HomeMy WebLinkAboutHistorical & Projected Oil & Gas Consumption, April 1996O|IL+G@AS HISTORICAL AND PROJECTED
OIL AND GAS CONSUMPTION — ,
APRIL 1996 : ky —
NATURAL & RESOURCES
DIVISION OF OIL & GAS
Cover Photo
Upper Right: K Pad drilling and pipeline construction south of Milne Point Unit.
Middle Right: Seismic geophone station box.
Lower Right: Test trench activity for the Northstar Unit Pipeline.
Left: Foreground; Alpine #1 Exploratory Wellhead in the Colville Delta.
Background; Doyon 141 at Bergschrund #2.
This publication was released by the Department of Natural Resources,
Division of Oil and Gas. 750 copies were produced at a cost of $2.66
per copy. The purpose of the publication is to inform the legislature
and the public of the state's Historical and Projected Oil and Gas
Consumption and Supply. This publication was printed in Anchorage.
STATE OF ALASKA
HISTORICAL AND PROJECTED
OIL AND GAS CONSUMPTION
Tony Knowles
Governor
John T. Shively
Commissioner
Department of Natural Resources
April 1996
Prepared for the Second Session
Nineteenth Alaska Legislature
TABLE OF CONTENTS
ALASKA OIL AND GAS RESOURCE MANAGEMENT ............. 1
1 RESERVES OF OILANDNATURALGAS.................. 3
2 || PROJECTED PRODUCTION OF OIL | lle) |.) lel lat le lat ne 5
3 HISTORICAL PRODUCTION OF OIL ...............0.... 17
4 HISTORICAL PRODUCTION OF NATURAL GAS ............. 25
5 HISTORICAL CONSUMPTION OF OIL .................. 33
6 HISTORICAL CONSUMPTION OF NATURAL GAS ............ 37
7 PROJECTED CONSUMPTION OF OILANDGAS............. 41
8|| ROYALTY IN-KIND VOLUMES |)! ft) |e) a fel fal it fill ie de ee ede EE 43
9 U.S. OIL PRODUCTION, IMPORTS AND OIL AND GAS PRICES .... 47
10 COOK INLET GAS, VOLUME ANDVALUE................ 48
APPENDIX A OILANDGASFIELDS..................... 49
APPENDIX B PRODUCING STATE OILAND GASLEASES ........ 53
APPENDIX C CRUDE OILASSAYS ..................... 69
APPENDIX D REFINERIES AND PROCESSING PLANTS ......... 71
APPENDIX, E ||CONVERSION|FACTORS 5) !) L/h) 6) fh) il ke) e) Lyi) Ai il 73
APPENDIX F DEFINITIONS OF STATUTORY TERMS ........... 75
ACKNOWLEDGMENTS ee ee) ay ete sl eye | al ie) Fl eee) et level ll fet fal ey ta 79
ALASKA OIL AND GAS RESOURCE MANAGEMENT _
Alaska’s oil and gas resources are owned and federal agencies and, in a very few cases, by
administered by three state agencies, by two private landowners.
| STATE OF ALASKA
Department of Natural Resources, Division of Oil and Gas (DO&G)
—estimates the volume and value of oil and gas resources within proposed lease sale areas
—leases and licenses state land for oil and gas exploration and development
—sets the conditions under which state oil and gas leases may be developed
—approves plans of operation and monitors lease development for consistency with regulations
and lease terms
—collects oil and gas royalty revenue
—administers contracts administers contracts
—approves and administers oil and gas unit agreements and plans of exploration and development
Department of Revenue, Oil and Gas Audit Division (DOR)
—collects oil and gas severance taxes
—audits oil and gas royalty and tax payments
—estimates how much tax and royalty money the state will receive. This figure is used to prepare
the state’s annual budget
Alaska Oil and Gas Conservation Commission (AOGCC)
—insures the greatest ultimate recovery of oil and gas on private, state and federal leases
—monitors production to insure that production is efficient and that oil and gas are not wasted
—protects correlative rights of lease and land owners
—monitors production meters at each field
| —approves plans of development
| —regulates well drilling, well treatment, well spacing, waste disposal, ground water protection,
and production rate
FEDERAL GOVERNMENT
Bureau of Land Management
—leases and administers onshore federal oil and gas resources
Minerals Management Service
—leases and administers offshore federal oil and gas resources
PRIVATE LANDOWNERS
—most private oil and gas holdings are owned by Cook Inlet Region Inc. and Arctic Slope Region Inc.,
Alaska native corporations, and a few are owned by private landowners. |
1 RESERVES OF OIL AND NATURAL GAS
PROVEN RESERVES
Only a fraction of the original oil or gas in any
reservoir can be extracted, and that fraction
depends on available technology and the eco-
nomics of producing the oil or gas. A producers
decision whether or not to develop a new reser-
voir, or to continue producing a developed field,
depends on the difference between the cost of
extracting the oil or gas and the value of the oil
or gas.
Reserves are an estimate of how much oil and
gas can be economically extracted from a res-
ervoir. Though reserves can be calculated by
many methods, there is no consensus within the
industry for a single method. Each of the three
state agencies that regulate oil and gas produc-
tion, DO&G, AOGCC and DOR, calculate re-
serves by different methods for their different
requirements; DO&G and AOGCC calculations
emphasize geologic and engineering factors,
whereas DOR calculations emphasize oil and
gas economics and prices.
DO&G's table of reserves (Table 1) was com-
piled from recent analyses of field perform-
ances. In late 1995 DO&G calculated the
rate-of-decline, between 1996 and 2015, of the
large North Slope fields (Table 2A). The cumu-
lative oil produced by each field in this fifteen
year period are those field’s estimated reserves.
Cook Inlet reserves are based on long produc-
tion histories but uncertain economic prospects.
Reserves of undeveloped North Slope and
Cook Inlet oil pools are more speculative, pri-
marily because their economics are uncertain
but also because some are incompletely deline-
ated.
Reserve estimates of large oil fields typically
increase through their development years and
ultimate recoveries are often much greater than
early predictions. In the early 1980’s Prudhoe
Bay’s ultimate recovery was estimated to be
about nine billion barrels. By January 1986
Prudhoe Bay had produced 4.4 billion barrels
with reserves of 5.8 billion barrels, and by Janu-
ary 1996 the field had produced 9.0 billion bar-
rels with reserves of 3.1 billion. Much of this
increase in projected ultimate recovery has
been due to improved technology in horizontal
drilling, coiled tubing workovers, gas cycling
and enhanced oil recovery. Further improve-
ments in technology, expansion of enhanced
recovery operations and additional infill drilling
may further increase future reserve estimates,
but the main variable affecting future oil recov-
ery likely will be the perceived future price of oil.
ROYALTY RESERVES
All of the North Slope oil and gas reserves are
on state land except those of the South Barrow,
East Barrow and Walakpa gas fields. All Cook
Inlet reserves are on state land except Swanson
River, Beaver Creek and Birch Hill oil fields and
parts of Beluga River, Kenai and Cannery Loop
gas fields.
TABLE 1 — ESTIMATED REMAINING RESERVES AND ROYALTY SHARE, AS OF 1/1/96
OIL: MILLIONS OF BARRELS GAS: BILLIONS OF CUBIC FEET
Reserves Royalty Share Oil [1] Gas Royalty Oil [1] Gas
= Percent
NORTH SLOPE
DEVELOPED East i i {9} - -
Endicott [2 310 [8 286 14.4 45 127 Kup aruk her 1,335 [8 12.5% 167 82 Kuparuk Other [3] 236 [8 tol 12.5% 30 [10] Lisburne 64 [8 296 12.5% 8 37
Milne Point [4] 348 [8 11 ; 14.6% 51 2
Niakuk/Alapah 56 [8 33 [7 12.5% 7 4
Point Mcintyre 498 [8 645 [7 12.2% 61 79
Prudhoe Bay 3,070 [8] 26,000 [8 12.5% 384 3,250
Prudhoe Bay Other [5] 6 [8 TA 12.5% 1 1 South Barrow - 4 9 = =
Walakpa - 28 9) - -
UNDEVELOPED
North Star/Seal Island 140 [8] [10] 12.5% 18 [10]
Pt. Thomson/Flaxman Island 200 [8] 3,000 [7] 12.5% 25 375
TOTAL 6,263 31,563 795 3,956
COOK INLET
PROVEN AND DEVELOPED
Beaver Creek [6] 1 [7] 122 [7 [9] - - Beluga River - 488 [8 7.5% - 37 Cannery Loop = 50 [8 4.0% as 2 Granite Point 16 [8] 29 [8 12.5% 2 4 Ivan River, Lewis River, Pretty Creek, Stump Lake 75 [8 12.5% 7 9 Kenai = 174 [7 2.1% - 4 McArthur River 44 [8 600 [8 12.5% 6 75 Middle Ground Shoal 15 [7 12.5% 3 2 North Cook Inlet 1,000 [8 12.5% - 125 North Trading Bay 20 [8 12.5% - 3 Sterling - 23 [8 12.4% - 3
Swanson River [6] 13 4 155 [8 [9] - - Trading Bay 8 29 [7, 12.5% <1 4 West Fork = 3 [8 [9] - <1 West McArthur River 9 [8] 1 [8 12.5% <1 <1
PROVEN BUT UNDEVELOPED OR SHUT-—IN Birch Hill - 11 [7] [9] - - Falls Creek - 13 [7] 12.5% i 2 Nicolai Creek om 2 12.5% = <1 North Fork - 12 12.5% - <1 Sunfish 25 [8] [10] 12.5% 3 [10] West Foreland - 20 [7] 12.5% - - TOTAL 133 2,842 13-268
STATE TOTAL 6,396 34,405 808 4,223
1] Includes oil, condensate, and NGL. 2] Includes Sag Delta North. 3] K-10, Tabasco and West Sak. 4] Includes Schrader Bluff and Sag River. 5] North Prudhoe Bay State and West Beach. 6] Combined casinghead and dry gas. Alaska Oil and Gas Conservation Commission. '8] William Van Dyke, Division of Oil and Gas. '9] No State leases. 10] Insufficient data. Revised 03/06/96
2 PROJECTED PRODUCTION OF OIL
NORTH SLOPE
North Slope oil production peaked at 2.0 million
barrels per day in 1988 and has declined to 1.4
million barrels per day in 1995. DO&G esti-
mates that the combined production from the
presently operating and to-be-developed fields
will decline to 384 thousand barrels per day in
2015 and that cumulative production between
1996-2015 will be 6.0 billion barrels.
