaver Creek” 240 118 — - - - - - 122 122 Beluga River 742 220 249 _- - 440 - - -167 273 Birch Hill iH - _ _ - _ _ _ ll ll Falls Creek 13 _ _ _ _ - - _ 13 13 Granite Point 26 - - - _ - _- cd 26 26 Ivan River 26 _ _ _ = 1064 _ ~ -80 26 Kenai? 1,109 4007 - _ 4047 - _ 737 227 227 Lewis River 22 - -_ = i 994 _ _ 0 22 McArthur River 90 - _- - - - _- — 90 90 Middle Ground Shoal 14 - _- - _- - - - 14 14 Nicolai Creek 17 _ ad _ _- - _ - 17 17 North Cook Inlet 951 30° - _- _ - 2316 - 690 690 North Fork 12 _- _- - - _ _- _ 12 12 Sterling 23 - - _- - _ - _- 23 23 Swanson River? 259 _ _ _ - - _ _ 259 259 Trading Bay” 13 13 - _- _- — _ - 0 0 West Foreland 20 _ - _ - _ _- _ 20 20 West Fork 6 6 = = _ = _ _ 0 0 Total 3594 787 249 - 404 645 231 78 1277 1845 1 See Table Ill-1. Reserve data are AOGCC estimates. 2 Enstar's December 16, 1982 contract with Marathon commits 250 Bcf of natural gas from the Beaver Creek, Kenai and Trading Bay fields. In this table, the 250 was assumed to represent a total commitment of the Trading Bay reserves with the remaining commitment coming equally from Beaver Creek and Kenai. 281 Bcf from Union Oil Contract and 119 Bef share of Marathon Contract. Secrest and Swift, 1982, P. 2.4. Royalty. Reported with North Cook Inlet, but much is actually supplied by Kenai Field (op. cit.) Assumes gas taken at maximum allowable rate since Secrest & Swift's 1/1/80 commitment estimate. This assumption seems reasonable, as apparent depletion from 1/1/80 to 1/1/82 was 204 Bcf. N @ AA & 11-23 Field Uncommitted Reserve Beluga River 275 Bef Kenai 227 Bef McArthur River 90 Bef North Cook Inlet 690 Bef Total 1,280 Bef The Beluga River field is leased by ARCO, Chevron and Shell, and is the sole supplier for Chugach Electric's Beluga Station. With PALNG's contractual commitments, the total commitment of the reserve had exceeded the estimates published by the Alaska Oil and Gas Conservation Commission (AOGCC). Assuming the release of PALNG's commitments, Beluga River field reserves as estimated by AOGCC exceed remaining commitments by 273 Bef. It is therefore reasonable to assume that 273 to 440 Bef of natural gas is available at Beluga River field for acquisition by Chugach Electric. The other three producing fields with uncommitted reserves--Kenai, McArthur River, and North Cook Inlet--have contractual arrangements for supplying natural gas to the Phillips/Marathon LNG plant that serves Tokyo Electric and Tokyo Gas, and for supplying natural gas feedstock to the Collier Carbon and Chemical Company's ammonia/urea plant. There are also many corporate ties between the field leaseholders and the major industrial customers (see Table II-11) that would indicate it is unlikely that much of the uncommitted reserves in these three fields would become available to Chugach Electric. Uncommitted reserves in unproducing fields amounts to 565 Bcf. Most of this, 381 Bef, is concentrated in two fields--Beaver Creek and Swanson River. There is a total reserve of 240 Bcf in Beaver Creek, of which an undisclosed portion has been dedicated to Enstar through their December 16, 1982 contract with II-24 Table I-11 CORPORATE INTERESTS IN COOK INLET BASIN FIELDS WITH CONNECTED UNCOMMITTED RESERVES Other Field Operator Participants Customers Kenai Union Oil Marathon Collier Carbon & Chemical ARCO Enstar Chevron Chevron/ARCO McArthur River Union Oil ARCO Collier Carbon & Chemical North Cook Inlet Phillips Petroleum Marathon Tokyo Gas Chevron Tokyo Electric Amoco Enstar (Royalty) CABOT Notes: Collier Carbon & Chemical is a subsidiary of Union Oil. Natural gas from the Kenai Field is being used to satisfy part of the Tokyo Gas and Tokyo Electric contracts. Source: Secrest and Swift, 1982, Appendix A. 11-25 Marathon. Burns &McDonnell has apportioned 118 Bef of the contract's 250-Bcf commitment to the Beaver Creek field, assuming that the commitment would be divided equally between it and the Kenai field, after committing all the reserves of the much smaller Trading Bay field. It would seem unlikely that any of the Beaver Creek reserve would become available to Chugach Electric. The Swanson River field is primarily an oil field, with most of its natural gas reserve consisting of gas from the Kenai field that has been injected for pressure maintenance. This is "rental gas," which, if produced, would probably be utilized in the LNG or ammonia/urea plants (Secrest and Swift, 1982, p. 2.9). It probably is not available for purchase by Chugach Electric. Of the remaining uncommitted natural gas fields, all are small fields not currently connected, but, for the most part located close to existing facilities or pipelines. These fields are summarized in Table II-12. No one field is of major importance, and many represent less natural gas than is currently consumed in a year's operation at the Beluga Station. However, Chugach could consider the reserves of these for acquisition, as two (Ivan River and Lewis River) are relatively close to the Beluga Station, and others could be acquired through physical displacement with other consumers. By this process of elimination, Chugach Electric is left with only those natural gas fields listed on Table II-12. This shows that trere are few major fields where Chugach Electric does not face direct competition with other consumers, who often have corporate ties to the natural gas producers and who are using the gas for export purposes. This information is summarized in Figure II-2. CHU4. FSA : II-26 Table II-12 REMAINING UNCOMMITTED COOK INLET BASIN NATURAL GAS RESERVES Uncommitted Field Reserve (Bcf) Near Beluga Station Beluga River 273 - 440 Ivan River 26 Lewis River 22 Subtotal 321 - 488 Near Other Producing Facilities Birch Hill 11 Granite Point 26 Middle Ground Shoal 14 Nicolai Creek 17 Sterling 23 West Foreland 20 Subtotal 111 Remote From Producing Facilities Falls Creek 13 North Fork 12 Subtotal 25 TOTAL 457 - 624 11-27 PROVEN RESERVES WITH CONTRACT COMMITMENTS (1749 BCF) OTHER CONTRACTS (1500 BCF) ECONOMICALLY RECOVERABLE UNDISCOVERED RESERVES - AVERAGE VALUE (2040 BCF) CHUGACH ELECTRIC CONTRACT (249 BCF) APPARENTLY AVAILABLE FOR OTHER CORPORATE PROCUREMENT INTERESTS (457-624* BCF) (1388 BCF) \ OTHER PROVEN RESERVES (1845 BCF) Figure 1-2 eee iar urisa ar acacbis by chs oss ARR OF Cee Leg a producing companies, but not inciuded in the total reserve estimate. 11-28 Review of Consumption of Cook Inlet Natural Gas The consumption of Cook Inlet natural gas can be divided into the in-state and export sectors. In-state consumption consists of sales to natural gas utilities, sales to electric utilities (Chugach Electric and Anchorage Municipal Light & Power), and sales to military installations. Export consumption is generated by the activities of the Collier Carbon and Chemical Company's ammonia/urea fertilizer plant and the Phillips-Marathon LNG plant. The Collier Carbon plant consumes approximately 50 Bef per year of natural gas and the Phillips-Marathon ING plant consumes about 50 Bef per year (DCED, 1983, p. II-31). These natural gas processing export facilities represent over two- thirds of the current total production of natural gas in the Cook Inlet Region. The Railbelt Region consumed (in-state) 47.1 Bef of natural gas in 1981. In its 1983 Long-Term Energy Plan, the Department of Commerce and Economic Development projected that this figure would _— to 121.5 Bef by 2000 (p. IV-2). This value includes some amount of North Slope gas, under the assumption that one of the pipeline systems is built. That makes this projection unsuitable for use in estimating remaining Cook Inlet natural gas reserves. Secrest & Swift projected that the consumption of Cook Inlet gas would grow to 99.7 Bef per year by 2000 (see Table II-13). Cumulative in-state consumption of Cook Inlet natural gas for 1983-2000 is projected to be over 1,300 Bef. If a consumption level of 100 Bef per year is maintained by the export sector, total cumulative Cook Inlet natural gas consumption would exceed 3,100 Bef between 1983 and 2000. Continuing this trend, the 3,600 Bcf estimated reserve for the Cook Inlet Basin (see Table II-1) would be depleted in 2003. II-29 Year 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 ESTIMATED IN-STATE CONSUMPTION Chugach 25.14 26.43 26.94 27.48 28.22 28.97 29.75 30.54 32.78 33.45 36.20 38.04 39.97 41.57 43.23 44.96 46.76 48.63 Table I-13 OF COOK INLET NATURAL GAS (Bcf Per Year) Others 30.27 31.31 32.40 33.83 34.28 31.98 33.00 34.09 35.41 36.79 38.23 39.73 41.30 43.07 44.94 46.89 48.93 51.06 Source: Secrest & Swift, 1982, p. 2.24, 2.26. 11-30 Annual 55.41 57.74 59.34 61.31 62.50 60.95 62.75 64.63 68.19 70.24 74.43 77.77 81.27 84.64 88.17 91.85 95.69 99.69 Total Cumulative 55.41 113.15 172.49 233.80 296.30 357.25 420.00 484.63 552.82 623.06 697.49 775.26 856.53 941.17 1,029.34 1,121.19 1,216.88 1,316.57 There are a number of assumptions in the above calculations. Secrest & Swift's economic work was performed at a time when forecasts were more optimistic regarding economic growth and regional energy needs. The export industries may not continue to the year 2000 (or, to the contrary, they may expand). The DCED projection estimated a higher level of consumption in 2000, but they assumed that North Slope gas would be available. The availability of North Slope gas would relieve the potential strain on natural gas reserves in the early 2000s. The DGGS has estimated that another 2,000 Bef of undiscovered economically recoverable reserves may exist. This represents about another 10 years of consumption at 200 Bef per year. It is not typical for a region's natural gas supplies to be suddenly exhausted after several decades of constant production. For the Cook Inlet Basin, it would be reasonable to assume that production mania decrease over time, requiring that other fuel sources be acquired for electrical generation. Likely supplemental fuels would be North Slope natural gas, coal and fuel oil. LONG-TERM PRICE CONSIDERATIONS Burns & McDonnell's assumptions on the long-term performance of Cook Inlet Basin natural gas prices are presented in Table II-14. For study purposes, it is suggested that the cost of natural gas at the existing units at the Beluga power plant is represented by the costs in the "Existing Beluga River Contracts" column of Table II-14 to the extent that this source is available. This source of gas is supplemented and eventually replaced by "New Supplies-Beluga River" natural gas prices shown on Table II-14. These prices were derived by adding II-31 Table II-14 SUMMARY OF COOK INLET BASIN GAS PRICE ASSUMPTIONS ($/Mcf) Existing Beluga New Supplies Year River Contracts! Beluga River? Enstar? 1983 .2362 2.43 1.60 1984 .2403 2.50 1.72 1985 .2403 2.58 1.80 1986 .2445 2.80 2.40 1987 2445 3.04 2.68 1988 .30 3.29 2.95 1989 .30 3.57 3.35 1990 31 3.87 3.77 1991 31 4.17 4.12 1992 32 4.48 4.41 1993 .32 4.82 5.41 1994 33 5.17 6.62 1995 33 5.56 7.10 1996 34 5.98 7.48 1997 34 6.43 7.95 1998 i) 6.91 8.28 1999 —S 7.42 8.97 2000 _ 7.99 9.64 2001 _ 8.59 10.52 2002 _ 9.23 11.28 i Includes $.03/Mcf for Alaska production tax. 2 Includes 4.7 percent for Alaska production tax. s For study purposes, it is assumed that the cost of natural gas for new units is equal to the ‘‘Enstar’’ costs after 1992. 11-32 4.7 percent for production taxes to the prices anticipated to come from the recent Enstar-Shell contract for Beluga River field gas. The cost of natural gas for existing wnits at the Bernice Lake, International and Knik Arm plants is presented in the "Enstar" column of Table II-14. This gas is estimated to exceed the price of new supplies at Beluga in 1993, due primarily to gas transmission costs and a higher production tax assumption. The difference in the price of natural gas for new generating units could lead to a bias in the siting of these units; however, in the long run, the price of natural gas at any particular location is subject to considerable uncertainty. New units at the Beluga power plant would probably use natural gas from the Beluga River field as long as it was both physically and contractually available. To the extent this gas is not available, new Beluga units would probably receive gas from Enstar. New units at other locations would probably purchase gas from Enstar, although it may be possible to contract directly with producers in other fields. Given the uncertainties on long-term gas prices and availability, the cost of natural gas to units (referring to Table II-14) can be handled by: o Having existing units at Beluga take the "Existing Beluga River Contracts" prices for as long as the committed reserves last; o Having new combined-cycle units take the "Existing Beluga River Contracts" prices, for as long as the committed reserves last (requiring existing combustion turbine units to take the "New Supplies-Beluga River" prices); II-33 o Having new combustion turbine units at the Beluga power plant utilize the "New Supplies-Beluga River" prices; o Having all units at other locations take the "Enstar" prices. THE FUEL USE ACT EXEMPTION The Powerplant and Industrial Fuel Use Act of 1978 (Fuel Use Act) was developed by Congress to conserve domestic oil and natural gas resources through encouragement of fuel substitution and by restricting the construction of new oil and gas-fired power plants. Permanent exemptions are available under Section 2.2 of the Act; however, the filing of the required exemption petitions can be a time-consuming and expensive procedure. A special Alaska Exemption to allow the construction of natural-gas-fired power plants has been recently signed into law as part of the 1983 Department of the Interior Appropriations Bill (H.R. 7356). As a result of the Alaska Exemption, any Alaskan utility can receive permanent exemptions to allow the construction of natural-gas-fired power plants, and the use of natural gas as a fuel in these power plants. The exemption filing must be made in accordance with Section 212(f) of the Fuel Use Act, "Permanent Exemption for Powerplants Necessary to Maintain Reliability of Service." However, the evidentiary requirements of this exemption are considered automatically fulfilled by virtue of the utility being located in Alaska. II-34 There are two major restrictions contained in the Alaska Exemption: o The exemption petition must be accepted by the Economic Regulatory Agency by December 31, 1985. However, the power plant or unit for which the exemption petition was filed may be scheduled for construction subsequent to December 31, 1985. o Natural gas for new power plants receiving a permanent exemption under the Alaska Exemption cannot come from the Prudhoe Bay Unit. This restriction does not appear to apply to other existing units owned by the petitioning utility, or to units for which exemptions are obtained by other means allowed by the Fuel Use Act. These restrictions are not as severe as they may first appear. For the former restriction, there appears to be no regulatory limit on how far in the future after the December 31, 1985 deadline construction could be scheduled. This would probably be limited by some practical planning horizon determined by Chugach Electric. The latter Alaska Exemption restriction would not prevent the use of North Slope natural gas in existing units. If the North Slope gas supplies ever became interconnected with the Cook Inlet natural gas pipeline system, then it may be possible to direct North Slope gas to pre-1983 units and Cook Inlet gas to post-1982 units that have received the Alaska Exemption. This would require either some form of evidence to prove that the gases are not comingled, or further legislation to allow North Slope gas to displace Cook Inlet gas at specific locations. II-35 FEDERAL NATURAL GAS DECONTROL There has been considerable interest recently in the debate surrounding the federal decontrol of natural gas prices and alternatives to the current phased partial decontrol of natural gas prices under the Natural