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Home My WebLink AboutAPA3104IS HD 9561.7 A4 A42 1986 AlASKA STATE DOC HISTORICAL D PROJECTED OIL AND GAS e ONSUMPTION JANUARY 1986 Alaska Department of NATURAL RESOURCES DIVISION OF. OIL & GAS STATE OF ALASKA HISTORICAL AND PROJECTED OIL AND GAS CONSUMPTION Bill Sheffield Governor Esther C. Wunnicke . Commissioner Department of Natural Resources january 1986 Prepared for the Second Session Fourteenth Alaska Legislature TABLE OF CONTENTS PAGE Executive SLJTUTiary..... • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • 1 Chapter 1 Royalty Oil Program ••••••••••••••••••••••••••••••••••••••• 3 Chapter 2 Reserve Estimates ••.•.•....•.•••..••••••••••.••.•••••.•••. 7 Cod< Inlet North Slope Undiscovered Resources Chapter 3 Historical Oil and Gas Production and Consumption ••••••••• l3 Oil Production Oil Consumption Gas Production Gas Consumption Chapter 4 Consumption Forecast •••••••••••••••••••••••••••••••••••••• 29 Transportation Space Heating Utility Electricity Generation Industrial Chapter 5 Analysis of Surplus ••••••••••••••••••••••••••••••••••••••• 35 Sensitivity of Results Appendix A.l Oil and Gas Field Production Data ••••••••••••••••••• A.l.l Appendix A.2 Cod< Inlet Lease Ownership •••••••••••••••••••••••••• A.2.1 Appendix A.3 Cod< Inlet Field Ownership •••••••••••••••••••••••••• A.3.1 Appendix B Demand Projection Methodology and Assumptions ••••••••• B.l Appendix C Crude Oil Analyses •••••••••••••••••••••••••••••••••••• C.l Appendix D Conversion Factors •••••••••••••••••••••••••••••••••••• D.l Appendix E Definitions of Statutory Terms •••••••••••••••••••••••• E.l Appendix F Alaska Refineries and Transportation Facilities .•••••• F.l Appendix G Oil and Gas Field Maps .•••••••••.••••••••••.•••••••••• G.l Appendix H Acknowledgments ....•..•.........••.......••.•.•..•.... H.l -i- . i LIST CF TABLES PAGE Table 2.1 Estimated Recoverable Reserves and Royalty Share .•.•..•.•.•.•...•..•...••••••••••• 9 2.2A Estimated Availability of Oil for Sale ••••••••••••••• ll 2.28 Estimated Production and Sales for North Slope Royalty Oil ........................................ 12 Table 3.1 Historical Oil Production •••••••••••••••••••••••••••• l5 3.2 Historical Oil Consumption, Sales and Shipments ••..•••••••••..••••••••.••...... l5 3.3 Historical Gas Production .••••••••••••••••••••••••••• l7 3.4 Historical Gas Consumption ••••••••••••••••••••••••••• l8 Table 4.1 4.2 Table 5.1 5.2 LIST CF FIGURES Figure Figure 2.1 3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 3.9 3.10 3.11 4.1 4.2 Projected Demand for Oil ••••••••••••••••••••••••••••• 31 Projected Demand for Gas ••••••••••••••••••••••••••••• 33 Surplus Oil and Gas ...•..••••.•.••••.............•... 38 Sensitivity Analysis of Net Oil and Gas •••••••••.•••• 38 Predicted State Production ••••••••••••••••••••••••••• lO Historical Oil Production •••••••••••••••••.•.•••••••• l6 Historical Oil Consumption-Fuel Sales •••••••••••••• l6 Historical Gas Production •••••••••••••••••••.••••••.• 20 Historical Gas Consumption-Public •••••••••••••••••• 21 Historical Gas Consumption-Industrial •••••••••••••• 21 Southcentral Alaska Coastal Fuel Movements-Inbound .•••••••.•••••••••• 22 Southcentral Alaska Coastal Fuel Movements-Outbound •••••••••••••••••• 23 Southeastern Alaska Coastal Fuel Movements-Inbound ••••••••••.••••.••• 24 Southeastern Alaska Coastal Fuel Movements-Outbound .•.•••••.•••.••••• 25 Western Alaska Coastal Fuel Movements-Inbound .••••••••••••••..•• 26 Western Alaska Coastal Fuel Movements-Outbound •••••••••••••••••• 27 Projected Demand for Oil ••••••••••••••.•••••.•••••••• 32 Projected Demand for Gas ••••••••••.•••••••••••••••••• 32 -ii- I ! EXECUTIVE SUfiiMARY This report compares estimates of how much oil and gas Alaska has in reserves with estimates of how much oil and gas Alaska will consume in the 15 years between 1986 and 2000. The report is issued each year to comply with AS 38.05.183(d), which states: "(d) Oil or gas taken in kind by the state as its royalty share may not be sold or otherwise disposed of for export from the state until the commissioner determines that the royalty-in-kind oil or gas is surplus to the present and projected intrastate domestic and industrial needs. The commissioner shall make public, in writing, the specific findings and reasons on which his determination is based and shall, within 10 days of the convening of a regular session of the legislature, submit a report showing the immediate and long-range domestic and industrial needs of the st~te for oil and gas and an analysis of how these needs are to be met. ••l Chapter 1 describes the state's royalty oil program, cites sources of past oil and gas disposals, reviews disposals made during 1985 and outlines the disposals proposed for 1986. High, mid and low estimates of oil and gas reserves, and their respective royalty shares, are given in Chapter 2. Whereas high estimates are somewhat probabilistic and assume increasing oil prices, mid and low estimates are derived from proven and probable reserves and assume relatively stable oil prices. These more modest figures, therefore, are prudent values for long range policy considerations. The mid range oil estimate is 9.5 billion barrels of oil, yielding a 1.2 billion barrel state royalty share. Of this royalty share, 98.7% is on the North Slope. The mid range estimate of gas is 40.8 trillion cubic feet. The state's share of this gas is 4.9 trillion cubic feet. Again, 92.7% of the gas is on the North Slope. Production estimates of reserves are also given for the 15 year period. North Slope oil production will peak at about 1.9 million barrels per day in 1987, and will then decline to about 700,000 barrels per day by 2000. Cumulative state oil production is expected to be about 6.9 billion barrels. By then, Cook Inlet production will continue to be comparatively modest. Chapter 3 presents historical data on production and consumption of Alaska oil and gas. Between 1978 and 1985, oil fuel consumption grew 8.9% per year to a total of 1.4 billion gallons in 1985, while in the same period gas consumption grew 3.3% to 217 billion cubic feet in 1985. These figures are the starting points for the consumption projections detailed in Chapter 4. Chapter 4 presents forecasts of oil and gas consumption from 1986 to 2000. Alaska will consume about 26 billion gallons of fuels and 3.7 trillion cubic feet of gas during that period. Consumption growth rates will be considerably lower than they have been until now; it is estimated that during the period, annual growth will be 1.9% for oil and 1.3% for gas. The methods and assumptions used in generating the forecasts are included. 1 See Appendix E for discussion of statutory definitions. -1- i i 1 ~ In Chapter 5, estimates of state reserves and future production are compared with estimates of future consumption. The comparison shows that for the next 15 years, Alaska's supply of oil and gas will be greater than consumption. The supply and demand projections used in this report are uncertain estimates by nature, and should be viewed as likely outcomes. They are applicable only if the underlying assumptions presented here are approximated by future events. For example, in-state consumption will be influenced by economic and population growth which in turn will be fueled by world energy and natural resource prices. Development of the Susitna hydroelectric project would dramatically affect the in-state demand for natural gas, particularly after the late 1990s. The potential growth of a natural gas export market would similarly affect in-state natural gas availability as well as prices. The supply side of the in-state balancing equation also is probabilistic. The mid-range estimates of oil and gas resources (9.5 billion barrels, 40.8 trillion cubic feet) are reasonably certain. However, development of a system for natural gas from the North Slope remains uncertain. Estimates of undiscovered resources must be treated as highly speculative and of minimal value for planning or projection purposes. Even if these undiscovered resources exist (which they may not), there is no guarantee that they will be discovered or developed in an appropriate time-frame (if ever) to assure long-run continuous hydrocarbon supplies. Fiscal resources devoted to the hydrocarbon discovery and development process by the major oil firms will be largely determined by world market conditions, not by surplus or deficit conditions in Alaska's relatively small intrastate market. In summary, under reasonable assumptions about in-state reserves and consump- tion, not only is the current inventory of hydrocarbon reserves more than adequate to meet the estimated demands of Alaskans for the next 15 years, but significant quantities of hydrocarbons are surplus to requirements and therefore are available for export from the state. -2- ·' CHAPTER 1 ROYALTY OIL PROGRAM When a landowner sells the right to explore for and develop oil and gas, it usually reserves to itself a percentage of the oil and gas ultimately produced if the explorationis successful. That percentage is known as a royalty interest or royalty share. The State of Alaska holds a royalty interest in the lands it has leased for oil and gas exploration and development, and is currently receiving royalty payments from oil and gas production in Cook Inlet and on the North Slope. Under Alaska Statutes and the terms of state oil and gas leases, the state can take its royalty share of oil and gas either 11 in-kind 11 or 11 in-value. •• When the state takes its share of production in-kind, the Commissioner of Natural Resources, acting on behalf of the state, disposes of the oil or gas through negotiated contracts or competitive sales. When royalty shares are taken in-value, or in money, individual lessees market the state's share of production and reimburse the state accordingly. The history of the state's royalty in-kind disposals to January 1, 1983 may be found in the department's Review of Alaska Rotalty Oil of that date. The long term negotiated royalty in-kind disposals tohevron U.S.A., Inc. and Tesoro Alaska Petroleum CompanY of December 9, 1983, and to the Golden Valley Electric Association (GVEA) of February 8, 1985 were reviewed in the 1985 Historical and Projected Oil and Gas Consumption report (Supply/Demand study). The delivery of ANS royalty oil to Chevron and Tesoro began in May 1984 and October 1985, respectively. GVEA began taking ANS royalty oil under its new contract in July 1985. The 1985 Supply/Demand study also addressed the termination of the Tesoro Cook Inlet royalty oil contract in October 1985, at which time the state began receiving Cook Inlet royalty oil in value, as well as the competitive royalty oil sale of December 1984 and its attendent contingent backup disposals. One royalty in-kind disposal in addition to the GVEA royalty oil disposal occurred in 1985. This was the disposal resulting from the department's April 18, 1985 solicitation to sell 15,000 bpd of Kuparuk.royalty oil. The contract term of six months called for delivery of Kuparuk royalty oil upon the October 1, 1985 expiration of the six-month competitive contracts resulting from the 1984 competitive sale. The termination of the royalty oil contracts resulting from the solicitation of April 18, 1985 will coincide with the April 1, 1986 termination of all outstanding competitive royalty oil contracts. At this time North Slope royalty oil is taken both in-value and in-kind. Three in state refiners, Chevron, Tesoro, and MAPCO Petroleum, Inc., hold long term negotiated contracts with the state for the purchase of Prudhoe Bay royalty oil taken in-kind. Tables 2.2A and 2.28 depict estimated total North Slope production to 2012 and current North Slope royalty oil sales. In addition to the three in-state refineries mentioned above, these sales include the GVEA disposal, the one year competitive royalty contracts resulting from the 1984 competitive sale, and the six-month Kuparuk River Unit royalty contracts resulting from the solicitation of April 18, 1985. -3- On September 16, 1985 the department issued a document entitled Analysis and Recommendations for Disposition of State Ro~alty Oil (Analysis). The Analysis reviewed the state's December 1984 competit1ve sale and the solicitation of April 18, 1985, and evaluated negotiated royalty oil disposal options resulting from the department's Solicitation for Proposal(s) to Purchase Prudhoe Ba and/or Ku aruk River Unit Ro alt Oil of A ril 1 1985 o 1c1ta 1on • ter cons1 er1ng comments rom t e oya ty 1 and Gas Development Advisory Board, legislators and many members of the public, the Commissioner of Natural Resources determined that the state's interests would be best served by a negotiated long term sale to Petro Star, Inc. (Petro Star) and Chevron, and additional short term competitive sales. That policy was implemented through the department's Final Findings and Determination to Sell Kuparuk River Unit Royaltt Oil to Petro Star, Inc. and Chevron U.s.A., Inc. of December 9, 1985 and the inal Findings and Determination to Conduct a Competitive Sale of Prudhoe Bay Royalty Oil of December 13, 1985. Under the proposed contract with Petro Star and Chevron, the department intends to sell approxamately 6,500 barrels per day of royalty oil from the Kuparuk River Unit. Of this volume, a maximum of 2,500 barrels per day will be sold to Petro Star and about 4,000 barrels per day will be sold to Chevron, with both sales occurring under a single long-term noncompetitive contract. The volume to be sold is expressed as a percentage of unit production. Owing to its long-term nature, the Petro Star/Chevron royalty oil contract requires legislative approval. The department also intends to hold a short-term competitive royalty oil sale on February 4, 1986 for 9.6 percent (approximately 18,000 barrels per day) of state royalty oil from the Prudhoe Bay Unit. Since the term (six-months) of these competitive contracts is less than one year, legislative approval is not required for this disposal. The terms and conditions of the above planned disposals may be found in the final findings and determination documents referenced above. Such decision documents have accompanied all of the state's previous royalty in-kind disposals and likewise describe the terms and conditions of those disposals. During 1986, several ammendments to Tables 2.2A and 2.28 may be expected as a result of 1) the termination of the competitive contracts issued for the competitive sale of December 1984, 2) the termination of the Kuparuk River Unit royalty oil contracts resulting from the solicitation of April 18, 1985, and 3) the two new disposals mentioned above, which are expected to take effect in 1986. As mentioned, the state began taking all Cook Inlet Royalty oil in-value on October 1, 1985. The department's decision to convert Cook Inlet royalty in-kind to royalty in-value was based on the state's desire to have Cook Inlet royalty oil available for foreign export. Following the federal administration's October 28, 1985 announcement of its intention to permit the export of oil produced in Cook Inlet, the department issued the Cook Inlet Royalty Oil Export Sale Comment Document on November 25, 1985 (Comment Document). The Comment Document outlined the department's tentative schedule and terms for a proposed competitive sale of approximately 4,000 bpd of royalty oil gathered on the west shore of Cook Inlet for exeort to and refining in Japan. The department's desire to negotiate a backup .. or contingent royalty oil contract to facilitate the competitive royalty oil sale was also outlined in the Comment Document. -4- Pursuant to the department's intent, the Preliminary Findings and Decision for West Side Cook Inlet Robalt~ Oil Solicitation for Backup Contract was published on December ~. 1 85. That preliminary finding addresses the solicitation for a negotiated backup purchase of the west side Cook Inlet royalty oil proposed for competitive sale and export to Japan. The primary purposes of the proposed backup contract are 1) to insure that the state will have a responsible purchaser for the royalty oil nominated for in-kind disposal for the competitive export sale, and 2) to allow the department to reduce the lag time between the sale and delivery of royalty oil. The selection of a backup purchaser and the publication of a final finding is expected soon after the close of the comment period, which is January 20, 1986. The execution of a backup contract and subsequent six-month notice to commence taking west side Cook Inlet royalty oil in-kind (to enable near term delivery for the proposed competitive export sale) is predicated on the planned actions of the federal goverment, which are subject to postponement. Nevertheless, the department expects that the present in-value status of Cook Inlet royalty oil will change in 1986 as a result of the anticipated backup royalty oil contract and the planned competitive Cook Inlet royalty export sale. -5- -6- I i CHAPTER 2 RESERVE ESTI~~TES AND ROYALTY SHARE This chapter discusses estimates of oil and gas reserves in the state and the state's royalty share of these reserves. The reserve estimates have been developed for low, mid and high cases. Terms of individual oil and gas lease contracts were used to calculate the state's royalty share of the respective reserves. The low estimates assume stable to falling oil and gas prices and less satisfactory than predicted reservoir performance. The high estimates assume rising oil and gas prices and better than expected reservoir performance. The mid case estimates assume stable oil and gas prices and average reservoir performance. The estimated reserves and royalty share for oil and gas are shown in Table 2.1. The estimates have been developed separately for Cook Inlet, the North Slope and the "undiscovered" category, as different sources of information were drawn upon for each category. Cook Inlet Considerable historical and subsurface information is available about the oil and gas reserves in the Cook Inlet area, and major (i.e. large) new oil discoveries are not considered likely at this time. The reserves are assumed to remain constant for low, mid and high estimates. Cook Inlet reserves account for about 1.8% of the low, 1.3% of the mid, and 0.9% of the high estimates of statewide total proven and probable oil and gas reserves. North Slope Oil and gas reserve estimates shown in Table 2.1 are for currently leased state lands. Current North Slope oil production is from the Sadlerochit reservoir in the Prudhoe Bay Unit and the Kuparuk River reservoir in the Kuparuk River Unit and the Kuparuk River Formation in the Milne Point Unit. Full scale production from the Lisburne Reservoir is expected to commence in 1986 and production from the Endicott field in the Duck Island Unit is expected to commence in 1988. There also are some pilot production programs underway in the Lisburne reservoir and in the shallow Cretaceous sands. Additional enhanced oil recovery operations at Prudhoe Bay Unit, over and above what is already planned, recovery of gas condensate and natural gas liquids from the Sadlerochit and Lisburne gas caps and enhanced oil recovery from the Lisburne reservoir represent an oil resource (versus oil reserves) of about two billion additional barrels of liquids that may, or may not, be economically recoverable some time in the future. Enhanced oil recovery operations are extremely sensitive to capital costs and well head prices. Recovery of liquids from the Sadlerochit and Lisburne gas caps (and absent gas sales, concomitant reinjection of the dry gas back into the reservoirs) would require additional investment by the respective gas cap owners. The possibility for conversion of any of the above mentioned resources to the proven reserves category and the timing of that conversion must be view as speculative at this time. -7- Various lease holders on the North Slope continue to experiment with techniques to economically produce the vast amounts of oil held in the shallow Tertiary and Cretaceous age sands located west of Prudhoe 8~. Technology and equipment alreaqy exists to produce these types of deposits in more temperate climates. However, permafrost considerations, surface-related construction and operating constraints, and the projected well head price of the produced oil to date have combined to s~ie any commercial development of these relatively shallow (but large) reservoirs. Pilot production projects and laboratory testing continue in an effort to improve project economics. Tables 2.2A and 2.28 lists production forecasts for some of the fields listed in Table 2.1. Figure 2.1 graphically portr~s these estimates. As illustrated, North Slope production is expected to increase slightly until 1987~ then begin to decline in 1988. Currently, no gas is exported from the North Slope. The Alaska Natural Gas Transportation System for carrying gas to the Lower 48 is targeted for comple- tion in the early 1990's at the earliest, but it is uncertain when construction of the line will actually commence. The proposed pipeline capacity will permit exports in the range of 2.0 to 2.4 billion cubic feet per d~, with an expected level of 2.0 billion cubic feet per d~. Alternative marketing of North Slope natural gas is being considered, but these prospects are also very uncertain at this time. Undiscovered Resources Estimates of undiscovered oil and gas resources in Alaska are discussed here for the reader's information only and have not been used in the forecasts developed in this report. The United States fiiinerals Management Service (MMS) estimates the quantities of conventionally producible reserves based upon both public and confidential information to which it has access. At the 95% confidence level, the mean MMS estimates of undiscovered resources are 3.3 billion barrels of oil and 13.8 trillion cubic feet of gas.l National Petroleum Council (NPC) resources estimates require yields on investment of greater than 10% for oil and gas and 15% for oil alone before a field is considered "commercial. •• With these thresholds in mind, NPC estimates that 17.8 billion barrels of undiscovered oil and 10.