Of note this year, BP is aggressively pursuing
additional development at Milne Point unit and
at its Niakuk project. BP also is actively explor-
ing for oil and gas east of Prudhoe Bay. The
Prudhoe Bay owners have completed the sec-
ond phase of the Gas Handling Expansion
(GHX-II) project. Kuparuk River unit owners
have agreed to pursue a large scale enhanced
oil recovery project using a miscible injectant
and Endicott and Point Mcintyre operators are
studying miscible injectants at those fields.
COOK INLET
Cook Inlet oil production peaked at 230 thou-
sand barrels per day in 1970 and has declined
to 43 thousand barrels per day in 1995. DO&G
estimates that production will decline to 12 thou-
sand barrels per day in 2006 and that cumula-
tive production between 1996 and 2006 will be
93 million barrels.
Cook Inlet fields probably will continue to pro-
duce well into the next century, but DO&G pro-
jects output only to 2006 because regional
The projection does notinclude production from
Swanson River and Beaver Creek, because the
state holds no leases in these fields, and does
not include a production forecast for Sunfish,
because of recent disappointing delineation re-
sults.
AVAILABLE ROYALTY OIL
The state currently takes North Slope royalty oil
both in-value and in-kind, whereas it takes Cook
Inlet oil only in-value. The production forecast
estimates that the state’s royalty share of pro-
duction will decline from 185 thousand barrels
per day in 1996 to 49 thousand barrels per day
in 2015 and that cumulative royalty production
between 1996 and 2015 will be 783 million
barrels. From this volume, two North Slope
in-kind contracts commit a maximum of 142
million barrels, which leaves at least 642 million
available in-value barrels.
PRODUCERS SHARE OF NORTH SLOPE PRODUCTION
The production projection for North Slope in-
cludes several fields that are not producing yet.
The five major fields that are presently produc-
ing are projected to yield 5.7 billion barrels
between 1996 and 2015. At present offtake
percentages, producers will recover:
Arco 1.8 billion barrels 31%
BP 2.5 billion barrels 44%
Exxon 1.1 billion barrels 20%
a 5 production depends on economic factors which Other 0.3 billion barrels 5%.
can not be reasonably estimated beyond then.
Summary of Projected Oil Production ;
_ 1996 2006 2015 _ Cumulative |
Barrels per Day |
North Slope — 1.4 million 754 thousand 384 thousand 6.0 billion 98%
Cook Inlet 38 thousand 12 thousand 93 million 2%
State 1.5 million 766 thousand 384 thousand 6.1 billion 100%
Barrels per year
North Slope 511 million 275 million 140 million 6.0 billion 98%
Cook Inlet 14 million 4.4 million 93 million 2%
State 534 million _280 million 140 million 6.1 billion 100%
TABLE 2A — PRODUCTION FORECAST AND AVAILABLE ROYALTY OIL
THOUSANDS OF BARRELS PER DAY
Royalty 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
ercent
PRODUCTION FORECAST [1]
NORTH SLOPE
Endicott {2} 80 74 68 62 58 54 50 47 43 40 37
Greater Point Mcintyre [3] 180 169 154 140 125 112 101 92 84 75 70
Lisburne 14 13 12 11 10 10 10 10 10 10 10
Niakuk/Alapah 23 23 20 17 14 12 10 9 8 7 6
Point Mcintyre 140 130 120 110 99 89 80 72 65 58 54
Other [4] 3 3 2 2 2 1 1 1 1 = -
Kuparuk 285 279 273 267 261 255 242 230 207 186 168
Kuparuk Other [5] = 3 3 3 6 6 6 35 43 50 60
Milne Point [6] 40 70 75 75 75 71 64 58 52 47 43
New Field [7] 7 i = = 10 20 30 30 30 28 26
Prudhoe Bay 840 785 710 640 585 535 480 445 405 375 350
TOTAL 1,425 1,380 1,283 1,187 1,120 1,053 973 937 864 801 754
COOK INLET [8]
McArthur River 18 16 14 13 12 10 9 8 8 7 6
Middle Ground Shoal 7 7 7 6 5 5 4 4 3 3 3
Granite Point 7 6 5 5 4 4 3 3 3 2 2
West McArthur River 4 4 3 3 3 2 2 2 2 1 1
Trading Bay 2 2 1 1 1 1 1 1 1 1 1
TOTAL 38 34 30 27 24 22 20 18 16 14 12
STATE TOTAL 1,463 1,414 1,313 1,214 1,144 1,075 993 955 880 815 766
AVAILABLE ROYALTY OIL
NORTH SLOPE
Endicott [2] 14.4% 12 1 10 9 8 8 7 7 6 6 5
Greater Point Mcintyre [3] 22 21 19 17 15 14 12 1 10 9 9
Lisburne 12.5% 2 2 2 1 1 1 1 1 1 1 1
Niakuk/Alapah 12.5% 3 3 3 2 2 2 1 1 1 <1 <1
Point Mcintyre 12.2% 17 16 15 13 12 aBI 10 9 8 7 7
Other [4] 12.5% <1 <1 <1 <1 <1 <1 <1 <1 <1 - -
Kuparuk 12.5% 36 35 34 33 33 32 30 29 26 23 21
Kuparuk Other [5] 12.5% - <1 <1 <1 <1 <1 <1 4 5 6 8
Milne Point [6] 14.6% 6 10 11 1 11 10 9 8 8 7 6 New Field [7] 16.7% - - - - 2 3 5 5 5 5 4
Prudhoe Bay 12.5% 105 98 89 80 73 67 60 56 51 47 44
TOTAL 180 175 163 151 143 135 125 120 111 103 97
COOK INLET [8] McArthur River 12.5% 2 2 2 2 1 1 1 <1 <1 <1 <1
Middle Ground Shoal 12.5% <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1
Granite Point 12.5% <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1
West McArthur River 12.5% <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1
Trading Bay 12.5% <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1
TOTA 5 4 4 3 3 3 2 2 2 2 2
STATE TOTAL 185 179 167 154 9 113105 98
IN-KIND ROYALTY OIL SALES
Mapco [9] 35 35 35 35 35 35 35 35 i - -
Tesoro [10] 38 36 32 - - - - - - - - TOTAL _73 717 85 HH HS - - -
IN—VALUE ROYALTY OIL TOTAL 112-109 99 119111 102.92 87 113-105 98
Note: numbers may not sum to totals due to rounding. 1] Includes oil, condensate, and NGL. 2] Includes Sag Delta North. '3] Combined production from Lisburne, Niakuk/Alapah, rae Prudhoe Bay State, Pt. McIntyre and West Beach.
5 6) 7
North Prudhoe Bay State and
K-10, Tabasco and West Sak. Includes Schrader Bluff and Sa Badami, North Star, or Colville
lest Beach.
River. elta.