Gas Policy Act of 1978 (NGPA). The Reagan administration, among others, has supported the total deregulation of natural gas prices. Other forces, in response to the outcries of residential consumers, have called for more stringent price controls at the retail level. There is also a movement to excuse natural gas transmission pipelines from the take-or-pay provisions of their existing supply contracts. The effect of natural gas deregulation upon Alaskan natural gas prices would seem to be uncertain. New federal regulations could affect the timing of the development of North Slope natural gas, as it is currently restricted from overseas export. According to Ted Moninski, Alaska Public Utility Commission (APUC) Deputy Director, the APUC's jurisdiction over Chugach Electric's Beluga field contracts is also uncertain, as the APUC has not, in the past, tried to exercise review power over the contracts. The latest Enstar contracts have removed Enstar's natural gas costs from comparison to the national price of natural gas by tying price adjustments to the regional price of fuel oil. The APUC has not undertaken any detailed analysis of the impact of federal natural gas deregulation proposals upon Alaskan natural gas (personal communication, March 8, 1983). It is too early in the 98th Congress to tell how the proponents of various natural gas issues will act. Early in 1983, it was predicted that there would II-36 probably be several bills introduced to Congress, but it is possible that there would be no major changes to natural gas regulations this year (Energy Users Report, Jan 20 1983, p. 87). The Administration's bill was introduced by Senator James A. McClure (R-Idaho) on February 28. Since then, several alternatives have been proposed and other bills have been introduced. As of June 1983, the issues of federal natural gas decontrol were being debated in both the Senate Energy Committee and House Energy Subcommittee on Fossil Fuels. It is difficult, at this time, to accurately anticipate the outcome of the decontrol debate. eee Ke II-37 Part Ill - North Slope Natural Gas PART III NORTH SLOPE NATURAL GAS INTRODUCTION The North Slope natural gas field (referred to technically as the Prudhoe Bay Field) contains over 88 percent of Alaska's natural gas reserves, as well as a majority of the state's natural gas resource potential. Knowledge of this large, undeveloped reserve has generated a substantial amount of interest in its commercial development. While many alternative means of development have been suggested in the past, most aspects of North Slope natural gas can be understood by reviewing the two large-scale development alternatives presently receiving much public debate: the Alaska Natural Gas Transportation System (ANGTS) and the Trans Alaska Gas System (TAGS) (see Figure III-1). NATURAL GAS RESERVES Natural gas reserve information for the state of Alaska has been presented in Table II-1. The North Slope Oil and Gas Province accounts for over 29,000 Bef of Alaska's total reserve of 32,600 Bef. Of this portion, almost 28,800 Bef of natural gas are located in the Prudhoe Bay field, which is the field usually being referred to when "North Slope natural gas" is being discussed. Other fields identified in the North Slope Oil and Gas Province are the Kuparuk River, the East Barrow and the South Barrow. DELIVERY SYSTEM DESCRIPTIONS As discussed in Part II, the natural gas reserves of the Cook Inlet Basin, although perhaps larger than currently estimated, are finite. As the Cook Inlet TII-1 Prudhoe Bay Rampart Fairbanks Healy @® Trans Alaska Oil Pipeline System (Aleyeska) Oil - in place seeeeee= Alaska Natural Gas Transportation System (ANGTS) Gas - proposed Trans Alaska Gas System (TAGS) Gas - proposed Figure 111-1 PIPELINE DELIVERY SYSTEMS W1-2 Basin reserves deplete, other fuel sources will be needed as a _ supplement. North Slope natural gas is one such possible supplement. The principal proposed North Slope natural gas delivery systems are discussed below. Both proposed systems have projected 1990 completion dates. When one of these systems is in place, it may be used to provide gas to supplement the depleting Cook Inlet Basin gas supplies. It should be remembered that Cook Inlet Basin natural gas supplies would not suddently "run out," rather, production will slowly decrease over time as the reserves deplete. The costs associated with North Slope natural gas, whether blended into the Cook Inlet Basin natural gas supply system or provided "by wire" from dedicated generation facilities, would probably not be felt as a single drastic cost increase. Rather, the price of North Slope natural gas would be assimilated over a period of years, reflecting this source's overall contribution to generation fuel supplies. The Trans Alaska Gas System (TAGS) The TAGS concept consists primarily of transporting natural gas by pipeline from Prudhoe Bay to a liquefied natural gas (LNG) preparation facility at tidewater in south central Alaska, and shipping the LNG to Japan in direct competition with Japan's imports of crude oil. An economic evaluation of TAGS has been released recently by the Governor's Economic Committee on North Slope Natural Gas (1983). The Governor's Committee assumed that the pipeline would be aligned parallel to the Trans Alaska Oil Pipeline System (Alyeska) to the vicinity of Fairbanks. South of Fairbanks, the TAGS alignment would follow Alaska Highway 3 until that highway veers to the east toward Palmer. TAGS would continue south along the Susitna River and pass under Cook Inlet. The pipeline would be aligned to the southwest along the east bank of Cook Inlet to the Nikishka area. III-3 Nikishka was chosen due to the existing petroleum plant facilities, available sites, relative ease of access by both land and water, and a developed infrastructure (Governor's Economic Committee, 1983, "Engineering," p. 4). North Slope natural gas, as produced, contains 12.63 percent carbon dioxide (co,), a noncombustible gas which would be removed from the raw natural gas prior to export. The 00, is removed from the natural gas at the LNG facility, ‘rather than at the well head, as its presence in the gas allows the gas to carry more heavy hydrocarbons ("natural gas liquids") which have a relatively high market value and can improve the economics of the pipeline (Ebasco, 1982a, Chapter III). The Governor's Economic Committee has evaluated TAGS in terms of three stages of production: Phase I: 0.95-Bef/d of raw gas, one intermediate compressor station, starting operation in 1990. Phase II: 1.75 Bef/d of raw gas, seven intermediate compressor stations, starting in 1992; and Phase III: 2.83 Bef/d of raw gas, 14 intermediate compressor stations, starting in 1994 (Governor's Economic Committee, 1983, "Engineering," p- 8 and "Executive Summary," p. 6.). The original TAGS schedule was to complete Phases I, II and III in 1988, 1990, and 1992, respectively. This has been advanced two years since the release of the Governor's Economic Committeé report (personal communication with Mead III-4 Treadwell, Governor's Economic Committee, May 25, 1983). There are two means by which fuel would be available from TAGS: o The state of Alaska is entitled to a royalty share (12.5 percent) of the gas produced from Prudhoe Bay for consumption (natural gas used to operate equipment on the field or to maintain field pressure is exempt) (Ebasco, 1982a, p. IV-2). o The process of removing CO, from the raw gas at the LNG facility may yield a "waste gas" containing 195 Btu per cubic foot. This gas would be produced at a level of about 0.43 Bef/d. This fuel could be burned only in properly modified combustion turbines. By blending the waste gas with the processed gas to a heat content of 400 Btu per cubic foot (equivalent to 1 cubic foot of processed gas per 3.43 cubic feet of waste gas), combustion turbines could be used without modifications (Ebasco, 1983, p- 6-4 and 6-5). The Alaska Natural Gas Transportation System (ANGTS) The Alaska Natural Gas Transportation Act, enacted by Congress on October 22, 1976, set forth the procedures for expediting the selection, approval and construction of a pipeline to transport North Slope natural gas to the lower 48. Congress approved the route selection in 1977. The ANGTS has been designed to carry approximately 2 Bef/d of natural gas. The Office of the Federal Inspector provides the following summary of the project: III-5 The entire project stretches 4,800 miles from Prudhoe Bay, on the northern coast of Alaska, along the route of the Trans Alaska Oil Pipeline to Delta Junction, south of Fairbanks. There the gas line turns southeast and continues south into Canada, generally following the Alaskan-Canadian highway. Just north of Calgary, it splits into two legs--the West Leg going to Antioch, California, and the East Leg almost to Chicago, Illinois. The lower portion of the system is being built now to transport Canadian gas to U.S. markets while the northern segments are being designed and built. Phase One facilities on the Western Leg involving expansion of an existing pipeline are completed, and on October 1, 1981, Canadian gas began to flow through the system to southern California. Construction of the Eastern Leg began in early May 1981 and is scheduled to be completed by fall 1982, when it will begin to carry Canadian gas to midwest and eastern markets (Office of the Federal Inspector). The Alaskan segment of ANGTS was originally scheduled for completion in 1986-87. Construction is now planned to begin in 1987, with initial deliveries commencing in 1990 (Booz, Allen & Hamilton, 1983, p. II-1). If ANGTS is completed, the state of Alaska would be entitled to its royalty share of 12.5 percent of the gas produced for sale. This amount and possibly additional quantities of pipeline gas, would become available for in-state consumption. The quantity of royalty gas has been estimated to be 91 to 114 Bef per year (Secrest and Swift, p. 6.1). Since the routing of ANGTS would bypass south-central Alaska, Chugach Electric's opportunity for utilization of North Slope natural gas would be to generate electricity in the Fairbanks region and III-6 construct the necessary transmission system to deliver the energy to Chugach Electric's service territory. A natural gas pipeline from Fairbanks to Anchorage has not been proposed as part of ANGTS. Gas Pipeline from North Slope to Fairbanks As part of its evaluation of the utilization of North Slope natural gas, Ebasco (1983) considered the possibility of constructing a 22-inch high-pressure natural gas pipeline along the ANGTS right-of-way from the North Slope to Fairbanks. In this plan, the waste gas would be extracted at a gas conditioning plant located on the North Slope. The natural gas delivered to Fairbanks would be used for electrical generation and residential and commercial heating and cooking. Ebasco assumed that the naturally occurring propane would be injected back into the pipeline gas after conditioning, yielding a product that is 88 percent methane with a heat content of 1,100 Btu per cubic foot. Part of the electricity generated at Fairbanks would be transmitted to Anchorage through the construction of a new 345-kV transmission line and the upgrading of the existing Healy-Fairbanks and Willow-Anchorage line segments. The natural gas pipeline would have a peak flow rate of 0.397-Bcf/d in Ebasco's medium load growth forecast case (Ebasco, 1983, Chapter 4). Average flow rates would be considerably lower than this. Through the end of their study period (2010), Ebasco estimated that the average flow rate would be about 59.4 Bef per year in their medium load growth forecast case, and 32.2 Bef per year in their low growth forecast case (p. 4-33 and 5-6). III-7 ESTIMATED COSTS Cost and Availability of Natural Gas From TAGS The engineering cost and preliminary design of TAGS was performed by Brown & Root, Inc. The economic analysis of Brown & Root's basic cost data was performed by Dillon, Read & Co., Inc. (Governor's Economic Committee, 1983). Brown & Root's estimates of construction and operation and maintenance costs are presented in Table III-1. These costs are based on three phases of construction (Phase I, II and III), scheduled for completion, respectively, in 1990, 1992 and 1994. Since the three construction phases have been designed so that each completed phase can be operated without the following phase, Dillon, Read assessed the economics of two systems: the Phase I standing alone, and the completed Phase III system. The fully completed Phase III system, with a delivery capacity of 2.83 Bef/d of raw natural gas, was assumed to be the base case of Dillon, Read's evaluation. The smaller Phase I system, capable of delivering 0.95 Bef/d of raw natural gas, was included to examine the potential advantages of building a smaller system. Based on the Brown & Root construction costs (Table III-1), Dillon, Read estimated the installed capital costs for the Phase I and Phase III systems. This amounted to $11.6 billion in 1988 for the Phase I system and $25.5 billion in 1992 for the total Phase III system. These costs have not been revised to reflect the two-year change in the TAGS schedule. These installed capital costs adjust the 1982 capital costs in Table III-1 by allowing for cost inflation up to the time when each cost is incurred in the construction schedule, and for interest charges on construction loans. Based on these installed capital costs, and Brown & Root's estimated operating and maintenance costs, Dillon, Read _III-8 Table III-1 TRANS ALASKA GAS SYSTEM—ESTIMATED CUMULATIVE COST SUMMARY! (Millions of 1982 $) Phase | Phase |! Phase II! Capital Costs? Pipeline 4,608 6,276 8,243 Conditioning Facilities 702 982 1,423 Liquefaction Facilities 1,863 2,995 4,628 Total 7,173 10,253 14,294 Operating and Maintenance Costs/Annual Pipeline 20 35 49 Conditioning Facilities 19 27 39 Liquefaction Facilities 39 66 105 Total 78 128 193 1 Cumulative” means that Phase II includes Phase I, and Phase III includes Phases | and II. 2 “Capital Costs’’ do not include inflation or interest during construction, i.e., these are not ‘‘installed costs.’’ Source: Governor’s Economic Committee, 1983. Table II|-2 PROSPECTIVE TRANS ALASKA GAS SYSTEM TARIFFS — PRODUCTS DELIVERED TO SOUTH-CENTRAL ALASKA (1983 $) Natural Gas! Propane Butane ($/MMBtu) ($/Barrel) ($/Barrel) Lower Tariff? Higher Tariff? Lower Tariff? Higher Tariff? Lower Tariff? Higher Tarrif? Phase I System 4.24 5.64 16.13 21.49 18.59 24.75 Phase III System 3.33 4.39 12.68 16.73 14.62 19.28 1 Natural gas pricing in Governor’s Economic Committee report was on a heat content basis. 3 “Lower Tariff’’ is based on a 30 percent after tax return on investment with a 75/25 debt-to- equity ratio. 