~ trillion cubic feet of undiscovered gas could be produced commercially. A majority of the oil and gas resources identified by the MMS and the NPC are likely to be found on federal and private lands. 1 Minerals Management Service, "Estimates of Undiscovered, Economically Recoverable Oil and Gas Resources for the Outer Continental Shelf as of July 1984,11 OCS Report, MMS 85-0012, 1985. 2 11 'NPC' Sees Big US-Arctic Resources,'' Oil and Gas Journal, November 23, 1981. -8- ESTIMTED REJtAININ& R£CDYERABI..E RESERVES AND ROYALTY SHARE TABLE 2.1 OIL (ftillians Df Barrels) &AS (Billion Cubit Feetl •......•.•................••........... I I I .. I I I It I I I I I I. I I I I I I I I I I I I I I I I I I I I I 1 I I I I I I I I Recoverable Ros;lty Rttoverable Ro~lty Reserves are Reserves are .................... • t •••••••••••••••• *I I I I I I It It I I I I' I I I I I It I I I I . ....•....•...••. LIDI lllD HISH LOll ftlD HIGH LOll ftlD HI&H LON ftiD HIGH COOK INLET [ll haver Creek 230 230 230 [2] Belu~a River BOO 800 800 [2] 60 60 60 I Birt Hill 11 II II I canner0 Loop 300 300 300 [2] 9 9 9 -, Falls reek 13 13 13 -· --Granite Point 25 25 25 3 3 3 18 lB 18 2 2 2 Ivan River, lewis River, 600 75 75 75 Pretty Creek and Stuap Lake 600 600 [21 Kenai 850 850 850 [2] 17 17 17 McArthur River 58 58 58 7 7 7 650 650 650 [2][3] 81 81 81 Middle &round Shoal 14 14 l4 2 2 2 9 9 9 1 I I licola:i Creek 3 3 3 North Cook Inlet 859 859 8S'1 [2] 107 107 107 North Fork 12 12 12 Sterling 23 23 23 0 0 0 Sllanson River 22 22 22 260 260 260 [2] 0 0 0 Tnding Bay 3 3 3 <1 (1 <1 [3] [3] [31 [3] [3] [3J Mest Foreland 20 20 20 3 3 3 ltest Fork 6 6 6 SUBTOTAL 123 123 123 12 12 12 4,664 4,664 4,664 356 356 356 IORTH SLOPE E2J Beaufort Sea 0 300 0 45 0 Endicott 275 375 450 34 47 56 600 BOO 1,200 75 100 150 &wydyr Bay Area 0 30 60 0 4 8 ----Kuparuk River Unit 820 1,070 1,320 103 134 165 135 220 260 17 28 33 lisburne reservoir 300 400 600 38 50 75 BOO 1,100 1,600 100 138 200 ftilne Point Area 40 60 100 7 II 18 Point Thotson Area and Flaxaan Island Area [4l 300 350 600 38 44 75 3,200 5,000 6,000 400 625 750 Prudhoe Bay Unit 5,000 6,055 7,150 625 757 894 2'1,000 29,000 29,000 3,625 3,625 3,625 Shallow Cretaceous Sands 0 750 3,000 0 94 375 --------------------------------- ------~--- SUBTOTAL 6,735 9,390 13,280 844 1,185 1,666 33,735 36,120 38,060 4,217 4,515 4,758 ===== ===== =-==== -=== -= -== ==-=== ====== ====== ===== ====-==-== STATE TOTAL 6,858 9,513 13,403 856 1,197 1,678 38,3'19 40,784 42,724 4,573 4,871 5,114 [IJ As of 12/84 1 except •here noted as £21. Aliska Oil and Gas Conservation Co11ission, •1984 Statistitll Report.• [2l As of 9/85. Estiaates by Van ~ke, M •• [31 ftcArthur River Jas reserves inc ude Tr&ding Bay field gas reserves. [41 Oil and ~as con ensate. S/D86;T2_1;1/ /86 -9- PREDICTED ST,~TE PRO[)UCTIO~~ (DO&G, 12/85) 2 1 .9 1 .8 1. 7 1 .6 1 .5 >. 1 .4 0 o-1.3 !... (I) 1 .2 a. (I) 1 . 1 ~ 1 !... I 0 0.9 ..... CD 0 0.8 I c 0 0.7 :2 0.6 0.5 0.4 0.3 0.2 0.1 0 1986 1990 1995 2000 2005 2010 D 'lUI'AL STATE PRODUCTION + 'JUrAL PRUDHOE BAY 0 'JUrAL ROYALTY PRODUCTION PRODUCTION I 1-' 1-' I ESTI"ATED AYAILAIIILITY OF OIL FOR SALE !Thousand Barrels/Day) YEAR: 1986 1987 1918 1999 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 TABLE 2.21 Sill flllbll . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... PRODUCTION llortb Slope PrudhOI! Bay r.uparut lisburne Endicott ftilne Point Other Cook Inlet 1,550 220 0 0 30 0 1,550 220 50 0 30 0 1,376 220 60 50 30 0 1,183 220 70 100 25 20 1,018 187 80 100 20 20 Gran itt Point 7. 288 6. ~60 ~. 904 5,312 4. 784 ftcllrthur RiYtr 22.872 19.048 15.888 13.272 11.104 Trading Bay 1.864 1.464 1.184 0.984 0.832 "iddlt Ground Shoal 7.184 6.216 5.376 4.656 4.032 NliL 3.360 3.360 3.360 3.360 3.360 928 159 90 100 15 20 846 135 100 100 15 20 772 i22 100 85 10 155 706 109 100 75 10 155 646 591 541 491 91 89 80 72 90 80 72 65 70 65 60 55 10 0 0 0 t55 140 128 123 458 421 65 58 58 52 50 45 0 0 118 ll2 387 357 328 302 278 255 235 216 52 47 42 38 34 31 28 25 47 42 38 34 31 28 25 20 40 20 10 0 0 0 0 0 0 0 0 0 0 0 0 0 105 100 95 88 67 56 44 42 tn 1n 161 155 :s,m:,m 20 15 10 0 814 540 15 10 0 0 4~1305 0 0 0 0 374~125 0 0 0 0 71,175 40 38 37 35 691 1245 10,195 ~·lll 10:024 6,132 SUBTOTAL...JIORTH SLOPE 1,800 1,850 1,736 1,618 1,425 1,312 1,216 1,244 11155 1,069 965 881 813 149 688 631 566 513 462 410 370 332 303 274 246 215 190 8,407,045 SUBTOTAL-COOk INLET 42.568 36.648 31.712 27.584 24.112 59,358 ::a::: ::-::aa: =•==== ====== ====•= :an :za::c ===== as:::aa a:::: sa: ::ae ae aaz ..:: s::: a:c::: :::t na a:c::c ::s ••• an ••• -an aa •..:••••=• TOTAL 1,943 1,887 1,768 1,646 1,449 1,312 1,216 1,244 1,155 1,069 965 8BI 813 749 689 631 566 513 462 410 370 332 303 274 246 215 190 8,466,403 ROYALTY OIL FOR SALE North Slope Prudhoe lily m kuparut [IJ li sburne [ lJ Endi colt [2] "ilne Point [JJ othtr m Cook Inlet 194 28 0 0 5 0 lir ani te Point 0. 911 ftcllrthur Ri vtr 2.859 Trading Bay 0.233 "idtlle Ground Shoal 0.891 NliL 0.420 SUBTOTAL -IIIIRTH SlOPE 227 SUBTOTAL-COOK INLET 5.321 TDTIL ROYM. TY OIL SALES IIIII CO 6VEA [4J Tesoro !Old) (~J llfl!l) [6J Chlm'DII (7] COIIPI!titht Sill! 181 Petroshr [91 CIIIPI!titive S.alt [101 TOTAL ROYALTY OIL IJ YALUE IPotentiall ::::: 232 35 5 48 27 19 6~ 6 II 204 28 194 172 148 28 28 28 6 8 9 0 7 14 5 5 5 0 0 3 0.820 0.738 0.664 2.381 1.916 1.659 0.183 0.148 0.123 0.777 U72 0.582 o. 420 0. 420 0.420 233 219 205 4. ~81 3. 964 3. 448 ===== 237 35 5 48 27 19 7 140 97 223 35 5 42 24 17 7 . ., .. 129 209 35 4 36 20 14 7 == 117 92 127 23 10 14 4 3 0.591 1.388 0.104 0.504 0.420 181 3.014 184 35 3 ll 18 12 6 ::s 116 106 20 17 II 13 14 14 3 3 3 3 97 15 13 12 2 23 166 154 161 88 14 13 II 2 23 150 81 74 61 62 57 53 48 45 4l 12 II 10 9 8 7 7 6 5 II 10 9 I 7 7 6 5 5 to 9 8 a 1 6 6 3 1 2 0 0 0 0 0 0 0 0 23 20 19 18 17 16 15 14 13 38 35 32 29 27 25 2l 21 54443321 44433210 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 12 ' 7 6 5 5 5 5 19 0 0 0 0 4 m 101 109:318 61,913 52,311 12,812 98,596 1,362 3,750 289 1,253 767 139 125 114 105 '17 89 II 73 66 59 52 47 42 38 34 31 27 24 1,071, 722 7,420 :aa: a:r::c er.: D::c :::r: ==• ---:r:aa -• n:a a:r:& === === :a:ca =• :n ::.c -an na -• -• aacc:: .. :c 166 35 3 28 16 II 5 154 35 3 26 15 10 4 161 35 3 24 13 9 3 150 139 125 114 105 91 89 81 35 2 22 12 a 3 3 ts =•e ==• •== :as s:c ••• ==• aaa :aa z~• ••• : .. 27 24 1,019,142 229,99 12 082 m:m 62,717 43,489 18,615 6,570 s ...... 105 99 9l 87 83 38 35 35 35 35 35 35 35 35 501,7115 78 u 62 74 67 101 cro 79 10 62 54 46 311 11 59 52 n 42 311 n 31 21 24 577,357 llote: nutlttrs uy IIOt SUI to totals due to roundin• errors. (IJ 12.51 of production. [81 One yellr 1111! of 50,000 BPD fr01 Prldhoe and 15,000 BPD fr01 kuparul, dae to flld "arch 31,1986. (2J 14.01 of production hwiqhted liYI!ragl!l. 131 18.01 of production !weighted iveragel. 141 2.66n of PrudhDI! Bay production. [~) 24.5331 of Prudhot Bay production. 161 13.861 of PrudbOI! Bay production. [7] 'f.61 of Prudhol! Bay production. (9J A propoutl Petro Star/Chevron contnd •ill be sulltlttl!tl to thw ll!l}lsl.ature for ipprov.al of a Ull! of 6 500 BPD royalty oil fro• the kuparul Rivtr Unit. Petro Stir/Chevron initially •oul~ purchase 6L!OO BPD. The contract it e•pected to tiiHI!ftCI! in late 1916 and expire Septellbl!r 30 ln6. UOJ On Fl!bruiry 4, 1986 the !ilate Mill sell by cotpetithe bid llpproritattly 18,000 IPD for a six""lllllth ttra c01encin1J Junt I, 1986. S/D861T2_2U/8/86 JAIIIIIRY ll. 19B6 STAll OF III.ASKA TABU 2.21 IIEPAR1l£11T IJf IMTURAI. AESIIURCES DIVISION IJf Oil AND &AS E9T!KATED l'miiJCTTOII MD SIII.ES FOR NORTH SlOPE ROYALTY Oil 191 ESTIMTEI TOTM. PRODOCTIIJI ESTIMTED ROYIII.TY ESTIMitt SALES IJf ROYI. Tl Oil IBARA£LS PER DAYI f)ARR£lS P£R DAYI IIIAIIIIELS PER DAYI ------____ ,.. ---------------~----------------------------.... ----------......... ---.... -----~--_______ .,. _________ .. ----.. ------------................................ -.... ------------.,. ________ .., ............... ____ ......... __ .. _____ ................... _________ .... _ ............ -----·--------··---------------- Ill Ill Ul Ill Ill (21 131 141 151 161 111 Ill TOTAl TOTAl TOTAl TO Till fOUL TOTAl PRimtiOE lTI'R LISIIII!IE MICOTT lilliE PT. TDIAl MPCO &YEA ltSORO TESORO CHEYIKMI CORPETITIVf: PETROitlE\'11111 CORPETITIVf: IIII'I.Tl YEAR PRIJDIIOE «UPARIJ:' LISBURIIE EMDICDTI NlliiE PT. ROYALTY ROYIII.TY ROYALTY ROYIII. TY ROYIII.TJ ROYAlTY I OlD I IIIElll SAlE 11-11-IM IPRIIPDSEDI SALE H·ll6 •• YM.IIi IPRIIPOSElll ..................... _ .. _ ... ------------ 1'1115 1,550,000 lBO, ODD 3,toll 1,733,0DD m,n» 12,500 3n 216,625 35,0DD ~.167 41,533 26,867 18600 t.= 11,411 19116 l:m:= 220,000 30,0DD 1,1100,000 1~1:1: 27,500 5,400 226,650 35,000 5,167 47,~3 ll::tl 18:600 6,000 18,0DD 22,4113 1981 220,000 ::::= 30,000 1,1150,0DD 21 500 6250 5,400 232,'100 35,000 H~~ 47,533 \~:%~ .. ~ 93,233 19118 1,376,000 220,000 li'o.= 30,000 1,736,000 111,000 21:500 1:500 7,000 ~.400 219,400 35,0DD 42,197 23,1151 6,500 ::·m "" I, 183,000 220,0DD 10,000 ~.ooo 1,5'18,000 141,815 21,500 8,750 14,000 ~500 202,625 35,000 3:m 36,218 20,~ "·'" .. ~ 1990 I,OIB,ODD 181,000 80,000 100,000 20,000 1,405,000 121,250 73,313 10,000 14,000 ,600 178,225 35,000 3,393 31,218 17,646 12,216 5,525 73:227 I 'I'll 928,000 159,0DD 1:::: 100,000 IS, ODD 1,:1'!2,000 111.0~1) 19,815 11,250 14,000 2,100 163,825 35,000 3,093 28,4511 16,086 11,136 4,698 ~NU 1'1'12 846,000 135,000 100,000 15,000 I, 196,000 105,750 16,815 12,500 14,000 2, 700 151,825 35,000 2,820 25,944 14,664 10,152 3,9119 1993 m,ooo 122,000 100,000 85,000 IO,ODD 1,089,000 ... ~ 15,250 12,500 11,'100 1,1100 131,'150 35,000 2,573 23,614 13,382 9,264 3,605 se:m 1'1'14 706,0DD 109,000 100,000 15,000 10,000 1,000,000 89,250 13,6~ 12,500 10,500 1,1100 126,675 35,000 2,353 11,650 12,238 8,472 3,220 43,141 1'1'15 646,000 911,000 90,000 70,000 10,000 914,000 80,750 12,250 11,250 9,800 1,800 115,850 35,000 2,895 n,m 1996 nr,ooo 89,0DD 80,000 65,000 0 825,000 1l,815 11,125 10,000 9,100 0 104,100 35,000 2,630 66,410 1997 1,000 ~:= 12,000 60,000 0 151,000 61,625 10,000 9,000 8,400 0 '15,025 35,000 ltt,025 1'1'18 4'18,000 65,000 55,000 0 690,000 62,250 9,000 8,125 7,700 0 81,075 35,000 52, on 1'1'19 459,000 65,000 511,000 50,000 0 631,0DD 57,250 8,125 7,250 !,ODD 0 79,625 35,000 44,625 2000 m,ooo 58,000 52,000 45,000 0 576,000 52,625 7,250 6,500 6,300 0 12,675 35,000 37,61'.S 2001 387,000 52,000 41,000 40,000 0 526,0DD 48,375 6,500 5,875 5,600 0 66 350 35,0DD ~·m 2002 357,000 47,0DD 42,0DD 20,0DD 0 466,000 44,625 5,815 5,250 2,800 0 sa',550 35,000 2003 328,000 42,000 38,000 10,000 0 418,0DD ~~:~ 5,250 4,750 1,4~ 0 52,400 35,000 11:400 2004 302,000 38,000 34,000 0 0 314,000 4,750 4,250 0 46,150 46,750 2005 211,000 34,000 li,ODD 0 0 343,000 34,750 4,250 3,815 0 0 42,875 42,11'.S 2006 255,000 31,000 28,000 0 0 314,000 11,Bn 3,115 3,500 0 0 39,250 ,,,250 2007 235,000 28,000 25,000 0 0 281,000 29,375 3,500 3,125 0 0 36,000 36,000 2001 216,000 25,000 20,000 0 0 261,000 27,000 3,125 2,500 0 0 32,625 32,62:1 2009 l'lf,OOO 20,000 15,000 0 0 234,000 24,R75 2,500 1,87' 0 0 29,250 r.·= 2010 183,000 15,0DD 10,000 0 0 209,000 22,915 1,815 1,250 0 0 26,000 20!1 161,000 10,000 0 0 0 178,000 21,000 1,250 0 0 0 22,250 22:250 2012 135,000 0 0 0 0 155,000 lq,315 0 0 0 0 19,315 !II 1111 E!TIMI£ IJf FIEll PEIIFOIIIIIIIC£, OECEIIIIEI 19115. 16! IEliVOJES !:NIDI Rll n1:1 FIIR :It ODD ... IF I'IIIJIIIIE NY I 12! &Vf:A'S ltM-YEAII COIITRIICT c-.uCE& Jll.Y I, 19115. IIUIIIITITY IS 2.66n IIIIT ROYAllY Oil AIID • .,.~ IPIIIf lTI'Mli ltii'ER IIIIT ROYIII.TY OIL, AIID till ClliTlllllf FOR YEll!! AS A ll£5UI.T OF TJI£ !lEt. II, 19114 ...... IJf DATU PIIUDIIIJ£ ROYIII.IY Oil. COIIPETITII'E SALE AND THE SUBSEOIJOO KII'ARIJ:' SII.ICITATIIJI. PRIUII TO TMT N TillE !MIS OIL REMIIIU '1M VALUE.' I f3l rESOlD'S COII!RM:T IS CIJil!II:MlU AT ITS MITIUI IIUIIIITJn IJf 24.5331 IJf DAilY PRIJDIIOE IHIYAl TY OIL TH£ ClliTRliCl EIPJRES JIIURY 1'1'15. 111 A Pltiii'OS£D PETRO STMICHEYIKMI tlli11M:T IIU IE TO THE lEIISLATUA£ FUR IIPI'Illl\'111. Of A 54llE OF 6 500 JPt ROYIII. TY Oil lTI'ARIJI( "' ~~J:~/~H 1Jli ~Ei:l'~ff,~vrr.':t ~lt/'~~ RIVER UWIT. PETRO STARICHE\iiil IWITII.LY IOUl 6,0DD I'D. THE CORTRIICT IS ROYAllY Oil AND EIPTRES JAil. I, 1995. EIPECTED TO CORRENtE IM LATE 1986 AII'D EIPTRE SEPTEIIIEII 30, 1'1'16. 181 011 FEilllllfii!Y 4, 19116 THE STATE fill SEll IY COII'£TITII'E tiD 151 CHE~ Oil'S CIJITIIiiCT CAllS f«M A MliiUIIlUAIIIITY IF 9.61 OF DAllY IIPPI!DmATEl Y 18,900 BPD FOR A STHOIITM TEO COIII:IItlll& Jill[ I, 19116. PRUOIIOE ROYALTY Oil. Til CIJI111l1Cl EIPJA£S JA!IUAIIY I, 1995. doj (9) lncludf• cnly llold• in, 111' pl•nnl!d lor prlllluctlan h th ntll" Iuton. j :.:J Oil Production CHAPTER 3 HISTORICAL OIL AND GAS PRODUCTION AND CONSUMPTION Aside from a minor amount produced from Katalla field before 1933, all significant Alaska oil has been produced from two areas, Cook Inlet and the North Slope. Cook Inlet fields have produced a total of 1.058 billion barrels, including an estimated 17 million barrels in 1985. North Slope fields have produced a cumulative 4.556 billion barrels, of which about 647 million barrels were produced in 1985. Historical oil production data are shown in Table 3.1 and Figure 3.1. More specific data and information on individual fields are included in Appendix A.l, A.2, and A.3. Oil Consumption Nearly a11 of the oil products consumed in Alaska are refined fuels. ~uch of these fuels are refined in state, and the balance is imported (see Chapter 5 for further discussion). Figures 3.6 through 3.11 show Alaskan coastal fuel movements in 1981. The state Division of Revenue (DOR) collects and reports fuel sales from distributers. The major categories of this data are shown in Table 3.2 and Figure 3.2. During the nine year reporting span, aviation fuel data probably indicate the general quantity consumed and end use of these fuels. Other categories, however, are less reliable both in quantity consumed and end use. This is due to interaction of many factors affecting the reports sent to DOR, year by year, including variability in completions of reports, shifts in taxation and alternation between reporting categories. The most spectacular effect of these, and possibly other, factors are the large changes between 1984 and 1985 sales, when 11 0ther Diesel" increased 50%, "Marine Gas 11 increased 88% and 11Marine Diesel" decreased 27%. Gas Production Natural gas is produced from the same areas as oil, Cook Inlet and the North Slope. Production data for these areas are given in Table 3.3 and Figure 3.3. Cook Inlet fields began production in the mid 1960's and since then have produced about 4,742 Billion cubic feet to the end of 1985. Of the estimated 1985 production of 303 billion cubic feet, 29.0% was injected, resulting in net production (i.e. net of injection) of 215 billion cubic feet. Since North Slope production began in the mid 1970's, cumulative production has been about 5,680 billion cubic feet to the end of 1985. Of the estimated 1985 production of 1019 billion cubic feet, 81.3% was injected for a net production of 109 billion cubic feet. -13- Gas Consumption Table 3.4 and Figures 3.4 and 3.5 show gas consumption data from 1971 to 1985. Between 1978 and 1985, Cook Inlet gas sales increased by an annual average of 2.6%, while field uses decreased by 5.3%. Of the net 215 billion cubic feet produced in 1985, 197 billion cubic feet (91.6%) were sold and 18 billion cubic feet (8.4%) were consumed in field operations. Of the gas sold, 33% was exported as LNG, 27% was used to produce Ammonia-Urea, 20% was consumed for electrical generation, 11% went to producers and 12% was sold to gas utilities. (These percentages total to 103%, a result of discrepancies between data sources). Most of the net North Slope gas production is consumed in field operations and the remainder is sold, primarily to TAPS. In 1985, of the net 109 billion cubic feet produced, 89 billion cubic feet (81.7%) was used in field operations and the 20 billion cubic feet balance was sold, including 14 billion cubic feet to TAPS. Most of the gas produced from fields near Barrow is used for electricity generation and gas utilities in Barrow. -14- HISTORICAL OIL PRODUCTION TABLE 3.1 YEAR: 1977 1978 1979 1980 1981 1982 1983 1984 1985 [11 &rowth l4J ••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••• 1978-1985 PRODUCTION [21 (""bbl/Yearl &ross State Production 171.318 447.810 511.335 591.640 587.339 618.910 625.527 630.408 663.158 5.771 I tea: TAPS Throughput, PS 11 112,315 397.149 467.939 554.934 556.067 591.142 600.859 608.836 647.807 7.241 Itea: Liftings at Valdez 96.669 394.080 464.394 548.895 547.026 583.370 592.119 596.588 643.512 7.261 [1] Estiaated fro• part-yearly reports. [21 Alaska Oil and ijas ~onservation CDIIission, •statistical Report,• 1977-1985 and Alyeska Pipeline Service to., personal tDIIUn1cat1on. (3] Average annual growth, S/086;13_1_2;1/14/86 HISTORICAL OIL CONSUNPTION -SALES AND SHIPNENTS TABLE 3.2 YEAR: 1977 1978 1979 1980 1981 1982 1983 1984 1985 l1l &rowth [4J . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........ 