[8] Projection is not extended beyond 2006 because production is very sensitive to short term economics. Beaver Creek and Swanson River fields are not included because the state has no leases in either field. 9] 35,000 BPD of Prudhoe royalty production. ontract expires December 2003. 10]30% of Prudhoe Bay Unit royalty production. ‘ontract expires December 1998. Revised 04/12/96
Cumulative Royalty 2007 2008 2009 2010 2011 2012 2013 2014 2015 Production
Percent _ (MBI)
PRODUCTION FORECAST [1]
NORTH SLOPE
Endicott [2] 35 32 30 28 26 24 22 21 19 310,250 Greater Point Mcintyre [3] 65 55 51 47 43 40 38 35 33 623,785
Lisburne 9 8 7 6 5 5 5 5 5 63,875 Niakuk/Alapah 5 - ~ _- Sa = - - - 56,210
Point Mcintyre 51 47 44 41 38 35 33 30 28 497,860 Other [4] = = a = = = = - - 5,840
Kuparuk 150 136 126 117 109 102 94 88 82 1,334,805
Kuparuk Other [5] 60 60 57 54 49 44 39 36 33 236,155
Milne Point [6] 40 38 35 32 31 29 28 26 25 348,210
New Field [7] 23 21 19 17 16 15 14 13 12 118,260
Prudhoe Bay 330 305 285 265 250 230 215 200 180 3,069,650
TOTAL 703 647 603 560 524 484 450 419 384 6,041,115 COOK INLET [8] McArthur River - - i i - i - i i 43,837
Middle Ground Shoal - - - - - - - - - 19,528 Granite Point - 7 - - - - = - - 15,987 West McArthur River = i = = = = =- - - 9,162 Trading Bay - - - - - - - - - 4,526 TOT, - - - - - - - - - 93,039
STATE
TOTAL 703 647 603-560 524 484 450 419 384 6,134,154
AVAILABLE ROYALTY OIL
NORTH SLOPE
Endicott [2] 14.4% 5 5 4 4 4 3 3 3 3 44,800 Greater Point Mcintyre [3] 8 7 6 6 5 5 5 4 4 76,480
Lisburne 12.5% 1 1 <1 <1 <1 <1 <1 <1 <1 7,984 Niakuk/Alapah 12.5% <1 - - - - - - - - 7,026 Point Mcintyre 12.2% 6 6 5 5 5 4 4 4 3 60,739 Other [4] 12.5% - - - - - - - - - 730
Kuparuk 12.5% 19 17 16 15 14 13 12 1 10 166,851 Kuparuk Other {5] 12.5% 8 8 7 7 6 6 5 5 4 29,519 Milne Point [6] 14.6% 6 6 5 5 5 4 4 4 4 50,665 New Field [7] 16.7% 4 4 3 3 3 3 2 2 2 19,714
Prudhoe Bay 12.5% 41 38 36 33 31 29 27 25 23 383,706
TOTAL 90 83 7 72 67 62 58 54 49 771,734
COOK INLET [8] McArthur River 12.5% = - oa = i i = i = 5,480
Middle Ground Shoal 12.5% - - - - - 7 i 7 = 2,441 Granite Point 12.5% - = = - - - - - - 1,998
West McArthur River 12.5% - - - - - - - - - 1,145 Trading Bay 12.5% 7 = = = = = = i - 566
TOT) = i - = i = = i - 11,630
STATE
TOTAL 90 83 77 72 67 62 58 54 49 783,364
IN—KIND ROYALTY OIL SALES Mapco [9] = - - = - = 7 - 102,200 Tesoro [10] = = - - - 7 i = - 38,717 TOTAL - - - - - = = - - 140,917
IN—VALUE ROYALTY OIL
TOTAL 90 83 7 72 67 62 58 54 49 642,447
TABLE 2B — PRODUCTION FORECAST AND AVAILABLE
ROYALTY OIL FOR PRODUCING NORTH SLOPE FIELDS
THOUSANDS OF BARRELS PER DAY Total 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
Offtake
PRODUCTION FORECAST FOR NORTH SLOPE [1]
Endicott [2] 80 74 68 62 58 54 50 47 43 40 37
Amoco 10.40% 8 8 7 6 6 6 5 5 4 4 4 Arco 0.02% <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1
BP 57.12% 46 42 39 35 33 31 29 27 25 23 21 CIRI 0.66% Tia <1 <1 <1 <1 <1 <1 <1 <1 <1
Doyon 0.138% <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1
Exxon 20.84% 17 15 14 13 12 11 10 10 9 8 8 NANA 0.40% <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1
Unocal 10.43% 8 8 7 6 6 6 5 5 4 4 4
Greater Point Mcintyre [3] 180 169 154 140 125 112 101 92 84 75 70
Arco 28.18% 51 48 43 39 35 32 28 26 24 21 20
BP 37.91% 68 64 58 53 47 42 38 35 32 28 27
Exxon 33.92% 61 57 52 47 42 38 34 31 28 25 24
Kuparuk 285 279 273 267 261 255 242 230 207 186 168
Arco 55.08% 157 154 150 147 144 140 133 127 4114 102 93
BP 39.27% 112 110 107 105 102 100 95 90 81 73 66 Chevron 0.11% <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 Exxon 0.22% <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 Mobil 0.37% q 1 1 n<t <1 <1 <1 <1 <1 <1 <1
Union 4.96% 14 14 14 13 13 13 12 11 10 9 8
Milne Point [4] 40 70 75 75 75 71 64 58 52 47 43
BP 91.19% 36 64 68 68 68 65 58 53 47 43 39
Oxy 8.81% 4 6 7 7 7 6 6 5 5 4 4
Prudhoe Bay 840 785 710 640 585 535 480 445 405 375 350
Arco 27.38% 230 215 194 175 160 146 131 1229 tit 103 96
BP 41.16% 346 323 292 263 241 220 198 183 167 154 144
Chevron 0.62% 5 5 4 4 4 3 3 3 3 2 2
Exxon 27.37% 230 215 194 175 160 146 131 122)) ita 103 96 LL&E 0.038% <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 Marathon 0.04% <1 <1 <1 <1 <1 <A <1 <1 <1 <1 <1
Mobil 1.46% 2 1 10 9 9 8 iw 6 6 5 5
Phillips 1.45% 12 1 10 9 8 8 7 6 6 5 5
Shel 0.10% 1 1 1 1 1 1 <1 <1 <I <1 <1
Texaco 0.40% 3 3 3 3 2 2 2 2 2 2 1
TOTAL Amoco 8 8 7 6 6 6 5 5 4 4 4
TOTAL Arco 438 416 388 362 339 319 293 274 249 226 208
TOTAL BP 608 603 565 525 492 458 418 388 352 322 297
TOTAL Chevron 6 5 5 4 4 4 3 3 3 3 2 TOTAL CIRI <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 TOTAL Doyon <1 <1 <1 <1 <1 <1 <i <1 <1 <1 <1
TOTAL Exxon 308 288 261 236 215 196 177 163 149 137 128 TOTAL LL&E <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 TOTAL Marathon <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1
TOTAL Mobil 13 12 1 10 10 9 8 iL 7 6 6 TOTAL NANA <1 <1 <A at) bt <A <i <1 <1 <1 <1
TOTAL Oxy 4 6 a 7 7 6 6 5 5 4 4
TOTAL Phillips 12 1 10 9 8 8 7 6 6 5 5 TOTAL Shell <1 <1 <1 <1 <1 <1 <1 <4 <1 <1 <1
TOTAL Texaco 3 3 3 3 2 2 2 2 2 (4 1
TOTAL Unocal 22 22 21 20 19 18 17 16 15 13 12
TOTAL NORTH SLOPE 1,425 1,377 1,280 1,184 1,104 1,027 937 872 791 723 668
Royalty Percent
AVAILABLE ROYALTY OIL Endicott {2} 14.4% 12 1 10 9 8 8 7 7 6 6 5
Greater Point Mcintyre [3] 12.5% 22 21 19 17 15 14 12 1 10 9 9
Kuparuk 12.5% 36 35 34 33 33 32 30 29 26 23 21 Kuparuk Other 12.5% = <1 <1 <1 <1 <1 <1 4 5 6 8 Milne Point [4] 14.6% 6 10 11 11 11. 10 9 8 8 7. 6
Prudhoe Bay 12.5% 105 98 89 80 73 67 60 56 51 47 44 TOTAL 180 175 163 151 141 131 120 115 106 98 92
IN—KIND ROYALTY OIL SALES
Mapco fal 35 35 35 35 35 35 35 35 = = - Tesoro [6 38 36 32 - - - - = — - -
TOTAL 73 71 67 35 35 35 35 35 = - -
IN—VALUE ROYALTY OIL TOTAL 107. 104 96 116 106 96 85 80 106 98 92
Note: numbers may not sum to totals due to rounding. Includes oil, condensate, and NGL. Includes Sag Delta North. Combined production from Lisburne, Niakuk/Alapah, North Prudhoe Bay State, Pt. Mcintyre and West Beach. Includes Schrader Bluff and Sag River. 35,000 BPD of Prudhoe royalty production. Contract expires December 2003. eal Ces Bay Unit production’of Prudhoe Bay Unit royalty production. Contract expires December 1998. Vis DION
Cumulative
Total 2007 2008 2009 2010 2011 2012 2013 2014 2015 Production Offtake (MBbI)_
PRODUCTION FORECAST FOR NORTH SLOPE [1] Endicott [2] 35 32 30 28 2 24 #22 21 19 310,250 Amoco 10.40% 4 3 3 = a — = = = 26,952 Arco 0.02% <1 <1 <1 = — a = — = 52
BP 57.12% 20 18 a = = = - — = 148,026
CIRI 0.66% <1 <1 <1 = = a = = - 1,710 Doyon 0.18% <1 <1 <1 = a es a = a 337 Exxon 20.84% 7 7 6 = 3 oS = 2 = 54,007 NANA 0.40% <1 <1 <1 - = = = = 1,037 Unocal 10.43% 4 3 3 = = = = = = 27,029 Greater Point Mcintyre [3] 65 55 51 47 43 40 38 35 33 623,785
Arco 28.18% 18 15 14 13 12 11 11 10 9 175,783
BP 37.91% 25 21 19 18 16 15 14 13 13 236,477 Exxon 33.92% 22 19 17 16 15 14 13 12 11 211,588
Kuparuk 150 136 126 117 109 102 94 88 82 1,334,805
Arco 55.08% 83 75 69 64 60 56 52 48 45 735,211