3 “Higher Tariff’’ is based on a 40 percent after tax return on investment with a 75/25 debt to equity ratio. Note: The prices in the Governor's Economic Committee report were in 1988 dollars. Here they have been converted to 1983 dollars, using that report's escalation assumption of 7.0 percent per year. Source: Governor's Economic Committee, 1983. . UN-9 estimated the tariff charges that would be charged for transporting the North Slope natural gas (and associated liquid products) to south-central Alaska. This information is presented in Table III-2. In its analysis, Dillon, Read developed two tariff cost scenarios, based on the rate of return on equity investment required by potential investors. The “lower tariff" was based on a 30 percent after tax return on investment, reflecting limited equity risk. The "higher tariff" was based on a 40 percent after tax return on investment, reflecting higher equity risk. In both cases, a 75/25 debt-to-equity ratio was assumed. The Governor's Economic Committee assumed that the price of TAGS gas would increase at the general rate of inflation (ibid, "Economics," p. 42, Table yrs No tariff was estimated for the low-Btu waste gas that would be a by-product of the gas conditioning plant at Nikishka. The Governor's Economic Committee report recommended two possible uses for the waste gas: power generation and ' oil field injection. Cost and Availability of Natural Gas Available from ANGTS Although the lower 48 segments of ANGTS are completed, the Alaskan segment of the system is still a subject of public debate. The lower 48 segments of the system are designed to be used for other purposes, so the completion of those segments of the system does not dictate that the Alaskan portion must be finished. As shown on Figure III-i1, completion of the Alaskan portion of ANGTS would make North Slope natural gas available to the interior of Alaska (including Fairbanks), but not to the Anchorage area. If the Alaskan portion is TII-10 finished according to the current schedule, North Slope natural gas would be available in the Fairbanks area in 1990. The probability of the completion of the ANGTS has been reduced due to decreasing world energy prices and the apparent inability of the ANGTS sponsors to obtain the $27.1 billion (1982 dollars) estimated to be required for completion of the system. Recent reports from Washington (Anchorage ‘Times, January 20, February 9, and February 16, 1983) indicate a continuing skepticism regarding the completion of the ANGTS system. Cost estimates of ANGTS are uncertain, as there are several capital cost estimates for the completed system, and the structure of the tariff has not been precisely defined. Price information has been obtained from Secrest and Swift (1982) and Northwest Pipeline Company. According to the Secrest and Swift estimates, the 1982 cost of the ANGTS natural gas delivered to the lower 48 has been estimated to be $10.60 per MMBtu. The cost of this gas to Alaskan consumers could be the total delivered cost, or a pro rata share of the cost based on the capital cost of constructing the pipeline -as far as Fairbanks. Based upon the estimated 1980 capital costs of ANGTS (Table III-3) and the location of Fairbanks along the Alaskan portion of the system, Secrest and Swift (1982) have estimated the cost of ANGTS gas at Fairbanks (Table III-4). This amounts to $5.92 per MMBtu; of which $2.13 is the wellhead value and $3.79 is the tariff. The 1982 capital cost estimate is higher than the 1980 estimate, but the relative proportions of the major cost items has not changed, so the cost estimate method is still valid. III-11 Table III-3 SUMMARY OF ALASKA NATURAL GAS TRANSPORTATION SYSTEM CAPITAL COSTS (Billions of $) Estimated Cost Share of Segment 1980$ 1982$ Total Cost Gas Conditioning Plant 3.6 4.3 16% Alaskan Segment 10.8 12.7 47% Canadian Segment 5.8 6.8 25% United States 2.8 3.3 12% (East and West Legs) 23.0 27.1 100% Note: Capital Costs include contingencies; exclude inflation and interest during construction. Sources: DCED, 1983, p. A-20 Secrest and Swift, 1982, p. 6.5. Table III-4 COST COMPONENTS OF ALASKA NATURAL GAS TRANSPORTATION SYSTEM (1982 $ Per Mcf) Cost to Cost to Cost Component Fairbanks Lower-48 Wellhead Value 2.13 2.13 Gas Conditioning 1.36 1.36 Transmission Wellhead to Fairbanks! 2.43 2.43 Fairbanks to Canada _ 1.55 Canada and Lower-48 _ 3.13 Delivered Cost 5.92 10.60 x Fairbanks is approximately 450 miles (61 percent) down the 740 mile long Alaskan segment. Source: Secrest and Swift, 1982, p. 6.4-6.6 1-12 Northwest Pipeline has estimated that the ANGTS gas would be delivered to Fairbanks for $7.76 per MMBtu in 1990 (in 1982 dollars). This is based on a gas wellhead value of $2.45 per MMBtu and $5.31 per MMBtu for the tariff. The performance over time of the price of ANGTS natural gas will depend upon the structure of the transmission tariff. Secrest and Swift attempted to estimate the performance of the estimated ANGTS price by assuming that the Sithaad sade of the gas ($2.13) remains fixed in real terms and the tariff portion ($3.79) decreases at a real rate of 13.5 percent per year beginning with the first year of deliveries (1990). By applying general escalation rates of 6.5 percent for 1982-1985, 7.0 percent for 1985-1990, and 6.0 percent for 1990-2002, the annual escalation is equal to 2.3 percent. The 2002 price would be 10.07 per MMBtu. This information is presented in Table III-5. The use of a declining tariff is meant to represent the effect of capital depreciation. Secrest and Swift gave the following warnings: It should be noted that the constant decay factor tends to overstate the tariff in early years and understate it in later years. This is because typical gas pipeline tariffs decrease more rapidly in early years due to accelerated depreciation of the fixed investment. However, the constant factor used approximates the likely behavior of the price series and the inaccuracy noted is of less consequence than the uncertainty regarding the actual level of the delivered price (Secrest and Swift, 1982, p. 6.6). III-13 Year _— 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 Wellhead Value 2.13 2.27 2.42 2.57 2.75 2.94 3.15 3.37 3.60 3.82 4.04 4.29 4.54 4.82 5.11 5.41 5.74 6.08 6.45 6.83 7.24 Table III-5 ESTIMATED PRICE PERFORMANCE FOR ALASKA NATURAL GAS TRANSPORTATION SYSTEM GAS AT FAIRBANKS (Current $ Per MMBtu) Secrest and Swift Estimate Northwest Pipeline Estimate Tariff? 3.79 4.03 4.30 4.58 4.90 5.24 5.61 6.00 6.42 6.00 5.60 5.23 4.88 4.56 4.26 3.98 3.72 3.47 3.24 3.03 2.83 Delivered Price 5.92 6.30 6.72 7.15 7.65 8.18 8.76 9.37 10.02 9.82 9.64 9.52 9.42 9.38 9.37 9.39 9.46 9.55 9.69 9.86 10.07 Wellhead Value 2.45 2.61 2.78 2.96 3.17 3.39 3.63 3.88 4.15 4.40 4.66 4.94 5.24 5.55 5.89 6.24 6.61 7.01 7.43 7.88 8.35 Tariff? 5.31 5.66 6.02 6.41 6.86 7.34 7.85 8.40 8.99 8.39 7.90 7.39 6.89 6.44 6.03 5.63 5.27 4.92 4.61 4.31 4.02 1 Tariff increases at general inflation until first year of deliveries (1990), after which it is then adjusted for both inflation and a constant decay rate of 13.5 percent (see text). Effective rate of decline after 1990 is: or a 6.6 percent rate of decrease. 1.06 (escalation) = 0.934 1.135 (decay rate) 7 Tariff increases at general inflation until first year of deliveries, after which it is adjusted for both inflation and a constant decay rate of 11.76 percent (see text). Effective rate after 1990 is: or a 5.2 percent rate of decrease. 1.06 (escalation) = 948 1.1176 (decay rate) Sources: Secrest and Swift, 1982, p. 6.4-6.6. Communications with Northwest Pipeline. 1-14 Delivered Price 7.76 8.27 8.80 9.37 10.03 10.73 11.48 12.28 13.14 12.79 12.56 12.33 12.13 11.99 11.92 11.87 11.88 11.93 12.04 12.19 12.37 Northwest Pipeline has provided information on the annual price of ANGTS gas for 1990 to 1994 on a 1982 dollar basis. This has been extrapolated to 2002 and restated on a current dollar basis, using the same general escalation assumptions discussed above, on Table III-5. From the data provided, the decline rate of the tariff is estimated to be 11.76 percent per year. For the 1982-2002 time period, the average annual rate of escalation is equal to 2.4 percent. The 2002 price would be 12.37 per MMBtu. Summary The price of North Slope natural gas associated with the two principal transportation system options is summarized in Table III-6. While it is uncertain if either system will ever be completed, ANGTS is planned to make North Slope natural gas available to the Fairbanks area in 1990, and TAGS is planned to make North Slope natural gas, and perhaps a waste gas byproduct, available to south central Alaska in the 1990-1994 time frame. ee eH TII-15 Year 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2001 2001 2002 SUMMARY OF Table III-6 NORTH SLOPE GAS PRICE ASSUMPTIONS (Current $ Per MMBtu) Alaska Natural Gas ! Price details are shown on Table III-5. 2 Prices shown are averages of the ranges shown in Table III-2. Transportation System? (at Fairbanks) Secrest Northwest sand Swift —Fipeline_ 10.02 13.14 9.82 12.79 9.64 12.56 9.52 12.33 9.42 12.13 9.38 11.99 9.37 11.92 9.39 11.87 9.46 11.88 9.55 11.93 9.69 12.04 9.86 12.19 10.07 12.37 1-16 Trans Alaska Gas System? Phase | 7.84 8.32 8.82 9.35 9.91 10.51 11.14 11.80 12.51 13.26 14.06 14.90 15.80 (at Nikishka) Phase III 6.14 6.51 6.90 7.31 7.75 8.22 8.71 9.23 9.79 10.37 11.00 11.66 12.35 Part IV - Alaskan Coal PART IV ALASKAN COAL INTRODUCTION Coal mining has been conducted intermittently in Alaska for over 100 years. The first report of coal in Alaska was made in 1786 by Capt. Nathaniel Portlock, an English trader who found coal at what is now Port Graham on the Kenai Peninsula. By 1855 the first Alaskan coal mine was opened by the Russian-American Company at Coal Cove. The mine was operated from 1855 until 1867, when the United States took possession of Alaska. From 1880 to 1915 coal mining was carried on intermittently at several localities, including Unga Island, Herendeen Bay, Chignik Bay, Kachemak Bay, and along the Yukon River. Sustained coal production began with the completion of the Alaskan Railroad from Anchorage to the Matanuska and Nenana coal fields in 1916 and 1918, respectively. Coal production continued to increase until 1953, at which time the oil and gas fields in Cook Inlet were developed. Nearly all of the coal mined during this time came from the Evans Jones Coal Mine in the Matanuska field and Healy River Mine in the Nenana field. Oil and gas eventually replaced the Matanuska coal as means for providing heat and power. The military in Anchorage shifted from burning coal to oil in 1967, further reducing production, except for local needs. The recent increase in demand for electric power, current trends in oil and gas prices, and the Federal government's energy policies have prompted an interest in opening the Beluga field and expanding the Nenana fields. IvV-1 SUMMARY OF FIELDS Coal is found in all major geographical subdivisions of Alaska. As shown in Figure IV-1, there are 17 major coal fields in Alaska (McGee and Emmel, 1979, Figure 1) ranging in age from Carboniferous to Tertiary, and ranging in grade from lignite to semianthracite. The only fields that have been developed extensively are the Matanuska and Nenana. Nenana Field Roughly 94 percent of the coal mined in Alaska today comes from the Nenana field. The coal-bearing group of rocks in the Nenana field are approximately 2,800 feet thick. The coal beds have been designated by letter, A through G, and then numbered, 1 through 6. Of these coals, only four principal beds are mined, F, 1, 2, and 3. These beds vary greatly in thickness from less than 30 feet to over 50 feet. The coal in this field is generally subbituminous C or subbituminous B in rank, varying in heat content from approximately 8,500 to 9,500 Btu per pound. Sulfur content is approximately 0.2 percent. Mining is largely confined to the south limb of the field, where beds dip less than 45 degrees and there is a stripping ratio of 4 to 1. The coal beds mined are subbituminous in rank, and have few shale partings. All this coal now goes from the mine directly to the tipple and market. In the past, coal containing partings was stockpiled and washed during the summer months. The coal washing plant is now closed indefinitely because the coal that required washing is no longer mined. IV-2 fAl Map compiled fom McGee and Emmel, 1979, Alaska Coal Resources and Alaska Dept, of Natural Resources, 1977,"Energy Resource Map of Alaska: Subbituminous WA Bituminous Semianthracite SPN KaPwn> Northern Alaska field Point Hope field Nulato field Yukon field Eagle field Nenana field Jarvis Creek field Broad Pass Field Yentna field Susitna field Matanuska field Beluga field Kenai field Cook Inlet field Bering River fiels Chignik field Herendeen Bay field MAJOR ALASKAN COAL FIELDS Susitna Field, Beluga Field The Susitna field contains the largest reserve of coal recoverable by strip mining in Alaska. The southern portion of this field is also referred to as the Beluga field. The coal-bearing formation here is relatively flat, and in many sections coal beds more than 50 feet thick will have less than 120 feet of cover. A near horizontal bed of subbituminous coal 30 to 50 feet thick has been traced for more than 7 miles along the Chuitna River (NRC, 1980, p. 24). Several other promising occurences are known to exist elsewhere in the Beluga field. The quality of most of the Beluga coals is typically 6,600 to 8,200 Btu per pound, 16 to 22 percent ash, 20 to 30 percent moisture, and 0.1 to 0.2 percent sulfur. Due to the field's favorable stripping ratio, low sulfur content, nearness to tidewater, and accessibility to a labor supply, an active leasing and exploration program is underway, especially in the Beluga area. Matanuska Field The Matanuska field is located in the Matanuska Valley, just east of Palmer. Within the field are three well-defined and persistent groups of coal beds, and a fourth, local group. Within a given group of coal beds, individual seams vary in thickness within short distances. The beds may be clean in one area, and extremely dirty in another. Most of the coal found in the valley is bituminous, but some is semianthracite. In the Wishbone Hill District, there are three series of beds, with individual beds up to 23 feet thick. They run 12,000 to 12,500 Btu per pound, with Iv-4 approximately 11 percent ash and 0.3 to 0.5 percent sulfur. Mining occurred in the southern portion of the district until 1968, when the Evans Jones Mine closed. It produced a total of approximately 6 million tons of coal from eight beds. The northern portion of the district has been mined periodically since the early 1900s. The coal-bearing strata are complexly folded and faulted with intrusions, making mining difficult and expensive. The only remaining operations produce coal for sale to individuals for domestic heating purposes. Kenai Field The Kenai field, which is located along the eastern edge of Cook Inlet, contains the site of the first coal mine in Alaska. The coal-bearing group of this field is over 5,000 feet thick and is essentially flat lying, although some faulting is present. This group contains approximately 30 coal beds, subbituminous in rank, and ranging in thickness from 2-1/2 feet to 10 feet. Despite the proximity of the coal to tidewater, the flat lying structure, and other favorable factors, the Kenai field has not been mined in recent times because the coal seams have been considered too thin for commercial development (DOE, 1977, Vol. 2, p. 435). In addition, the majority of the Kenai field is under state and native title, with intense recreational, private and municipal surface use which will probably preclude surface mining; however, there may be potential for underground recovery (Rao and Wolff, 1980, p. 25). IV-5 Cook Inlet Field (Kenai Offshore Field) The Cook Inlet field, located offshore of the Kenai Peninsula, is sometimes considered a separate field, although it actually connects the Kenai Field with the Beluga Field. The size of this field has been determined largely by the extensive drilling for oil and natural gas in Cook Inlet. Approximately 2,900 square miles offshore have been proved to be coal bearing. Northern Alaska Field Alaska's principal coal-bearing deposits are in the North Slope Basin, north of the Brooks Range, and extend offshore into the Chuckchi Sea. This field ranks _ among the major coal deposits of the world. Its known strippable reserves rank this field second in subbituminous coal and third in bitumincus coal in the United States (Conwell, 1980, p. 505). The coal-bearing formation has a measured thickness of over 15,000 feet, with coal occurring throughout the formation. The majority of the coal beds are lenticular and are more than 3-1/2 - feet thick. Ten-foot beds are common, and 40-foot beds are known. In some places coal forms 10 percent of the entire stratigraphic section (NRC, 1980, p. 16). However, the exact extent of the coal resources on the North Slope are largely unknown. The difficulty of access, the