1978-1985 FUEl SALES [3] (ftillion &allons/Year) Avilti on Gas 16.770 15.830 16.925 16.912 18.754 16.596 15.244 17.398 18.566 2.301 Exe•ct 1.521 0.685 0.552 0.558 0.574 0.589 0.498 0.574 0.491 -4.65% Tau le 15.249 15.145 16.373 16.354 18.180 16.007 14.746 16.825 18.075 2.561 Aviation Jet 330.744 363.607 415.164 416.184 400,177 432.366 517.575 603.671 471.239 3.77% Exe'!tt 227.581 250.601 288.974 286.110 247.619 99.957 242.815 304.177 210.551 -2.431 Taxa le 103.163 113.006 126.190 130.074 152.558 332.409 274.760 299.494 260.688 12.68% ftarine Sas 11.766 7.714 8.296 7.598 7.602 7.878 8.568 8.956 17.122 12.061 Exeagt 5.707 0.554 0.292 0.025 0.085 0.032 0.052 0.120 0.183 -14.65% Taxa le 6.059 7.160 8.004 7.573 7.517 7.846 8.516 8.835 16.939 13.091 ftarine Diesel 38.613 51.985 59.492 67.711 72.282 99.443 147.569 124.416 90.095 8.!7% Exe!tt 6.396 10.116 6.325 5.370 5.153 30.443 75.395 50.874 1.038 -27.771 Taxa le 32.217 41.869 53.167 62.341 67.129 69.000 72.174 73.542 89.057 11.38% Other Sas 186.213 187.359 181.329 177.353 186.446 210.644 197.968 223.188 221.145 2.40% Ex~t 5.094 8.290 7.527 8.162 9.084 12.809 10.887 11.038 14.152 7.94% Tau le 181.119 179.069 173.802 169.191 177.362 197.835 187.081 212.150 206.993 2.09% other Diesel 165.752 184.876 269.377 302.647 326.440 411.125 420.279 436.308 654.387 19.791 Exea~t 46.160 54.050 120.960 120.939 117.074 187.856 178.494 191.195 411.396 33.64% Taxa le 119.592 130.826 148.417 181.708 209.366 223.269 241.785 245.113 242.991 9.25% TOTAL FUEL SALES 749.858 811.371 950.583 988.405 1,011.701 1,178.052 1,307.203 1,413.937 1,472.554 8.891 SHlPKENTS t2l (ftftbbl/Yearl Liftings at Valdez 96.669 394.080 464.394 548.895 547.026 583.370 592.319 596.588 643.512 7.261 [1] Estiaated fro• part-yearly reports. [21 Alaska Oil and &as Conservation Cottission, •statistical Report,• 1977-1985 and Alyeska Pipeline Service to., personal co11unication. [3] Alaska Departaent of Revenue, 'Report of ftotor Fuel Sold or Distributed in Alaska.• [41 Average annual growth. S/D86;T3_1_2i1/14/86 -15- FIGURE 3.1 HISTORICAL OIL PRODUCTION 700 600 500 .., ~ 400 .... 0 til c: ~ .:500 :.i 200 100 0 1977 1980 1985 IJ 'IDTAL STATE + THROUGHPUT 0 LIFI'INGS AT P.roDUCTION AT PS #1 VAlDEZ FIGURE 3 • 2 HISTORICAL OIL COf'\JSUMPTIOI'\J·-FUEL SALE 1.5 1.4 1.3 1.2 1.1 1 .., c· 0.9 ~- 8 0.8 c. 0.7 ~ ffi 0.6 0.5 0.4 0.3 0.2 0.1 0 1977 1980 1985 J 'IDTAL + AVIATION ~ AVIATION b. MARINE X OTHER GAS v arHER DIESEL FUEL SALES GAS JET DIESEL -16- I 1-' .._J I HISTORICAL &AS PRODUCTION !Billion Cubit Feet/YearJ TABLE 3.3 YEAR: 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 lll Browth (3) ..•••• •.••.. .••••. ••.••• ......• ••.•.•• •••..•• ••••••• .•••••• ••••••• ••••••• ••••••.•• ••••••••• ••••••••. ••••••••• 1978-1985 STATE 121 Production Injection Net Production 227.94 222.79 225.24 232.97 256.399 271.162 375.832 602.687 738.485 898.155 948.554 1,090.655 1,171.121 1,212.705 1,321.874 73.88 76.13 87.78 49.04 83.007 97.077 171.188 375.405 503.003 661.947 695.515 817.863 886.364 909.617 997.746 154.06 146.66 137.46 183.93 173.392 174.095 204.644 227.292 235.482 236.208 253.039 272.792 294.757 303.088 324.128 RAILBELT (Coot lnletJ £21 Production 227.94 222.79 225.24 230.18 252.554 265.253 279.961 293.800 305.075 299.942 299.051 309.119 306.343 306.956 302.703 Injection 73.98 76.13 87.78 49.04 83.007 97.077 103.108 103.551 112.868 115.437 100.410 102.248 94.385 93.687 87.932 Net Production 154.06 146.66 137.46 181.14 169.547 168.176 176.953 190.249 192.207 184.505 198.641 206.871 211,958 213.269 214.771 NON-RAILBELT !North Slope! Production --- Injection Net Production 2.79 3.945 5.909 95.871 308,887 433.410 598.214 649.504 781.536 164.778 905.749 1,019.171 0.00 0.000 0.000 68.080 271.854 390.136 546.509 595.106 715.615 791.979 815.929 909.813 2.79 3.845 5.909 27.791 37.033 43.274 51.705 54.398 65.921 72.799 89.820 109.358 £11 Estiaated froa part-yearly reports of cited sources. 11.871 14.991 5.201 0.431 -2.311 1.751 18.591 18.841 16.731 £21 1971-73: Stanford Research Institute "Natural 6as Deaand and Supply to the Year 2000 in the Cook Inlet Basin of South Central Alaska,• Nov. 1977. 1974-95: Alaska Oil and Gas Conserva~ion Co11ission, 'Report of Gas Disposition,• aonthly reports. "Injection• does not include gas rented froa Beaver Crtek and Kenai fields for injection into SNanson River field. (3] Average annual groMth. SID86;T3_3_4;1/7/B6 HISTORICAL BAS CONSUftPTION (Billion Cubic Feet/Yearl TAIL£ 3.4 YEAR: 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1994 1915 (11 Bro•th ll2l ...... ...... ...... ...... ....... ....... ....... ....... ....... ....... ....... ....... ....... 1978-1985 STATE (2] Field Operations 45.25 36.56 20.90 52.48 31.639 28.322 48.859 55.180 57.865 62.001 62.166 72.876 77.S90 95.249 107.248 9.961 Vented and Flared 33.18 20.98 6.93 9.05 10.557 6.674 15.729 6.183 4.551 4.846 5.660 6.983 5.084 9.075 5.986 ..0,461 Used on Leases 10.96 14.86 12.42 41.40 17.963 18.424 29,966 35.055 38.123 43.575 44.592 52.724 58.893 68.481 82.675 13.041 Shrinkage 1.11 0.72 1.55 2.01 3.119 3.224 3.145 3.426 2.847 2.438 2.434 2.602 2.726 2.657 I. 716 -9.401 Other 0.00 o.oo 0.00 0.02 o.ooo o.ooo 0.019 10.516 12.344 11.142 9.480 10.567 10.887 15.036 16.871 6.991 Sold £31 121.72 123.72 130.94 130.65 141.754 145.763 155.785 172.101 177.616 174.208 190.873 199.914 207.167 207.840 216.880 3.361 Power qeneration 14.69 15.38 16.70 17.45 25.461 27.613 28.590 29.718 33.141 33.520 33.947 36.222 36.651 37.000 40.606 4.561 Publlc £4][5] 8.14 8.91 10.63 II. 76 19.619 22.189 23.590 24.592 28.155 28.757 29.386 31.392 32.055 32.662 35.815 5.521 "ilitary [41 6.55 6.47 6.07 5.68 5.842 5.424 5.000 5.126 4.986 4.763 4.561 4.830 4.596 4.338 4.791 -0.961 Gas Utilities 10.24 13.10 14.76 15.13 12.092 12.551 12.683 13.454 14.045 15.521 16.213 19.564 19.518 20.911 24.958 9.531 Residential t4l£5l 5.44 6.03 6.52 6.72 5.548 5.916 6.010 6.536 6. 911 7.773 8.385 10.520 10.609 11.507 12.860 10.151 CoHercial £41 4.80 7.07 8.24 8.41 6.544 6.635 6.673 6.918 7.134 7.748 7.828 9.044 8.909 9,404 12.098 8.311 LM6 £61 63.24 59.87 60.99 61.87 64.777 63.509 66.912 60.874 64.111 54.844 68.823 64.438 67.729 65.892 6S.381 1.031 A•onia-Urea [7] 19.49 20.58 20.64 22.10 23.888 24.257 28.620 48.879 51.657 54.699 53.836 55.220 50.338 50.083 53.977 1.431 Producers [81 13.40 12.59 10.41 12.477 11.588 6.703 10.523 6.958 5.190 5.601 11.383 12.698 18.362 21.341 10.631 Refiners £91 0.56 1.94 2.47 3.268 1.785 0.199 0.237 0.285 0.380 0.316 0.486 0.502 0,938 0.983 22.531 TAPS £101 o.oo 0.00 o.oo o.oo 0.00(1 0.000 1.754 6.949 8.648 10.686 11.106 11.952 13.277 12,856 14.369 10.94% Unaccounted for till 14.06 0.83 3.32 0.89 (0. 2091 4.460 10.324 1.467 u. 2291 (0. 6321 1.031 0.649 6.454 1.798 (4. 7351 RAILBELT Field Operations 45.25 36.56 20.90 49.83 28.830 24.467 24.416 25.949 24.101 22.304 20.559 20.957 19.380 22.468 17.780 -5.261 Vented and Flared 33.18 20.98 6.93 7.98 9.496 5.421 4.848 3.870 2.710 3.045 3.175 3.494 2.560 3.260 2.345 -6. 9ll Used on Leases 10.96 14.86 12.42 39.85 16.215 15.822 16.404 16.228 14.564 14.608 14.950 14.861 14.056 14.597 13.719 -2.371 I Shrinkage 1.11 0.72 1.55 2.01 3.119 3.224 3.145 3.426 2.847 2.438 2.434 2.602 2.726 2.657 I. 716 -9.401 ...... Other o.oo o.oo 0.00 o.oo o.ooo 0.000 0.019 2.425 3.980 2.213 0.000 o.ooo 0.038 1.954 o.ooo -9.401 ro Sold £31 121.72 123.72 130.94 130.51 140.717 143.710 152.437 164.300 168.106 162.201 178.082 185.913 192.578 207.940 196.990 2.631 I Po•er ~eneration 14.69 15.38 16.70 17.45 25.461 27.613 28.590 29.718 33.141 33.520 33.632 35.818 36.169 36.520 40.096 4.371 Pubhc £41 8.14 8.91 10.63 11.76 19.619 22.189 23.590 24.592 28.155 28.757 29.071 30.988 31.573 32.182 35.306 5,301 "ilitar{ £41 6.55 6.47 6.07 5.68 5.842 5.424 5.000 5.126 4.986 4.763 4.561 4.830 4.596 4.338 4.791 -0.961 Gas Utili ies 10.24 13.10 14.76 15.13 12.092 12.551 12.683 13.454 14.045 15.521 15.778 19.025 19.111 20.903 24.470 8.921 Residential [41 5.44 6.03 6.52 6.72 5.548 5.916 6.010 6.536 6.911 7.773 7.950 9.981 10.202 10.999 12.372 9.541 Co1aercial £41 4.80 7.07 8.24 8.41 6.544 6.635 6.673 6.918 7.134 7.748 7.828 9.044 8.909 9.904 12.098 8.3ll LNG £61 63.24 59.87 60.99 61.87 64.777 63.509 66.912 60.874 64.111 54.844 68.823 64.438 67.729 65,882 65.381 1.03% Atonia-Urea [7] 19.49 20.58 20.64 22.10 23.888 24.257 28.620 48.879 51.657 54.699 53.836 55.220 50.338 50.083 53.977 1.431 Producers £81 13.40 12.59 10.41 12.477 11.588 6.703 10.523 6.958 5.190 5.601 11.383 12.698 18.362 21.341 10.631 Unaccounted for £111 14.06 I. 39 5.26 3.36 2.022 4.192 8.929 0.852 (1.8061 (1.5731 0.412 0,029 6.533 16.090 (8.2751 NON-RAILBELT Field Operations £31 2.65 2.808 3.856 24.444 29.231 33.763 39.697 41.607 51.921 58.210 74.732 89.468 17.331 Vented and Flared 1.08 1.061 1.254 10.882 2.313 1.840 1.801 2.485 3.490 2.524 5.814 3.641 6.701 Used on Leases 1.56 1.747 2.602 13.562 18.826 23.559 28.967 29.642 37.864 44.837 53.884 68.956 20.381 Shrinkage 0.00 0.000 0.000 o.ooo 0.000 0.000 o.ooo 0.000 0.000 0.000 0.000 o.ooo 0.001 Other 0.02 0.000 0.000 0.000 8.092 8.364 8.929 9.480 10.567 10.849 15.034 16-.871 11.071 Sold [3] 0.14 1.037 2.054 3.347 7.802 9.512 12.007 12.791 14.000 14.589 15.088 19,890 14.301 PoNer generation [51 0.315 0.404 0.482 0,480 0.467 10.341 [13] Gas Ut1lities £51 0.435 0.539 0.407 0.508 0.447 0.681 [13] Refiners [ 9] 0.56 I. 94 2.47 3.268 I. 785 0.199 0.237 0.285 0.380 0.316 0.486 0.502 0.938 0.983 22.531 TAPS UOJ 0.00 o.oo 0.00 0.00 o.ooo 0.000 I. 754 6.949 8.648 10.686 11.106 11.952 13.277 12.856 14.369 10.941 Unaccounted for £111 12.231) 0.269 1.394 0.616 0.579 0.941 0.619 0.619 10.079) 0.306 3.624 I 1-' \0 I [1l Estitated fro• part-yearly reports of cited sources. £21 Does not include NON-RAllBELT itets larked ---. £3] Alaska Oil and Gas Conservation Collission, "Report of Gas Disposition,• tonthly reports. [41 1971-82: Annual reports fro• Alaska Pipeline Co., ENSTAR and Kenai Utility Service Co. to Alaska Public Utilities C011ission 1983-85: Enstar Natural Gas Co., personal COIIUnlcation, £51 BarroN Utilities and Electric Cooperative Inc. personal co111nication. £61 1971-74: Stanford Research Institute, "Natural &as De~and and Supply to the Year 2000 in the Cook Inlet Basin of South Central Alaska • Nov. 1977. 1975-79: Su1 of ll production fro1 Kenai and Beaver Creek gas fields in: Alaska Oil and Gas Conservation COitission, "Report of Gas D\sposition,• and 1980-85: [7] 1971-74: 1975-79: 2) sales fro• North Cook Inlet gas field in: Alaska Oil and Gas Conservation C011ission, "Kenai Gas Sales.• Royalty reports fro• producers to Division of Oil and Gas. Stanford Research Institute, "Natural Gas Detand and Supplt to the Year 2000 in the Cook Inlet Basin of South Central Alasla • Nov. 1977. Sut of 11 sales fro• Kenai and Beaver Creek gas fields to Collier Chetical in: Alaska Oil and Gas Conservation Cottisslon, •kenai Gas Sales,• and 2) sales frot "cArthur River gas field in: Alaska Oil and &as Conservation Co11ission, ""onthly Report of &as Disposition.• 1980-85: Royalty reports fro• producers to Division of Oil and Gas. [8l Royalty reports frot Union to Division of Oil and Gas, ite• Rental Gas. £91 Royalty reports fro• Union to Division of Oil and Gas, itets Alaska Pipeline-Nikiski, Chevron Rental Gas and letering. £101 Royalty reports fro• ARCO to Division of Oil and Gas. £111 Calculated difference betNeen "Sold" and su1 of listed "Sold" itets. £12J Average annual growth. £131 Average annual growth, 1981-1985. 5/DB6;T3_3_4;1/7/B6 FIGURE 3.3 HISTORICAL GAS PRODUCTION 1.4~----------------------------------------------~ 1.3 1.2 1.1 1 0.9 0.8 0.7 1::: 0.6 ~ ~ 0.5 0.4 0.3 0.2 ~-a---e---e---a-- 0.1 04---~~~~--~--~--~~--~--~--~~--~--~--4 1971 o 'IOI'AL POODUCl'ION 1975 + INJ:EX:TION -20- 1980 198~ <> NET PRODUCl'ION FIGURE 3.4 HISTORICAL GAS CONSUMPTION-PUB. 220 210 200 190 180 170 160 1i 150 t! 140 I) 130 ::.0 120 :J 0 110 c: 100 ~ 90 m 80 70 60 50 40 30 20 10 1971 0 TOI'AL FUEL SALES 1975 + PCw.ER GENERATION 1980 1985 o GAS UTILITIES FIGURE 3.5 HISTORICAL GAS CONSUMPTION-IND. 220 200 180 160 1) 140 ~ .!:! 120 ..0 :J 0 100 c: ~ 80 l:D 80 40 20 0 1971 :I rorAL FUEL SALES + LNG 1975 o AMMJNIA -UREA 1980 1985 b. PRODUCERS X REFINERS V TAPS -21- SOUTHCENTRAL ALASKA COASTAL FUEL MOVEMENTS-INBOUND FOR 1981 WESTERN ALASKA CiiMhl I .. Mi -o- Oinll I~ TOTAL INBOUND GOIOIM 833 Jilt FUll 818 Dinet 894 Total Total 16 g;::..;.._----1~ -. • ~· ..... ".. • . .,...s ....,_ • ....... . UNITS IN THOUSANDS OF BARRELS (1 1000 bbl). WIDTHS OF LINES ARE PROPORTIONAL TO QUANTITY TRANSPORTED •. DATA SOURCE• KEISER, G., TEAL, D., FUEL CONSUMPTION ANO PRICING IN ALASKA, A REGIONAL ANALYSIS, HOUSE RESEARCH AGENCY REPORT 83-C, JAN. 1984 .o co, () HAWAII GOilllline -o- Jet Full 210 DieM! 12 Totol 222 -22- FIGURE 3.6 SOUTHEAST ALASKA s-o-. 5 .Nt fUll I OieMI II Total ·~ -·wAlHIN~tbli -· -·-·-·-·-· GCIIIoiiM 90 .lilt Full 516 ~ !.21 Talal 727 CALIFORNIA Gosoline 257 .... Full 290 OieMI 237 1084 SOUTHCENTRAL ALASKA COASTAL FUEL MOVEMENTS-OUTBOUND FOR 1981 -~· • -.J~· . UNITS IN THOUSANDS WESTERN Goaollne olll Fuel Diesel Total OF BARRELS (1,000 bbl). WIDTHS OF LINES ARE PROPORTIONAL TO QUANTITY TRANSPORTED. DATA SOURCE r KEISER, G., TEAL, D., FUEL CONSUMPTION AND PRICING IN ALASKA, A REGIONAL ANALYSIS 1 HOUSE RESEARCH AGENCY REPORT 83-C, .JAN. 1984 .o TOTAL OUTBOUND Gas.ollne 1 0 I 9 Jet Fuel 73 Dl.w! 818 -23- FIGURE 3.7 SOJTt£AST ALASKA Gaaoline 211 Jet Fuel 39 .... Dla.i 72 322 'NA !iHINt fON - - - - -• - - G.:ao~ 340 Jel Fuel -o- Oieul 17 Totot ~7 OREGON Gaocllne 97 "" FUll -o- Diesa~ -o- Tolol 97 CALIFORNIA GOIOiinl 301 ..1e1 FUll -o- Dio..ol 61 412 ·_'·! SOUTHEAST ALASKA COASTAL FUEL MOVEMENTS-INBOUND FOR 1981 -. • pi'~-..... .. ..•. .,..s ...._ • . , . UNITS IN THOUSANDS OF BARRELS (1,000 bbl). WIDTHS OF LINES ARE PROPORTIONAL TO QUANTITY TRANSPORTED. DATA SOURCE• kEISER, G., TEAL, u., FUEL CONSUMPTION ANO PRICING IN ALASKA, A REGIONAL ANALYSIS, HOUSE RESEARCH AGENCY REPORT 83-C, .IAN. 1984 .o ...... 0 -24- TOTAL INBOUND GoiOiine 458 .... Fuel 240 Diesel 974 TCital 1672 FIGURE 3.8 SOUTHEAST ALASKA COASTAL FUEL MOVEMENTS-OUTBOUND FOR 1981 -. . UNITS IN THOUSANDS OF BARRELS (1,000 bbl). WIDTHS OF LINES ARE PROPORTIONAL TO QUANTITY TRANSPORTED. DATA SOURCE I KEISER, G., TEAL, D., FUEL CONSUMPTION AND PRICING IN ALASKA, A REGIONAL ANALYSIS 1 HOUSE RESEARCH AGENCY REPORT 83-C, .JAN. 1984 .. ..... 0 -25- TOTAL OUTBOUND GclsoiM 4 Jet Fuel 76 Diewt 16 Total 96 OTHER Gasoline >1 Jlt Full -o- Diesel !I Totol !I FIGURE 3.9 WASHINGTON Goaolln• -o- .Mt Fuel 71 Oieoel )I Total 76 WESTERN ALASKA COASTAL FUEL MOVEMENTS-INBOUND FOR 1981 .... .. TOTAL INBOUND Gcnclinl :u:s ,.. Fuel 641 Oiftel 1748 Total 2712 . . .. _$;~· ...~ Jl··. ·~.....,..... ., . UNITS IN THOUSANDS OF BARRELS (1,000 bbl). WIDTHS OF LINES ARE PROPORTIONAL TO QUANTITY TRANSPCRrED •. DATA SOURCE• KEISER, G., TEAL, 0., FUEL CONSUMPTION AND PRICING IN. ALASKA, ~ REGIONAL ANALYSIS,· HOUSE RESEARCH AGENCY REPORT 83-C, JAN. 1984 SOUTHCENTRAL ALASKA GoloiiM 20 """"' 34 a-~ 41e 470 HAWAII Gasoline .l•t Ml Diesel .. Total . , 0 -o- 75 12 87 -26- FIGURE 3.10 WASHINGTC»> Gasoline 73 .,., Fu.l 321 Dine! 243 Totol 637 WESTERN ·ALASKA COASTAL FUEL MOVEMENTS-OUTBOUND I FOR 1981 , . .. • . . . .,. , ... ;J'------..l ~··. ·~~....... . UNITS IN THOUSANOS OF BARRELS (1,000 bbl). WIDTHS OF LINES ARE PROPORTIONAL TO QUANTITY TRANSPORTEO. OATA SOURCE a KEISER, G., TEAL, D., FUEL CONSUMPTION ANO PRICING IN ALASKA, A REGIONAL ANALYSIS, HOUSE RESEARCH AGENCY REPORT 83-C, .JAN. 1984 .. ...... 0 FIGURE 3.11 -27- -28- CHAPTER 4 CONSUMPTION FORECAST A projection of consumption of oil and gas for the 15 year period from 1985 1999 was prepared by the Institute for Social and Economic Research (ISER) for the January 1985 issue of this report. The ISER projection has been retained in this report except for two adjustments: projected consumption of Aviation Jet fuel has been reduced because of lower than expected actual consumption in 1985, and projections for all catagories have been extended one year to the year 2000. Summary Consumption of oil and gas in all major categories is forecast to increase in future years. Consumption of liquid petroleum will increase from 1,507 million gallons in 1986 (about 36 million barrels of crude oil equivalent) to 1,970 million gallons in 2000 (47 million barrels). This represents a 1.9 percent annual growth rate. The five and ten year annual growth rates are 1.6 and 1.9 percent, respectively. Space heating use of petroleum will grow 2.0 percent annually. Vehicle transportation use will increase 2.0 percent annually. The use of fuel oil for electricity generation in 1986 reflects the introduction of several hydroelectric facilities which replace fuel oil generation. Fuel oil consumption subsequently increases, and the 15-year growth rate will be 3.1 percent annually. Industrial use of petroleum liquids will remain constant. Consumption of natural gas will grow from 218 billion cubic feet in 1986 to 262 billion cubic feet in 2000 (annual growth of 1.3 percent). Although industry currently consumes the majority of natural gas and is forecast to continue to be the dominant user, growth of gas use for space heating will outstrip growth in industrial use. Over the next 15 years, use of gas for space heating will increase from 21.0 billion cubic feet in 1986 to 36.0 billion cubic feet in 2000 (3.9 percent annual growth). Use of gas for electricity generation will grow from 38.0 billion cubic feet in 1986 to 45.0 billion cubic feet in 2000 (1.2 percent annual growth). The consumption of natural gas for industrial uses will grow from 158.0 billion cubic feet in 1986 to 182.0 billion cubic feet in 2000 (1.0 percent annual growth}. Transportation Liquid Fuels Transportation fuel consumption will grow moderately with population growth in future years, increasing from 1,190 million gallons in 1986 to 1,578 million gallons in 2000 (Table 4.1}. Jet fuel consumption will grow most rapidly (3.3 percent annually}, followed by diesel fuel consumption (1.3 percent annually) and gasoline (0.4 percent annually). Fuel-use efficiency will increase in all types of uses but will be most evident in highway gasoline consumption which is projected to decline on a per capita basis. _______ _ lsee Appendix B for methodology and assumptions. -29 Total consumption projected over the 15-year period from 1986 to 2000 is 20,411 million gallons. This is approximately equivalent to 486 million barrels of crude oil. Space Heating The majority of fuel oil used for space heating is consumed outside the rail- belt although fuel oil is important where natural gas is not available. Out- side of the railbelt, most space heating is done with fuel oil. Fuel oil con- sumption for this use grows from 181 million gallons in 1986 to 239 million gallons in 2000. Space heating fuel consumption will increase moderately with population and an increase in the size of the building stock relative to population. Natural gas use will grow more rapidly than fuel oil use, from 21.0 billion cubic feet in 1986 to 36.0 billion cubic feet in 2000 (Table 4.2). The relatively rapid growth of natural gas use is attributable to the rapid population growth in the railbelt, as well as to the extension of the natural gas market into the Matanuska Valley. The expansion of the natural gas market is estimated to increase gas use by about 9 percent by 1995. Barrow, on the North Slope, is the only location outside of the railbelt presently served by natural gas. Utility Electricity Generation Fuel oil use for utility electricity generation will grow at an average annual rate of only 1.2 percent. This is due to the availability of power from several recently completed hydroelectric plants in locations currently using fuel oil for generation. Natural gas use for utility electricity generation will exhibit strong growth in the next 15 years as the majority of incremental electricity demand growth in the railbelt is met with additions to natural gas-fired generation. Natural gas use increases from 38.0 billion cubic feet in 1986 to 45.0 billion cubic feet in 2000. The percentage of electricity in the railbelt provided by natural gas reaches a high of 81 percent in 1992 but declines in 1993 to 72.9 percent, when the Bradley Lake hydroelectric facility comes on line.2 After 1993, the proportion of railbelt electricity generated by natural gas begins to increase, reaching 75.4 percent in 1999. Industrial Fuel Use The major industrial use of fuel oil (not including transportation) is in the petroleum industry. Pipeline fuel for the Alyeska pipeline is the largest element of this use. In addition, a significant amount of fuel is used for electricity generation. Both of these uses are projected at constant levels. Increased use of natural gas in future years will be related to petroleum pro- duction. This increase will be concentrated on the North Slope where expanded petroleum activity will be concentrated. The other large use of natural gas, the production of Ammonia-Urea, will continue requiring constant amounts of natural gas. 2The Susitna Hydroelectric Project is considered in Chapter 5. -30- PROJECTED DEMAND FOR OIL (Million &allons/Year) TABLE 4.1 YEAR: 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 TOTAL [11 &rowth t3l .......