BP 39.27% 59 53 49 46 43 40 37 35 32 524,178
Chevron 0.11% <1 <1 <1 <1 <1 <1 <1 <1 <1 1,468
Exxon 0.22% <1 <1 <1 <1 <1 <1 <1 <1 <1 2,937 Mobil 0.37% <1 <1 <i <1 <1 <1 <1 <1 <1 4,939 Union 4.96% 7 7 6 6 5 5 5 4 4 66,206
Milne Point [4] 40 38 35 32 31 29 28 26 25 348,210
BP 91.19% 36 35 32 29 28 26 26 24 23 317,533
Oxy 8.81% 4 3 3 3 3 3 2 2 2 30,677
Prudhoe Bay 330 305 285 265 250 230 215 200 180 3,069,650
Arco 27.38% 90 84 78 73 68 63 59 55 49 840,470
BP 41.16% 136 126 117 109 103 947 885 823 74.1 1,263,468 Chevron 0.62% 2 2 2 2 2 1 1 1 i 19,032
Exxon 27.37% 90 83 78 73 68 63 59 55 49 840,163 LL&E 0.038% <1 <1 <1 <1 <1 <1 <1 <1 <1 921 Marathon 0.04% <1 <1 <1 <1 <1 <1 <1 <1 <1 1,228
Mobil 1.46% 5 4 4 4 4 3 3 3 3 44,817
Philli 1.45% 5 4 4 4 4 3 3 3 3 44,510 Shel 0.10% <1 <1 <1 <1 <1 <1 <1 <1 <1 3,070
Texaco 0.40% 1 1 1 1 1 <1 <1 <A <1 12,279 TOTAL Amoco 4 3 3 - = = = = = 26,952
TOTAL Arco 191 174 162 150 141 130 121 113. 104 1,751,515
TOTAL BP 276 «6253 «6235 ) = 202-—S is: 190 176 165 154 142 2,489,682
TOTAL Chevron 2 2 2 2 2 2 1 1 1 20,500 TOTAL CIRI <A <1 <1 - - - - - - 1,710 TOTAL Doyon <1 <1 <1 - - - - - - 337
TOTAL Exxon 120 109 102 89 83 UL 72 67 61 1,108,695 TOTAL LL&E <A <1 <1 <1 <1 <a <1 <1 <1 921 TOTAL Marathon <1 <1 <1 <1 <1 <1 <a <1 <1 1,228
TOTAL Mobil 5 5 5 4 4 4 3 3 3 49,756 TOTAL NANA <1 <1 <1 = = = — = — 1,037
TOTAL 4 3 3 3 3 3 2 2 2 30,677
TOTAL Phillips 5 4 4 4 4 3 3 3 3 44,510 TOTAL Shell <A <1 <1 <1 <1 <1 <1 <1 <1 3,070 TOTAL Texaco 1 1 1 1 1 <1 <1 <1 <1 12,279
TOTAL Unocal 11 10 9 6 ) 5 5 4 4 93,236
TOTAL NORTH SLOPE 620 S66 527 489 459 425 397 370 339 5,686,700
all oan
AVAILABLE ROYALTY OIL
Endicott [2] 14.4% 5 5 4 4 4 3 3 3 3 44,800 Greater Point Mcintyre [3] 12.5% 8 a 6 6 5 5 5 4 4 76,480
Kuparuk 12.5% 19 17 16 15 14 13 12 11 10 166,851
Kuparuk Other 12.5% 8 8 7 7 6 6 5 5 4 29,519 Milne Point [4] 14.6% 6 6 5 5 5 4 4 4 4 50,665
Prudhoe Bay 12.5% 41 38 36 33 31 29 27 25 23 383,706
TOTAL 86 80 74 69 65 60 55 52 47 752,020
IN—KIND ROYALTY OIL SALES
Mapco [5 — = = = = = as = 102,200 Tesoro [6 ) = = = = = = = = 38,717 TOTAL _ - ~ = - - - - - -___ 140,917
IN—VALUE ROYALTY OIL
TOTAL 86 80 74 69 65 60 55 52 47 611,103
TABLE 2C — PRODUCTION FORECAST AND AVAILABLE
ROYALTY OIL FOR PRODUCING COOK INLET FIELDS
THOUSANDS OF BARRELS PER DAY Cumulative
Total 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Production Offtake (MBbI)_
PRODUCTION FORECAST FOR COOK INLET [1]
Granite Point 7 6 5 5 4 4 3 3 3 2 2 15,987
Mobil 32.26% 2 2 2 1 1 1 1 <1 <1 <1 <1 5,157 Unocal 67.74% 4 4 3 3 3 3 2 2 2 2 1 10,830
McArthur River 18 16 14 13 12 10 9 8 8 7 6 43,837
Marathon 46.19% 8 If, 7 6 5 5 4 4 3 3 3 20,248
Unocal 53.81% 10 9 8 7 6 6 5 5 4 4 3 23,588
Middle Ground Shoal 7 7 i 6 5 5 4 4 3 3 3 19,528
Shell 72.35% 5 5 5 4 4 3 3 3 2 2 2 14,128
Unocal 27.65% 2 2 2 2 1 1 1 1 <1 <1 <1 5,399 Trading Bay 2 2 1 1 1 1 1 <1 <1 <1 <1 4,526
Marathon 50.00% <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 2,263
Unocal 50.00% <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 2,263
West McArthur River 4 4 3 3 3 2 2 2 2 1 1 9,162
Stewart 100% 4 4 3 3 3 2 2 2 2 1 1 9,162
TOTAL MARATHON 9 8 7 7 6 5 5 4 4 3 3 22,511
TOTAL MOBIL 2 2 2 1 1 1 1 1 <1 <1) ||| 5,157
TOTAL SHELL 5 5 5 4 4 3 3 3 2 2 2 14,128
TOTAL STEWART 4 4 3 3 3 2 2 2 2 1 1 9,162
TOTAL UNOCAL 17 15 14 12 11 10 9 8 it 6 6 42,080 TOTAL COOK INLET 38 34 30 2724 22 20 18 16 14 12 93,039
Royalty Percent
AVAILABLE ROYALTY OIL
Granite Point 12.5% <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 1,998
McArthur River 12.5% 2 2 2 2 1 1 1 1 <1 <1 <1 5,480
Middle Ground Shoal 12.5% <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 2,441 Trading Bay 12.5% <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 566
West McArthur River 12.5% <— <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 1,145
TOTAL 5 4 4 3 3 3 2 2 2 2 2 11,630
Note: numbers may not sum to totals due to rounding. [1] Projection is not extended beyond 2006 because production
Is very sensitive to short term economics. Beaver Creek and Swanson River fields are not included because the state has no leases in either field.
Revised 04/12/96
10
RS boot yyy boast On re VEL Sas se
See
1997 199g 1999 2009 2001 2002 2003 2004 2005 2006
11
Figure 2A-3 - Available State Royalty Oil
Thousands of Barrels per Day
200
160
120
80 40
0
STATE
NORTH SLOPE
Prudhoe Bay
Kuparuk
Greater Point Mcintyre
Point Mcintyre
Milne Point
Endicott
Kuparuk Other
New Field
Lisbume
Niakuk/Alapah ee
Other One 2004
COOK INLET aad 1996
2006
Figure 2A-4 - Available Cook Inlet Royalty Oil
Thousands of Barrels per Day
= NM Wh
0
COOK INLET
McArthur River
Middle Ground Shoal
Granite Point
West McArthur River
Trading Bay
12
Figure 2A-5 - Historical and Projected Production of State Oil
Millions of Barrels per Year
Sy est i
STATE St
NORTH SLOPE
Prudhoe Bay
Kuparuk
Endicott
Point Mcintyre
Milne Point
West Sak
Lisburne
Niakuk
COOK INLET
Soy
—<ih— 7005 2010 2015
1981 1975 4965 1970
1958.
Figure 2A-6 - Historical and Projected Production of Cook Inlet Oil
Millions of Barrels per Year
HSS
COOK INLET
McArthur River
Middle Ground Shoal
Granite Point >
Trading Bay
West McArthur River
13
Figure 2A-7- Historical and Projected Production of State Oil,
Log Scale
Millions of Barrels per Year
a North|Slope
Prudhoe|Bay
Kuparuk Pp
100 Pt. McIntyre ]
Cook Inlet --——
10 ]
Endicott
Milne Pt.
Lo J 1962 1970, 98Q QT 2000 2010 2015 eee |
Figure 2A-8 - Historical and Projected Production of
Cook Inlet Oil, Log Scale
Millions of Barrels per Year
Cook Inlet
McArthur River
100
10
Trading Bay
Ground West Shoal McArthur River — 1958 1970 4980 1990 2000 2006
14
- Figure 2A-9 - Prudhoe Bay Production Performance
Liquids: Millions of Barrels per Year Gas: Billions of Cubic Feet per Year
2800
2400
Gas Total liquids 2000 — oF | |
7a - Water \
Condensate | 1200 +—
800 —— |
400 _ 0 1976 1980 1985 1990 1995 Note: Total liquids includes oil, NGL, condensate and water
15
3 HISTORICAL PRODUCTION OF OIL
Asmall amount of oil was produced from Katalla
field near Cordova before it was abandoned in
the 1930’s. Now, all the state’s oil is produced
from two areas, the North Slope near Prudhoe
Bay and upper Cook Inlet.
NORTH SLOPE
BP discovered Prudhoe Bay field in 1968. It
was the first commercial oil discovery on the
North Slope and no transport system of any kind
connected the field with an ice free port. During
the next several years, while a transport system
was designed and constructed, the field was
delineated and partially developed. Small
amounts of oil and gas were produced to fuel
the field operations and surplus crude and re-
sidual oil was injected back into the reservoir.
The Trans Alaska Pipeline System (TAPS) was
begun in 1975 and completed in 1977. Ku-
paruk, Lisburne and Milne Point fields were
linked to TAPS during their development. En-
dicott field, like Prudhoe Bay field, was devel-
oped before its oil transport system was
constructed and, like Prudhoe Bay, produced
and injected small volumes of oil until its cause-
way connection to TAPS was completed.