general absence of human settlements and transportation facilities, and the harsh environment of the North Slope will make coal mining there difficult. Surface mining could have a severe environmental impact on the region's vegetation and permafrost, and perhaps on wildlife. Optimum methods of controlling environmental impacts of surface operations in Arctic areas are not yet known (NRC, 1980, pe 19). IV-6 Other Alaskan Coal Deposits Coal outcrops occur in several other locations in Alaska. Most of these deposits are small and have attracted little interest. Coal has been found on the Seward Peninsula, Point Hope, and along the Yukon River. Its character and extent are relatively unknown. In southwestern Alaska there are small coal fields with thin beds at Unga Island (lignite), and Herendeen Bay and Chignik (bituminous, subbituminous and lignite), that have not been extensively explored. The Bering River field, approximately 200 miles east of Anchorage, contains bituminous and semianthracite coal. The strata is highly folded and faulted, and total coal resources are poorly known. Coal occurs at several locations in the Alexander Archipelago. Thin beds of lignite occur on some of the islands. A small mine at Kotzenahoo Inlet on Admirality Island supplied Juneau with coal prior to 1929. There are also several other existing fields, on which little or no geologic or reserve data is available. RESERVES The total coal resources in Alaska are difficult to estimate due to the limited available data, other than information obtained from outcrop areas and drilling adjacent to the outcrop area. Estimates of undiscovered resources vary widely, reflecting the scarcity and ambiguity of the data that is available. A summary IV-7 of Alaskan coal reserves can be found in Table IV-1. The measured, indicated, and inferred reserve categories are based on the parameters proposed by the United States Geological Survey and the United States Bureau of Mines. Measured reserves are those for which tonnage is computed from information obtained from outcrops, drill holes, workings, etc. The sites for inspection, sampling, and measurement are so closely spaced and the geologic character so well defined that size, shape, and mineral content are well established. Indicated reserves are those for which tonnage and grade are computed partly from specific data and partly from projection for a reasonable distance on geologic evidence. Inferred reserves are quantitative estimates based largely on broad knowledge for which there are few, if any samples or measurements. The estimate are based on an assumed continuity or repetition, of which there is geologic evidence. Hypothetical reserves are defined by McGee and Hmmel (1979, p. 1) as those resources for which there is a wide range of possible error. LAND OWNERSHIP Essentially, there are no privately owned coal lands in Alaska (Conwell, 1981, p- 504). The coal lands are either federal or state lands to which the appropriate leasing laws apply. The majority of coal leases are concentrated within two major fields (Table IV-2), with a third area having considerable land awaiting conversion to leases (Table IV-3). The area with the greatest potential for development in the near future, the Beluga field, contains the largest proportion of leases in the state. Three companies (Mobil Oil, Beluga Coal Company, and Wilson, Bass, Hunt) control approximately 90 percent of the Beluga leases and are the three largest lease holders in the state. All three companies are involved in extensive drilling and exploration programs. Beluga IV-8 Table IV-1 ALASKA’S COAL RESOURCES (tons x 10%) Indicated & Coal Field Measured Inferred Hypothetical Northern Alaska .235 58-137 513-3300 Nenana .862 6.0 8.7 Susitna .275 2.7-10.2 27 Kenai .002 —— 34 Cook Inlet _ — 100 Matanuska .007 -108-.130 .149 Others —_ .233-.386 -7-1.8 TOTAL* 1.4 67-154 680-3470 *Totals rounded. Source: McGee, D. L. and Emmel, K. S., Alaska Coal Resources, 1979 Figure 2 Iv-9 Major Coal Field Area Susitna Beluga Upper Beluga Lake Nenana Healy Nenana Kenai Kenai Matanuska Matanuska Total N.A.: Not Applicable. Table IV-2 STATE OF ALASKA COAL LEASES Leaseholder Mobile Oil Corp. Starkey Wilson, Richard D. Bass Trust Estate, & W.H. Hunt Beluga Coal Co. Elton to Stabio Meadowlark Farms Albert E. Slone Meadowlark Farms Usibelli Coal Mine Inc. Meadowlark Farms Arctic Coal Co. Don Renshaw B&G Shallit B&G Shallit Warren Coal Co. American Exploration & Mining Co. H. A. Faroe Paul Omlin Robert W. Gore Source: ‘‘State of Alaska Coal Leases, March 8, 1982’. Division of Minerals and Energy Management. 1V-10 Associated Interest N.A. Diamond Chuitna Placer Amex N.A. Amax Coal N.A. Amax Coal N.A. Amax Coal N.A. N.A. N.A. N.A. N.A. N.A. N.A. N.A. Total Acres of All Leases 23,080 20,571 17,686 2,310 800 80 3,080 15,832 12,820 2,440 600 480 880 40 1,410 780 760 180 103,829 Table IV-3 STATE OF ALASKA CONVERSION TO LEASE APPLICATIONS Major Coal Field Area Name Kenai Ninilchik C. A. Wynne Others Anchor Point C. A. Wynne Homer J. M. Pope Source: ‘‘State of Alaska Coal Leases, March 8, 1982,"’ Division of Minerals and Energy Management. 1V-11 Total Acres 13,249 1,760 15,849 Coal Company is a wholly owned subsidiary of Placer Amex, Inc., and the Wilson, Bass Hunt leases have been subleased to Diamond Chuitna. The Alaska Department of Natural Resources has announced that it is considering the offering of 22,000 acres of state coal lands in the Beluga field for competitive lease sales in May, 1983. At the International Conference on Coal, Minerals and Petroleum, held in Anchorage on February 16-17, 1983, DNR Commissioner Esther Wunnicke announced that, due to soft market conditions, the offering has been reduced considerably. The placement of the proposed lease sale lands relative to other major lease holdings in the Beluga field is shown in Figure IV-2. Usibelli Coal Mine, Inc., is the fourth largest leaseholder in Alaska, and the largest leaseholder in the Nenana field. Their leases are all in the vicinity of the Usibelli Mine, Alaska's only large-scale mining operation. Meadowlark Farms, a subsidiary of Amax Coal, is the other major lease holder in the Nenana field. POTENTIAL COAL DEVELOPMENT Because of their vast size, the coal resources of the North Slope may attract considerable interest. The flat lying beds along the coast appear suitable for surface mining. However, there are no present transportation facilities in the Arctic suitable for coal development. Mining on a scale large enough to justify the cost of development of a transportation system could have severe environmental impacts whose mitigation would be uncertain. Surface and Iv-12 EL-Al Initial Sale Area Final Sale Area = Placer Amex, Inc. Coal Leases CAPPS MINE AREA \S WZ _Bass, Hunt & Wilson Coal Leases SCARP CREEK PROPOSED DIAMOND SHAMROCK MINE PROPOSED LONE RIDGE MINE SPSAAN SS S $ SSTSLIINIAV AY BELUGA PROPOSED 4 POWER j CENTER RIDGE J PLANT MINE THREE MILE AREA oe : LONE CREEK oo COOK INLET N ay Source: State of Alaska, DNR, DMEM, Preliminary Analysis of the Director Regarding Beluga Coal Lease Sale, and Beluga Coal Company Figure IV-2 BELUGA COAL FIELD COAL LEASE AREA underground mining techniques necessary to develop the region's vast resources are many years in the future (NRC, 1980, p. 2). Of the interior coal fields, the Usibelli Mine in the Nenana field is presently the only mine producing a substantial amount of coal. Mining has been conducted in the area for several years, and reclamation practices have been developed. The Alaska Railroad serves the area and can be used for moving coal to market. Although the total coal resources of the region are modest, further development May become feasible following the mining and reclamation practices of the Usibelli Mine. Coal deposits in the fields around Cook Inlet appear favorable for development. The permafrost is sporadic or nonexistent, and the fields are near potential domestic markets and have relatively easy access to tidewater. Beluga is probably the most attractive of these fields, because of the size of its total resources, the thickness of its coal seams, and the geologic simplicity of the near surface coal strata that makes it easily accessible by surface mining methods (NRC, 1980, p. 2a). The Matanuska field is favorably located with respect to transportation facilities. However, the field's measured reserves are limited and geologic conditions may present operational problems. Any future mining here would probably be by underground methods. IvV-14 The Kenai coal field is located near tidewater and is accessible by roads; however, the coal is present only in thin seams and recovery would be costly. There are two hurdles to overcome in the development of Alaskan coal resources. The major problem is transportation. The present surface transportation facilities are poorly developed. Also, the potential for development is decreased by physiological barriers, such as the Alaska and Brooks ranges between which are hundreds of miles of wetlands. In addition, so little is known about Alaska's geology that the potential for discovery of new coal fields is high (Rao and Wolff, 1980, p. 29). COAL AVAILABILITY AND COST This assessment of Alaska coal supplies has identified two potential coal supply regions, the Nenana and the Beluga fields. The only commercial operation in the Nenana field is Usibelli Coal Mine, Inc. (Usibelli). There are two companies controlling leases in the Beluga field who have expressed interest in the commercial development of their reserves--Placer Amex, Inc., and the Diamond Chuitna Project. Nenana Coal Field Current production is at a rate of approximately 800,000 tons per year. The majority of the coal produced is used to generate electricity and is supplied by truck to the nearby 25-MW Healy generation plant of the Golden Valley Electric Association. Additional coal is crushed, and shipped on the Alaska Railroad to the Fairbanks area and is consumed by the Fairbanks Municipal Utilities System, IV-15 the University of Alaska, and the military installations at Clear Air Force Base, Eielson Air Force Base, and Fort Wainwright. Stoker coal is also produced for local domestic use. Usibelli has exported some coal through the Port of Anchorage to the Korea Electric Power Corporation for test burning. If Usibelli agrees with the amendments proposed for a long-term contract between it, Suneel Alaska, and Korea Electric, the mine will have dedicated its current capacity and would not be in a _ position to consider the expansion of its output for several years. There are three coal seams on the mine property, but only two are mined at any one time. An analysis reflecting the average of the seams is presented in Table IV-4. Exploratory drilling and outcrop measurements result in an estimated recoverable reserve of 240 million tons. There is state land adjacent to Usibelli's holdings which could have approximately 240 million additional recoverable tons of coal on them. Communications with Usibelli Coal Mine, Inc., have revealed that this company believes it will not be in a position to discuss the further expansion of its mining capacity until after 1985. Although unwilling to discuss the expansion of its capacity, Usibelli has been willing to discuss current production and coal prices. This data has been combined with price information on the cost of the coal mined from an expanded operation at the Usibelli operation to develop the coal price data presented in Table IV-5. At the time of a DOE study, Usibelli had reported that the current capital facilities at the mine could produce 2.1 million tons per year. Additional investment could raise production to 4.1 million tons per year. These production levels, with prices representing IV-16 Table IV-4 COAL ANALYSIS NENANA FIELD — USIBELLI COAL MINE, INC. Average Range Adjusted (air dry basis) (air dry basis) (as received) Proximate Analysis (% by Weight) Moisture 18 12-22 28 Volatile Matter 40 37-43 34.0 Fixed Carbon 36 34-46 30.5 Ash 9.8 7.1-16.9 7.2 Sulfur 0.25 0.15-0.40 22 HHV (Btu/Lb.) 9550 9250-9850 7850 Hardgrove Grindability 40 29-45 — Initial Deformation 2128°F 2000° F-2300°F _ (Reducing Atmosphere) Table IV-5 USIBELLI COAL MINE, INC., COAL PRICE DATA Price (f.o.b. Mine) Production Level Base Year (Tons Per Year) $/Ton $/MMBtu Of Dollars _ Source 800,000 22.66 1.44 1982 (1) 2,100,000 16.00-18.00 1.00-1.12 1980 (2) 18.60-20.90 _ 1982 (3) 4,100,000 26 .00-28.00 1.62-1.75 1980 (2) 30.25-32.60 _ 1982 (3) I Discussion with Joseph Usibelli, Sr., January 21, 1983. ? UsDOE, 1980, p.4. 3 4.D. Little, 1983, p. B-6. 1V-17 an average rate of inflation of 7.8 percent per year over a two-year period, appear (without citation) in the 1983 Energy Plan (Draft). The Usibelli coal would most likely be transported by rail from the mine's coal loading facility to a new coal-fired power plant. This coal would probably be shipped under an annual volume tariff or contract with the Alaska Railroad, with the equipment used in a unit train or trainload configuration. The difference between trainload and unit train shipments is in the utilization of equipment. In both trainload and unit train systems, a single string of rail cars is loaded, hauled and unloaded, usually with time restrictions for the loading and unloading of cars. In a trainload system, the rail cars and locomotives are not dedicated to continuous service to one shipper. The equipment may be used in other service after the cars are unloaded. In a unit train system, the rail cars and locomotive power are in continuous dedicated service to one shipper. The exclusive dedication of equipment in unit train service can be justified only when the annual volume and the distance of movement are, in combination, large enough to require this service. When unit train service is feasible, costs can be lowered through the optimum utilization of equipment and labor. There currently are no annual volume (trainload or unit train) shipments of coal in Alaska. Mr. John T. Gray, Manager, Marketing and Sales for the Alaska Railroad has declined to discuss such arrangements at this time due to their negotiations with Usibelli and Suneel Alaska for the shipment of coal to Korea Electric through the Port of Seward. Existing single-car coal freight rates, taken from Alaska Railroad Freight Tariff 105-E, are summarized in Table IV-6. In his presentation at the Alaska Coal Marketing Conference on February 19, IV-18 Origin Healy, Lignite, or Suntrana COAL FREIGHT RATES IN ALASKA Destination Anchorage Broad Pass Cantwell Clear Site Curry Dome Eielson AFB Eklutna Elmendorf AFB Fairbanks Ferry Fort Richardson Fort Wainwright Girdwood Matanuska Denali Park Moose Pass Nenana North Nenana Palmer Portage Seward Summit Talkeetna Wasilla Whittier Willow Woodrow Table IV-6 Approximate Distance (Miles) 243 55 38 41 109 96 141 217 237 113 15 237 133 207 12 328 54 57 213 293 357 46 131 201 172 351 i Rates quoted in Alaska Railroad Freight Tariff 105 _ is in ¢/ton. Rates in ¢/ton-mile was estimated. Rates based on 40,000 pound minimum. IV-19 Single Car Rate! ¢/Ton- ¢/Ton Mile 1,102 4.53 537 9.76 460 12.11 448 10.93 754 6.92 690 7.19 999 7.09 1,010 4.65 1,184 5.00 765 6.77 357 23.80 1,184 5.00 872 6.56 1,109 3.92 983 4.75 357 29.75 1,137 3.47 537 9.94 549 9.63 1,010 4.74 1,112 3.80 1,164 3.26 496 10.78 808 6.17 960 4.78 1,115 3.66 866 5.03 1,164 3.36 Estimated Annual Volume Rate ¢/Ton- ¢/Ton Mile 947 3.89 461 8.38 395 10.39 385 9.39 648 5.94 593 6.18 858 6.09 868 3.99 1,017 4.30 657 5.82 307 20.44 1,017 4.30 749 5.64 953 3.37 844 4.08 307 25.56 977 2.98 457 8.54 472 8.27 868 4.07 955 3.26 1,000 2.80 426 9.26 694 5.30 825 4.11 958 3.14 744 4.32 1,000 2.85 1982, Frank H. Jones, General Manager and Chief Executive Officer of the Alaska Railroad, reported that current negotiations for the Healy to Seward annual volume export movement were headed towards a freight rate of $10 to 311 