••..••...................... , ....•..............•.... . ..... 1986-2000 STATE Vehicle Transportation [2] 1190 1205 1217 1242 1269 1294 1316 1344 1378 1411 1443 1471 1509 1543 1578 20411 2.041 Jet Fuel 489 502 515 532 550 568 585 605 627 650 672 694 720 745 771 9225 3.31% Civilian Daaestic 260 270 280 293 308 323 336 353 372 391 410 428 451 472 495 5441 4.711 Military and International 229 232 235 239 242 245 249 252 255 259 262 266 269 273 276 3784 1.341 Gasoline 253 252 250 252 253 254 255 256 259 261 262 263 265 267 268 3870 0.411 Aviation 19 19 19 20 20 20 20 21 21 22 22 22 22 23 23 314 1.371 Highway 224 223 221 222 223 224 224 225 227 228 230 230 232 233 234 3399 0.311 Marine 10 10 10 10 10 10 10 10 11 11 11 11 11 11 12 157 1.311 Diesel 448 451 452 459 466 472 476 483 493 501 508 514 524 531 539 7316 1.331 High11ay 311 313 313 318 323 327 330 335 342 347 352 357 363 368 373 5072 1.311 tlarine 138 138 139 141 143 145 146 148 151 154 156 158 161 163 165 2244 1.281 :race Heat 181 184 185 189 193 195 199 203 207 212 221 224 235 237 239 3103 2.011 ility &eneration 32 33 34 34 36 36 37 39 40 41 44 45 49 49 49 598 3.091 Industry 105 105 105 105 105 105 105 105 105 105 105 105 105 105 105 1574 o.oo1 Pipehne Fuel 84 84 84 84 84 84 84 84 84 84 84 84 84 84 84 1260 o.oo1 Electricity Generation 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 314 0.001 i TOTAL [1 l 1507 1527 1541 1571 1603 1629 1657 1690 1730 1770 1813 1845 1898 1934 1970 25685 1.931 RAILBELT Vehicle Transportation £21 905 913 925 948 972 998 1016 1039 1073 1100 1115 1146 1158 1203 1250 15760 2.331 Jet Fuel 405 414 425 439 453 469 483 498 517 534 545 565 575 602 630 7553 3.231 Civilian Doaestic 214 221 229 240 252 265 276 288 304 319 330 346 358 379 402 4422 4.611 Military and International 192 193 196 199 201 205 207 209 213 215 215 218 217 223 228 3131 1.241 6asoline 187 186 185 186 187 188 188 189 191 192 191 192 190 193 197 2842 0.371 Aviation 16 16 16 16 16 17 17 17 17 18 18 18 18 18 19 256 1.241 Highway 166 164 163 164 165 166 165 165 167 168 167 168 166 168 171 2493 0.211 Marine 6 6 6 6 6 6 6 6 6 6 6 7 6 7 7 93 1.111 Diesel 313 314 315 324 332 340 345 352 365 374 379 389 393 408 423 5366 2.171 High11ay 216 218 219 226 232 239 243 249 260 268 273 280 285 297 309 3813 2.591 Marine 96 96 97 98 99 101 102 103 105 107 107 109 108 111 114 1553 1.241 srce Heat 75 75 75 76 76 77 77 77 78 78 79 80 80 82 85 1169 0.901 U ility &eneration 8 8 8 8 8 8 8 8 8 8 8 8 8 9 9 123 0,841 Industr( TOTAL [ l NDN-RAILBELT Vehicle Transportation £2l 285 292 292 294 298 296 300 305 305 312 328 326 350 340 329 4651 1.031 Jet Fuel 84 88 90 93 97 99 102 107 110 116 127 129 145 143 141 1673 3.771 Civilian Do1estic 46 49 51 53 56 58 61 65 67 72 80 82 93 93 93 1019 5.161 Military and International 38 39 39 40 41 41 42 43 43 " 48 47 52 50 48 654 1.681 6asoline 65 66 65 66 67 66 66 67 68 69 72 71 75 73 72 1028 0.731 Aviation 3 4 4 4 4 4 4 4 4 4 4 4 5 4 4 59 2.08?: Highway 58 59 58 58 59 58 59 59 59 61 63 62 66 64 63 906 0.591 Marine 4 4 4 4 4 4 4 4 4 4 5 5 5 5 5 64 1.611 Diesel 136 137 137 135 134 132 131 131 127 126' 129 126 130 123 117 1950 -1.071 High~ta·y 94 95 94 92 91 88 87 85 81 79 80 76 78 72 66 1260 -2.491 ltarine 41 42 42 43 44 44 44 45 46 47 49 49 52 52 51 691 1.571 ,, srace Heat 106 110 111 114 117 118 122 126 129 134 142 144 155 154 154 1934 2.701 U ilitt &eneration 24 25 26 26 28 28 29 30 31 33 36 37 40 41 41 475 3.901 Sout east 5 7 7 7 7 B 9 9 10 10 11 12 12 13 14 142 7.63X Rest of State 18 19 19 19 20 20 20 21 22 23 25 25 28 27 26 333 2.661 Industr( TOTAL [ l [1l Suas aay not equal totals due to rounding errors. ' t2l Includes industrial{ ailitary and govern1ent use. Excludes pipeline fuel. j [3] Average annual grow h. S/DS6;T4_1;t/7/86 -31- I() 1: g• 8 1: 0 :.:: . ffi 1i If 0 :0 ::J (.) 1: ~ m FIGURE 4.1 PROJECTED DEMAND FOR OIL 2 1.9 1.8 1.7 1.6 1.5 1.4 1.3 1.2 1.1 1 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0 1986 1990 1995 2000 'l.Ul'AL + TRANSPORT <> SPACE HEAT 11 ELEX:TRICITY X INDUS- roNSUMPTION GENERATION TRIAL PROJECTED DEMAND FOR G~ 4 • 2 280 260 240 220 200 180 160 140 120 100 80 60 40 20 1986 1990 D 'l.Ul'AL + SPACE HEAT roNSUMPTION 1995 2000 t> ELEX:TRICITY 4 INDUSTRIAL GENERATION -32- PROJECTED DEftAND FOR &AS (Billion Cubic Feet/Yearl TABLE 4.2 YEAR: 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 TOTAL t1l &rowth £21 •• I I • • I -1 I -1 a ,J -1. I I • I I a I I I. I' I. I I I I I e It I I I I I I I • I I I I I I I I e • I I e I I I I 1986-2000 STATE Vehicle Transportation 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.001 srce Heat 21 22 23 24 25 26 27 28 29 30 31 32 33 34 36 420 3.921 U ility Generation 38 38 39 39 40 41 42 38 39 40 41 42 42 44 45 607 1.221 Industry 158 162 167 171 176 182 182 182 182 182 182 182 182 182 182 2650 1.02% Allon1a·Urea Production 50 50 50 so 50 50 50 so 50 50 50 50 50 50 50 750 0.001 "ilitary P01er Generation 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 69 0.001 Petroleu1 Production 104 108 112 117 122 127 127 127 127 127 127 127 127 127 127 1831 1.441 Pipeline Fuel 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 191 0.001 "iscellaneous 91 95 99 104 109 114 114 114 114 114 114 114 114 114 114 1641 1.621 TOTAL til 218 222 228 234 241 248 250 247 250 252 253 255 256 259 262 3678 1.321 Itea: I~ection Ite1: L RAILBELT Vehicle Transportation 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.001 Space Heat 21 22 23 24 25 26 27 28 29 30 31 32 33 34 36 418 3.98% Current llarket 21 21 22 23 23 24 25 26 27 28 28 29 30 31 33 393 3.281 "atanuska Valley 0 0 I 1 I 1 2 2 2 2 2 2 2 3 3 25 Utility &eneration 38 38 38 39 40 40 41 37 39 39 40 41 41 43 44 597 1.051 Industry 87 87 87 87 87 87 87 87 87 87 87 87 87 87 87 1307 0.001 A11onta·Urea Production 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 750 0.001 "ilitary Power Generation 5 5 5 5 5 5 5 5 5 5 5 5 5 5 s 69 0.001 Petroleu• Production 33 33 33 33 33 33 33 33 33 33 33 33 33 33 33 488 0.001 Pipeline Fuel 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.001 fti scell aneous 33 33 33 33 33 33 33 33 33 33 33 33 33 33 33 488 0.001 TOTAL Ul 146 147 148 149 151 153 155 152 155 157 158 160 161 164 167 2321 0.96% Itea: I~ection Itea: L NON-RAILBELl Vehicle Transportation 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.001 Sface Heat 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 3 0.001 U ilith Generation 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 10 0.001 Sout east 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o.oox Rest of State 1 I 1 1 1 1 1 1 I I 1 I I 1 I 10 0.00% Industrl 71 75 79 84 89 94 94 94 94 94 94 94 94 94 94 1344 2.02% Petro eu1 Production 71 75 79 84 89 94 94 94 94 94 94 94 94 94 94 1344 2.021 Pipeline Fuel 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 191 0.00% ftiscellaneous 58 62 67 71 76 82 82 82 82 82 82 82 82 82 82 1153 2.501 TOTAL [IJ 72 76 80 85 90 95 95 95 95 95 95 95 96 96 96 1356 2.08% Itea: I~ection Ite1: L lll Su1s 1ay not equal totals due to rounding errors. [2J Average annual growth. S/D86JT4.2;J/7/B6 -33- i I -34- Summary CHAPTER 5 ANALYSIS OF SURPLUS Under reasonable assumptions about recoverable reserves and Alaska consump- tion, the current inventories of both oil and gas are more than sufficient to meet the presently identifiable needs of Alaskans for the next 15 years. Liquid Petroleum Table 5.1 shows that the cumulative 15-year Alaska demand for liquid petroleum is approximately 612 million barrels of crude oil equivalent. This is equal to approximately half the reserves of royalty oil and is 7 percent of total reserves. No attempt has been made to compare petroleum products produced at Alaska refineries with petroleum products consumed in the state. Currently the capacity of Alaskan refineries exceeds Alaskan consumption (about 81 thousand barrels per day), but the product mix which the refineries can produce does not match the product mix demanded (Figures 3.6 thru 3.11). The resulting cross-hauling of crude oil out of Alaska and refined products into the state is a common feature of petroleum markets, in general, and does not represent an inefficient distribution of refining capacity or mismatch of supply and demand. It is also recognized that a direct volume for volume comparison cannot be made between demand for refined products and availability of crude oil. A direct comparison would be unrealistic since a barrel of crude oil does not yield a barrel of refined products. Natural Gas Table 5.1 indicates that the cumulative 15-year Alaska demand for natural gas is 3.677 trillion cubic feet of gas. This is approximately 76 percent of the state royalty share of gas in the combined current inventory at Cook Inlet and on the North Slope. Since the transportation of natural gas normally requires a pipeline, partic- ular markets for gas which are linked by pipeline to supplies are relevant for the determination of excess supply. Table 5.1 shows that there is a net surplus in both the Cook Inlet and North Slope markets. The Alaska royalty share of Cook Inlet gas alone, however, is insufficient to meet the projected Cook Inlet requirements over the next 15 years. Projections Beyond Current Inventory We assume recoverable reserves represent a 15-year inventory of petroleum in the ground based upon historical reserve-to-production ratios. Because a very sizable investment is required to develop a petroleum reservoir into recover- able reserves, reserves will be 11 proven Up 11 at a rate to maintain sufficient inventory consistent with the growth in demand. Excessive proven reserves, like excessive inventories, result in unnecessary carrying costs to reservoir -35- owners and will be avoided if possible. This is the basis for the 15-year time horizon for demand used in this analysis. As time passes, the growth in demand will stimulate the search for reserves to replace those produced, and market forces will work to keep supply and demand in balance. Sensitivity of Results The positive net surpluses of oil and gas calculated in this chapter are insensitive to a reasonable range of changes in the assumptions underlying the projections. These are discussed in turn and shown in Table 5.2. Reserve Estimates Because the low reserve estimates are quite similar to the mid-range esti- mates, the positive oil and gas surpluses are not significantly affected by using low reserve estimates. Economic Growth Faster population growth will accelerate the use of liquid fuels relative to the use of natural gas because a larger portion of liquid fuel use is population sensitive. Even so, the net surplus of petroleum liquids would be reduced only marginally by growth of population-related consumption at double the base case rate. Increased use of natural gas would reduce the surplus by an equally small percentage. Export of Gas To the extent natural gas is exported, it is unavailable for the local market. Cumulative exports over the next 15 years from current operations are projected to be about 945 billion cubic feet. If a facility comparable to the once proposed Pacific Alaska LNG project were built, it would annually export 160 billion cubic feet. With an assumed first year of operation of 1990, cumulative exports to California through 2000 would be 1,760 billion cubic feet. Combined exports to Japan and California would be 2,705 billion cubic feet, reducing reserves for instate use, and the net surplus, by 6.6 percent. In the absence of new Cook Inlet reserves, assumptions would be negative by just 0.2 trillion cubic feet. If a new export facility were to be constructed it is anticipated that exploration for natural gas in Cook Inlet would accelerate (it is currently at a near stand still) and additional reserves would be discovered once again creating a surplus condition. Susitna Hydroelectric Project If the Susitna hydroelectric Project were built, it could begin to replace electricity generation by natural gas and fuel oil in 1996. If natural gas use were cut back 75 percent beginning in that year, cumulative gas consumption would decline 161 billion cubic feet. Fuel oil use for electricity consumption in the Railbelt could be eliminated at a savings of 33 million gallons (about 786,000 barrels). -36- I :i 1 Natural Gas Availability in Fairbanks If, by some means, natural gas became available in Fairbanks, electricity ~eneration space heating in Fairbanks could be converted to gas. This could 1ncrease annual natural gas consumption by 5 billion cubic feet as coal and fuel oil were backed out. Fuel oil use would fall by 8 million gallons annually. Natural gas consumption for space heating would gradually replace fuel oil and coal, and could eventually capture 75 percent of the market. If gas became available in 1993 and captured this share of the market by 1997, gas consump- tion for space heat could increase 25 billion cubic feet, and fuel oil consumption could fall by 145 million gallons. The net surplus of gas would fall very marginally as a result of these changes, and the net surplus of liquid fuels would increase very marginally. -37- :! -~ SURPLUS OIL AND GAS TABLE 5.1 OIL GAS (Thousand Barrels! !Billion Cubic Feet! ---------------------------------------Total State Total State STATE Royalty Royalty Reserves [1] 9,513 1,197 40,784 4,871 Estiaated Production 664 83 81 [3] 7 [3] fro• reserves thru 1985 [2] Estiaated reserves 8,849 1,114 40,703 4,864 as of Jan. 1 1986 Estiaated cuaufative tonsuaption, 612 [4] 612 [4] 3,677 3,677 1986-2000 !15 ~ears! NET SURPLUS !DEF CIT! 8,237 [5] 502 [5] 37,026 1,187 COOK INLET Reserves [1] 123 12 4,664 356 Estiaated Production 17 2 54 4 fro• reserves thru 1985 Estiaated reserves 106 10 4,610 352 as of Jan. 1 1986 Estiaated cuaufative consuaption, 2,321 2,321 1986-2000 !15 rears) NET SURPLUS IDEF CIT! 2,289 U,9691 NORTH SLOPE Reserves [1] 9,390 1,185 36,120 4,515 Estiaated Production 647 81 27 3 fro• reserves thru 1985 Estiaated reserves 8,743 1,104 36,093 4,512 as of Jan. 1 1986 Estiaated cuaufative consuaption, 1,356 1,356 1986-2000 !15 rears! NET SURPLUS IDEF CIT! 34,737 3,156 [11 Fro• Table 2.1. [2] Estiaate of production fro• date of relfrve estiaate to end of 1985. Production fro• state royaltf share is proportional to state royalty share of reserve. [3] Total gas disposi ion net of relnjection, fro• Chapter 3. Production fro• state royalty share is froportion of state royalty gas in total. [4] Consuaption in 1a Ions converted to 42 gallon barrels. [5] Although availa ility of trude oil can not be directly toapared, on a voluae per voluae basis, to tonsuaption of refined products. S/D86;T5_1i1/7/86 SENSITIVITY ANALYSIS OF NET OIL AND GAS TABLE 5.2 Low Reserve Estiaate 50% increase in growth of population-related consuaption Export of LNG Susitna Hydro Natural Gas available in Fairbanks S/D86;T5_2;1/7/86 Percent Reduction in Net Surplus Oi 1 Gas l"illion !Billion Barrels! Cubic Feet! 27.9'% 0.57. 0.0'% +2.0'% 5.8'% O.St 6.6t 0.4t o.oz -38- APPENDIX A.l OIL AND GAS FIELD PRODUCTION DATA OIL AND BAS FIELD PRDDUCTJON DATA FIELD LOCATION BEGAN PRODUCTION OIINER OPERATOR AVERAGE KDNTHLY PRODUCTION 1/1/85 thru 9/30/85 ESTIIIATED CUMULATIVE PRODUCTION AS OF 12/31/85 ESTliiATED RESERVES AS OF 12/31/85 ESTIIIATED PERCENT OF FIELD DEPLETED AS OF 12/ll/85 IELU6A RIVER Cook Inlet, onshore, Mest side 1/68 ARCO, Chevron, Shell Chevron OIL Bbl Bbl lbl Casinghead RtF IICF IICF ROYALTY 12.51, Effective rate: 7.5551 PURCHASER Chugach Electric, EISTAR ------------------------------- &AS &as llell 11 770,235 IICF 202 1 521,275 IICF 794,689,295 IICF 201 LEASES State ADL: 17592, 17599 1 17658, 21126 1 21127, 21128 1 21129, 58815, 58820, 5BB31 COitftENTS APPENDIX A.l Until recently, Chugach Electric was the only current purchaser of this gas. Chugach uses this gas for power generation which is delivered to the Anchorage aarket. Enstar has recently purchased Beluga River gas under contract froa Shell and just c01pleted a pipeline fro• the field through the ltat-Su Valley to Anchorage. · Due to the existence of several Federal leases, the statt's effective royalty share is 7.5551. FIELD LOCATION BE&AN PRODUCTION DINER OPERATOR AVERAGE IIONTHLV PRODUCTION 1/1/85 thru 9/30/85 ESTiftATED CUKULATIVE PRODUCTION AS OF 12/31/85 ESTlltATED RESERVES AS OF 12/31/85 ESTlftATED PERCENT OF FIELD DEPLETED AS OF 12/31/85 ROYALTY PURCHASER LEASES State ADL: COIIIIENTS Production to cattence in 1986. CANNERY LOOP Cook Inlet, onshore, east side Field delineation underway Union OIL Casinghead Bbl Bbl Bbl IICF IICF IICF -A.l.l- &AS &as Nell ftCF ftCF 300 1 000 1 000 ftCF ._;; --~ . i FIELD LOCATION BE&AN PRODUCTION OttNER DUCK ISLAND I SA6 DELTA tENDICOTT RESERVOJRI North Slope onshore/offshore Facilities design underway, production expected to begin in 1988. OPERATOR SOHIO OIL &AS Casinghead &as Well AYERA&E IIONTHLY PRODUCTION Bbl ltCF IICF 1/1/85 thru 9/30/85 ESTIIIATED CUIIULATIVE PRODUCTION Bbl IICF IICF AS OF 12/31/85 ESTJIIATED RESERVES 375,000,000 Bbl IICF eoo,ooo ,ooo lltF AS OF 12/31/85 ESTJKATED PERCENT OF FIB.D DEPLETED AS OF 12/31/85 -------------------ROYALTY PURCHASER -------------------------------LEASES State ADL: tm!IIENTS FIELD FALLS CREEK LOCATION took Inlet6 onshore, east side BE&AN PRODUCTION Shut-in 19 1 OWNER OPERATOR Chevron OIL &AS Casinghead &as Well AYERA6E IIONTHLY PRODUCTION Bbl IICF IICF 1/1/85 thru 9/30/95 ESTIIIATED CUIIULATIVE PRODUCTION BU IICF 18,983 IICF AS OF 12/31/95 ESTIIIATED RESERVES Bbl IICF 13,000,000 IICF AS OF 12/31185 ESTIIIATED PERCENT OF <11 FIELD DEPLETED AS DF 12/31/95 ---------·---------------------ROYALTY PURCHASER -------------------------------LEASES State ADL: CDIIIIEHTS -A.1.2- FIELD LOCATION &RANITE POINT Cook Inlet, offshore, •est side 12/67 lEBAM PRODUCTION DINER OPERATOR AMOCO, ARCD, Chevron, Setty, ftobil, Phillips, Superior, Texico, Union MOCD, ARCO, Teuco, Union OIL AVERAGE ftONTil.Y PRODUCTION 251,153 Bill 1/1/85 thru 9/30/85 ESTifiATED CUftULATIVE PRODUCTION 100,844 1065 Bbl AS OF 12/31/85 ESTlfiATED RESERVES 21 1986,163 Bbl AS OF 12/31/85 ESTJRATED PERCENT OF FIELD DEPLETED AS OF 12/31/85 821 ROYALTY 12.5 X PURCHASER Tesoro ARCO ttl AMOCO Platfor• £11 Union tll Casinghead 177,210 fiCF 87 1 422 1 650 fiCF 