North Slope production peaked at 744 million
barrels per year (2.0 million per day) in 1988
then declined to 526 million barrels per year (1.4
million per day) in 1995. The combined fields
have produced 10.8 billion barrels by end of
1995, 83% of it from Prudhoe Bay, 12% from
Kuparuk and 5% from the other pools.
Recent additions from several small pools have
somewhat offset the regional decline. Point
Mcintyre, North Prudhoe Bay State, West
Beach and Niakuk pools began production in
1993 and 1994 and Milne Point production in-
creased in late 1994 and 1995.
From the beginning of Prudhoe Bay field’s pro-
duction, the water and natural gas dissolved in
the crude oil have been separated from the oil
and, supplemented with sea water, injected
back into the reservoir. The combined volume
of sea water, formation water, dissolved gas,
and free gas produced from the wells progres-
sively increased and the proportion of oil to gas
and oil to water decreased. As the gas volume
approached the capacity of the facilities, the
17
facilities became production bottlenecks. To
alleviate these constrictions the gas handling
and water handling facilities were expanded in
1986, 1991 and 1993-1994.
COOK INLET
Swanson River field was the first significant oil
producer in Alaska. The field was discovered
in 1957 and began production in 1959. Several
significant nearby fields were discovered and
brought to production between 1965 and 1972.
Two fields, West McArthur River and Sunfish,
were discovered in 1991. West McArthur River
began production in 1993 and a pipeline was
completed to Trading Bay Production Facility in
1994. Sunfish development remains uncertain.
Regional production peaked at 83 million bar-
rels per year in 1970 and has declined to 15.5
million barrels in 1995. By the end of 1995 Cook
Inlet fields have produced 1.2 billion barrels of
oil, 48% from McArthur River, 19% from Swan-
son River and the balance from all other fields.
TAPS FLOW
Table 3 shows the volume of oil produced from
the fields, the volume of oil passing Pump Station
#1 (PS #1), the starting point of TAPS, and the
volume of oil loaded on ships at Valdez. Most of
the volume difference between field production
and “Throughput at PS #1" is fuel used to run
production operations at the North Slope fields.
The difference between "Throughput at PS #1"
and “Liftings at Valdez” is the volume used for fuel
by TAPS pump stations and the volume diverted
for feedstock and fuel by the Mapco and Petrostar
refineries at North Pole and Valdez.
NATURAL GAS LIQUIDS
Most North Slope fields and several Cook Inlet
fields have produced NGL at some time in their
histories. Part of the Prudhoe Bay, Lisburne and
Endicott NGLs are blended with crude oil up-
stream of the respective LACT meters and the
remainder is injected into their respective reser-
voirs.
Beginning in 1996 a small volume of NGLs will
be shipped from Prudhoe Bay field to Kuparuk
field for use in a miscible injection project.
Summary of Historical Oil Production
Peak Peak Year 1995 Cumulative
Year Production Production Production
Barrels per Day North Slope 1988 2.0 million 1.4 million 11 billion 90% Cook Inlet 1970 226 thousand 43 thousand 1.2 billion 10%
State 1988 2.0 million 1.5 million 12 billion 100%
Barrels per Year North Slope 1988 723 million 526 million 11 billion 90%
Cook Inlet 1970 82 million 16 million 1.2 billion 10% State 1988 738 million 542 million 12 billion 100%
18
TABLE 3 — HISTORICAL OIL PRODUCTION
MILLIONS OF BARRELS PER YEAR
Type[1] 1958 1959 1960 1961 1962. 1963 1964 1965 1966 1967 1968
NORTH SLOPE |
Endicott oil - - - - - - - = - ea a
NGL = - - - - - - - - ae uy
inj i a = ri PL Tv Ti oT i oT i eh a - - - - - - on i on
Kuparuk oi - - - - - - - - _ i i
i NGL - - - - - - - = o at L
net = - - - - - - - = - oo
Lisburne oil - - - - - - - = - ae ty
NGL - - - - - - — = t ak a
net i - - - - - - - - = wd
Milne Point oil - - = - - - - = us oe wd
North Prudhoe Bay oil - - - - - = = a ual at ui
State NGL - - - - - - - = _ = iz
net i - - - - - - - 7 i a!
Niakuk oil - - - - - i = = 0 a i
NGL - - - - - - o i a iC
net a - - - - - - - _ _ um
Point Mcintyre oil - - - - - _ - a - a u
NGL - - - - - - _ i 7 a i
net - - - - - - = ia ns a ds
Prudhoe Bay oil [2] - - - - - - - a i i i
NG - - - - - - - - - - - inj - - - - - _ - - - 7 7
net - - - - - - - Bn i i LL
Sag River oil - - - - - - i 7 i ah i
Sag Delta oil - - - - - - - ae i Al ual
NGL - - - - - - - - 7 = os
net - - - - - - - a i a i
Schrader Bluff oil - - - - - - - es ee te
West Beach oil - - - - - - - - _ i
NGL - - - - - = - a | = a
net - - - - - - - a - - i
West Niakuk oil - - - - - - _ ae - a a
NGL - - - - - - - 7 7 7 ia
net - - - - - - - a i Sl a
West Sak oil - - - - - - - - = i a
TOTAL OIL [2] - - - - — 7 7 a a a i
TOTAL NGL - - - - - - - 7 - a i
TOTALINJECTION - - - - - - 7 Ee a i i
TOTAL NET - - - - - - 7 7 o _ L
COOK INLET Beaver Creek oil a: = - - - - - - - al =
Cannery Loop [3] NGL - - - - - - - i - = 4
Granite Point oil i: mi a | ef 7 i 0.002 — 7.052 13.131 Kenai [3] NGL - - - - - _ - a pa i a
McArthur River pl fr i 7 7 = - - 0.001 0.003 0.749 21.782
net om a i aa = 7 i 0.001 0.003 0.749 21.782 Middle Ground Shoaloil i a i -) i i - 0.027 2649 7.404 14.134 Redoubt Shoal oil i 5 oa = = i = = - - 0.002
Swanson River a 0.036 0.187 0.558 6327 10.259 10.740 11.054 11.099 11.712 12.980 13.619 Ms fc _ - - - - - - - 0.004
net 0.036 0.187 0.558 6327 10.259 10.740 11.054 11.099 11.712 12.980 13.624 Trading Bay ol : - - - - - - - 0.002 0.000 0.729 3.477
net - - - - - - - 0.002 0.000 0.729 3.477 West McArthur River oil - - - - - - - - Ba a a
TOTAL OIL 0.036 0.187 0.558 6327 10.259 10.740 11.054 11.131 14.364 28.913 66.146
| TOTAL NGL ae ms 7 as S aan 7 7 i - 0.004
TOTAL NET 0.036 0.187 0.558 6.327 10.259 10.740 11.054 11.131 14364 28913 66.148
| STATE
TOTAL OIL [2] 0.036 0.187 0.558 6.327 10.259 10.740 11.054 11.131 14.364 28.913 66.146 TOTAL NGL - - = - - - = 7 7 - 0.004 TOTAL INJECTION i 7 - - - - - - 7 at fm
TOTAL NET 0.036 0.187 0.558 6.327 10.259 10.740 11.054 11.131 14.364 28.913 66.150
TAPS FLOW [4] Throughput at PS #1 7 7 aa - - - - - J - te
Liftings at Valdez = = a - - - - - = ~ o
Source: Alaska Oil and Gas Conservation Commission (GCC). “Alaska Production Summary by Field and Pool", monthly report. 1] oil = crude oil, NGL = natural gas liquids, liq = liquids (oil + NGL), inj = injection, net = oil+NGL—inj. 2] Includes condensates. 3] Gas field temporarily produced NGL. 4] 1977-81: Alaska Oil and Gas Conservation Commission, "Statistical Report." 82—95: Alyeska Pipeline Service Co. 5] Endicott reserves includes Sa Delta North. 6] Milne Point reserves includes Sag River and Schrader Bluff. 7] North Prudhoe Bay State reserves includes West Beach. 8] West Sak reserves includes K-10 and Tabasco. vised 04/17/96
19