per ton. Conversations with personnel involved with the development of export coal movements indicate $10 per ton would be the more realistic figure, although this figure may still be high. Applied to the current Healy to Seward single-car freight rate of $11.64 per ton, the annual volume rate of $10 per ton represents a cost reduction of approximately 14.1 percent. In Table IV-6, this discount has been applied to the existing single-car coal freight rates to estimate annual volume rates for those particular origin-destination pairs. Statistical analysis of this information shows that these annual volume rate estimates can be generalized with the equation: Freight Rate ($/ton) = (2.49 Ln distance) - 4.68 Immediately north of the Usibelli Mine, Meadowlark Farms have demonstrated the availability of commercial quantities of coal and have obtained extensive state coal leases. Preliminary evaluations are currently being performed. Beluga Coal Field The Susitna field contains the largest reserve of coal recoverable by stripping in southern Alaska (Conwell, 1980, p. 505). The southern portion of the field (the Beluga field) is in the exploratory and predevelopment stage, although it is located in a region with little infrastructure to support mining operations. The current effort to develop base fields is oriented toward large-scale mining. The Diamond Chuitna Project is the largest planned operation. Approximately IV-20 20,000 acres of this field is held in lease by Starkey Wilson, Richard D. Bass Trust Estate and W. H. Hunt. There is a joint-venture between W. H. Hunt (Chuitna Coal Company) and Diamond Shamrock Coal Corporation, the Diamond Chuitna Project, of which Diamond Shamrock is the managing partner. There has already been considerable exploration and a preliminary mine plan has been developed. The Diamond Chuitna Project has idenitifed approximately 320 to 330 million recoverable tons of coal on these leases, at a stripping ratio of approximately - 5:1. The coal occurs in five seams, varying in thickness from 7 to 20 feet. A weighted average quality of the coal expected to be recovered is given in Table IV-7. A preliminary mining plan developed by Bechtel calls for an annual level of production of 10 to 15 million tons of coal per year. Current schedule calls for production to start in the 1988-90 time period. If the mine cannot be justified to be on stream by 1990, then it probably would not be justified again until the late 1990s. Diamond Shamrock believes there are three major market regions for the project; the Northwestern U.S., Hawaii, and the Japan-Korea-Taiwan area. The project is approximately 11 miles from the Diamond Chuitna proposed port facility. Transportation alternatives of conveyor, slurry pipelines and rail are currently under consideration. Iv-21 Table IV-7 COAL ANALYSIS BELUGA FIELD — DIAMOND CHUITNA PROJECT Tonnage Weighted Average Range Proximate Analysis (% by Weight Equilibrium Moisture Basis) Moisture 27.610 22.10-32.2 Volatile Matter 33.76 29.9-38.8 Fixed Carbon 30.28 27.1-35.4 Ash 8.06 5.0-15.9 Sulfur 13 .06-.26 HHV (Btu) 7807 6550-8470 Ultimate Analysis (% by Weight) Carbon 63.16 53.7-67.1 Hydrogen 4.34 3.0-5.3 Nitrogen 1.05 .7-1.5 Oxygen 20.29 18.0-23.5 Chlorine 05 .01-.22 Ash 11.15 6.6-19.6 Sulfur 18 .08-.62 Grindability 15.7-44.0 Initial Deformation (reducing atmosphere) 1960° F-2410°F IV-22 Placer-Amex has three reserve blocks in the Beluga coal field. The average quality of their reserves is presented in Table IV-8. The easternmost block (see Figure IV-2) is located about six miles from Chugach Electric's Beluga Station. This is their smallest reserve and has received little exploration. However, Placer-Amex has identified over 20 coal seams which average 10-feet thick per seam. The ‘westernmost reserves of Placer-Amex contain the Capps Mine Area. The surface rights are controlled by Cook Inlet Region Inc., a native corporation. This reserve is being evaluated for an eight million tons of coal per year coal- to-methanol synthetic fuels project. The research is being funded by the Department of Energy. Placer-Amex's central reserve block is adjacent to and immediately west of the Diamond Chuitna reserves. Two potential mine sites have been identified here, the Lone Ridge Mine and the Center Ridge Mine. This area is the subject of most of Placer-Amex's exploration work. It is for this area they are currently performing a coal export study for five million metric tons per year to Japan. This study has included drilling, sample analysis, engineering, and environmental baseline work (Resource Development Council, 1982). Both of the above proposed Beluga field mining ventures are under primary consideration for providing coal to the international market. In most cases, in-state demand for coal could be filled only if there were sufficient export markets to justify the development of what are considered optimally sized mines (5 million tons per year, or multiples thereof). Diamond Chuitna has expressed IV-23 Table IV-8 COAL ANALYSIS BELUGA FIELD—PLACER—AMEX LEASES Chuitna Property—Center Ridge Area Proximate Analysis, As Received (% by Weight) Moisture 23.5 Ash 13.9 Volatile Matter 36.0 Fixed Carbon 26.6 Sulfur (% by Weight) 18 HHV (Btu/Ib) 7,565 Chuitna Property—Lone Ridge Area Proximate Analysis, As Received (% by Weight) Moisture 25.0 Ash 13.6 Volatile Matter 32.8 Fixed Carbon 28.6 Sulfur (% by Weight) 0.14 HHV (Btu/Ib) 7,390 Capps Area Proximate Analysis, As Received (% by Weight) Moisture 23.4 Ash 23.3 Volatile Matter 28.4 Fixed Carbon 24.9 Sulfur (% by Weight) 17 HHV (Btu/Ib) 6,320 1V-24 an interest in discussing a mine dedicated to a mine-mouth power plant. Coal price information for the Beluga field is shown in Table IV-9. Mobil Oil Company has leases on the western flank of the Yetna River Basin which have been consolidated into two tracts. This area is approximately 90 miles northwest of Anchorage and 45 miles north of Cook Inlet. Presently, access into the area is only by air. Based on preliminary reconnaissance drilling, both lease blocks have been identified to contain multiple coal seams that are potentially mineable. Their analyses indicated in-place reserves of approximately 500 million tons, to depths of 250 feet. The quality of this coal is dependent upon the amount of partings in the seams, and varies considerably. Heat content ranges from 5,400 to 9,450 Btu per pound, moisture content ranges from 20 to 30 percent, ash from 6 to 40 percent and sulfur from 0.1 to 0.2 percent. Mobil has stated that their preliminary reconnaissance exploration program has located reserves suitable for further evaluation, from the viewpoint of marketability and production economics. A significant detailed exploration program is underway, the results of which are anticipated to be used to complete preliminary mine and market feasibility studies (Resource Development Council, 1982). As part of a continuing program by the U.S. Geological Survey (USGS) to collect and analyze representative samples of coal in the United States, 118 coal samples have been collected in Alaska. A summary of these analyses is found in Tables IV-10, IV-11, IV-12, and IV-13. Quality information about Alaskan coal IV-25 Table IV-9 BELUGA FIELD COAL PRICE DATA Production Heat Mining Level Content Operation (Tons Per Year) (Btu Per Pound) $ Per Ton Placer Amex 5,000,000 TPY 7,500 15.00—22.50 1,200,000 TPY 7,200 24.48—34.56 Diamond Chuitna +5,000,000 TPY 7,750 _ 1,000,000 TPY 7,750 18.60—23.25 Sources: 1 UsDOE, 1980, P. 3. 2 Conversation with Cole McFarland and Benno Putsch, Placer Amex, Inc., February 14, 1983. 8 Conversations with Robert B. Stiles, Diamond Chuitna, January 19 and 24, 1983. 1V-26 Price (f.o.b. Mine) $ Per MMBtu 1.00—1.50 1.70—2.40 1.20—1.50 Base Year of Dollars 1980 1983 1983 1983 Source (1) (2) (3) Table IV-10 SUMMARY OF U.S.G.S. ANALYSES OF ALASKAN COAL HEALY QUADRANGLE Observed Range Minimum Maximum Proximate Analysis (% by Weight) Moisture 14.8 32.7 Volatile Matter 27.3 38.8 Fixed Carbon 23.4 33.4 Ash 5.2 34.5 HHV (Btu/Lb.) 6130 9210 Ultimate Analysis (% by Weight) Hydrogen 4.6 6.9 Carbon 35.6 52.2 Nitrogen Bs) 8 Sulfur = 7 Oxygen 24.5 44.6 Ash Mineral Analysis (% by Weight) SiO, 16 51 Al,03 8 23 CaO 2 37 MgO 1.6 7.3 Na,O <.09 53 K,0 .29 2.8 Fe,03 1.7 9.1 TiO, 57 Ld SO; 1.0 27 P05 <.1l 1.2 Ash Fusion, Temperatures (°C) Initial Deformation 1170 1270 Softening 1210 1320 Fluid 1270 1390 Source: Rao and Wolf, 1980, p. 246-48. IV-27 Table IV-11 SUMMARY OF U.S.G.S. ANALYSES OF ALASKAN COAL KENAI QUADRANGLE Observed Range Minimum Maximum Proximate Analysis (% by Weight) Moisture 18.0 26.5 Volatile Matter 30.0 43.2 Fixed Carbon 20.5 33.1 Ash 4.8 26.9 HHV (Btu/Lb.) 6170 8580 Ultimate Analysis (% by Weight) Hydrogen 5.3 6.6 Carbon 35.4 50.3 Nitrogen 6 el Sulfur 2 1.3 Oxygen 30.8 40.2 Ash Mineral Analysis (% by Weight) : a SiO, 16 54 Al,03 10 21 CaO 4.1 23 MgO 3.3 8.1 Na2O -40 6.1 K,0 .39 4.1 Fe203 2.2 14 TiO, .57 97 SO; 2.3 6.8 P05 <1.0 1.7 Ash Fusion Temperatures (°C) Initial Deformation 1020 1240 Softening 1040 1290 Fluid 1070 1340 Source: Rao and Wolf, 1980, p. 249-51. IV-28 Table IV-12 SUMMARY OF U.S.G.S. ANALYSES OF ALASKAN COAL SELDOVIA QUADRANGLE Observed Range Minimum Maximum Proximate Analysis (% by Weight) Moisture 11.0 22.3 Volatile Matter 38.4 41.4 Fixed Carbon 277 33.0 Ash 8.3 23.5 HHV (Btu/Lb.) 7890 8610 Ultimate Analysis (% by Weight) Hydrogen 5.2 6.3 Carbon 45.4 50.0 Nitrogen 9 Lt Sulfur 3 4 Oxygen 24.6 37.9 Ash Mineral Analysis (% by Weight) SiO, 14 54 Al,03 7.9 25 CaO 2.9 25 MgO 75 4.0 Na2O .38 6.4 K,0 48 3.1 Fe203 2.6 17 TiO, 34 1.1 SO3 2.3 16 P205 <.10 3.1 Ash Fusion Temperatures (°C) Initial Deformation N/A N/A Softening N/A N/A Fluid N/A N/A N/A — Not Available Source: Rao and Wolf, 1980, p. 252-54. IV-29 Table IV-13 SUMMARY OF U.S.G.S. ANALYSES OF ALASKAN COAL UTUKOK RIVER QUADRANGLE Observed Range ' Maximum Minimum Proximate Analysis (% by Weight) Moisture 1.8 Volatile Matter 25 Fixed Carbon 32.8 Ash 2.3 HHV (Btu/Lb.) 8100 Ultimate Analysis (% by Weight) Hydrogen 4 Carbon 46.1 Nitrogen 1 Sulfur 2 Oxygen 11.3 Ash Mineral Analysis (% by Weight) SiO, Al,03 CaO MgO Na2O K,0 Fe2,03 TiO, SO3 P05 Ash Fusion Temperatures (°C) Initial Deformation Softening Fluid Source: Rao and Wolf, 1980, p. 255-57. 3.8 8.4 .80 1.0 45 12 1.8 >) 34 05 1140 1170 1190 IV-30 25.5 58.6 37.2 13820 5.8 72.5 1.8 36.7 61 36 q 38 12 7.1 4.2 33 | 5.6 17 8.9 1600 1600 1600 is dependent on an active geological mapping and exploratory drilling program. Most sampling done prior to this current program was of insufficient quantity and quality to be useful (Rao and Wolff, 1980, p. 263). Summar; The coal and transportation costs for coal from the Nenana and Beluga fields are summarized in Table IV-14. The Nenana coal costs are calculated on a delivered basis for two possible power plant sites discussed in the Power Supply - Study; Nenana North, which is approximately 50 miles north of the Usibelli Mine, and Nenana South, which is approximately 200 miles south of the Usibelli mine. The development of escalation assumptions is discussed below. One recent study (Secrest and Swift, p. 3.8ff) has attempted to estimate future costs for Beluga field coal. This estimate was developed from the expected increases in the price of various coals (Australia, Canada, South Africa, lower-48) delivered to Japan. The price increases for these competing coals would be based upon the increased costs of expanding production to meet the anticipated growth in the international coal trade. The authors then estimated how much Alaskan coal prices could increase and maintain their competitive position. The authors estimated that Alaskan coal prices (f.o.b. ship) could increase at a rate of 2.1 percent per year in real terms between 1985 and 2000. The above analysis was based on anticipated growth rates in the international steam coal market. If this market does not expand as anticipated, real price increases that could be supported by the export market would probably be lower. In the same study, Secrest and Swift (p. 3.16ff) also determined that a likely IV-31 Coal Source Power Plant Site Nenana North Site Nenana South Site Beluga Mine-Mouth COAL PRICE ASSUMPTIONS (1983$) Table IV-14 F.0.B. Mine? 21.03 21.03 20.93 7 Based on discussions with producers in the coal field areas. 2 Estimated by Burns and McDonnell. ($/ton) Delivered Average Freight? Escalation? ($/ton) ($/ton) ($/MMBtu) (1983-2002) 5.06 26.09 1.664 7.5% 8.51 29.54 1.884 7.5% NA‘ 20.93 1.35° 7.4% 3 Escalation is the average compound rate of increase. The escalation factors were: Coal (f.0.b. Mine) 1983-85 7.6% 1985-90 8.1% 1990-2002 7.1% 7 Estimated heat content is 7850 Btu per pound. . Estimated heat content is 7750 Btu per pound. § NA — Not Applicable. Rail Freight 8.1% 8.6% 7.6% IV-32 real rate of increase for the price (f.0.b. mine) of Nenana field coal would be 2 percent per year. This rate of increase was based upon the authors' analysis of the market price of Usibelli Coal Mine, Inc., during 1965-1980. They cited the fact that Usibelli claims this coal will have low or zero real price escalation, and that this observation has been supported by the terms and conditions of the Golden Valley Electric Association and Fairbanks Municipal Utility System contracts. The authors went on to state that, since the contracts expire in 1988 and 1985, respectively, the 2 percent real rate of increase is reasonable, since price performance after the expiration of the contracts cannot be predicated. Tussing and Erickson (1982, pp. 27-29) contend that the 2.0-2.1 percent real rate of inflation used by Secrest and Swift is influenced largely by its similar escalation assumption for fuel oil. They state that Secrest and Swift assumes that coal prices in Alaska will be directly influenced by international coal prices, which will be influenced by world oil prices. Tussing and Erickson also say that, with recent downward adjustments in the concensus opinion on future changes in world oil prices, Secrest and Swift's assumption of 2 percent real escalation for Alaskan coal is unfounded. Furthermore, they assert that “nothing in the world supply-demand picture suggests further real coal-price rises in the forseeable future" (Tussing and Erickson, 1982, p. 32). This assumption of no real price increases is further supported by the draft of the 1983 Energy Plan (DCED, 1983). In the list of "Parameters for Financial Analysis" in Appendix F of the Plan, the cost of coal is reported to show no real increase during the 1982-2000 time period. IV-33 For purposes of this study, a range of increase for coal prices (f.o.b. mine) would be O-2 percent above inflation. Using a 1 percent rate of real increase as an average case, the nominal rate of increase for the price of coal would be 7.6 percent for 1983-85, 8.1 percent for 1985-1990, and 7.1 percent thereafter. To estimate an inflation rate for the cost of rail transportation, the changes in selected freight rates in the Freight Tariff 105 series, which commenced in December 1977, was compared to the changes over the same time period in the Association of American Railroads’ (AAR) Index of Railroad Material Prices and Wage Rates for the United States. The Freight Tariff 105 freight rates were shown to increase at a lower rate than the AAR Index, but still higher than general inflation. Based on the past performance of the Tariff 105 freight rates, it is estimated that coal freight rates will escalate at a real rate of approximately 1.5 percent per year. In nominal terms, this would be 8.0 percent for 1983-85, 8.5 percent for 1985-90, and 7.5 percent thereafter. * ee He IV-34 nm) Part V - Alaskan Oil PART V ALASKAN OIL RESERVES Although Alaska is currently not self-sufficient in refined petroleum products, there appears to be substantial reserves available. As of January 1, 1982, there were 7,886 million barrels of proven crude oil reserves in Alaska (Alaska Oil and Gas Conservation Commission, 1981, p. 23), with about 993 million barrels of this being state royalty oil (see Table V-1). This quantity of oil is expected to be sufficient to cover projected cumulative in-state consumption through the year 2000 (Goldsmith and O'Connor, 1980, p. 17). Land on which there has been a discovery of oil or gas or which the USGS deems highly potential can be designated as a favorable petroleum geological province. The federal government is presently moving towards the award of leases on these onshore areas. Three such provinces have been designated: 1. Cook Inlet Tertiary - This province in south-central Alaska contains two oil fields and twelve gas fields onshore and extends offshore where five oil fields and three gas fields have been identified. 