15,873,480 lfCF au [11 Stall 11ount of casinghead gas sold to AMOCO for use on platfora. -------------------------------LEASES State ADL: 17586 1 17587, 18742 1 18761 COflfiENTS &AS &is lell IICF IICF IICF &as froa this field is tisinghead gas and was foraerly flared. DO&C Flaring Order 1104, 6/30/71, has prohibited flaring since 7/1/72 and this gas is now rtcovered and used locally. FIELD LDCATJON BE&AN PRODUCTION OINER OPERATOR AVERAGE fiONTHLY PRODUCTION 1/1/85 thru 9/30/BS &MYDYR BAY UNIT AREA Marth Sl~e, onshore/offshore Field delineation underway Conoco OIL Casinghead Bill ESTlfiATED CUftULATIVE PRODUCTION AS OF 12/31/85 Bbl ESTJ"ATED RESERVES AS OF 12/31185 ESTJfiATED PERCENT OF FIELD DEPLETED AS OF 12/31/SS ROYALTY PURCHASER LEASES State ADL: COitPIENTS Bbl IICF IICF "CF -A.l.3- &AS &as tlell "CF "Cf . ' •;' FIELD 1£111 SPRIII&S UfiiT AREA LOCATION North Slope, onshore BE&AN PRODUCTION Unit agreetent approved in 1984. DINER OPERATOR MCD OIL &AS tninghead &as hll AVERAGE IIONTHL Y PRDDUCTI ON Bbl IICF fltF 1/1/85 thru 9/30/85 ESTJKATED CUftULATJVE PRODUCTION Bbl "CF lltF AS OF 12/31185 ESTiftATED RESERVES Bbl IICf IICf AS OF 12/31/85 ESTJIIATED PERCEHT OF FIELD DEPLETED AS OF 12/31185 -------------------------------ROYALTY PURCHASER -------------------------------LEASES 5bte AIL: C91U!ENTS FIELD IVAN RIVER LOCATION Cook Inlet& onshore, west side BE&AN PRODUCTION Shut-in 19 6, suspended DIINER OPERATOR Chevron OIL &AS Casinghead &as llell AYERA&E IIONTHL Y PRODUCTION Bbl ltCF ftCF 1/1/85 thru 9/30/85 ESTiftATED tunULATIVE PRODUCTION 8111 IICF ftCF AS Of 12/31/85 ESTIMATED RESERVES Bbl IICF [I] ftCF AS OF 12/31185 ESTiftATED PERCENT OF FIELD DEPLETED AS OF 12/31/85 [Jl Ivan River, Lewis River, Pretty Creek and Stu1p Late reservts are co1bintd under lewis River reserves, beloN. ROYALTY PURCHASER LEASES State ADL: tOIIl'IENTS -A.1.4- FIELD LOCATION BE&AN PRODUCTION OlfNER OPERATOR AYERASE ftONTHL Y PRODUCTION 1/1/85 thru 9/30/85 ESTI"ATED CUMULATIVE PRODUCTION AS OF 12/31/85 ESTI"ATED RESERVES AS OF 12/31185 ESTIMATED PERCENT OF FJELD DEPLETED AS OF 12/31/85 ROYALTY PURCHASER KAVIK North Slope, onshore Suspended ARCO OIL Bbl Bbl Bbl Casinghead -------------------------------LEASES State ADL: CDIIItENTS FIELD LOCATION BEGAN PRODUCTION OIINER OPERATOR AVERAGE "ONTHLY PRODUCTION 1/1/85 thru 9/30/85 WIAI Cook Inlet, onshore, east side 1162 ARCO, Chevron, "arathon, Union Union OIL Cuinghead Bbl ESTIKATED CUMULATIVE PRODUCTION AS OF 12/31/85 11,877 Bbl [1 l ESTJ"ATED RESERVES Bbl AS OF 12/31185 ESTJ"ATED PERCENT OF FIELD DEPLETED AS OF 12/31185 [11 Natural gas liquids. &liS &as llell fiCF &AS &as lieU ICF 9,854,629 ftCF "CF 1,659,033,655 ftCF ftCF 820,436 ftCF 671 ROYALTY 12.51, Effective rate: Kenai, 2.068791; Kenai Deep, 0.01 PURCHASER Alaska Pipeline Chevron LEASES COIIIENTS City of Kenai lfarathon LNG Rental vas (SManson River oil fieldl Union Union-Chevron exchange State ADL: 00593, 00594, 00588, 02411, 308223, 324598 The Kenai Unit provides 1ost of the gas sales in the Cook Inlet area. The state does not receive the full 12.51 royalty share because of the predo1inance af Federal leases in the unit and the conveyance of land to Cook Inlet Region Inc. -A.l.S- FIELD LOCATION BE&AN PRODUCTION OIINER OPERATOR AVERAGE IIDNTHLY PRODUCTION 1/1/85 thru 9/30/85 KUPARUK North Slope, onshore 12/81 ARCO, BP, Chevron, E1xon, ~bil, Phillips, Sohio, Union ARCD OIL BAS Casinghead-Gross Casinghead--Net 6,525,877 8bl £11 8,210,727 IICF 1,425 1 406 IICF ESTJIIATED CUMULATIVE PRODUCTION AS OF 12/31185 197,859 Bbl Ul 224,032,900 IICF 38,579,3~ IICF ESTIMATED RESERVES AS Of 12/31/85 ESTJ~TED PERCENT DF FIELD DEPLETED AS DF 12/31185 t1J Includes N&L. ROYALTY PURCHASER All owners LEASES COIIIIENTS FIELD LOCATION State ADL! BEGAN PRODUCTION DNNER OPERATOR AVERAGE IIONTHLY PRODUCTION 1/1/85 thru 9/30/85 1,050,422,369 Bbl IICF 215 1723,783 IICF 161 15% 12.5 % 25512 ~13 25519 25520 25521 25522 25523 25524 25527 25531 2~2~ 25545~ 25546~ 25547', 25548: 25549: 2~50~ 25567~ 2~68~ 25569 25570 2~71 25572 25573 25583 25584 25585 25586 25587 25588 25589~ 25590~ 25591~ 25592~ 25601~ 25602~ 25603~ 25604~ 25605: 25606 25607 25608 25609 25610 25628 25629 25630 25631 25632 25633 25634: 25635: 25636~ 2563~ 25638~ 25639~ 25640: 25641: 25642: 25643 25644 25645 25646 25647 25648 25649 25650 25651 25652 25653 25654: 25655: 25656: 2565r, 25658: 25659: 2566o~ 25661: 25664~ 25665 25666 25667 25668 25669 25670 25671 25672 25673 25674 25675 25676: 2567T, 25678', 25679', 2568o', 25681', 25684', 25685', 25686', 25687 25689 25690 25691 25695 28234 28236 28242 28244 28247 28248 47449~ 81230~ 318602,~ 318603J 318b05, 318628, f18630, l48923, I 348924 348924, 3550i3, 3550i4, 3550~0 LEIIIS RIVER Cook Inlet, onshore, west side 1984 Ci tits Service OIL Casinghead Bbl &AS IICF &as llell 62,154 IICF ESTJIIATED CUMULATIVE PRODUCTION AS OF 12/31/85 Bbl IICF 11441 1 401 IICF ESTliiATED RESERVES AS OF 12/31/85 Bbl IICF 599 1 813 1 537 IICF £11 ESTIIIATED PERCENT OF <11 FIELD DEPLETED AS OF 12/31/85 &Is Well t1l Ivan River, Lewis River, Pretty Creek and Stutp Late rtserves are colbintd under Lewis River reserves. ROYALTY PURCHASER LEASES COIIIIENTS State ADL: 12.51 /Bbl '"CF 51798, 58799, 58800, 511801, 58802, 58803, 58804, 58805, 58806, 75999 Short ter1 gas sales to Enstar began in 1984. -A.1.6- IICF IICF IICF FIELD LOCATION BE&AH PRODUCTION OWNER OPERATOR AVERA&E KDNTHLY PRODUCTION 1/1/85 thru 9/30/85 LISBURNE RESERVOIR North Slope, onshore/offshore Field del1ne1tion and facilities design underlay, production expected to begin in 1986-87, ARCO OIL 69,244 Bbl Casinghead 97,263 "CF &AS &as llell ESTiftATED CUNULATIYE PRODUCTION AS OF 12/31/85 1,422,266 Bbl 2,041,649 ftCF ftCF ESTiftATED RESERVES AS OF 12/31/85 ESTIItATED PERCENT OF FIELD DEPLETED AS OF 12/31/85 ROYALTY PURCHASER ---------------------------.---LEASES State ADL: COMitEHTS FIELD LOCATION BE&AN PRODUCTION OWNER OPERATOR AYERA&E ftONTHLY PRODUCTION 1/1/85 tbru 9/30/85 399,792,267 Bbl 1,099,708 1211 ftCF {1% <n 12.51 £ARTHUR RIVER Cook Inlet offshore, 111t side 12169 AftOCO, ARCO, Chevron, Getty, ftarathoa. Phillips, Union Union . OIL &AS Casinghead &u llell ftCF 644,894 Bbl tll 333 1 460 ftCF 504' 821 ftCF ESTIItATED CUftULATIVE PRODUCTION 514,855,660 Bbl [11 186 1050 1 661 ltCF 113,953,335 ftCF AS OF 12/31/85 ESTIMATED RESERVES 50,261,276 Bbl ltCF [2J 647,485,157 ftCF (31 AS OF 12/31/85 ESTlftATED PERCENT OF 911 321 FIELD DEPLETED AS OF 12/31/85 [1] Includes N&L. t2l Included under &as Nell reserves. [3] Trading Bay reserves are colbined •ith ftcArthur River reserves. ROYALTY 12.5 1 PURCHASER Tesoro LEASES State ADL: 17579, 17594, 17002, 18716, 18729, 18730, 18758, 18772, 18777, 21068 CO""ENTS &as fro• this field is casinghead gas and Mas for1erly flared. DO&C Fl~ring Order 1104, 6/30/71 1 has prohibited flaring since 7/1/72 and this gas is no• recovered and used locally. -A.l. 7- FIElD LOCATION BEGAN PRODUCTION !liNER OPERATOR "IDDL£ &ROUND SHOAL Cook Inlet, offshore, east side 9/67 IMOCO, ARCOJ Chevron, Setty, Phillips, Shell MOCO, Shell OIL BAS Casinghead lis lell AVERAGE MONTHLY PRODUCTION 254,850 Bbl 175,709 "CF l7, 910 tiCF 1/1/85 thru 9/30/85 ESTJKATED CUftULATJVE PRODUCTION 147,014 Bbl AS OF 12/31185 74,237,880 tiCF 1,437,504 "CF ESTIMATED RESERVES 10,941,801 Bbl AS OF 12/31/85 ESTIRATED PERCENT OF FIELD DEPLETED AS DF 12/31/85 93% [JJ Included under Casinghead reserves. ROYALTY 12.5 X PURCHASER Tesoro LEASES State ADL: 17595, 18754, 18756 COMMENTS 6,436,571 "CF 92% Recent increases in gas prices aay encourage a reevaluation of this gas. IICF UJ &as froa this field is casin~ead gas and was foraerly flared. DOSC Flaring Order 1104, 6/30/71, has prohibited flaring since 7/1/72 and this gas is no• recovered and used locally. FIELD LOCATION BE&AN PRODUCTION OlfNER OPERATOR ftiLNE POINT North Slope, onshore Production co11enced in 1985. Chaaplin, Chevron, Cities Service, COIOCO, Reading • Bates Conota OIL &AS Casinghead &u lell AVERAGE MONTHLY PRODUCTION Bbl tiCF 1/1/85 thru 9/30/85 ESTIMATED CUMULATIVE PRODUCTION Bbl MCF AS OF 12/31/85 ESTIMATED RESERVES 60,000,000 Bbl AS OF 12/31/85 "CF ESTIMATED PERCENT OF FIELD DEPLETED AS OF 12/31/85 ROYALTY PURCHASER LEASES COIIMENTS State AIL: Estiaated effective rate, 181. 25509, 25516, 25518, 315848, 47433, 47434, 47437, 47438 -A.l.8- IICF MCF "CF NICOLAI CREEK FIELD LOCATION BE&AN PRODUCTION DitMER Cook lnltt, onshore~ffshore, ~est side 10/6Bt now shut-in Superior, Texaco OPERATOR AVERAGE IUJNTHI. V PRODUCTION 1/1/85 thru 9/30/85 ESTiftATED CUftULATIYE PRODUCTION AS OF 12/31/85 ESTIMATED RESERVES AS OF 12/31/85 ESTiftATED PERCENT OF FIElD DEPLETED AS OF 12/31185 Texaco OIL Bbl Bhl Bbl ROYALTY 12.5 X PURCHASER AtiOCO -------------------------------LEAS£5 State ADL: 11585, 17598, 63279 CDftftENTS Casinghead II:F ftCF &AS &as llell IU:F 1,0&2,055 ftCF 3,000,000 ftCF 261 &as fra1 this stall field, Mben productd, is used only by platfarl and share production facilities. At present there is no production and no prospective purchaser far the state's royalty share. IIORTH COOk INLET FIELD LOCATION BEGAN PRODUCTION DitHER Cook Inlet, offshart, lid-channel 3/69 OPERATOR Phillips Phillips AVERAGE ftONTHLY PRODUCTION 1/1/85 thru 9/30/85 ESTiftATED CUftULATIYE PRODUCTION AS OF 12/31/85 ESTIRATED RESERVES AS OF 12/31/85 ESTIRATED PERCENT OF FIELD DEPLETED AS OF 12/31/85 ROYALTY PURCHASER Alaska Pipeline Phillips ------------------------------- OIL Bbl Bhl Bbl 12.5 X Casinghead LEASES State ADL: 17589 1 17590 1 18740 1 18741, 37831 CDftftENTS &AS ftCF tu:F ftCF &as lell 3,830 1682 ftCF 733,719,471 IU:F 846,507,953 ftCF 461 &as froa this field is prilarily delivered to the Phillips LNG plant and subseqaently sold in Japan. -A.l.9- IIIORTH FORK FIELD lOCATION BE&AN PRODUCTION MER Cook Inlet, onshore, east side Shut-in 1965 OPERATOR Chevron AVERAGE ~NTHLY PRODUCTION 1/1/85 thru 9/30/85 ESTl"ATED CUKULATIYE PRODUCTION AS OF 12/31/85 ESTIKATED RESERVES AS OF 12131/85 ESTI"ATED PERCENT OF FIELD DEPLETED AS OF 12/31/85 ROYALTY PURCHASER -------------------------------LEASES State AIL: COII"ENTS FIELD LOCATION BE&AN PRODUCTION DINER OPERATOR AVERAGE "ONTHLY PRODUCTION 1/1/85 thru 9/30/85 OIL Cuinghead Bbi Bbl Bbl POINT TIIIMSON UllT AND FLAJ"AN ISLAND Marth Slope, onshore/offshore Shut-in EXXON OIL Casinghead Bbl ESTIKATED CUftULATlYE PRODUCTION AS OF 12/31/85 Bbl IICF ESTJKATED RESERVES AS OF 12/31/85 350,000,000 Bbl £11 51000 1000,000 "CF [1l ESTIMATED PERCENT OF FIELD DEPLETED AS OF 12/31185 [11 Oil and gas condensate. ROYALTY PURCHASER LEASES State AIL: C~~NTS Gas ~ell ~F 12,000,000 "CF n &AS Gas ~ell "CF Unit Area expansion approved in 1984. ~rket analysis underway to deter•ine develop1ent potential ofgas condensate and natural gas liquids production and sales fro• the unit. -A.l.lO- FIELD LOCATION BEBAN PRODUCTION DINER OPERATOR AVERA&E ftDNTHLY PRODUCTION 1/1/85 thru 9/30/85 PRUDHOE BAY -SADLEROCHIT RESERVOIR Marth Slope, onshore 10/69 Alerada-Hess, ARCD, BP, Chevron, Exxon, Betty, LL,E, "arathon, "obil, Phillips1 .Shell, Sohio ARCO, Son1o OIL Casinghead-Gross 47,293 1 162 BbJ £11 76 1513,903 ftCF &~ Clsinghead·Net 71421,810 ~F ESTIMATED CUftULATIVE PRODUCTION 41 357 1077 1577 8bJ £11 5,434 1680,942 ftCF 513 1097 1872 ftCF AS OF 12/31/85 ESTI"ATED RESERVES 51913 1 1291514 Bbl ftCF 28 1977 1734 1570 ftCF AS OF 12/31/85 ESTlftATED PERCENT OF FIELD DEPLETED AS OF 12/31/85 [11 Includes M&L. ROYALTY PURCHASER ftapto·BVEA Tesoro Chevron LEASES State ADL: COftftENTS 42% 2% 12.51 25637 28238 28239 28240 28241 28244 28245 28246 28257 28258 28259~ 28260~ 28261~ 28262: 28263: 28264: 28265~ 28275: 28276~ 28277 28278 28279 28280 28281 28282 28283 28284 28285 28286 28287 28288~ 28289: 28290: 28299: 28300~ 28301: 28302~ 28303: 28304~ 28305 28306 28307 28308 28309 28310 28311 28312 28313 28314 28315 283161 283201 28321 1 283221 283231 283241 283251 283261 283271 28328 28329: 28330: 28331: 28332: 28333: 28334: 28335: 28339: 28343: 28345 28346 28349, 34628 34629, 34630, 34631 34632 47446 47447 47448 47449: 47450, 47451: 47452, 47453, 47454: 47469: 47471: 47472: 47475 47476 The state,s royalty share of oil produced is 12.5%1 with 14.9% of this share presently being taken in kind and sold to North Pole Refinery and Bolden Valley Electric Assn. An additional 35.51781 of the state,s share is taken in kind and sold to Tesoro. The retainder is taken in value. Additional royalty oil sales in 1984 are conteaplated to be taken in value. Saall aaounts of produced gas are presently sold to the Trans-Alaska Pipeline. There presently is no other aarket. The state's roualty share of gas is 12.5%, which is taken in~value. Unit Area expansion approved 1984 1 with additional developaent work continuing. -A.l.ll- &as Nell FIELD LOCATION BEGAN PRODUCTION OWNER OPERATOR AVERA&E "ONTHLY PRODUCTION 1/1/85 thru '1/30/85 STERLING Cook Inlet, onshore, east side 5/62 llarathon, Union Union OIL CISinghead Bbl ESTl"ATED CUftULATJVE PRODUCTION AS OF 12/31/85 Bbl ESTJIATED RESERVES Bbl AS OF 12/31/85 ESTI"ATED PERCENT OF FIELD DEPLETED AS OF 12/31185 ltCF "CF "CF ROYALTY 12.51, Effective rate, 1.554611 PURCHASER Sport Lake Greenhouse ---------------------------·---LEASES State ADL: 02497, 320912, 324599 co"nENTs SAS &as llell 11 027 lfCF 21 086,637 IICF 22 1'187,672 "CF 81 Since Federal and Cook Inlet Region Inc. leases are included, the state's royalty share is approxiaately 1.61. The only gas sold froa this field is tonsuaed locally. There is no 911 pipeline currently available to deliver this gas froa this field to any other aarket. Because of l11ited reserves, there is no current prospect of additional 11rkets. FJELD LOCATION BEGAN PRODUCTION DIINER OPERATOR AVERAGE ~NTHLY PRODUCTION 1/1/85 thru 9/30/85 ESTI"ATED C~ULATIVE PRODUCTION AS OF 12/31/85 ESTJnATED RESERVES AS OF 12/31/85 ESTJnATED PERCENT OF FJELD DEPLETED AS OF 12/31/85 STUftP LAKE UNIT AREA Cook Inlet, onshore, •est side Suspended Chevron OIL Casinghead Bbl Bbl Bbl BAS Gas llell ltCF lfCF [1] "CF [ll Ivan River, Le•is River, Pretty Crttk and Stuap Late reserves are coabined under Le•is River reserves, above. ROYALTY PURCHASER -------------------------------LEASES State ADL: CO""ENTS -A.l.l2- FIELD LOCATION BE&AN PRODUCTION DINER OPERATOR AVERAGE "ONTHLY PRODUCTION 1/1/85 thru 9/30/85 THEODORE RIVER lPRETTY CREEK UNIT AREA> Cook Inlet, onshore, •est side &uspended Chevron OIL Casinghead Bbl ftCF ESTIKATED CUftULATIVE PRODUCTION Bbl "CF AS or 12131185 ESTI"ATED RESERVES Bbl IICF AS OF 12/31/85 ESTI"ATED PERCENT OF FIELD DEPLETED AS OF 12/31/85 &AS &as Mell KCF IICF [1] lttF ttl Ivan River, Lewis River, Pretty Creek 1nd Stu1p Late reserves are tDibined under le~is River reserves, above. ROYALTY PURCHASER -------------------------------LEAS£5 State ADL: COitltENTS Production to t011ence in 1986 with delivery of gas to Enstar. FIELD LOCATION BEGAN PRODUCTION OINER OPERATOR AVERAGE ltDNTHL Y PRODUCTION l/1/85 thru 9/30/85 TRADING BAY Cook Inlet, offshore, •est side 12/67 llarathon, Union Union OIL Casinghead 14,692 Bbl [1) 87,138 IICF ESTIKATED CUKULATIIIE PRODUCTION AS OF 12/31/85 87 1 424,728 Bbl Ill 58,803,352 IICF ESTIKATED RESERVES AS OF 12/31/85 1,983,691 Bbl ESTIKATED PERCENT OF 981 FIELD DEPLETED AS OF 12/31/85 Ill Includes N&L. I2l Trading Bay reserves are tOibined with ltcArthur River reserves, above. ROYAlTY 12.5 X PURCHASER Tesoro LEASES State ADL: 18731 CD""ENTS 6AS &as tlell 34,961 ltCF I2l IICF &as fro• this field is casinghead gas and for1erly was flared. DDSC Flaring Order 1104, 6/30/71, has prohibited flaring since 7/1/72, and this gas is noN recovered and used locally. lEST FORK FIELD LOCATION BEGAN PRODUCTION OMHER Cook Inlet, onshore,east side Shut-in gas field. OPERATOR OIL Casinghead AVERAGE IIONTII. Y PRODUCTION Bbl IICF 1/1/85 thru 9/30/BS ESTiftATED CUftULATJYE PRODUCTION Bbl JICF AS OF 12/31/85 ESTINATED RESERVES Bbl ftCF AS OF 12/31/85 ESTiftATED PERCENT OF FIELD DEPLETED AS OF 12/31185 ----ROYALTY PURCHASER --------------LEASES Shte ADL: C8flltENTS FIELD lEST SAK RESERVOIR LOCATION North Sl:ge, onshore BEGAN PRODUCTION Pilot pr uction underway OIINER OPERATOR ARCO, Conor:o OIL Cuinghead AYERA&E ltONTII. Y PRODUCTION Bbl JICF 1/1/85 tbru 9/30/85 ESTiftATED CDnULATIVE PRODUCTION 3,365 Bbl 4,980 ftCF AS OF 12/31/85 ESTlftATED RESERVES N/D Bbl MID ftCF AS OF 12/31/85 ESTiftATED PERCENT OF FIELD DEPlETED AS OF 12/31/85 -------------------------------ROYALTY PURCHASER -------------------------------LEASES State ADL: COftltENTS Reservoir delineation and engineering/geological studies continuing. S/D Tbl: Apdxa, rev: 1/8/85 -A.l.l4- &AS 61s llell 21333 ftCF 1,547,210 ftCF 5,972,004 ftCF 21% &AS &as llell ftCF ftCF ftCF APPENDIX A.2 COOK INLET LEASE OWNERSHIP COOK INLET LEASE OWNERSHIP APPENDIX A.2 (Data for 7/1/84 Tbru 6/30/851 FIELD LEASE OIINERSHIP SALE YOLUIES Sub-unit ---------------------------------------~----------------Producer llorkint %of Avera~e State Royalty Share Purchaser Interes field ftonth y Production -------------fftcfllto.l 1 ftcfllto. BEAVER CREO:: Union 50.00% 394,717 ftarathon 50.00% 394,717 ==== ========= TOTAL 789,433 BELUGA RIVER llell 214·35 Chevron 100.001 135 985 7.5551 10,274 church 7.13X 127', 863 7.555% 9,660 Ens ar 0.45% 8,122 7.5551 614 All Other lieU s Chevron 33.331 552,855 7.5551 41,768 Chugach 28.70% 515,065 7.5551 38,913 En star 2.11% 37 790 7.5551 2855 ARCD 33.33% 552~855 7.555% 41 1,768 Chuiach 28.70% 515,065 7.5551 38,913 Ens ar 2.11X 37,790 7.555% 2 855 Shell 33.33% 552 855 7.5551 41:768 church 28.70% 515~065 7.555% 38,913 Ens ar 2.11X 37,790 7.5551 2,855 -----------Subtotal-Chu~ach Subtotal-Ens ar 1,672,942 121,490 I ----============= TOTAL 1,764,060 I 4 1onth average. GRANITE POINT Granite Point I "obil 75.00% 2,321 A"DCO ftarathon Union 25.001 784 MOCD ftarathon Granite Point JI AftOCD 25.001 ARCD 12.501 Chevron 12.50% Gettf 25.001 Phil ips 25.00% -------------Subtotal-AtroCO 2,312 Subtotal-ltarathon 2,350 f ==== ·=========== TOTAL 3,095 I 4 •onth average. -A.2.1- FIELD LEASE OMNERSHIP SALE YOLUftES Sub-unit --------------------------------------------------------Producer Workini X of Avera!e State Royalty Share Purchaser Interes field ltonth y Production ·-·---------lflt;flfto. l X fk:flfto. KENAI Union 50.00% APL 1-Anchorage 10.28% 845,622 ' 2.0691 17,494 APL -Nikiski 0.19% 15,888 2.0691 329 Union-chevron Exchange 0.19% 15,518 2.0691 321 Ci tl of Kenai 0.251 20,590 2.0691 426 Ren al 4.501 370 334 2.0691 7,661 Rental-Additional 2.371 1941,981 2.0691 4 034 Union Clinical 40.73% 3,352,041 2.069% 69:347 "arathon 50.00% APL I-Anchorage 14.381 1,183,535 2.0691 24,485 APL II-Anchorage 4.48% 368,603 2.0691 7,626 APL-Nikisti 0.191 15,888 2.0691 329 City of Kenai 0.251 20 599 2.0691 426 Rental 4.50% 370:242 2.0691 7,660 Rental-Additional 2.36% 194,450 2.0691 4 023 Tokyo Utilities 15.32% 1,261,073 2.0691 26:089 -----·------Subtotal-Union 4,814,974 Subtotal-~rathon 3,414,390 Subtotal-API. I-Anchorage 2,029,157 Subtotal-APL II-Anchorage 368,603 Subtotal-APL -Ni ki sti 31,776 Subtotal-Union-Chevron Exchange 15,518 Subtotal-Cit{ of Kenai 41,189 Subtotal-Ren al-SManson R. 740,576 Subtotal-Rental-Additional 389 431 Subtotal-Union Chetical 3 r:d 041 Subtotal-Tokyo Utilities 1:261:073 ==== ======·===== TOTAL 8,229,364 LEWIS RIVER 6rou~ 1 i ties Svcs 81.00% N/D Ens tar Pacihc Ltg 19.001 N/D En star 6rou~ 2 ities Svcs 15.00% N/D En star Paci fie Ltg 85.001 N/0 Ens tar &ro~ 3 acihc Ltg 100.001 En star ==== ==========-TOTAL 153,171 ·' t4 tonth average. ftcARTHUR RIVER Nest Foreland Union 49.001 3,248 "arathon 49.001 3,248 ARCD 2.001 133 Middle Kenai 6 Union 49.001 7,484 "arathon 49.001 7,484 ARCD 2.00% 305 Hetlock Union 40.95% 49,192 ARCD 12.901 15,496 "arathon 40.951 49,192 Alto CO 1.40% 1,682 Phillips 1.401 1 682 Setty 1.401 1:682 Chevron 1.001 1,201 Kenai 6 Zone-K10 Union 100.001 213,401 :.::: -·===== TOTAL 355,431 -A.2.2- FIELD LEASE DlfNERSHIP SALE VOLUftES Sub-unit --------------------------------------------------------Producer Markin~ t of Avera~e State Royalty Share Purchaser Interes field ftonth y Production ------------Cftd/fto.l 1 lltflfto. ftlDDLE GROUND SHOAL Grou~ 1 lOCO 25.00% 8,071 ARCO 12.50% 4,036 Chevron 12.50% 4 036 6ett{ 25.00% a',o11 Phil ips 25.00% 8,071 SrouB 2 hell 66.67% ARCO 33.33% ·=== ==·====·== TOTAL 32,284 NORTH COOK INLET Pbilli~s 100.00% ~932,294 Phil ips '931,648 Boiler fuel 93 Turbine fuel 347 NORTH TRADING BAY 6rou~1 RCO 100.001 6rouf 2 exar::o 50.00% Superior 50.00% •=== TOTAL SOUTH IlDDLE &ROUND SHOAL AID CD 25.00% ARCD 12.50% Chevron 12.50% 6ett{ 2~.00% Phil ips 25.00% -=== TOTAL STERLING Union 50.00% Peninsula Greenhouse 736 1.55~% 11 ftarathon 50.00% Peninsula Greenhouse 736 1.555% 11, === ==-======== TOTAL 1,472 RANSON RIVER Soldotna Creek Unit Chevron 50.00% ARCO 50.00% Swanson River Unit Chevron 44.75% ARCO 44.75% Union 5.25% ftarathon 5.25% ==== TOTAL -A.2.3- FIELD LEASE DMNERSHIP &ALE YOLUfiES Sub-unit --------------------------------------------------------Producer llorkini X of Avtra~e State Royalty Share Purchaser Interes fitld ftonth y Production ----------------(ftcf/"o.l X "cf/fto. TRADINS BAY A-b ltarathon 33.33% CISS5 ~ 12.500X 3 Union 33.33X CIBSS 25 12.500X 3 Suterior 1b.b7% 1665 12 12.500% 2 Texaco 1b.b7X CIS6S 12 12.500X 2 A-15 ftarathon 33.33% CJ6SS B 12.500X Union 33.33X CI&&S B 12.500X 1 Su~erior 1b.b7X 1665 4 12.500X 0 Texaco lb.b7% Non-Pool 4 12.500% 0 Union 50.00X CI665 547 12.500% bB ftarathon 50.00X CI&SS 547 12.500X bB ··== •z======== TOTAL I, 190 1/ Averape 1onthly volu1e is calculated as annual volu1e divided bl 12 10nths. 2/ Royal land contract values are the 1ost current in effect as~ July 1985. 