Type[1] 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979
NORTH SLOPE Endicott oil - - = — a = = = a a a NGL = od = oe a = a 2 aa = a inj ad 2 a a a oad oad = = = = net = = i a a = = = = > = Kuparuk oil = 0.006 — = o = = = = = = NGL = = = = = = — a oa = = net = 0.006 = = a a a 7 = = = Lisburne oil = - 2 o 3 = = = = = = NGL = = — = os = os =) ed = 3 net a S = ad a S = = = = = Milne Point oil = = = =) S = = = = = = North Prudhoe Bay oil = = = = = a = = = = = State NGL =) = oa =) 2 = = = = = = net = = — = = = a = = 2 cS Niakuk oil SS S = = oS = = = = = SS NGL a = = = = = — =) = = So net = = = a GS ad = = = c = Point Mcintyre oil = = = = = = = a — a NGL = = = = = al = = = i = net oS = = Ss = = = = = = = Prudhoe Bay rok 2) 0.277 1.193 1.157 0.922 0.944 2170 2.870 4.604 115.2 258 397. 679 468. 412
inj 0.217 0.879 0833 0.792 0.817 1640 2.147 3.611 2c 075 =
net 0.060 0.314 0.324 0.130 0.127 0.530 0.723 0.993 113.183 397.679 468. 412 Sag River oil So oS So om S a 2 So Sag Delta oil = S = = a = = od = = = NGL = oS = eS = = = — = = = net a I I = = = = = = = — Schrader Bluff oil S a = ad = S I 7 = oad ad West Beach oil a = a od = = = a oa = = NGL i = = oad = — 7 = oe = ad net = —) oa = J = =) = a ad = West Niakuk oil a = = a = S = = — = a NGL = = = = = = a = = = a net = = = ad a oI 3 a = = = West Sak oil = = = ot el oe a = = = TOTAL OIL [2] 0.277 1.199 1.157 0.922 0.944 2.170 2.870 4.604 115.258 397. 679 468.4 412 TOTAL NGL = = = = = = = = TOTALINJECTION 0217 0879 0833 0792 0817 1.640 2147 3611 2075 — TOTAL NET 0.060 0.320 0.324 0.130 0.127 0.530 0.723 0.993 113.183 397.679 468. 412
COOK INLET Beaver Creek oil = = = 0.002 0.416 0375 0.322 0.302 0.276 0.223 0.211 Cannery Loop [3] NGL - - = = = a oe th
Granite Point oil 9.183 7522 5577 4663 4.767 4.237 4.361 4.471 4.711 4867 4613 Kenai [3] NGL 0.002 0,002 0.001 0.002 0.001 0.000 0.001 0.001 0.000 0.001 0,000 McArthur River oil 31.301 40.165 40.537 40.774 38.884 39.145 40.876 35.810 33.235 30.223 25.440 NGL = 0.426 0.593 0.570 0.661 0654 0.644 0653 0.733 0.730 0.541 net 31.301 40.591 41.130 41.344 39.545 39.798 41.520 36.464 33.968 30.953 25.981 Middle Ground Shoaloil 10.467 12.719 11.304 9.719 10.239 9.001 8670 8864 7.617 6382 5.545 Redoubt Shoal oil = = = = = ae Se a a = - Swanson River oil 13.151 12.408 11.466 8896 10.064 9.765 8.754 7.591 5.981 4.870 4.344 NGL 0.070 0.063 0.077 0.012 0.098 0.096 0.089 0.090 0.086 0.065 0.080 net 13.221 12.471 11.543 8908 10.163 9861 8843 7.681 6066 4.935 4.424 Trading Bay oil 9.936 9.600 8744 8585 7.825 7.552 6128 5366 4.276 3.567 2.892 NGL = 0.039 0.039 0.025 0,051 0.043 0.031 0.026 0.044 0.019 0.014 net 9.936 9639 8782 8610 7.877 7.594 6.158 5.392 4320 3.587 2.906 West McArthur River oil - - - - - - - = a = _
TOTAL OIL 74.038 82.415 77.628 72.640 72.196 70.074 69.111 62.404 56.095 50.132 43.045 TOTAL NGL 0.073 0.530 0.710 0608 0812 0.793 0.765 0.770 0863 0.815 0.635
TOTAL NET 74.111 82.945 78.338 73.248 73.007 70.867 69.876 63.175 56.958 50.946 43.680
STATE
TOTAL OIL [2] 74.315 83.614 78.785 73.562 73.139 72.244 71.980 67.009 171.353 447.810 511.457 TOTAL NGL 0.073 0530 0.710 0608 0.812 0.793 0.765 0.770 0863 0.815 0.635 TOTAL INJECTION 0.217 0879 0.833 0.792 0817 1640 2.147 3.611 2.075 = TOTAL NET 74.171 83.265 78.661 73.378 73.134 71.397 70.598 64. 168 170.141 448.625 512.¢ 092
TAPS FLOW [4] ‘Throughput at PS #1 — - ce i - = - — 112.315 397.149 467.939 Liftings at Valdez = = = = - - - — 96.669 394.080 464.394
20
TABLE 3 — HISTORICAL OIL PRODUCTION
MILLIONS OF BARRELS PER YEAR
Type[1] 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989
NORTH SLOPE
Endicott oil = - - - - = 0.011 8.796 37.441 35.746
NGL = - = = - - = 0.003 0.492 0.839
inj = - - - - i 0.007 0.014 -
net = = i i - - 0.004 8.785 37.933 36.584
Kuparuk oil = 1.092 32.406 39.876 46.084 78.926 93.900 102.448 110.891 109.770
NGL — - = i - 0.761 1.072 1.257 0.256 -
net = 1.092 32.406 39.876 46.084 79.687 94.972 103.705 111.146 109.770
Lisburne oil 0.002 0.208 0.087 0.294 1.123 3.594 16.199 15.095 13.737
NGL = = = = _ = = 0.458 1.008 1.093
net = 0.002 0.208 0.087 0.294 1.123 3.594 16.657 16.103 14.830
Milne Point oil = - - - 7 0.704 4.709 0.040 = 3.715
North Prudhoe Bay oil = = - - - - — State NGL - - ~ - - - - - = -
net = = = =_ i = = = = - Niakuk oil = - - - = = = = - - NGL - - - - - - - = - -
net = =< oa i = = = = = = Point Mcintyre oil a a - - - = = = = = NGL - - - - - - - = = =
net - 7 - - - - - - - a
Prudhoe Bay oil [2] 555.394 555.170 558.889 560.837 561.952 568.534 561.538 572.045 559.412 505.940
NG 0.254 0.450 0.500 Os1t 0.317 0.056 0.280 14¢ 610 19. 9.274 16. 3.928 in
net 555.6 648 555. 620 559. 389 561. 4148 562.2 269 568! 590 561 1767 586 ¢ 655 578. 686 522. 869 Sag River oil a oa a - = = = = = Sag Delta oil = = co a - i = = = 0.349
NGL = - - - 7 = = i = 0.005
net = ae - - - - - - ~ 0.354 Schrader Bluff oil - - - - - - - - - <.001
West Beach oil - - - a 7 = = - = =
NGL 7 - - - - = = = — - net - - = - - - - = = = West Niakuk oil = = - - = = = = = = NGL - - - - - - - = - - net - - = - - - = - - West Sak oil = i = 0.006 0.124 0326 0.300 - - i
TOTAL OIL [2] 555.394 556.264 591.503 600.806 608.454 649.613 664.052 699.527 722.840 669.258
TOTAL NGL = G:450 0.500 0.311 0.317 0.817 1.302 16.328 21.029 16. 864 TOTALINJECTION - 0.007 0014 —
TOTAL NET _ 555.< 394 556.1 714 592. 003 601. 447 608.7 771 650.430 665.347 715.841 743.869 688.1 123
COOK INLET
Beaver Creek oil 0.214 0180 0182 0170 0159 0146 0158 0.185 0.141 0.227 Cannery Loop [3] NGL = = - - - = - - - - Granite Point oil 4.394 3975 3467 3550 3.287 3.052 3169 2803 2677 2.275 Kenai [3] NGL i - = = - = = = - - McArthur River oil 20.894 18.022 15.806 13.564 11.707 7.454 7942 7.375 7.143 6.955
NGL 0.412 0484 0449 0332 0317 0.194 0.228 0.196 0.162 0.000
net 21.306 18.506 16.255 13.896 12.024 7648 8.170 7.571 7.305 6.955 Middle Ground Shoaloil 4.854 4.291 3573 3.381 3.238 3.098 3.211 2.834 2.742 2.769 Redoubt Shoal oil ag = = - P = - - - - Swanson River oil 3.724 2938 2999 3.017 2517 2165 2.055 2.059 2.127 1.875 NGL 0.064 0.048 0.048 0.045 0.039 0.026 0.054 0.030 0.033 0.024 net 3.787 2.986 3.047 3.062 2556 2.191 2.109 2.089 2.159 1.899 Trading Bay oil 2.167 1.669 1.384 1.081 1.075 1.029 1.046 0935 0886 1.264 NGL 0.006 0.005 0.002 0.004 0.005 0.004 0.002 0.001 0.000 i net 2.173 1675 1.386 1.085 1.080 1.032 1.048 0936 0.887 1.264 West McArthur River oil 7 i = i = i - - = - TOTAL OIL 36.247 31.075 27.411 24.763 21.984 16.944 17.580 16.191 15.716 15.366 TOTAL NGL 0.481 0538 0499 0.381 0.361 0.223 0.284 0.227 0.195 0.024 TOTAL NET 36.728 31.613 27.910 25.144 22344 17.167 17.865 16.418 15.911 15.390
STATE oo TOTAL OIL [2] 591.641 587.339 618.914 625.569 630.437 666.557 681.632 715.718 738.555 684.625 TOTAL NGL 0.481 0.988 0: ).299 0.692 0. 678 1.040 1.586 16.555 21.224 18.888 TOTAL INJECTION - 0.007 0.014 — TOTAL NET 592.4 122 588.2 327 619.¢ 913 626.2 261 631.1 115 667.597 683.211 732.259 759.780 | 703. 513