2. Gulf of Alaska Onshore Tertiary - Also lying in south-central Alaska, this province includes the Katalla field, site of Alaska's first oil production. The field produced 154,000 barrels of oil from 1902 to 1933, when it was shut in. Other wells have found signs of oil. V-1 Table V-1 ESTIMATED ALASKAN OIL RESERVES (As of January 1, 1982) Reserves! —Oil Field _ _!Millions of Barrels) _ Beaver Creek 1 Granite Creek 35 Kuparak River 447 McArthur River 90 Middle Ground Shoal 26 Prudhoe Bay 7,264 Swanson River 19 Trading Bay 4 Total 7,886 = Reserve is defined as petroleum discovered, defined and producible, but not yet produced. Source: Alaska Oil and Gas Conservation Commission, 1981 Statistical Report, p.23. V-2 3. Cape Lisburne - This region in northwest Alaska includes the portion of the North Slope west of the National Petroleum Reserve-Alaska. The eastern part of the province contains Prudhoe Bay, Umiat, and Kuparuxk oil fields and Barrow gas field. The Alaskan Outer Continental Shelf is expected to play an important role in supplying the U.S. with crude oil through the year 2000. Ten areas have been identified which could help ease the U.S. transition from imports to alternative sources. As estimated by the USGS, these areas could contain more than 10 billion barrels of oil. Estimating timely discoveries and eight-year production lead time, these areas could supply 1 to 2 million barrels per day of new oil by the early 1990s (Oil & Gas Journal, Jan. 12, 1981). In 1981, total annual Alaskan oil production was 587,366,066 barrels, which was slightly less than in 1980. Production since 1960 has increased over ten-fold (see Table V-2), with production becoming relatively stable in 1981 and 1982. As of March 1962, there were four refineries in Alaska, with an aggregate crude capacity of 150,500 barrels per calendar day. OIL PRICE PROJECTIONS The assumptions on the long-term performance of the price of petroleum products used in this report will have a substantial impact on the results of Burns & McDonnell's evaluation of Chugach Electric's long-term energy alternatives, which will culminate in the Power Supply Study. There are three items that are particularly impacted by the long-term price of oil: V-3 Table V-2 ANNUAL ALASKAN OIL PRODUCTION (1960—1981) Total Production Year (Barrels) 1960 557,999 1961 6,326,501 1962 10,259,110 1963 10,739,964 1964 11,053,872 1965 11,131,271 1966 14,364,432 1967 28,913,488 1968 66,145,673 1969 74,315,218 1970 83,614,089 1971 78,784,865 1972 73,562,103 1973 73,139,415 1974 72,267,358 1975 71,980,167 1976 67,008,789 1977 171,353,027 1978 447,810,171 1979 511,335,085 1980 591,642,018 1981 587,336,066 Source: Alaska Oil and Gas Conservation Commission, 1981 Statistical Report, p.6. v4 Energy Demand: The price of oil will affect the level of activity in exploratory drilling and, to a large extent, determine the level of tax revenues derived from oil production taxes. Both of these factors can impact the level of economic activity in Alaska which, in turn, will affect the level of energy demand. Cook Inlet Basin Natural Gas Prices: The last two natural gas supply contracts executed by Enstar for the purchase of Cook Inlet Basin gas have tied the "inflationary" adjustment of the base price of the gas to charges in the f.o.b. price of No. 2 fuel oil at the Tesoro refinery at Nikiski, Alaska. This gas price will become part of the tariff charged for gas supplied to Bernice Lake, International and Knik Arm. This price adjustment mechanism may also appear in the contracts Chugach Electric is now negotiating with Shell Oil. In this study, the long-term trends in world crude oil prices has been used to represent the long-term trends in the price of refined products in Cook Inlet Basin. This is a valid assumption for long-term trending, as the ‘price of crude oil is the overriding determinant of the price of the refined products. This does not hold so well in shorter time periods, as the short-term prices of refined products will be influenced by other market conditions such as inventory levels and seasonal consumption patterns. Export Market Development: Many plans for the development at Alaska's energy resources are dependent upon the existence of substantial export markets. These export projects rely upon relatively high international oil prices in order to justify their high development costs. For example, the Beluga Coal field projects rely upon high world oil prices to encourage Pacific Rim utilities and industries to decrease their V-5 dependence on oil through oil-to-coal conversions and the construction of new coal-fired facilities. The TAGS and PALNG projects would place Alaskan LNG in direct competition with oil in Japan. The ANGTS project would place North Slope natural gas in competition with other natural gas supplies in the lower 48, where natural gas prices are determined in part through government regulation and in part through competition with refined petroleum products. In most of the above cases, the loss of export markets would reduce the availability of energy resources. However, the termination of the PALNG project has released approximately 660 Bef of Cook Inlet natural gas for other purposes, which could include in-state consumption. Review of Projections The concensus opinion on oil price forecasting seems to be that the real price of oil will decline in the next few years and climb slowly in the long term (Tussing and Erickson, 1982, pp 15-18). This is a substantial change from the assumption of constantly increasing real-world oil prices used until very recently in many studies of long-term energy alternatives, including the "Railbelt Study" performed by Battelle Pacific Northwest Laboratories (Secrest & Swift, 1982). In that study, a 2 percent rate of increase for real oil prices was selected as an "average" case, based on what then was a concensus opinion of many experts in the energy industry. The low escalation case was assumed to be a real rate of increase of one percent per year, and the high case was set at a real rate of increase of three percent per year (Secrest and Swift, p 8.4). The change in the long-term outlook for oil prices results from the observations that: o The world's intensity of use of oil products (on a barrels per unit of GNP basis) has begun to decrease; o Non-OPEC sources of oil have successfully responded to past increases in world oil prices by developing new capacity; and o OPEC appears to be having trouble in controlling the downward trend in world oil prices through further production cutbacks--many OPEC countries cannot make further production cutbacks due to their heavy debt burdens and ambitious domestic development programs. The result of these recently observed events is that OPEC is losing its position as the world's price-setter for oil, at least for the short and intermediate term. In the long run, increases in world demand for energy due to the economic development of third-world nations could absorb much of the world's excess oil production capacity and lead to real increases in the world price of oil. There does not yet seem to be a concensus on the likelihood or timing of this event. Given the uncertainties surrounding the future price of oil, Burns & McDonnell has decided to develop three alternative oil price paths based upon the assumptions used in recent studies. The seven recent reports which were consulted for this evaluation were: V-7 o Alaska Department of Revenue, 1982, Petroleum Production Revenue Forecast, Quarterly Report, December 1982; o American Gas Association, 1983, Total Energy Resources Model: The Winter 1983 A.G.A. - TERA Base Case; o Chase Econometrics, 1983, Energy Analysis Quarterly, First Quarter, 1983; o Department of Commerce and Economic Development, 1983, 1983 Long Term Energy Plan (Working Draft); o Merrill Lynch Economics, Inc., 1983, Long-Term Energy Outlook, 1982-1992; o Secrest and Swift, 1982, Railbelt Electric Power Alternatives Study: Fossil Fuel Availability and Price Forecasts; and o Tussing and Erickson, 1982, Alaska Energy Planning Studies .... The long-term crude oil price projections developed in these studies, in terms of real rates of increase, are summarized in Table V-3. These projections represent a wide range of opinion on the direction of oil prices in the near (1982-1985) and long (1985-2000) term. The Alaska Department of Revenue (DOR) develops estimates of the future price of crude oil to help in its determination of the future revenues Alaska can expect to collect from oil and gas production royalties. Their findings on crude oil v-8 COMPARISON OF RECENT PROJECTED RATES OF INCREASE Table V-3 FOR THE WORLD PRICE OF CRUDE OIL Source Tussing and Erickson Alaska Dept. of Revenue — Low Merrill Lynch? Alaska Dept. of Revenue — Average Alaska Dept. of Commerce and Economic Development — 1983 Energy Plan Chase Econometrics — Base Case Secrest & Swift — Low American Gas Association Secrest & Swift — Medium Alaska Dept. of Revenue — High Secrest & Swift — High Notes: i Merrill Lynch projection estimate was given to 1992; Burns & McDonnell extended the trend to 2000. Sources: Tussing and Erickson, 1982. Alaska Department of Revenue, 1982. 1982-1985 -5.2% -15.9% -2.5% -8.9% -3.4% -9.0% +1.0% -0.7% +2.0% -3.0% +3.0% Department of Commerce and Economic Development, 1983. Secrest and Swift, 1982. Chase Econometrics, 1983 Merrill Lynch Economics, Inc., 1983. American Gas Association, 1983. v-9 Time Period 1985-2000 5.2% -2.1% 0.0% +1.4% +1.4% +2.8% +1.0% +1.9% +2.0% +3.7% +3.0% 1982-2000 -5.2% -4.1% 0.4% -0.3% +0.6% +0.7% +1.0% +1.5% +2.0% +2.6% +3.0% prices and royalty revenues are presented in quarterly reports. Burns & McDonnell has obtained the probability distribution matrix that documents the average oil prices reported in the DOR Quarterly Report. From this matrix, Burns & McDonnell has established low, average, and high projections for the DOR projections, as shown on Table V-3. Due, in part, to the way the DOR has constructed their probability matrix, the low price forecast was taken at the 17 percent probability level and the high price forecast was taken from the 83 percent probability level. This means that DOR believes that there is only a 17 percent chance that the price of oil will change at a rate lower than what Burns & McDonnell has identified as the "low" case, and an 83 percent chance that the rate of increase will be lower than that selected by Burns & McDonnell to represent the DOR's "high" case. The American Gas Association (AGA) periodically publishes the results of its Total Energy Resource Analysis (TERA) Model. The AGA represents the interests of the natural gas production and transmission industry. The TERA model is constructed primarily to evaluate the impact of federal regulations and current pricing trends in other fuels upon the pricing of various categories of natural gas. The AGA oil price information summarized in Table V-3 is taken from their February 8, 1983 TERA report, the most recent one available. Their assumed decrease in the real price of oil in the 1982-1985 time frame is not as drastic as some other recent studies. In recent communications, an AGA representative has said that they may make a downward revision in its short-term oil price assumptions in the run of the TERA model scheduled for release in August 1983. V-10 The Chase Econometrics projection shown on Table V-3 is reflective of one segment of the current thinking on future oil prices. Its short-term (1982-85) forecast is similar to DORs, with a more severe decrease than that projected by Merrill Lynch, DCED or AGA. Their projected long-term (1985-2000) rate of increase is higher than the other recent projections, resulting in a composite rate of increase for the 1982-2000 period very similar to that forecasted by DCED. The draft of the Department of Commerce and Economic Development's (DCED) 1983 Long-Term Energy Plan discusses long-term trends in crude oil prices in its Appendix D. In short, DCED's projection shows a less drastic decrease in oil prices between 1982 and 1985 than does the DOR average case. However, in the post-1985 period, the DCED and DOR reports are in general agreement on the average projected real rate of oil price increase. The DCED report did not present any "low" or "high" oil price cases in its report. The information from the Merrill Lynch Econdmics report appeared in an article in Energy User News (February 24, 1983). This projection assumes that the oil- producing companies will only be able to obtain price increases equivalent to general inflation after 1985. The Secrest and Swift report, which was part of Battelle's "Railbelt Study," utilized low, medium and high oil price growth projections of 1.0 percent, 2.0 percent and 3.0 percent, respectively. As discussed earlier in this chapter, these assumptions were a valid summarization of the then-current consensus opinion, but are no longer so. In comparison, the net effect of the DCED's V-11 price growth assumption is 2.6 percent per year over the 1982-2000 time period, and the net effect of DOR's high growth case in 0.6 percent per year over the same time period. The range of projections used by Secrest and Swift appear to represent the "high" portions of more recent projections. The Tussing and Erickson report came to the conclusion that the long-term market clearing price of crude oil is approximately $13.00 dollars per barrel in constant 1982 dollars. The -5.2 percent values entered on Table V-3 for the Tussing and Erickson report represent the average annual rate of decrease that would be required to reduce the price of oil to $13.00 per barrel by the year 2000. The Tussing and Erickson study did not specify how long it may take for the market price of oil to return to the $13.00 per barrel level; therefore, the -5.2 percent rate of decrease can be regarded only as indicative of the type of price decrease that would be required to achieve a $13.00 per barrel price by 2000. Given all of the above considerations, Burns & McDonnell believes that it would be reasonable to utilize the DCED projections as its medium oil price, and the DOR low and high cases as low and high cases in this report. It is particularly expeditious to use the DCED oil price growth rates in this study, as the economic growth information developed by DCED in the Energy Plan is being used in the "Power Requirements Study" Burns & McDonnell is preparing for Chugach Electric. The low and high oil price growth information appears to be representative of the growth trends of the more extreme projections reviewed in this report, without being the most extreme cases. V-12 Fuel Oil Prices Fuel oil products are available from Tesoro and Chevron USA. Fuel oil prices were obtained from these two companies in June 1983. At their Anchorage terminals, Tesoro and Chevron have quoted posted prices of 86.89 and 88 cents per gallon, respectively, for No. 2 (distillate) fuel oil. Chevron dues not maintain a posted price for No. 2 fuel oil at its refinery on the Kenai Peninsula. Tesoro's posted price for No. 2 fuel oil at its Kenai Peninsula refinery is 85.3 