3/ Uuanti y ter1 could extend or shorten the contract period. 4/ Price reported by ftarathon is bein~ paid under protest. 5/ Contract Mrice is a gross price be ore transportation costs. 6VDLVAL;9/18/ 5 .·i -A.2.4- i I APPENDIX A.3 COOK INLET FIELD OWNERSHIP COOK INLET FIELD OWNERSHIP FIELD ADftiNISTRATDR Field Sub-unit LEASE lllftBER Lease D•ner, Interest BEAVER CREEK UNIT FEDERAL ftaratbon 100.0001 002-028078 002-028083 002-028118 002-028120 Subtotal CIRI llaratban 100.000'% 002-028078 002-028083 002-028118 002-028120 Subtotal TOTAL: FEDERAL+CIRI OIL PIA Tract Adain. Adain. Factor X af lea!e X af PIA 100.00000001 82.81250001 82.8125000'% 100.00000001 17.18750001 17.18750001 -------------------100.00000001 17.18750001 ;;:o::::&:::: ========== 100.00000001 100.00000001 -A.3.1- APPENDll A.3 &AS PIA Tract Ad1in. Factor X af lease 11/D 100.00000001 ti/D 100.0000000'% N/D 100.0000000% ti/D 100.00000001 -------67.686866o'l 7.8405018'1 100.0000000'% 8.316532o'l 1oo.ooooooo1 13.1048177'% 100.0000000% 3.05128131 100.00000001 ---------32.31313341 ·====·===== 100.00000001 Adain. 1 af PIA 11/D ti/D N/D N/D -----------67.o86B66o1 7.84050181 s.31o53261 13.10481771 3.0512813% ----------32.3131334% =:========= 100.00000001 FIELD AD"INISTRATOR Field Sub-unit LEASE NUftBER Lease Owner, Interest BELUGA RIYER UNIT STATE Chevron 33.3301 ADL-17658 Arca 33.330% ADL-17592 Shell 33.3401 ADL-17599 ADL-21126 ADL-21127 ADL-21129 ADL-21129 ADL-58815 ADL-58820 ADL-58831 Subtotal llell 1214-35 Chevron 100.0001 ADL-17658 ADL-17592 ADL-17599 ADL-21126 ADL-21127 ADL-21128 ADL-21129 ADL-58815 ADL-58820 ADL-59831 FEDERAL Chevron 33.330% 02-029656 Arca 33.330% 02-029657 Shell 33.3401 Subtotal Nell 1214-35 Chevron 100.0001 02-029656 02-Q29657 Subtotal CIRI Chevron 33.3301 02-029656 Arca 33.330% Shell 33.340% Subtotal Nell 1214-35 Chevron 100.0001 02-029656 Subtotal: FEDERAL+CIRI TOTAL: STATE+FEDERAL+CIRI FEE SiftPLE INTEREST Chevron Arca Shell 33.3301 FEE SI"PLE 33.3301 33.340% OIL PIA Tract Adtin. Adtin. Factor 1 of Lease X of P/A 0.00000001 0.0000000% TOTAL: STATE+FEDERAL+CIRI+FEE SIMPLE -A.3.2- SAS P/A Tract Adtin. Factor % of lease 12.7251000% 100.00000001 7.0085000% 100.00000001 6.0147000% 100.00000001 0.7857000% 100.00000001 9.40190001 100.00000001 14.5560000% 100.0000000% o. 5799000% 100.00000001 0.01580001 100.00000001 1.5893000% 100.00000001 7.76330001 100.00000001 ----------60.4402000% 12.72510001 100.00000001 7.0085000% 100.00000001 6.01470001 100.00000001 0.7857000% 100.00000001 9.40190001 100.0000000% 14.5560000% 100.0000000% 0.57990001 100.0000000% 0.0158000% 100.0000000% 1.5893000% 100.0000000% 7.7633000% 100.00000001 -----------60.4402000% 11.78800001 98.3034000% 27.5218000% 100.0000000% -----------39.3098000% 11.78800001 98.3034000% 27.5218000% 100.0000000% -----------39.3098000% 11.78800001 1.69660001 Adein. 1 of P/A 12.72510001 1. 00950001 6.0147000% o. 7857000% 9. 40190001 14.5560000% 0.5799000% o. 0158000% 1. 58930001 7.76330001 -----------60.44020001 12.72510001 7.00850004 6.01470001 o. 7857000% 9. 40190001 14. 5560000% o. 5799000% o. 0158000% 1. 58930001 7. 7633000% ----------- 60. 44020001 11. 58800481 27.52180001 ----------- 39. 1 0980481 11. 58900481 27.52180001 --------- 39. 1 0980481 0.1999952% 11.78800001 1.69660001 0.199~521 51.09780001 39. 30980004 :::::z::::: 99.7500000% 0.2500000% 100.0000000% 0.25000001 ::z:::::.:: 100.00000001 FIELD AD"INISTRATOR Field Sub-unit LE ASE NlllfBER Lease Owner, lnterest GRANITE POINT FIELD STATE Sroup 1 "ob il Union Group 2 AIDCD Ar co Chevron Sett/ Phil ips KENAI STATE Union "ara thon FEDERAL Union Cl RI "arathon Union "arathon 75.000% ADL-18761 25.000% 25.0001 ADl-17586 12.5001 ADL-17587 12.500! ADL-18742 25.000% 25.000% TOTAL: STATE 50.000% ADl-00588 50.000! ADL-00593 ADL-00594 ADL-02411 ADL-308223 ADL-324598 Subtotal 5o.ooot 02-028047 50.0001 02-028055 02-028056 02-028103 02-028140 02-028143 Subtotal 50.0001 02-028047 50.000% 02-028055 02-028056 02-028103 02-028140 02-028142 02-028143 ADL-00460 ADL-022330 Subtotal DIL PIA Tract Ad1in. Ad1in. ------~~~~~ --~~~!_:~~~: ____ :_~!_!!~ 100.00000001 100~00000001 100.0000000! 2.10400001 100.00000001 2.1040000! 1.24300001 100.0000000! 1.24300001 96.65300001 100.00000001 96.65300001 ' =========== 100.00000001 Subtotal: STATE•FEDERAL•CIRI OTHER UNION ~ "ARATHON LEASES Chevron Ar co Subtotal TOTAL: STATE+fEDERAL•CIRI+OTHER ... -A.3 .3- SAS P/A Tract Ad1in. Factor t of lease Adlin. ! of PIA 100.00000001 100.00000001 100.0000000! 2.10400001 100.0000000! 2.10400001 1.2430000% 100.0000000% 1.24300001 96.65300001 100.0000000! 96.65300001 ========·== 100.00000001 6.76070001 100.00000007. 6.76070001 7.44300001 100.00000001 7.44300001 0.67170001 100.0000000! 0.6717000% 0.76080001 100.00000001 0.76080001 0.0083000! 100.0000000! 0.00830001 0.9058000% 100.00000001 0.90580001 16.55030001 16.55030001 10.26950001 60.9085000! 6.25499841 15.44500001 39.77639841 6.14346471 10.66770001 91.27490001 9.73693251 0.3021000! 20.02562711 0.06049741 5.66250001 92.8239000! 5.25615331 5.93040001 96.79990001 5.74062131 ---------------------48.27720001 33.19266771 10.2695000% 39.0915000! 4.01450161 15.44500001 60.22360161 9.30153531 10.66770001 8.72510001 0.93076751 0.30210001 79.97437291 0.24160261 5.66250001 7.1761000% 0.40634671 19.33770001 100.00000001 19.33770001 5.93040001 3.20010001 0.1897787% 1.20860001 100.00000001 1.20860001 11.17190001 100.00000001 11.17190001 ---------------------79.99540001 46.80273231 ====z====== 96.54570001 2.67450001 100.00000001 2.6745000I 0.38990001 100.0000000! 0.38990004 0.38990001 100.00000001 0.38990001 ----------------------3.45430001 3.4S430001 =========== 100.0000000% <I 'I FIELD LEASE OIL &AS AD"IMISTRATOR NUftBER ------------------------------------------------------------------------------Field Sub-unit PIA Tract Adlin. Ad1in. P/A Tract Ad1in. Ad1in. Lease O.ner, Interest Factor %of Lease % of P/A Factor %of Lease X of PIA LEMIS RIVER UNIT STATE &rouf 1 Ci ies Svc 81.0001 ADI.-58798 Pacific Lt 19.000% ADL-58799 ADL-58800 ADL-58802 ADI.-58803 ADI.-58804 ADL-58805 ADL-58806 Subtotal &rouf 2 Ci ies Svc 15.0001 ADI.-58801 Pacific lt 85.0001 Group 3 Pacific Lt100.0001 ADL-75999 TOTAL: STATE IICARTHUR RIVER STATE »est Foreland Union 49.0001 ADL-18730 larathon 49.0001 ADL-17594 Arco 2.0001 ADI.-18729 ADL-18772 Subtotal Iiddle Kenai 6 Union 49.0001 ADL-17594 larathon 49.000% ADL-18730 Arco 2.0001 ADL-18729 ADL-18772 Subtotal He1lock Union 40.9501 ADL-17579 A reo 12.9001 ADL-17602 ftarathon 40.9501 ADL-18759 AIDCO 1.4001 ADL-18777 Phillips 1.4001 ADL-21068 Getty 1.4001 ADL-17594 Chevron 1.0001 ADL-18729 ADL-18730 ADL-18772 ADL-18716 Subtotal Kenai 6 lone{ K-10 Union 00.0001 ADL-19777 TOTAL: STATE 43.47000001 100.00000001 43.47000001 39.13000001 100.00000001 39.13000001 8.70000001 100.00000001 8.70000001 8.70000001 100.00000001 8.7000000% --------------------100.0000000% 100.00000001 26.67000001 100.0000000% 26.67000001 32.59000001 100.00000001 32.5900000% 34.81000001 100.00000001 34.81000001 5.93000001 100.00000001 5.93000001 --------------------100.00000001 100.00000001 12.94800001 100.00000001 12.94800001 3.70000001 100.00000001 3.70000001 2.77500001 100.00000001 2.77500001 4.60100001 100.00000001 4.6010000% 0. 92500001 1 00.0000000% 0.92500001 28.64800001 100.00000001 28.64800001 17.83300001 100.00000001 17.83300001 16.64800001 100.0000000% 16.64800001 9.24900001 100.00000001 9.24900001 2.67300001 100.00000001 2.67300001 ---------------------100.00000001 100.00000001 100.00000001 100.00000001 =========== 100.00000001 -A.3.4- 100.00000001 100.00000001 100.00000001 100.00000001 100.00000001 100.00000001 100.00000001 100.0000000% 100.00000001 100.00000001 100.00000001 100.00000001 100.00000001 100.00000001 100.00000001 100.00000001 100.00000001 100.00000001 100.00000001 100.00000001 100.00000001 100. 00000001 I 00. 0000000% 100. 00000001 100.00000001 100.00000001 100.00000001 100.00000001 100.00000001 100.00000001 100.00000001 100.00000001 -======== 100.00000001 43.47000001 100.00000001 43.47000001 39.13000001 100.00000001 39.13000001 8.70000001 100,00000001 8.70000001 8.70000001100.00000001 8.70000001 -------------------100.00000001 100.00000001 26.67000001 100.0000000% 26.6700000% 32.59000001 100.00000001 32.59000001 34.81000001 100.00000001 34.81000001 5. 93000001 100. 0000000% 5.93000001 --------------------100.00000001 100.00000001 12.94800001 100.00000001 12.94800001 3.70000001 100.0000000% 3.70000001 2.77500001 100.00000001 2.7750000% 4.6010000% 100.00000001 4.6010000% 0.92500001 100.00000001 0.92500001 28.64800001 100.00000001 28.64800001 17.83300001 100.00000001 17.8330000% 16.64800001 100.0000000% 16.6480000% 9.24900001 100.00000001 9.24900001 2.6730000% 100.00000001 2.67300001 ----------------------100.00000001 100.00000001 100.00000001 100.00000001 =-====== 100.00000001 I ----1 FIELD ADIIINISTRATOR Field Sub-unit LEASE lltmBER Lease Owner, Interest !liDDLE GROUND SHOAL STATE Group 1 AID co Arco Chevron &ettl Phi 1 ips Group 2 Shell Area Chevron ·NORTH COOK INLET STATE 25.000% 12.500% 12.500% 25.000% 25.000% ADL-17595 33.330% ADL-18754 33.330% ADL-18756 33.340% Subtotal TOTAL: STATE Phillips 100.000% ADL-17589 ADL-17590 ADL-18740 ADL-18741 ADL-37831 TOTAL: STATE NORTH TRADING BAY UNIT STATE Group 1 Arco 100.000% ADL-17597 ADL-18776 Subtotal Group 2 Texaco 50.000% ADL-34531 Superior 50.000% TOTAL: STATE SOUTH !liDDLE SROUND SHOALS STATE AIOCO Arco Chevron Settl Phi 1 ips 25.0001 12.500% 12.500% 25.000% 25.000% ADL-18744 ADL-18746 TOTAL: STATE OIL PIA Tract Adain. Factor % of Lease Adain. % of P/A 26.58800001 100.0000000% 26.5880000% GAS PIA Tract Adain, Factor 1 of Lease Ad1in. % of PIA 26.5880000% 100.0000000% 26.5880000% 45.23400001 100.0000000% 45.2340000% 45.2340000% 100.0000000% 45.2340000% 28.1780000% 100.0000000% 28.17800001 28.17800001 100.0000000% 28.17800001 -----------73.41200001 73.41200001 ========= 100.00000001 50.00000001 100.0000000% 50.0000000% 28.57000001 100.00000001 28.57000001 78.5700000% 78.57000001 21.43000001 100.0000000% 21.4300000% ---------------------::&::::=== 100.00000001 100.00000001 6.89656001 100.0000000% 6.8965600% 93.10344001 100.0000000% 93.10344001 &:::::::::: 100.00000001 -A.3.5- -----------------73.41200001 73.41200001 =========== 100.0000000% 44.7324000% 100,0000000% 44.73240001 6.54300001 100.00000001 6.54300001 8.1787000% 100.00000001 8.17870001 6.54300001 100.00000001 6.54300001 34.0029000% 100.0000000% 34.00290001 t::========= ::az======== 100.0000000% 100.00000001 FJELD LEASE OIL BAS ADIIINJSTRATOR lll.lftBER ------------------------------------------------------------------------------Field Sub-unit PIA Tract Ad1in. Ad1in. PIA Tract Ad1in. Adein. lease OMner, Interest Fidor 1 of lease X of P/A Factor 1 of lease 1 of P/A ------------------------ ------------ ----------------------- STERllNS UNIT STATE Union 50.000% ADL-324599 4.9484000% 100.0000000% 4.8484000% llarathon 50.000% ADL-324599 1.5990000% 100.0000000% 1.5990000% ADI..-02497 3.6283000% 100.0000000% 3.6283000% ADL-320912 2.36120001 100.0000000% 2.3612000% ----------------------Subtotal 12.4369000% 12.43690001 FEDERAL Union 50.0001 02-G28063 47.63880001 40.1451498% 19.1246676% "arathon 50.0001 02-028135 30.58220001 29.3066489% 8.9626180% ----------------------Subtotal 78.22100001 28.08728561 CIRI Union 50.000% 02-G28063 47.63880001 59.85485021 28.51413241 llarathon 50.0001 02-028135 30.58220001 70.69335111 21.61958201 ADL-01836 2.63160001 100.0000000% 2.63160001 ADL-51502 5.04630001 100.00000001 5.0463000% ADL-51502 1.66420001 100.0000000% 1.66420001 -----------------·--Subtotal 87.56310001 59.47581441 ··====:=== TOTAL: STATE+FEDERAL+CIRI 100.00000001 SIANSON RIVER UNIT t FEDERAL Chevron 48.486% 002-028077 0.86141001 100.00000001 0.86141001 0.9614100% 100.00000001 0.86141001 Arco 48.486% 002-028384 0.29070001 100.0000000% 0.29070001 0.29070001 100.00000001 0.29070001 Union 1.5141 002-028391> 0.02866371 100.00000001 0.0286637% 0.02866371 100.0000000% 0.02866371 Marathon 1.5141 002-028399 2.98886361 100.00000001 2.9988636% 2.98886361 100.0000000% 2.9888636% 002-028405 0.17109371 100.00000001 0.1710937% 0.1710937% 100.00000001 0.1710937% 002-028406 11.39199001 100.00000001 11.3919900% 11.39199001 100.0000000% 11. 39199001 002-028990 1.2663167% 100.0000000% 1.2663167% 1.26631671 100.0000000% 1.26631671 002-028993 0.6648250% 100.0000000% 0.6648250% 0.66482501 100.00000001 0.66482501 002-028996 16.5466071% 100.00000001 16.5466071% 16.54660711 100.00000001 16.546110711 002-028997 30.23385001 100.00000001 30.2338500% 30.23385001 100.0000000% 30.23385001 002-029002 0.1693000% 100.0000000% 0.1693000% 0.16930001 100.0000000% 0.16930001 ----------- ........ _______ ---------------------Subtotal 64.61361981 64.61361981 64.61361981 64.61361981 CIRl Chevron 48.486% 002-028077 1.4978900% 100.0000000% 1.48789001 1.48789001 100.00000001 1.48799001 Area 48.4861 002-028384 2.03490001 100.00000001 2.0349000% 2.03490001 100.00000001 2.0349000% Union 1.5141 002-028396 0.56013631 100.00000001 0.56013631 0.56013631 100.00000001 0.5601363% "•rathon 1.5141 002-028399 3.58663641 100.00000001 3.5866364% 3.58663641 100.0000000% 3.5866364% 002-028405 0,92390631 100.0000000% 0.92390631 0.92390631 100.00000001 0.92390631 002-028406 4.5038100% 100.0000000% 4.5038100% 4.50381001 100.00000001 4.50381001 002-028990 6.33158331 100.0000000% 6.3315833% 6.33158331 100.00000001 6.33158331 002-028993 3.89397501 100.00000001 3.89397501 3.89397501 100.0000000% 3.8939750% 002-028996 1.98559291 100.00000001 1.98559291 1.98559291 100.0000000% 1.98559291 002-028997 10.0779500% 100.00000001 10.0779500% 10.07795001 100.0000000% 10.07795001 -----------------------------------------Subtotal 35.3863802% 35.3863802% 35.38638021 35.3863802% ·========== =========== TOTAL: FEDERAL+CIRI 100.00000001 100.0000000% -A.3.6- ' ! l ·l : FIELD ADIUNISTRATOR Field Sub-unit Lease ONner, Interest TRADING BAY FIELD STATE LEASE NIJIIBER Well A-6 Marathon Union Superior Texaco 33.3331 ADL-18731 33.3331 llell A-15 "aratllon Union Superior Texaco Non-Pool ttarathon Union lEST FORK UNIT FEDERAL 16.6671 16.6671 35.0001 35.0001 15.0001 15.0001 50.0001 50.0001 TOTAL: STATE Enstar 100.0001 002-028988A OIL P/A Tract Ad1in. Factor 1 of Lease Ad•in. 1 of PIA &AS PIA Tract Ad1in. Factor 1 Df Lease Ad1in. 1 of P/A 4.99559001 100.00000001 4.99559001 5.05041001 100.00000001 5.05041001 2.39010001 100.00000001 2.3901000% 3.34061001 100.0000000% 3.34061001 92.61431001 100.00000001 92.61431001 91.60898001 100.00000001 91.60898001 -===-===== ====•===== 100.0000000% 100.00000001 100.00000001 100.00000001 100.00000001 t Slanson River factors far LP& are identical to factors for oil and gas. S/D86;APXA_3;1/10/86 APPENDIX B DEMAND PROJECTION METhODOLOGY AND ASSUP~TIONS Introduction APPENDIX B DEMAND PROJECTION METHODOLOGY AND AssOF.PTIONS Demand for oil and gas is best calculated by dividing total demand into use categories. Because the factors affecting the level and growth rate of demand by use are similar and the fact that oil and gas often compete with one another in a market for a particular use such as for space heating or electricity generation, demand may otherwise be distorted. The use categories in this studY are transportation, electricity, space heat (including cooking, water heating, and clothes drying), and industrial. A model called ENDMOD (ENergy Demand MODel) has been constructed for calculating future energy demands in Alaska. The factors most important in projecting future demand will vary by use cate- gory. In general, the most important are population (or households) and rel- ative fuel prices. The household is the basic consuming unit for the resi- dential sector, and is a good proxy for demand in the commercial sector. In the industrial sector, relative fuel prices are the primary demand deter- minate. In the residential and commercial sectors, fuel prices are more important in determining the type of fuel used. Transportation Use of Liquid Petroleum Introduction Projecting transportation fuel use requires the use of per capita consump- tion coefficients. Gasoline: a. Highway use (taxable and exempt) is the largest category of gasoline con- sumption in Alaska. Historically, demand is related to population, per- sonal income, and the fuel efficiency of the automobile stock. In Alaska, growth in the first two factors will tend to offset the effect of in- creased fuel efficiency in future years resulting in aggregate growth in use of this fuel. Nationally, per capita consumption of gasoline has fallen in recent years. We assume a continuation of this per capita trend for Alaska. In Alaska, per capita consumption of highway gas peaked in 1975 at 502 gallons per capita and declined to 383 gallons per capita in 1983. The estimated consumption for 1984 is 418 gallons per person. Demand is projected using a per capita, coefficient which declines one percent annually from the previous year. The initial value of 411 gallons per capita is the mean of per capita consumption of 1981 through 1984. b. Aviation gasoline (taxable and exempt) use has, in the past decade, been roughly 10 percent as large as highway gasoline use. Between 1971 and 1982, consumption of aviation gas per capita varied between 35 and 43 gallons. In 1982, consumption fell to 36 gallons from the peak of 43 gallons in 1981 and to 30 gallons per capita in 1983. Consumption -B.l- increased in 1984 to an estimated 33 gallons per capita. The initial value for aviation gas consumption is the 4-year mean of 35 gallons per capita. c. Marine gasoline (taxable and exempt) use has, in the past decade, been roughly 50 percent of the aviation gasoline consumption level with an apparently slightly slower growth rate. We assume a strong income elas- ticity of demand will result in maintenance of the current per-capita-use coefficient in future years. Consumption in 1983 was 17 gallons per capita. The