TAPS FLOW [4]
Throughput at PS #1 554.934 556.067 591.142 600.859 608.836 649.887 665.435 716.662 743.302 688.062 Liftings at Valdez 548.895 547.026 583.370 592.319 596.588 643.512 603.028 700.878 736.047 672. 461
21
Cumlative Reserves Field Type[1] 1990 1991 1992 1993 1994 1995 (MMBBL) (MMBBL) Depletion
NORTH SLOPE Endicott oil 36.181 38.996 40.603 38.433 33.916 33.005 303.132
NGL 0.845 1.170 1.468 1.551 1.481 1.203 past inj - i = - = — 0.02
net 37.027 40.165 42.071 39.985 35.397 34.208 312.164 310 [5] 51% Kuparuk oil 107.206 113.571 118.506 115.166 111.795 106.999 1,288.642 NGL - - - - - - 3.346 net 107.206 113.571 118.506 115.166 111.795 106.999 1,291.988 1,335 49%
Lisburne oil 14.669 13.316 12.517 8500 6957 5.482 111.781 NGL 1.204 1.337 1.464 1.277 0.986 0.823 9.650
net 15.873 14.653 13.981 9.777 7.943 6.305 121.431 64 66% Milne Point oil 6.624 6.701 5.812 5.704 5648 7.386 47.043 348 [6] 12%
North Prudhoe Bay oil = 0.420 0.769 0.754 1.943 State NGL - = 7 0.015 0.031 0.034 0.080 net - = = 0.435 0.801 0.788 2.023 6 [7] 37% Niakuk oil - - i - 3.373 6.400 9.772 NGL i as = = 0.028 0.071 0.098
net = = = 3.400 6.471 9.870 56 14% Point Mcintyre oil - i - 7E 519 37.545 50.154 95.218 NGL i i i 0.090 0.548 0.679 1.317 net - = 7.609 38.093 50.833 96.535 498 16% Prudhoe Bay oil [2] 470.140 465. 399 432.587 385.811 351.493 313.629 8,974.257
NG 16.¢ 094 21 807 23. 902 23.€ 879 22. 825 26. 810 ata in| K nat 486.2 fase 486. 706 456. 490 409.¢ 690 374.2 318 340.2 439 9,148.991 3,070 75% Sag River oil 0.142 0.142 ig Sag Delta oil 1.542 2.309 1. 002 0.761 0.368 0.228 6.554 5,
NGL 0.028 0.048 0.011 0.007 0.003 0.001 0.102
net 1.569 2.356 1.013 0.768 0.372 0.229 6.656 Schrader Bluff oil 0.004 0.756 1.185 1.060 1.030 1.163 5.147 [6] West Beach oil = bo 0.720 0.511 0.163 1.395
NGL = = i 0.009 0.012 0.005 0.027
net i = - 0.729 oes 0.168 1.422 [7] West Niakuk oil - = - 0.635 0.635
NGL - - - - - 0.006 0.006
net = = i = = o. 641 0.641 West Sak oil - - - - 0.755 236 [8] 0% TOTAL OIL [2] 636.366 641.048 612.162 564.093 553.406 526.1 140 10,846.416
TOTAL NGL 18.171 23.861 26.845 26.830 25.914 29.632 211.426 TOTALINJECTION - - - = - - 13.034
TOTAL NET 654.538 664.909 639.008 590.923 579.320 555.772 11,051.684
COOK INLET Beaver Creek oil 0.212 0.179 0.175 0.153 0.140 0.132 4.879 1 83% Cannery Loop [3] NGL - - oa = <.001 <.001 <.001 Granite Point oil 1.462 2.064 2.522 2.488 2.209 2.580 125.132 16 89% Kenai [3] NGL - - = - = = 0.012 McArthur River oil 4.265 7.247 7.397 6636 7.091 6.622 575.046
NGL 7 - i - = i 8.979 net 4.265 7.247 7.397 6636 7.091 6.564 583.967 44 93% Middle Ground Shoaloil 2.688 2.670 2.423 2.160 2.773 2.823 174.270 20 90% Redoubt Shoal oil - 7 = - = = 0.002 nodata Swanson River oil 1.878 1.962 1.773 1.576 1.672 1.712 221.911 NGL 0.019 0.023 0.019 0.018 0.023 0.017 1.360 net 1.897 1.985 1.792 1593 1696 1.721 223.262 13 94% Trading Bay oil 0.643 1.216 0.886 0.742 0.743 0.722 96.167 NGL - i = i = i 0.360 net 0.643 1.216 0.886 0.742 0.743 0.738 96.543 5 95% West McArthur River oil - 0.002 0.002 0.098 0.921 0.922 1.944 9 17% TOTAL OIL 11.147 15.340 15.179 13.853 15.550 15.513 1,199.106 TOTAL NGL 0.019 0.023 0.019 0.018 0.024 0.017 10.712 TOTAL NET 11.167 15.363 15.198 13.871 15.573 15.530 1,209.818
STATE
TOTAL OIL [2] 647.514 656.388 627.341 577.946 568.955 541.653 12,045.522 TOTAL NGL 18.191 23.884 26.864 26.848 25.938 29.649 222.138 TOTAL INJECTION - - - 13.034 _TOTAL NET _ 665.705 680.272 654. 206 604.7 794 594.¢ 894 571.302 12,254.626
TAPS FLOW [4]
Throughput at PS #1 654.551 665.175 639.390 591.220 579.320 498.659 Liftings at Valdez _ 636.199 647.345 623.217 570.707 559.082 481.092
22
[am IT 105, Samm TY) yp i Hill]
A eBay sss 1/1] ‘Pen =
Sag River SSS Saas = CooK INLET Gee? 3s PELLET TTS
1985
1975 1980 1999 1995
Jl cond RTOs Cook | WUT) s ay ~o TT
EEE SSS SSS SS SSS SMM
1965 1979 1975 1989 1985 1999 1995
23
4 HISTORICAL PRODUCTION OF NATURAL GAS
A small amount of gas is produced from three
fields near Barrow. All other Alaska gas is
produced from the same regions that produce
all the state’s oil, the North Slope near Prudhoe
Bay and upper Cook Inlet. The production re-
gimes of the two regions are very different be-
cause their markets are very different. The only
market for North Slope gas is as fuel for oil
production and related facilities at Prudhoe Bay
and no gas, excluding NGLs, is marketed off of
the North Slope. Most of the extracted gas is
injected back into the reservoirs and will be
available for sale if and when a major market
develops. Cook Inlet fields, however, lie near
the Anchorage and Kenai commercial markets,
the Unocal ammonia-urea plant, and the Phil-
lips-Marathon LNG plant. Consequently, nearly
all extracted gas is consumed and very little has
been injected.
NORTH SLOPE
North Slope gas production began in 1946 from
South Barrow field. This field and two more
recent fields, supply Barrow’s local use. Prud-
hoe Bay oil field was discovered in 1968, and
during the development of the field a small
amount oil and gas was produced for fuel.
Commercial oil production began in 1977 and
since then, a large amount of dissolved gas has
been produced with the oil, separated from the
oil, then injected back into the reservoir.
Through seventeen years of production, as oil
and gas have been withdrawn and the gas
returned to the reservoir, gas has become an
increasingly greater proportion of field produc-
tion. Net gas production has grown to 276
billion cubic feet in 1995 and is expected to
increase for the next several years. North Slope
fields have produced a cumulative net 2.8 trillion
cubic feet by the end of 1995. North Slope
lessees report NGL as natural gas, though most
of the liquid NGLs are blended with crude oil and
transported through TAPS to refineries.
COOK INLET
Cook Inlet gas production began at Swanson
River field in 1958. Production remained low for
several years. Regional production grew from
12 billion cubic feet per year in 1966 to 145
billion cubic feet per year in 1970 then rose
more gradually to a peak of 217 billion cubic feet
per year in 1985 and has generally declined to
214 billion cubic feet per year in 1995. Cook
Inlet fields have produced a cumulative net 4.9
trillion cubic feet by the end of 1995.
Since its early years, Swanson River operators
have enhanced the field’s oil recovery by inject-
ing the pool’s casinghead gas back into the
reservoir and by injecting additional gas bought
or “rented” from other fields. In late 1992 the
operator altered this program: no gas is im-
ported from other fields, most of the casinghead
gas is injected into the reservoir, and some gas
is sold.
Summary of Historical Gas Production
Peak Peak Year 1995 Cumulative
Year Production Production Production .