cents per gallon. Neither refinery maintains posted prices for No. 6 (residual) fuel oil. Chevron ships its residual fractions as a feedstock to other refineries in California. Tesoro sells most of its No. 6 fuel oil under long-term contracts; however, some is sold to Japanese fishing fleets on an annual contract basis. A representative price for this would be approximately $27 per barrel, or about 64 cents per gallon. Tesoro's No. 6 fuel oil has a heat content of 6,200,000 Btus per barrel and has a sulfur content of 0.5 to 0.7 percent. Estimated future prices for No. 2 and No. 6 fuel oil are presented in Table V-4. As explained in the previous section, the future No. 2 fuel oil prices are based on the DCED 1983 Energy Plan crude oil price projections contained in Table V-3. Estimated future prices for No. 6 fuel oil are subject to considerable variation, as No. 6 fuel oil is a byproduct of the refining process and tends to be more influenced than No. 2 fuel oil by short-term conditions of excess or deficit capacity. No. 6 fuel oil is generally used for steam production, and its major competition in the lower - 48 is bulk sales of natural gas to utilities and industry. V-13 Of the seven sources consulted above for crude oil price projections, five make some attempt at projecting the price of refined petroleum products. The Secrest & Swift escalation estimate is 2 percent per year in real terms, with low and high estimates of 1 and 3 percent, respectively. This projection is based on relatively old assumptions and is not considered further here. Of the other four projections, the DCED report (1983) estimates that the price of all refined petroleum products (including No. 6 fuel oil) will escalate in real terms at 1.5 percent per year over the study period, based on rates of 0.5 percent per year through 1985, 2.2 percent for 1985 to 1990, and 1.3 percent thereafter. The Merrill Lynch report projected a 6.8 percent decrease in No. 6 fuel oil prices for 1982-1983, and then essentially no real price increases through 1992 (the last year of their study period). The AGA and Chase Econometrics have estimated higher long-term escalation rates over the 1982-2000 time period, 1.9 and 2.5 percent, respectively. The AGA projection estimated an average real rate of price decrease of -0.4 percent for the 1982-1985 period, while the Chase Econometrics report showed a -2.2 percent rate of change for the same time period. Unlike the AGA report, the Chase Econometrics report provides annual price information, not just three- to five-year time intervals. The Chase Econometrics report projected a substantial (18 percent) price decrease for 1982-1983, with a large rate of increase (5.7 percent) for 1983-1990, and a lower rate (2.6 percent) thereafter. For the purposes of this study, the DCED projection of real price increases for residual fuel oil will be considered the v-14 base case, as it is about in the middle of the projections considered herein, and it can be assumed to have particular application to Alaska. This projection is used in Table V-4. ee eK V-15 Table V-4 SUMMARY OF FUEL OIL PRICES No. 2 Fuel Oil! No. 6 Fuel Oil? Year Cents/Gallon $/MMBtu $/Barrel $/MMBtu 1983 87.43 6.30 27.004 4.35 1984 89.9 6.48 30.19 4.87 1985 92.5 6.67 33.76 5.45 1986 100.4 7.24 36.92 5.95 1987 108.9 7.85 40.37 6.51 1988 118.1 8.52 44.15 7.12 1989 128.2 : 9.24 48.28 7.79 1990 139.1 10.03 52.79 8.51 1991 149.5 10.78 56.68 9.14 1992 160.7 11.59 60.87 9.82 1993 eo) 12.45 65.36 10.54 1994 185.7 13.39 70.18 11.32 1995 199.5 14.38 75.36 12.15 1996 214.5 15.47 80.92 13.05 1997 230.5 16.62 86.89 14.01 1998 247.8 17.87 93.30 15.05 1999 266.3 19.20 100.18 16.16 2000 286.3 20.64 107.58 17.35 2001 307.7 22.19 115.51 18.63 2002 330.7 23.84 124.03 20.00 1 Price projection based on estimates for crude oil prices from DCED, 1983, p. D-3. 3 Price projection based on estimates from DCED, 1983, p. F-2, for refined petroleum products. Average price No. 2 fuel oil at Tesoro’s and Chevron’s Anchorage terminals as of June, 1983. 4 Representative price for large volume annual contract sales, as provided by Tesoro. 3 V-16 Part VI - Refuse-Derived Fuel PART VI REFUSE-DERIVED FUEL AVAILABILITY AND USE Refuse-derived fuel (RDF) is a general term for solid boiler fuel manufactured from municipal waste. In order to be used economically as a boiler fuel, municipal waste must be available in sufficient quantities within a relatively limited area to minimize the extra handling and collection costs. These costs must remain low enough to make the extra cost of utilizing competitive with the cost of alternative fuels. In cases where landfill sites are distant from the waste collection area, part of the advantage of RDF can be measured in transportation cost savings. Only the municipalities of Anchorage and Fairbanks generate sufficient volumes of municipal waste to consider the use of RDF as a power boiler fuel. This report only addresses the potential for the development of Anchorage's municipal waste, as Fairbanks is outside Chugach Electric's service territory. It is assumed that the RDF potential in the Fairbanks area would be developed by one of the local utilities. Burns & McDonnell has discussed the development of Anchorage's RDF potential with Mr. Joel Grunwaldt of the Anchorage Department of Solid waste. Anchorage is rapidly approaching the capacity of its exist 1g landfills, and it will be difficult to find other landfill sites close to the area where the waste is generated. The municipality believes that if it can sell the energy generated VI-1 by an RDF facility, the cost of preparing RDF will be comparable to the cost of the longer truck haul to future, more remote landfill sites. The RDF facility would also reduce the amount of waste going to the existing landfill site, thereby extending its life and delaying the costs that will be incurred when a new site is developed. The heat content of shredded and air-classified RDF is approximately 6,700 Btu per pound. Shredding and classifying is necessary to remove materials detrimental to the furnace performance and operation. Although no specific data is available, RDF is expected to contain greater percentages of sulfur and nitrogen compounds than high-quality coal. This may make it difficult to site an RDF plant within a metropolitan area, negating the benefits of reduced transportation distances, and would probably impose an additional cost for some type of pollution control equipment. A recent study (Secrest and Swift, page 5.1) estimated that the volume of municipal waste generated in Anchorage in 1980, 161,000 tons, could support the fuel requirements of 21.7 MW of electrical generating capacity at an 80 percent load factor and a heat rate of 12,000 Btu/kWh. Recent communications between Chugach Electric and URS Company have indicated that the current capacity estimate for an Anchorage RDF-fueled power plant would be 10 to 12 MW in 1987 and approximately 25 MW in 2005. COST Based upon the limited available information, Secrest and Swift have estimated that the costs incurred by transporting RDF from the existing Anchorage vI-2 shredding facility to either Fort Richardson or a new boiler at the Knik Arm Station would be offset by the savings incurred by not having to dispose of the waste at a landfill. The cost of the RDF then becomes the cost of utilization associated with this fuel. Since Secrest and Swift has identified the coal boiler at Fort Richardson as the most likely RDF facility, the fuel's cost of utilization would include the capital and financing costs associated with the conversion project, plus the additional operating costs at the plant relative to the fuels normally used (natural gas and coal). Their estimated cost of utilization, including transportation of the RDF from the shredder to Fort Richardson and the cost of conversion, was $19.82 in 1981 dollars or about $1.50 per MMBtu. This cost could be reduced by any cost savings attributable to reduced landfilling costs. Secrest and Swift noted that the Fort Richardson boiler is nearing the end of its economic life, would probably be derated, and would provide negligible power for civilian consumption. The Anchorage Department of Solid Waste Services has contracted with URS Company for engineering studies on the. long-term alternatives available for waste disposal. One portion of these investigations will identify the cost of utilization of RDF for power generation. This study is expected to be completed by the end of 1983, with recommendations available by mid-1983. Until this investigation is completed, there is little other cost data available on RDF. However, the conclusion can be reached that, if favorable economics and environmental conditions do exist, the RDF resource is readily available i» the Anchorage area. eee Re VI-3 Part VII - Wood PART VII wooD INTRODUCTION Wood is available for power generation either as solid or chipped roundwood or mill residues. Wood is currently used as an energy source in Alaska as a residential space heating fuel, and in cogeneration at pulp and lumber mills in southeast Alaska and on the Kenai Peninsula. The economics of wood energy are favorable primarily in comparison to fuel oil as a residential heat source. The economics of wood-fired power plants (24-45 MW) have been described as "less certain" (Booz-Allen & Hamilton, 1982, p. II-16). It has been shown that wood has economic potential for direct power generation only in comparison to isolated diesel-fired generators. (Reid, Collins, 1981, Conclusion). Wood is presently under evaluation for use in direct power generation for remote interior communities (Reid, Collins, 1981). WOOD FOR DIRECT POWER GENERATION A study evaluating the suitability of wood for power generation (Reid, Collins, 1981) identified wood energy technologies for use in small interior communities. Approximate average electrical demand for communities identified as sources for direct wood-fired generation is less than 100 kW. Three generation alternatives were identified, and one alternative appears practical. A wood-fired steam plant is generally regarded as reliable. However, it does not appear appropriate for a small interior community due to the number and qualifications of the people required to run the plant. Wood gasifiers with and VII-1 without gas cleaning systems were also investigated in the Reid, Collins report. Gas cleaning systems have not yet proved reliable but it is anticipated that they will become more reliable in the future. Because wood gasifiers usually require water as part of the process, they do not appear suitable for an Alaskan village. A wood gasifier without gas cleaning is a simpler gasifier/generator and may be practical for a remote community. The amount of wood required to fuel a gasifier/generator will depend on the type of wood and the electrical demand. Heat content of typical woods found in Alaska vary from approximately 15 to 20 million Btu per cord. The amount of land required to produce wood for gasification has only been approximated. Hardwoods are most likely candidates for gasification since they are virtually unused for other purposes and grow quickly. A 35-kW gasifier/generator would require approximately 330 cords of wood per year, which is equivalent to a cut of 8.8 aeces (Reid, Collins, 1981, Sec 3.2). Assuming a 50-year rotation period, this wood consumption would require that approximately 13 acres of timber would be devoted per kilowatt of generation capacity. RESIDENTIAL HEATING Wood is available for space heating throughout Alaska, except in the North Slope Region. The Southeast and Railbelt regions of the state have sufficient acreage to allow for wood harvesting. The major limitation on wood harvesting is distance from consumer to timberlands and the accessibility of timberlands. Sustainable annual yields in Alaska range from two to four acres to support one cord of wood, with annual heating requirements for a typical home amounting to 20 to 40 acres of available timberland (DCED 1983). More energy efficient house VII-2 designs have been developed which can reduce annual consumption from ten cords per year to two or three. In urban areas of Alaska, current prices for wood average $100 to $120 per cord (DCED, 1983); this is comparable to fuel oil costs of $1.30 per gallon. However, accessibility to woodland and harvesting costs may raise the cost of wood beyond levels competitive with the price of oil. COGENERATION There are currently five wood mills, all in southeastern Alaska, that generate power from wood waste. These mills and their cogeneration capacities are: Louisiana Pacific - Ketchikan 10-15 MW Alaska Lumber & Pulp Co. - Sitka Unknown Alaska Timber Corporation - Klawock 4 MW Schnabel Lumber Co. - Haines 4 MW Mitkoff Lumber Co. - Petersburg Unknown The Alaska Resources Corporation (ARC) has invested in two of the southeast Alaska power projects, the Schnabel Lumber Company project at Haines, and the Alaska Timber Corporation project near Klawock. A recent study (Kerr, 1983) developed wood fuel quantity and quality estimates for the Haines project. Costs vary directly with the area logged and are responsive to the type of harvest, form of log transportation, defects, season logged, wood storage time and location, and current market conditions. Based on the information provided in the report (Kerr, 1983), the portion of logging costs attributed to hog fuel, and its fuel conversion costs, result in a hog fuel utilization cost of VIT=3 approximately $1.53/MMBtu. Hog fuel is the primary fuel for power generation and is a second-order residue by-product consisting of bark, sawdust, and fines. Given likely levels of power demand, the Schnabel Lumber Company was determined to have sufficient fuel resources from its long-term timber sale to meet the needs of Haines. It was assumed the sawmill produced enough wood residue on a continuing basis. Alternate fuel sources include other mills (Wrangell, Petersburg, Ketchikan, Sitka), beach logs and harvesting wood for fuel production. It has been recommended that an in-depth analyses be performed to determine environmental difficulties, costs, and total supply (Kerr, 1983). The Mitkoff Lumber Company is planning to install a gasifier, and then generate power from the gas. Louisiana Pacific's Ketchikan mill presently sells some power to the local utility. They also own another mill at Seward which is presently closed. If reopened, it would be feasible to install electrical generation facilities there. There are also two mills with generation potential in Chugach Electric's area of interest, the Kenai Sawmill and the Kodiak Lumber Mills, Inc., operation at Tyonek. The Kenai mill, however, was closed due to National Forest Service restrictions and is not expected to be reopened. The mill at Tyonek is a seasonal operation and it is expected that it may not be reopened this year. A study on the feasibility of cogeneration using wood waste as fuel has been developed for Lewis County, Washington (Rocket Research Company, 1980). Based vII-4 on a fuel supply and market survey, as well as a preliminary economic and financial analysis, a 25-MW plant was judged to be potentially feasible. ee ene VII-5 Part VIII - Peat PART, VITL PEAT INTRODUCTION Peat is defined as geologically young coal. It dines of partially decomposed plant matter and inorganic materials that have accumulated over time in an environment saturated by water. Peat is used as a fuel in the Soviet Union and northern Europe. Several countries, including the United States, have active peat research programs. RESOURCES Alaska has several massive peat deposits (Figure VIII-1). Since a good part of the resource is distributed throughout remote and practially inaccessible areas, estimates of total peat resources vary. An initial estimate by the Department of Energy (1979) showed Alaska to include 27 million acres of unfrozen peat. A more recent study (Ekono, Inc., and Northern Technical Services, 1980) estimated probable fuel peat occurrences to exceed 100 million acres statewide, with 5.5 million acres on the Kenai Peninsula and the Susitna Valley area showing a higher probability of occurrence of fuel peat deposits. Another recent study (Rawlinson and Hardy, 1982) indicated total land areas of peat of approximately 25 million acres, of which 5 million acres are considered as unfrozen fuel-grade peat. Estimates of potential energy range from 63 quads (Rawlinson and Hardy, 1982) to 741 quads (DOE, 1979). A preliminary assessment of. peat resources in Alaska (Ekono and Northern Technical Services, 1980) (Ekono, 1980) identified peat deposits in the Susitna VIII-1 Source: Northern Lechnical Services and EKONO,Inc., Peat Resource Estimation in Alaska, Final Report, 1980, Barrow Figure VIII-1 POTENTIAL ALASKAN FUEL PEAT OCCURRENCES VIN-2 Table VIII-1 SUMMARY OF ALASKA PEAT COMMERCIAL FEASIBILITY STUDY Sites 1. Susitna Basin (Trapper Lake) 2. Beluga (near power plant) 3. Kenai (between Kenai and Cohoe) End-Products Electric power via steam boiler Electric power via gasification combined cycle Methanol 2,500 ton/day scale (gasification/synthesis) Ammonia 1,200 ton/day scale High volatile solid fuel briquettes Low volatile granuals with co-product fuel oil OB te arvesting/Transport Systems Traditional milled peat with truck transport Suction dredging with pipeline Continuous deep cutting (deep milling) with conveyor Mechanical wet excavation with truck transport Floating mechanical (clamshell) excavator with pipeline transport Sime tir wy ewatering Technology High performance press (Bell/Sulzer) with various thermal drying alternatives High performance press with multiple effect evaporation (Carver-Greenfield) High severity wet carbonization (Koppelman) Partial oxidation (Zimpro) Low severity wet carbonization with 2-stage fluid bed drying VPenr~g Plant Scales/Concepts 1. 