initial value used to project consumption is the 4-year mean of 17.5 gallons per capita. Jet Fuel: Jet fuel consumption consists of domestic commercial operations, international commercial operations, and military operations. Domestic commercial opera- tions are a function of the Alaskan population and economY, and as such, have grown rapidly in per capita terms historically (taxable). International com- mercial operations are a function of world economic and political conditions, as well as aviation technology. Military operations are broadly a function, albeit a different one, of the same factors. These two latter categories cannot be separately identified in the historical data, but their combined total has shown relatively modest, although cyclical, growth since the early 1970s. The sharp decrease in reported exempt aviation fuel consumption (and a corresponding increase in taxable jet fuel consumption) in 1982 is probably a reporting error. We project domestic commercial consumption separately from international com- mercial and military use. We assume that the taxable jet fuel category is primarily domestic commercial consumption, and that the exempt jet fuel category includes international commercial and military consumption. The coefficient relating consumption to population for domestic commercial aviation has increased from 153 gallons per capita in 1971 to 350 in 1981 and 575 in 1984. (This excludes the reporting error of 1982.) The initial value for projecting the civilian domestic jet fuel is 525 gallons per capita. We assume future growth will exceed population but at a slower rate than it has historically because of increased efficiency of the capital stock. The coefficient grows by 3 percent annually. International commercial and military consumption of jet fuel is the only category of fuel consumption not projected on a per capita basis. While variation in international commercial and military consumption is difficult to project, growth during the preceding decade approximated 1 percent per annum. We use this figure to project future growth with 1984 consumption of 260 million gallons as the initial value. -B.2- Diesel: The categories used to report diesel fuel sales in Department of Revenue tax records have changed at least twice since 1979, making use of this source of data for projecting highway diesel consumption (or any type of consumption) difficult. Future growth in consumption is projected at the per capita use rate of 565 gallons. While the most recent reporting system provides a breakout of nontransportation sales in the "exempt other diesel" category, the estimates of highway diesel for earlier years require the assumption that the magnitude of nontransportation diesel sales is small in the "exempt highway" and later "exempt other" categories. Additionally, we assume that the old 11 0ff-highway category" is primarily nontransportation use. The per capita consumption of highway diesel fuel has grown steadily since 1978, when it reached a post-pipeline construction low. Future growth in con- sumption is projected, based upon the 3-year mean for 1982-1984. Marine diesel use has increased very rapidly since 1981. The source of this growth is impossible to determine from the data. We assume a constant per capita level of consumption of 250 gallons in future years. Regional Allocation Regional allocation of transportation fuels is made using the 1983 allocations of historical consumption as adjusted by projected shifts in regional popula- tion. Electric Utility Use of Liquid Fuels and Natural Gas Introduction Electric utility use of oil and gas is a derived demand based upon the demand for electricity and the methods used to generate it. We project this use of liquid fuels and natural gas by first estimating electricity demand for space heating and nonspace heating uses, then determining· the proportion generated by fuel oil and natural gas, and, finally, determining demand based upon the efficiency of generation (heat rate). Since the electricity generation alter- natives vary by region in Alaska, we project fuel use by three major regions of the state: Railbelt, Southeast, and the rest of the state. Rail belt a. Consumption of Electricity The total electricity demand is split into the demand for residential space heat and for all other uses. The space heating consumption rates are based upon the weighted average of electricity consumption for space heat by housing type as reported in the 1983 version of the Railbelt Electricity Demand (RED) model (Battelle Northwest Laboratories, June 1983). Consumption per household grows over the projection period due to increased electricity consumption for space heat in the new additions to the housing stock. -B.3- . . I The number of households using electric space heat depends upon the total number of households and the proportion of housing units which use electric space heat. Two factors are likely to influence the current proportion of households using electric space heat: (1) the extension of the gas utility into the Matanuska Valley and (2) the completion of the electric intertie between Anchorage and Fairbanks. The former will result in a portion of existing structures converting to natural gas from electricity for space heating. This will slow the growth rate of electricity use but increase the use of utility gas. The second factor may alter the relative price of elec- tricity in both Anchorage and Fairbanks relative to natural gas and fuel oil, thus causing some households, especially in Fairbanks, to switch from fuel oil to electric space heat. We assume the gas utility will continue to extend its market into the Matanuska Valley and aggressively market gas for space heating. Market penetration began in 1984, and during the next ten years, the electric space heating market in the Matanuska Valley will fall to half its current share. We assume the completion of the Anchorage-Fairbanks intertie does not signifi- cantly alter the price of electricity for consumers in either location. In particular, no shift towards electric space heating in Fairbanks is assumed as a result of the tie-in to the inexpensive gas-fired electricity from Anchorage. The per-household demand for electricity net of residential space heating uses is based upon historical consumption for 1980-1983 and the projected growth in consumption as reported by Battelle in the RED model documentation. This includes both residential and commercial consumption. b. Mode Split Except as noted below, future additions to capacity within the projection period are all gas-fired turbines. Incremental generation in Anchorage is entirely natural gas. Incremental generation in Fairbanks will depend upon the cheaper of the cost of purchased electricity from Anchorage generated by natural gas and the marginal cost of locally produced electricity generated by fuel oil. We assume electricity moves in both directions in the line at dif- ferent times. Fairbanks excess capacity provides reserves to Anchorage, and cheap Anchorage generation provides off-peak electricity to Fairbanks. Incre- mental generation in Fairbanks comes from Anchorage-produced electricity. The following assumptions specifically determine mode split: -B.4- 1. Coal-fired generation in Fairbanks remains constant at 354 thousand Megawatt hours annually. 2. Existing (Eklutna and Cooper Lake} hydroelectric facilities continue to provide railbelt power. 3. Fuel oil generation in Fairbanks declines 50 percent as a result of the intertie. 4. Solomon Gulch provides a firm annual average production of 54.6 thousand Megawatt hours annually. 5. Bradley Lake comes on line in 1993 and produces 330 thousand Megawatt hours annually. This backs out 4.4 billion cubic feet of natural gas annually. Heat rates are projected to remain at current levels. Southeast a. Consumption The growth rate in consumption per capita in Southeast is assumed to be the same rate as in the railbelt. These growth rates are applied to 1983 per capita consumption of 8,000 kwh per capita. The advent of less expensive electricity provided by hydroelectric power may cause electric space heating demand to grow and accelerate that growth rate. We assume this effect is insignificant. b. Mode Split As recently completed hydroelectric projects are brought on line, they will back out the use of fuel oil in electricity generation in those locations linked to the hydro power. The consumption of electricity in these communi- ties is estimated using the proportion of Southeast Alaska electricity con- sumption used by these communities in 1983. Rest-of-State Growth in per capita electricity demand in the rest of the state is assumed to occur at twice the rate projected for the railbelt. These growth rates are applied to 1983 per capita consumption rates of 3,900 kwh per capita. With the exception of Barrow, this region currently relies on fuel oil for electricity generation. This dependence is projected to continue into the future with the exception of Kodiak, which now receives hydropower from the Terror Lake project. ~B.S- Space Heating Use of Liquid Fuels and Natural Gasl Introduction In the Anchorage area, natural gas is the most economical fuel for space heating. Elsewhere, fuel oil is the least expensive alternative except where electricity generated by natural gas is available. In projecting future demands, we use different procedures for gas and fuel oil because of differences in data availability. Natural gas use is based upon a projection of the current level of consumption. Fuel oil demand is estimated based upon the proportion of the population assumed to heat with fuel oil, and estimates of mean household fuel oil consumption. This approach is necessitated because there is no reliable direct estimate of current fuel oil consumption for space heating. Rail belt Natural gas for space heating (and a small amount of related uses for gas purchased from utilities) is projected to grow as a function of population. Growth historically has occurred at a rate in excess of population due to gas retrofitting and expansion of the commercial sector. This trend will moderate in the future, and growth is projected to exceed population by two percent annually. In addition, a new gas market has opened in the ~~tanuska Valley. We estimate that by 1995, one-half of the building stock in the Matanuska Valley will utilize natural gas for space heating. The proportion of railbelt population heating with gas is 47 percent. This factor forms the basis for estimating the growth of space heating demand for natural gas in the Matanuska Valley. The resulting demand level is estimated on a per household basis for residential consumption and a per capita basis for commercial consumption. Residential natural gas consumption is approximately 200 thousand cubic feet per household. Per capita commercial consumption is 55 thousand cubic feet. Fuel oil use for space heating is generally preferred only where gas or gas-fired electricity is not available. Growth in its use will depend upon the location of new structures in the railbelt. We assume that the proportion of households using fuel oil for space heat declines slightly from the current share of 24 percent to 22.4 percent in 1999. Per household residential and per capita commercial fuel oil consumption are based on gas consumption figures converted to fuel oil on the basis of BTU equivalency. Nonrailbelt Outside the railbelt, space heating is almost entirely provided by fuel oil, with the exception of Barrow. Fuel oil consumption is calculated using the share of households with fuel oil space heat and the same per capita llncludes water heating, cooking, and other minor uses. -B.6- coeffiecient of fuel oil use for space heating as applied to the railbelt population. This estimate is consistent with surveys and small regional studies of fuel oil use in rural Alaska. This estimate entails compensating errors. On the one hand, the heating degree days are greater in most parts of the state which rely on fuel oil relative to Anchorage. On the other hand, the stock of structures is smaller outside Anchorage. For natural gas consumption in Barrow, a growth rate which exceeds population growth by 2 percent is applied to a base of current consumption. Industrial Use of Liquid Fuels and Natural Gas Industrial consumption is not a function of population, but rather of the availability of supplies and market opportunities. Since the major industrial users of petroleum fuels are small in number, they are best projected on a case-by-case basis. Ammonia-Urea Production Ammonia-Urea production using natural gas is assumed to continue at a constant level. Petroleum Production-Related Use a. Gas Use in Production Natural gas is utilized in petroleum production in Cook Inlet and on the North Slope for a variety of purposes, including space heatin9, electricity genera- tion, pump fuel, etc. The level of consumption is diff1cult to project because of its many uses, but it is primarily dependent upon petroleum production levels and petroleum employment levels. We assume the level remains constant in Cook Inlet. On the North Slope it grows 7 percent annually for seven years, and is constant thereafter. b. Oil Use in Production A small quantity of fuel oil is used in oil production. This is included in the miscellaneous industrial category. c. Gas Use in Transportation Included in gas use in production. d. Oil Use in Transportation Fuel oil fuels the pumps for most of the Alyeska pipeline. Annual consumption is estimated to be two million barrels of oil. This level is projected to remain constant. -B.7- Oil--Miscellaneous Some fuel oil is used in electricity generation for industrial self-supplied power. This amount, taken from Alaska Power Administration, is projected to remain constant. Military The military uses natural gas for electricity generation and space heating in the Anchorage area and fuel oil elsewhere. Military transportation use of fuel oil is counted in the transportation sector. Military natural gas use is projected to remain constant. Lack of data prevents the calculation of military fuel oil consumption for space heating. Injection Gas is injected into petroleum reservoirs to enhance oil recovery. Because this is only a temporary use of gas, it is not counted a part of final con- sumption. LNG Liquefied Natural Gas (LNG} is defined as export of gas for the purposes of this report. ECONC*1IC GROWTH ASSUMPTIONS Economic projections for estimating future petroleum demands are complicated this year because of the unsettled nature of the world oil market and the recent, rapid growth of the Alaska economy. The former makes it difficult to project activity in the petroleum industry, the most important basic sector industry in the economy, and activity generated by state government spending, which is primarily a function of the availability of petroleum revenues. The latter makes the task of relating recent growth to longer-term trends dif- ficult. The economic growth during the last 4 years, fueled by the dramatic growth in state spending resulting from the increase in oil prices, has generated an increase in population from 420,000 in 1980 (July 1, 1980) to an estimated 527,000 in 1984. This increase in population exceeds the magnitude of the growth which occurred between 1974 and 1976 during the peak construction years for the oil pipeline (approximately 67,000) and was unanticipated by all forecasts. The annual growth rate of 5.8 percent since 1980 is double the average annual growth rate of 2.9 percent in population between 1960 and 1980. The fact that this population change has been much more rapid than the increase in employment opportunities demonstrates the difficulty in accurately projecting longer-range population trends for Alaska, particularly within the context of a temporary boom generated by state spending. The base case economic projection used in this analysis contains a population growth rate of 1.4 percent annually and an employment growth rate of 1.3 percent. These growth rates are less than those observed over the first two decades of statehood, but are considerably above projections of growth of the -B.8- ·.·, • .. I ···1 national economy. For example, the U.S. Department of Commerce has recently projected population growth for the nation to the year TOOO at .8 percentage annually and employment growth at 1.2 percent annually. State population grows from 527,000 in 1984 to 652,000 in 1999. Nonagricultural ~age and salary employment grows from 222,000 in 1984 to 285,000 in 1999. This growth is consistent with many possible sets of assumptions about future basic sector activity and public sector spending as well as support sector and demographic responses. Future basic sector economic activity underlying this projection is similar to that u~ed in the Revised Reference Case scenario used in the Susitna Studies Program. The regional distribution of economic activity, employment, and population continues the historical trend of shifting gradually toward the railbelt as the economic center of the state. 1 Survey of Current Business. November 1980. 2This projection is identified as UP85. 16. 3Documented in full in ISER MAP Economic Model: State Model Documentation Version A85.1: December 1984. -B.9- APPENDIX C CRUDE OIL ANALYSES CRUDE OIL ANALYSES -COOK INLET CRUDE OIL ANALYSES -NORTH SLOPE £11 APPENDIX C WEST SIDE EAST SIDE{ SADLEROCHIT KUPAP.UK WEST DRIFT RIVE~ NIK15K SAK £21 CRUDE CRUDE Gravity, +API @ 60 +F 35 .3 34.6 Gravity, tAPI 26.4 23 22.4 Spec.Grav. @ 60 +F 0.8483 0.8519 Kin.Vis. @ 60 tF 42.42 eSt 79.98 95.92 Kin .Vis. @ 65 tF 6.94 7.34 Sulfur 11ti 1.06 I. 76 1. 82 @ 90 tf 6.77 7.17 Nitrogen, p~• 2090 1980 @122 tF 3.39 3.55 Carbon rest ue 11t1 4.4 7.37 7.62 Sui fur, wti 0.09 0.10 H2S, lb/1 000 bbl 0.35 (5 Nitrogen wtl 0.13 0.14 Salt, lbt{,ooo bbl 32.7 Cirbon 11tl 86.83 87.09 Ni/V, pp1 ll/26 19/57 22/61 Hydrogen 11t1 12.81 12. eo RVP, ~51 3.55 2.6 2.7 OxJgen wti 0.09 0.15 Pour Pt, IF 0 -55 -50 Se. and water, vall 0.05 0.1 Neut. no. ID9741 1.12 0.68 Mater, by dist., vall Nil 0.05 C4 AND LIGHTER RVP, ~si 7.5 7.85 Yield von 1.17 0.63 Pour t tf 0 -5 cs AND LIGHTER Flash Pt. P"CC IF <O (0 Yield, voll 2.12 BADGER DISTllATIOk C5 -150 tf C5 AND LIGHTER Yield, volt 2.2 1.6 I. 9 Yield , voll 0.4 0.7 Sulfur, 11tl (0.001 0.006 0.004 Co1position RON clear 71.5 "ethane 0.02 Traces "ON clear 69.8 Ethane 11.07 7.75 RON+ 0.5~ TEL/gal. 78.4 Propane 61.74 59.81 ISO -380 t I so-Butane II. 72 12.46 Yield, voll 15.6 14.5 14.4 Nor1al Butane 13.00 16.83 Sulfur, wtl 0.013 0.018 0.018 !so-Pentane 1.52 2.03 Paraffins, voll 39.7 38.3 36.4 Nor1al Pentane 0.93 1.12 Napthenes, voll 43.3 47 48.2 IBP -120 tF Aro••ticsF vel% 17.0 14.7 15.4 Yield voll 1.3 2.0 380 -650 I Gravity, API ! 60 tF I X Yield, voU 28.6 26.9 27.5 120 -374 ff Gravity, API 33.1 31.6 Yield von 31.4 29.5 Sulfur, wtl 0.414 0.66 0.700 Gravit6, API @ 60 tF 59.3 57.2 Pour Pt IF -25 -25 -35 374 -44 IF Cetane No. 45.8 45.4 42.1 Yield voll 6.0 6.5 N2, total rc• 79 Gravity, API @ 60 IF 40.9 40.6 Vis. eSt @ 0 +F 3.083 3.34 440 -610 +F Aroutics, vall 33.6 30.0 31.4 Yield vall 17.6 15.7 650 -840 ·~ Gravity 1 API @ 60 IF 35 .3 35.5 Yield, voll 16.4 19.9 16.6 610 + Res1d Gravity, API 23.8 20.5 21.1 Yield voll 41.3 43.9 Sulfur, wt! 1.10 l. 79 1.81 Gravity, API @ 60 IF 18.1 18.2 Aniline PtF tC 74.7 104 .3 Pour Pt, • 70 so 60 DISTlLATION CURVE, VOL, 1 Kin.Vis. @ 100 tF 34.2 43.99 IBF 86 84 Carbon Residue, ! 0.012 wt% 0.01 27. 131 120 Total Nitrogen, pp1 950 600 840 n 134 130 Basic Nitrogen 0.03 wti 0.02 0.023 67. 140 145 V/Ni ~~~ <1 81 !50 165 650 + RE DUAL 10! 163 195 Yield, voll 52 .4 56 55.6 m 192 213 Gravity, API 15 11.7 10.8 14! 211 219 Sulfur, wt! 1. 63 2.59 2.53 16I 220 239 Carbon Residue, 1 8.82 wtl 12.61 lltl'. 13.15 18! 240 254 Total Nitrogen, pp1 3600 207. 257 272 Pour Pt, IF 80 40 45 22! 273 292 Kin.Vii. @ 210 IF 47.54 97.15 135.3 24! 292 307 Kin.Vis. @ 275 tF 15.55 26% 309 324 Pentane insoluble, lltl 14.97 2BI 325 341 30! 340 361 32! 361 390 £11 Aalund, L.R., "Guide to Export Crudes for the '80s,• 34I 395 420 Oil and Gas Journal, Dec.19,1983. 3bi 420 430 £21 Crude not in production, but po1ot pro~ra1 is underw.y 387. 430 440 in Kuparuk area to deter1ine feasibili y. Assay sa1ple 40I 440 460 obtained during drill ste1 test and ••Y not be representative 42! 455 475 of the entire ilctululation. 441 475 490 467. 495 510 481 510 525 SOl 525 540 52 I 545 555 547. 601 X 561 607 l -c.l- APPENDIX D CONVERSION FACTORS Conversion Factors: 1 gallon diesel 1 gallon gasoline 1 gallon jet fuel 1 gallon crude oil 1 MCF natural Gas 1 barrel diesel 1 barrel gasoline 1 barrel jet fuel APPENDIX D CONVERSION FACTORS =0.0239 barrel crude oil equivalent =0.0215 barrel crude oil equivalent =0.023 barrel crude oil equivalent =0.1387 million BTU =1.000 million BTU =5.825 million BTU =5.248 million BTU =5.604 million BTU -D.l- APPENDIX E DEFINITIONS OF STATUTORY TEJ<rt1S APPENDIX E DEFINITIONS OF STATUTORY TERMS AS 38.05.183 states that oil and gas taken in kind as the state's royalty share of production may not be sold or otherwise disposed of for export from the state until the Commissioner of Natural Resources determines that the royalty-in-kind oil or gas is surplus to the present and projected intrastate domestic and industrial needs for oil and gas. The statute contains several key terms whose meaning must be resolved before an estimate can be made of oil and gas surplus to the state's needs. These key terms are: 1) "oil and gas, 11 2) "export, 11 3) 11 present, 11 4) :•projected, 11 5) "domestic, 11 6) 11 industrial, 11 7) "intrastate, •• and 8) 'how these needs are to be met. •• Each key term affects the size of the estimated demand for oil and gas in Alaska and consequently, the size of the projected surplus or deficit. The meaning of each term is discussed below. Oil and .Gas Crude oil and natural gas are fluids containing hydrocarbon compounds produced from naturally occurring petroleum deposits. Typical crude oil contains several hundred chemical compounds. The lightest of these are gases at normal temperatures and pressure, described as "natural gas." These light fractions of the crude oil stream include both hydrocarbon and non-hydrocarbon gases, such as water, carbon dioxide, hydrogen sulfide, helium, or nitrogen. The principal hydrocarbons are methane {CH4), ethane (C2H6), propane (C3H8), butanes (C4Hl0), and pentanes (C5Hl2). The gaseous component found most often and in largest volumes is, typically, methane. Heavier fractions of the crude stream are usually liquids. If a given hydrocarbon fraction is gaseous at reservoir temperatures and pressures, but is recoverable by condensation (cooling and pressure reduction), absorption, or other means, it is Tlassified by the American Gas Association (AGA) as a natural gas liquid (NGL). Natural gas liquids include ethane if ethane is recovered from the gas stream as a liquid. A related term is liquefied petroleum gas {LPG), composed of hydrocarbons which liquefy under moderate pressure under normal temperatures. LPG usually refers to propane and butane. A second related term is condensate, which refers to LPG plus heavier NGL component (natural gasoline). The lightest hydrocarbon fraction is methane, which is almost never recovered as a liquid, and which makes up the bulk of pipeline gas. If a natural gas stream contains few hydrocarbons which are commercially recoverable as liquids, ;t is considered "dry gas 11 or "lean gas.11 The distinction between 11 Wet" and "dry" is usually a legal one, which vades from state to state. 11 Crude oil" usually means the non-gaseous portion of the crude oil stream. Natural gas may occur in reservoirs which are predominately gas-bearing or in reservoirs in which the gas is in contact with petroleum liquids. Non-associated gas is natural gas from a reservoir where the gas is neither in contact with nor dissolved in crude oil. Associated gas occurs in contact loefinitions vary with processes. -E.l- ·-... with crude oil, but is not dissolved in it. A gas cap on a crude oil reservoir is a typical example of associated gas. Dissolved gas is dissolved in petroleum liquids and is produced along with them. Dissolved and associated gases are usually good sources of NGL while non-associated gases are often 11 dry. 11 The distinction between natural gas and its NGL components is important to a study of the supply and demand of royalty oil and gas because natural gas liquids have a multitude of uses when separated from the gas stream. For example, propane is both produced in Alaska and sold in Alaska as bottled gas for residential, commercial, and limited transportation uses, while butane is used for blending in gasoline and military jet fuel and as a refinery fuel. In addition, Marathon Oil uses LPG to enrich crude oil at its Trading Bay facilit2. It ships the combined fluids to the Drift River terminal for export. Potential uses for NGL also include the enriching (11 spiking 11 ) of pipeline gas and crop drying. Several years ago the Dow-Shell Petrochemical Group and Exxon studied the feasibility of utilizing the NGL contained in Prudhoe Bay natural gas as the basis for an Alaska petrochemicals industry. Since the State has the option of considering NGL separately from the gas stream, two definitions of natural gas consumption and reserves are possible. One of these would consider natural gas liquids as part of the gas stream. The second definition would treat the markets for LPG and ethane separately from those for gas. This requires a separate estimate of LPG consumption and gas liquids reserves. In this report, demand for LPG and ethane is estimated separately from that for gas; however, no separate estimate is made of gas liquids reserves. Export Taken in context, this term appears to mean the direct physical sending of oil and gas out of the state. However, when one considers the fact that much of Alaska 1 s industrial use of oil and gas is processed directly for export markets, the meaning of export versus 11 intrastate 11 is not so obvious. For example, it appears that processing of gas into another product, e.g., anhydrous ammonia, would probably be an 11 industrial 11 use rather than .. export" of gas, even though the ammonia is mostly exported. Liquefication to change the phase of the gas is a less obvious case. The liquefication of natural gas is considered a transportation process in this report. Still more troublesome is the use of gas and oil for transportation related to export. Is the gas and oil consumed in TAPS pipeline pump stations, for example, an 11 industrial 11 use in state? Or is it really 11 export 11 of that energy, since it is consumed in the exporting process? There is no reason why the State may not be approached in the future to commit royalty oil and gas to quasi-export uses. Indeed, a top dollar offer was made by the ALPETCO (later, Alaska Oil Company) for royalty oil ultimately destined (as petrochemical products) for out-of-state markets. Though the offer was made, payments in full were not made. Also, the state once committed royalty gas to the El Paso gas pipeline proposal for export of Prudhoe Bay gas, which involved liquefication. Neither 2 Kramer, L., Williams, B., Erickson, G., In-State Use Study for Propane and Butane. Prepared for the Alaska Department of Natural Resources. Kramer Associates, Juneau, October 1981. -E.2- proposal was clearly for in-state industrial use. In this report, industrial demand is treated with multiple definitions as outlined later in the chapter to show how different definitions of 11 export 11 affect the estimate of total consumption in Alaska. Present The problem here is that the term ''present" may mean "latest year" consumption, "average recent year'' consumption, "weather-adjusted" consumption, or "worst case" consumption. In the residential and co11111ercial sector particularly, each definition gives a somewhat different answer because of the variability of weather. The "worst case" consumption calculation can result in considerably higher gas consumption than the most recent year, if the most recent year happens to have been a relatively warm one. While it is not correct forecasting procedure to make long run forecasts of intrastate residential consumption of natural gas which assume worst case forecasts for every year, it may be prudent in practice to reserve part of the the State's gas and oil supply for bad weather. For forecasting, variability of weather makes the picking of a starting value for consumption somewhat tricky. In this report, Rail Belt consumption is based on average weather years. For the remainder of the state, trended per capita consumption is used, which approximates average weather conditions. Projected This is a very difficult concept, since many different projections of consumption would be possible even if it were possible to agree on a single concept defining consumption. Rates of economic development, population growth, and relative energy prices are key features of any consumption forecast, but assumptions concerning any of these variables are necessarily controversial. This report describes a range of possible consumption figures under precisely articulated definitions of consumption and varying paces of economic, population, and fuel price growth. The economic and population forecasts used in this report were done by the Uni~ersity of Alaska Institute of Social and Economic Research in December, 1984. The assumptions used to run their economic model are shown in Appendix B. Domestic Domestic consumption appears to mean Alaska residential consumption. As we saw above under the subheading "present", it is not at all obvious which definition of domestic consumption is the most appropriate, even when the identity of the customer is not in dispute. Some multifamily residential use may be described as 11 commercial", obscuring the definition of the customer and causing forecasting problems for natural gas. The definition of "domestic" considered in this report includes multifamily residential in "residential 11 or "domestic" use. Industrial As described above, ••industrial" energy use has a number of potential definitions. Since one intent of giving in-state industrial needs priority -E. . ·-~ over export uses of royalty oil and gas seems to be encourage in-state economic activity, 3 a day-to-day working definition of this industrial priority is that the royalty reserves be committed to the market which has the largest potential economic impact in Alaska. For forecasting purposes, however, it is difficult to say which markets will prove to be of the most economic benefit to the state. As a compromise, we will adopt four alternative definitions of 11 industrial 11 in this study. The four alternative definitions of industrial use of oil and gas used in this report are outlined below, beginning with the most restrictive and moving to the most liberal. Definition 1: Industrial use consists of any consumption of natural gas, petroleum, or their products in combustion (except that required to export oil or gas); or the chemical transformation of natural gas, petroleum, or their products into refined products for local markets. This definition explicitly excludes the exported products from refineries, as well as uses which merely change the physical form of the product (gas conditioning or liquefaction) for export, or which move the product to an export market (pipeline fuel, fuel used on lease, shrinkage, injection, vented and flared gas). Definition 2: Industrial use consists of ;any consumption of natural gas, petroleum, or their products in combustion (except in oil and gas production and transportation); or the chemical transformation of natural gas, petroleum, or their products into refined products. This definition counts feedstocks for petrochemical plants and refineries as industrial consumption. It also counts energy consumed by an LNG facility as industrial consumption. It excludes the feedstocks of LNG plants ;and fuel consumption by conditioning plants, pump stations, fuel used on lease, shrinkage, injection and flared gas. Definition 3: Industrial use consists of any consumption of natural gas, crude oil, or their products in combustion (except in oil and gas transport and extraction) or their chemical transformation into refined products. This definition permits the feedstocks of refineries to be counted as industrial consumption. It excludes fuels used in pump stations, in conditioning plants, fuel used on lease, and gas shrinkage, injection, or venting. Definition 4: Industrial use consists of any use of natural gas, crude oil, or their products in combustion, or their transformation into chemically different products. This definition permits feedstocks of refineries to be counted as industrial consumption, as well as energy consumption in conditioning plants and pump stations. It excludes injected gas, which is ultimately recoverable for other uses, and LNG processing, which is considered an export. Definition 4 will be used for the purposes of this report. 3However, see the short discussion of legislative intent beginning on page 9 of Kramer, Williams and Erickson, op. cit. That study raises many of the issues regarding surplus gas and oil discussed in this report. -E.4- None of the four definitions treats industrial use (including transportation) to include gas injected to enhance oil recovery, since in theory this gas remains part of the ultimately recoverable gas reserves of the state. Thus, it is not 11 Consumed." Intrastate It is unclear what is meant by intrastate consumption. Some uses, such as combustion of oil and gas products in fixed capital facilities in Alaska, are reasonably easy to categorize as intrastate. There are several uses in transportation which are not obviously within Alaska. These categories include the fuel burned in marine vessels such as cargo vessels, ferries, and fishing boats, and fuel burned in international interstate air travel. There are multiple ways to approach the definition of this consumption. The first is a sales definition: the fuel used in transportation which is sold in Alaska. The second approach is to base consumption on fuel used ln!Alaska or related to Alaska•s economy and population, regardless of the point of sale. This results in three logical definitions, described below: Definition 1: Intrastate consumption in transportation includes all sales of fuels to motor vehicles, airplanes, and vessels in Alaska, including bonded fuels. It excludes fuel consumed by motor vessels which was purchased in other states, and fuel consumed by airlines between Alaska locations unless the fuel was sold in Alaska. It also excludes out of state military fuel purchases. Definition 2: Intrastate consumption includes fuel consumed by motor vessels, airlines, and vehicles engaged in Alaskan economic activity. It includes use of fuel by American fishing boats in Alaskan waters regardless of where the fuel was purchased, use of fuel purchased in Washington State by Alaska State ferries, and fuel consumed by ships and aircraft involved in Alaska trade. It excludes sales to aircraft on international flights (bonded and unbonded), but includes military out of state purchases. Definition 3: The final definition is a compromise between the first two. It includes all fuel purchased within the state, plus military uses, but excludes fuel purchased out of state except for military uses. The basic definition in this report is the third definition. By excluding bonded and exempt jet fuel, the report also approximates Definition 2. Lack of data on out-state purchases by the military makes Definition 1 impractical. How These Needs Are To Be Met Any analysis of how the oil and gas needs of the intrastate domestic and industrial sector are to be met could include several sources of supply: state royalty oil and gas, in-state oil and gas reserves under other ownership, probable extensions of proven reserves, and imports of crude oil, petroleum products, and {in theory) natural gas. -E.S- APPENDIX F ALASKA REFINERIES AND TRANSPORTATION FACILITIES ~ . ....... I STATE CF ALASKA PETROLEUM PROCESSING PLANTS NIKISKI PLANT CAPACITY ---DATE PLANT IN DATE EXPANSIONS OPERATION PLANT PROOUCT DESTINATION Chevron Refinery Tesoro Refinery 18,000 BPD 48,SOOBPD; Crude Unit to 80,000 BPD in 1985 for No. Slope CrLI:Je Hydrocracker to 9,000 BPD. 14.5 TPD Sulfur Plant 1962 1969 ( 17 , 500BPD) Phillips-Marathon 230,000 MCF/Day 1969 LNG Union Chemica l INTERI!F ALASKA North Pole Refinery Petro Star Refinery Anvnonia 1,100,000 1969 tons/yr. Urea 1,000,000 tons/yr. 46 ,600 BPD; 1977 90,000 BPO BPD in 1985 for asphalt, leaded and Lnleaded gasoline, diesel and heating fuels, jet fuels. 6,000 BPD 1985 1983 Asphalt capa- city increased from 280,000 to 400,000 BPY JP4, Jet A, Furnance Oil, Diesels, Fuel Oil, Asphalt, Unfini- shed Gasoline. 1974, 1975, 1977,1980 Propane, Unleaded, Re- 1984 Hydrocracker gular, and Premimum 9000 BPD, Reformer Gasoline, Jet A, Diesel (to 10,000 BPD from Fuel, No .2 Diesel, JP4 6,000 BPO) and No . 6 Fuel Oil Liquified Natural Gas JP4, JA50, Furnance Oil, Diesels and Asphalt for Alaska; Unfinished gasoline, High Sulfur Fuel oil to Low er-48 states . Alaska except No.6 Fuel Oil to Low er-48 states Japan, by tanker, 2 tankers capacity 71,500 cu.m. each, avg. one ship every 9 days. 1977 Anhydrous Anvnonia, Urea West Coast and export by Fall 1980; Naptha Stabilizer Column 11,000 BBL, charge capacity, crude oil increased from 25,000 to 45,000 BPD. 1985 Asphalt capacity 2300 BPD Prills and Granules. tanker and bulk freigh- ter Military Jet Fuel (JP4) 3000-4000 BPD; Convner- cial Jet A Fuel, 5000-6500 BPD, Diesel Fuel No. 1, 1800-2100 No. 2, 1800-2500 BPD, Diesel Fuel No.4, BPD, 2800-3200 BPD, Asphalt BPO Fairbanks area, Nenana and river villages, Eilson AFB, Delta Junction, Tok, Glen- allen, and Anchorage area 1988: Aviation Gas Kerosine, #2 Diesel Alaska North of Alaska Range. APPENDIX G OIL AND GAS FIELD MAPS T11H tiOif r,.. ... . .. .,. Rll! ""' -".:..,.~·:_ __ - NORTH SLOPE UNIT MAP ALASKA DEPARTMENT OF NATURAL RESOURCES, DIVISION OF OIL AND GAS KAY BROWN. DIRECTOR COMPILED BY O.D. 8MITK, CARTOGRAPKER B E A U F 0 R T S E A .... "'"' Pump Station II Centnll Production Facility Selected Slate Elcplorat.ory Wells ~llmlt:taf~ Endlaltt Reservoir Dewolopment 011 Weils RilE PSI CI'F • __ , ____ , __ .... Net Prollt Share leeses Central Facilities Pad Selected F~l Exploratory Wells RI7E . ... .. OU endOasUnll Boundaries----- IAII •*": Tt••••••M Fro• V.T ••• ProJnllott IJ U.I.G.I •• Od,taal 1~:••• t:tlo,ooo. Atl Townettlpe-Uatat Marhllalt. Scale 11 839,520 approx. 1 inch = 13.25 miles · 12185 T a ALASKA OIL AND GAS CONSERIATlON COMMISSION MCHCIIUI8E , ALAIICA FIELD MD FACILITY LOCAnON MAP APPENDIX H ACKNOWLEDGEMENTS APPENDIX H ACKNOWLEDGEMENTS This document was prepared by the staff of the State of Alaska, Division of Oil and Gas: Kay Brown, Director James Eason, Deputy Director Bill Van Dyke, Petroleum Manager Sam Murray, Economist Dick Beasley, Geologist Dorothy Johnson, Clerk/Typist Dan Smith, Cartographer Nancy Wilson, Cartographer Consumption Forecast was prepared by Institute of Social and Economic Research, University of Alaska, Anchorage Scott Goldsmith, Associate Professor of Economics, Phil Rowe, Research Associate, -H.l-