250,000 ton/year high volatile fuel output 2. 2,000,000 ton/year high volatile fuel output 3. 262,000 ton/year semi-coke plus 100,700 ton/year fuel oil, on-site construction 4. 262,000 ton/year semi-coke plus 100,700 ton/year fuel oil, float-on/float-off modular construction Source: Wheelabrator-Frye, Inc., 1983. VII-3 Basin as potential sources for fuel. However, detailed estimates were not developed. Of the samples taken and analyzed, only 36 percent had ash contents less than 25 percent, the limit of peat fuel as specified by the DOE. The study recommended further investigations to evaluate the resource potential, and further refinement of existing data to assess the associated technological, economic, and environmental factors of peat resource development. VIABILITY OF PEAT UTILIZATION Ekono (1980) evaluated the technical viability of utilization of peat resources. It concluded peat could be utilized for both space heating and power generation, subject to certain limitations. Peat-fired furnaces are in use in Europe with heating capacities of up to 25 kW. Larger heating plants, up to 20 MW, can afford more elaborate mechanics that allow the use of milled peat in a well-controlled manner. Small peat-fired steam cycle plants use firing equipment similar to large heating plants, but adapted to a steam boiler that generates steam for the prime mover. All components of a small-scale steam generating system are proven and commercially available, but seldom are combined in a plant. Other forms of energy have been more competitive, due to the high investment and operating costs required for a peat-fueled plant. The major share of world fuel peat consumption is in steam boiler and turbine generating plants of 30 to 700 MW. Hither cogeneration or condensing power generation can be applied, with a condensing plant obtaining an overall VIII-4 efficiency of 35 percent. A favorable combination of fuel, power demand, and especially of thermal energy demand in cogeneration cases, is required for feasible operation. The high costs associated with transporting peat usually limits practical transportation to 100 miles, thus requiring plants to be sited near the peat deposits. If a coal is available within a radius of 150 miles of a plant, it would probably be more competitive (Ekono, 1980). Laboratory and pilot-plant experiments on peat gasification equipment are being run in several countries. A few experiments have been made using peat gas as a fuel for internal-combustion engines. Gas turbines are also being investigated. Gasifier equipment is subject to very steep economies of scale, and only large plants are under consideration for ongoing DOE programs. A feasibility analysis (Wheelabrator-Frye, 1983) was prepared to identify and document the commercial prospects for alternative methods of peat utilizaiton for energy production in south-central Alaska. Various harvesting, transportation, and dewatering alternatives were analyzed for three potential sites producing various end products (see Table VIII-1). The results of the study indicated that none of the harvesting and dewatering processes evaluated appear capable of producing a product which could be cost competitive with Alaskan coal. Several peat-derived products may command a premium over Alaskan coal based on lower moisture content, lower ash content, and final fuel form. Utilization of peat for electric power generation (via either steam boiler or gasification combined cycle) would not be cost competitive with the use of Alaskan coals for these markets. The most effective method for near-term commercialization of Alaskan peat appears to be coproduction of peat char VIII-5 granules and industrial fuel oil at a substantial-scale plant located near tidewater utilizing peat feedstock averaging 12 percent ash or _ less (Wheelabrator-Frye, 1983). COST ESTIMATES The cost of delivered peat is dependent on both the distance and method of transportation and the harvesting method used. Cost estimates of peat and peat- derived fuels as obtained and presented by Ekono (1980) and Secrest and Swift (1982) are presented in Table VIII-2. These estimates are for potential plant sites located near the deposit to be utilized. Expressed in 1983 dollars, these costs range from $1.90 to $5.10 per MMBtu. Larger milled-peat harvesting operations producing 1 to 6 million tons per year have been estimated to provide peat at $0.75 to $1.05 per MMBtu. Hydraulic harvesting and mechanical dewatering of 1 million tons per year is estimated to cost about $0.83 per MMBtu (Secrest and Swift, 1982, p. 4.4). Such large harvesting operations should be capable of supplying fuel for 120-MW to ‘700-MW plants. However, preliminary information regarding Alaska's resource base does not indicate areas of sufficient size to sustain operations of this size. Because of the capital-intensive nature of harvesting and fuel preparation, and steep economies of scale, smaller plants are not yet feasible unless competing energy costs are high. Table VIII-3 gives the estimated power generation costs of various-sized peat cogenerating plants (Ekono, 1980). * ee Ke VIII-6 Table VIII-2 COST ESTIMATES OF PEAT BASED FUELS (1980$) Process Method $/Million Btu Milled Peat 1.60—2.30 Sod Peat 2.90—4.20 Peat Briquettes 4.20—5. 20 Peat Pellets 3.40—4.80 Fuel Peat 1.95—2.40 Peat Fuel From Wet Carbonization 2.70—4.20 Source: EKONO, Peat Resource Estimation in Alaska, Vol. 2, p. 27. Table VIII-3 ESTIMATED POWER GENERATION COSTS FROM PEAT (1980 $) Plant $/kWh 250kW Cogenerating Steam 0.18—0.26 Engine Plant, Sod Fired 1MW _ Cogenerating Steam 0.12—0.18 Turbine Plant, Mill Fired 30MW _ Cogenerating Steam 0.03—0.07 Turbine Plant, Mill Fired 60MW _ Cogenerating Steam 0.02—0.04 Turbine Plant, Mill Fired Source: EKONO, Peak Resource Estimation in Alaska, Vol. 2, p. 28. VII-7 Bibliography BIBLIOGRAPHY Documents Alaska Department of Revenue, Petroleum Revenue Division, 1982, Petroleum Production Revenue Forecast, Quarterly Report, December 1982. American Gas Association, 1983, Total Energy Resources Model: The Winter 1983 A.G.A.-TERA Base Case, Arlington, VA, American Gas Association, 35 p. Booz-Allen & Hamilton, et al, 1982, State of Alaska Long Term Energy Plan, 1982 Report, prepared for the Division of Energy and Power Development, Department of Commerce and Economic Development, State of Alaska. » 1983, Evaluation of Alternatives for Transportation and Utilization of Alaskan North Slope Gas (Draft Summary Report), prepared for the State of Alaska Task Force on Alternative Uses of North Slope Natural Gas. Chase Econometrics, 1983, Energy Analysis Quarterly: First Quarter, 1983, Bala Cynwyd, PA, Chase Econometrics. Conwell, C.N., 1983, "Alaska," in 1982 Keystone Coal Industry Manual, New York, Mining Informational Services, McGraw Hill Mining Publications, 1466 p. Department of Commerce and Economic Development (DCED), Division of Energy and Power Development, State of Alaska, 1983 Long Term Energy Plan, Working Draft. Department of Natural Resources, Division of Geological and Geophysical Surveys, 1983, letter-report to Eric P. Yould, Alaska Power Authority on the subject of economically recoverable undiscovered oil and natural gas resources in Cook Inlet. Ebasco Services, Incorporated, 1982a, Use of North Slope Gas for Heat and Electricity in the Railbelt, Report on Existing Data and Assumptions, prepared for the Alaska Power Authority. , 1982b, Use of North Slope Gas for Heat and Electricity, in the Railbelt, Report on System Planning Studies, prepared for the Alaska Power Authority. , 1982c, Use of North Slope Gas for Heat and Electricity in the Railbelt, Report on Facility Siting and Corridor Selection, prepared for the Alaska Power Authority. , 1983, Use of North Slope Gas for Heat and Electricity in the Railbelt, Draft Final Report, Feasibility Level Assessment, prepared for the Alaska Power Authority. ENSTAR Natural Gas Company, 1983, Prefiled Testimony of Dale Teel and Dennis Gilmore, submitted to the Alaska Public Utilities Commission, April 8, 1983. prepared under contract to State of Alaska, Department of Commerce and Economic Development, Division of Energy and Power Development, for the U.S Department of Energy, Division of Fossil Energy. Ekono, Inc., and Northern Technical Services, 1980, Peat Resource Estimation in Alaska, Final Report, Vol. 1, prepared under contract to State of Alaska, Department of Commerce and Economic Development, Division of Energy and Power Development, for U.S. Department of Energy, Division of Fossil Energy. Goldsmith, Scott and O'Connor, Kristina, 1980, Historic and Projected Oil and Gas Consumption prepared for the Alaska Royalty Oil and Gas Development Advisory Board. Governor's Economic Committee on North Slope Natural Gas, 1983, Trans Alaska Gas System: Economics of an Alternative for North Slope Natural Gas, Anchorage: Office of the Governor, State of Alaska. Huck, R. W. and S. E. Rawlinson, 1982, "Peat Resource Inventory of South Central Alaska, A Data Report," State of Alaska, Department of Natural Resources, Alaska Division of Geological & Geophysical Surveys, Open File Report 150. McGee, D. L. and Emmel, K. S., 1979, Alaska Coal Resources, Alaska Department of Natural Resources, Division of Geological and Geophysical Surveys. Merrill Lynch Economics, Inc., 1983, Long-Term Energy Outlook, 1982-1992, as summarized in Energy User News, February 24, 1983, p. 233 ff. Mining Informational Services, 1981, 1982 Keystone Coal Industry Manual, McGraw Hill Mining Publications. National Research Council, 1980, Surface Coal Mining in Alaska. Prepared by the Committee on Alaskan Coal Mining and Reclamation, Board on Mineral and Energy Resources, Commission on Natural Resources, National Research Council, National Academy of Sciences. Office of the Federal Inspector, Alaska Natural Gas Transportation System, a brochure. proceedings of the conberence held at the ee oe Bese of Alaska, Fairbanks, October 21-23, 1980, MIRL Report Number 50. » Focus on Alaska's Coal "155 Proceedings of the conference held at the University of Alaska, Fairbanks, October 15-17, 1975, MIRL Report Number 37. Rawlenson, S. E. and Hardy, S. B., 1982, Peat Resource Map of Alaska: Alaska Division of Geological & Geophysical Sur Surveys, Open File | Report 152. Reid, Collins Alaska, Inc., 1981, Use of Wood Energy in Remote Interior Alaskan Communities, prepared for State of Alaska, Department of Commerce and Economic Development, Division of Energy and Power Development. Resource Development Council for Alaska, Inc., 1982, Alaska Coal Marketing Conference Proceedings, Anchorage, Alaska. ED! 9 Qa Petroleum-Proceedings, Anchorage, Alaska. Secrest, T. J. and W. H. Swift, 1982, Railbelt Electric Power Alternatives Study: Fossil Fuel Availability and Price Forecasts, prepared for the Division of Policy | Development and \d@ Planning, Office of the Governor, and the Governor's Policy Review Committee, State of Alaska, by Battelle Pacific Northwest Laboratories. Swift, W. H., Haskins, J. P., and Scott, M. J., Beluga Coal Market Study, 1980, prepared for the Division of Policy Development and Planning, Office of the Govenor, State of Alaska, by Battelle Pacific Northwest Laboratories. Tussing, Arlon R., 1982, "Reflections on the End of the OPEC Era,” in Tussing and Erickson, 1982, Alaska Energy Planning Studies Submitted to Alaska State Agencies in Fiscal-Year 1982, for Division of Policy Development and Planning, Office of the Governor, | State of Alaska, by Institute of Social and Economic Research, University of Alaska. Tussing, Arlon R., and Erickson, Gregg K., 1982, Alaska Energy Planning Studies, Fiscal-Year 1982, for Division of Policy Development and Planning, Office of the Governor, State of Alaska, by Institute of Social and Economic Research, University of Alaska. U.S. Department of Energy (USDOE), 1977, Alaska Regional Energy Resources Planning Project - Phase I. Prepared by Department cf Commerce and Economic Development, Alaska Division of Energy and Power Development, under Contract No. £4 76 C-06-2435. Washington, D.C., U.S. Dept. of Energy, U.2. ,» 1979, "Peat Prospectus," U.S. DOE, Washington, D.C. , 1980, Transportation and Market Analysis of Alaska Coal (Second Draft), Seattle: Office of the Regional Representative (USDOE Region X). Wheelabrator-Frye, Inc., 1983, Alaska Peat Commercial Feasibility Analysis, Executive Summary, Draft. Periodicals The Anchorage Times, February 16, 1983, "Gas Pipeline: Shadow of Doubt Cast on Project Future." Energy Users Report, January 20, 1983, “Many Bills, Much Talk Expected in 1983, Congressional Action on Price Issues Cloudy," p. 87. Hanley, P. T. and Wade, W. W., "New Study Analyses Alaska OCS Areas," Oil & Gas Journal, Jan. 12, 1981. Mills, Betty, January 20, 1983, "Lawyers Advise DNR on Gas Route," The Anchorage Times. , February 9, 1983, "Money Woes Stall Pipeline Construction," The Anchorage Times. Oil & Gas Journal, Nov. 2, 1981, p. 69. , March 2, 1982, p. 132. , "Interior Moving to Open Alaska Tracts," Jan. 18, 1982. * ee He * Appendix A - Notations AAR AGA ANGTS AOGCC APUC ARC Bef Bef/d Btu DCED DGGS DOR MMBtu Mcf PALNG RDF TAGS TERA USGS APPENDIX A NOTATIONS Association of American Railroads American Gas Association Alaska Natural Gas Transportation System Alaska Oil and Gas Conservation Commission Alaska Public Utilities Commission Alaska Resources Corporation billion cubic feet (of natural gas) billion cubic feet per day (of natural gas) British thermal unit (Alaska) Department of Commerce and Economic Development (Alaska) Division of Geological and Geophysical Surveys (Alaska) Department of Revenue Higher Heating Value (commonly called “heat content," measured in Btu's per physical unit) Million British thermal units thousand cubic feet (of natural gas) Megawatt Pacific Alaska Liquified Natural Gas Project (also known as Pac-Alaska) Refuse-Derived Fuel Trans Alaska Gas System Total Energy Resources Analysis Model United States Geological Survey