Cubic Feet per Day - _ |
North Slope 1995 754 million 754 million 2.6 trillion 34%
Cook Inlet 1994 507 million 588 million 49 trillion 64%
State 1995 1.3 billion 1.3 billion 7.7 trillion 100%
Cubic Feet per Year 7
North Slope 1988 276 billion 276 billion 2.6 trillion 34%
Cook Inlet 1970 215 billion 214 billion 49 trillion 64%
State 1988 490 billion 490 billion 7.7 trillion 100%
25
TABLE 4 — HISTORICAL GAS PRODUCTION BILLIONS OF CUBIC FEET PER YEAR Type [1] 1949 1950 1951 1952 1953 1954 1955 1956 1957 1958 1959 1960 1961
NORTH SLOPE East Barrow dry a a at = aT a = i rd i, = = oF Endicott csg a a = > aT TT =I a mi a ra iF inj = om = - a aT = = - - - a - net oa a = = im mn es a aa = a a oo Kuparuk csg - - - - z z ai = a Tr a a a inj = = = = = = = = 7 - = = - Lieb net Ti a = = 7 - = = Th a aT al in isburne = = = ad a a = a Th or a a a eee net a ra = eS oa 7 = ia 7 oa aT 7 it Milne Point csg a = = = 7 7 = = 7 a am iif it inj 7 = = = 7 z oa = = ced a ad aa
Niakuk [3] ot = = = = = am : = = = a = = csi ba ~ = = ee aa = = S a a = =
ini] a = = aa 7 a oT = a oT ad = a net = 4 = = = = = a — a a - I North Prudhoe cs 7 a = a = ai a ~ a = m7 T TI Bay State inj [2] = — = = = oF = oa a7 oT a a Tr net oe = = aa oe = = on a = - - Point Mcintyre csg 7 = a 4 i aa = = ae at in a a inj - - - - = - = a = - = - - net - - - = = - = = = - = - - Prudhoe Bay csg - - = — = = = = = = a = = inj - - at = 7 = = 7 = a - - ee an net a a = = a m7 aa 7 7 a oa oie or ig Del csg ae oT = om 7 7 = = a = = - - Sag River csg oa 7 = = = a = = = = = oe = Schrader Bluff esg - = - - = = = oe oe = aa = = South Barrow dry 0.033 0.091 0.135 0.137 0.075 0.027 0.115 0.103 0.114 0.119 0.132 0.172 0.172 Walak; dry a = oa aa oy = a = > a a = 4 West a oi = a a = a 7 a Ti a = ini] - = - = a = ca oe = 7 a 7 - net - = - = = or a 7 a = a - - West Sak csg - TOTAL GROSS 0.033 0.091 0.195 0.137 0.075 0.027 0.115 0.103 0.114 0.119 0.192 0.172 0.172 TOTAL INJECTED TOTAL NET 0.033 0.091 0.135 0.137 0.075 0.027 0.115 0.103 0.114 0.119 0.132 0.172 0.172
COOK INLET Albert Kaloa dry ee a = = a = = = ad a a 7 a Beaver Creek csg ty m3 = a a 4 - So od a a ai - ary MT A PEA Ne I 2a) eS ANE) Vee) Ae A et) UN ae | inj - - - - - - = = = - = - - net - - - - - - - - - - - - - Beluga River dry = a - — - - — = = — - - Birch Hill dry - - - - - - - - - - - - - Cannery Loop dry - = - = 7 - - = = - = - - Falls Creek dry - - - - - - - - - - - - - Granite Point csg = oy = im 7 = - = = = = - - dry = = = qi an = = 7 = or co = - net - - - - - - - - - - - - - Ivan River dry - - - - - - - - - - - - - Kanal dry am al a i ae = = - - - - 0.017 0.215 Lewis River dry - - - - - - - - - - - - - McArthur River csg os = - - = - - - - - - - - dry m oT ae oa a = a 7 oa =
Micehe Grou cea a a a z a es) us a a a ul iddle Grou esg - - - - - - - - - - - - - Shoal dry - - - - a - Es = a zit a all il
etd net Ti a i ik itt a im i i ia i 7 im loquawkie - a = a = = — a ad = = = Nicolai Creek ay - = = - - - - - - - - - - North Cook Inlet = dry - = - - - - - - - - - - - North Fork dry - - - - - - - - - - - - -
Pretty Creek dry - - - - - - - - - - - - - Redoubt Shoal csg = = - - oy - - - - - - - - Sterling dry - - - - - - - - - - - - -
Stump Lake dry - - - - - - - - - - - - -
Swanson River cesg - - - - - - - - - 0.006 0.027 0.099 1.293 dry - - - - - - - - - - - 0.020 — inj od = = ak a Ti = 7 TT ea = 46.482 — net - - - - - - - = — 0,006 0.027 (46.363) 1.293 Trading Bay csg - - - - - = - - - - - - -
dry = = = a a = = = aa a = = ad net - - - - - - - - - - - - - West Fork dry - - - - - - - - - - - - - W. McArthur River csg - - - - - - - - - - - - TOTAL GROSS - - - - - - - mn — 0,006 0.027 0.137 1.508 TOTAL INJECTED - - - - - - - - - - - 46.482 -
TOTAL NET = = ells = - - - - 0.006 0.027 (46.345) 1.508
STATE TOTAL GROSS 0.033 0.091 0.135 0. 137 0.075 0. 027 0.115 0. 103 0. 114 0.124 0.159 0.309 1.680 TOTAL INJECTED - - - 46.482 — TOTAL NET 0.033 0.091 0.135 0.137 0.075 0.027 0.115 0.103 0.114 0.124 0.159 (46.173) 1.680
Source: Alaska Oil and Gas Conservation Commission, "Alaska Production Summary by Field and Pool." dry = dry gas, csg = casinghead gas, inj = injected, net = dry + csg — inj. Division of Oil and Gas, royalty reports. Niakuk includes Niakuk 27. Endicott includes Sa: Delta '5] Milne Point includes Sey er and Schrader Bluff. Milne Point is assigned no gas reserves use most of its gas will be used for production fuel. Lon 26
Type [1] 1962 1963 1964 1965 1966 1967 1968 1969 1970 1971 1972
NORTH SLOPE East Barrow aes a at i Bi a 7 7 = a = Endicott ap = = an = = af iT mT oa im
Kuparuk - - - - - = fi a = = -
Lisburne aT aT im al 7 a rT Tl 7 Tl 7
Milne Point oT a a TT ny 7 rl fal a aT a
Niakuk [3] a - a 7 ms ra i i on - a
North Prudhoe mi aT i ii al a a a a i) iT Bay State 7 a - oT i aT aI a 7 ai 7
Point Mcintyre 7 7 mT a 7 i 7 i TT a a
Prudhoe Bay om ul i iM i 7 an 0.243 1.037 0.889 0.658
- - - - - im = 0.243 1.037 0.889 0.658 Sag Delta fai oT = = 7 al af ia a i in 328 River er a 7 a i i ia im aT il mm Schrader Bluff a oat 7 7 os - 7 ~ ra ry - South Barrow 0.197 0.211 0.249 0.389 0.438 0.475 0.504 0.582 0.619 0.627 0.675 Walak fal i ca i i 7 i: a 7 i 7 West ch os - - - i - i - a 7 -
West Sak cesg a Ly on 7 - - = - 7 - _ TOTAL GROSS 0.197 0.211 0.249 0.389 0.438 0.475 0.504 0.825 1.655 1.516 1.333 TOTAL INJECTED - = = - =. 7 = - = 7 = TOTAL NET 0.197 0.211 0.249 0.389 0.438 0.475 0.504 0.825 1.655 1.516 1.333
COOK INLET Albert Kaloa dry aT = i a 7 a Th = 0.095 0.024 = Beaver Creek os - - - - - - = - - - <.001 Ir ms a a a = a a ui a uv fas
inj - = i a a = = aT a = - net = om 7 a 7 a i - a i <.001 Beluga River dry - 0.014 0.137 — ad 0.168 2.018 3.038 3.571 4.055 4.142 Birch Hill dry - - - 0.065 - - - - - - - Cannery Loop dry - ~- - - mT - im - 7 7 - Falls Creek dry - - - a 0.019 - - - - - - Granite Point ssa i i - i a 4.890 10.036 8.043 9.211 7.753 5.773
net a - - ry an 4.890 10.036 8.043 9.211 7.753 5.773 Ivan River dry - - = - = mad = - - - - Kenai dry 1.460 3.106 4.493 5.985 33.375 39.624 46.014 59.340 80.612 72.184 76.007 Lewis River dry 7 = 7 = a 7 ag = > - - McArthur River csg he aT a TT i 0.220 6.124 9.565 14.989 15.732 15.477 dry aT 7 ni a ar - 0.032 4.629 4.699 3.572 4.245 net - a i ox os 0.220 6.155 14.194 19.688 19.304 19.722 reall Ground gsa - = ag 0.010 1.200 3.215 6.654 6.006 6.137 5.147 4.075 10a! Z a 7 i ie = a 7 ai — i
net - - - 0.010 1.200 3.215 6.654 6.006 6.137 5.147 4.075 Moquawkie dry - - - - - 0.034 0.353 0.514 0.083 - - Nicolai Creek dry a = ai a on a 0.026 0.387 0.202 0.141 0.066 North Cook Inlet = dry ae - mi mT oa - 7 7.881 40.947 45.024 41.580 North Fork dry - - - - 0.105 - - - - - - Pretty Creek dry - - - - - - - - - - - Redoubt Shoal csg - - - - - - <.001 - - - - Sterling dry 0.025 0.046 0.058 0.120 0.157 0.180 0.198 0.265 0.265 0.267 0.172 Stump Lake dry = = on a oF i = i = i - Swanson River csg 1.914 2.808 3.233 3.831 5.622 13.541 25.434 40.756 50.396 66.569 67.441 dry 0.157 4.838 3.943 2.141 0.740 - - - - - - inj 0.259 6.478 5.620 4.843 28.770 37.944 58.316 67.215 73.139 73.892 76.133 net 1.813 1.168 1.556 1.129 (22.407) (24.403) (32.882) (26.459) (22.743) (7.323) (8.692) Trading Bay ssa - - ri 0.001 <.001 0.722 2.961 7.119 7.156 9.097 5.668 y ut a 7 ing o a a i a pi a net - - - 0,001 <.001 0.722 «2.961 7.119 7.156 9.097 5.668 West Fork dry 7 i 7 7 7 iT 7 aT 7 - aT W. McArthur River csg a ps i ie as a - ba 7 oe - TOTAL GROSS 3.557 10.810 11.865 12.155 41.219 62.593 99.851 147.543 218.363 229.566 224.647 TOTAL INJECTED 0.259 6.478 5.620 4.843 28.770 37.944 58.316 67.215 73.139 73.892 76.133 TOTAL NET 3.298 4.333 6.245 7.311 12.449 24649 41.535 80.328 145.224 155.674 148.514
STATE
TOTAL GROSS 3.753 11.021 12.114 12.543 41.656 63.069 100.355 148.368 220.019 231.081 225.980 TOTAL INJECTED 0.259 6.478 5.620 4.843 28.770 37.944 58.316 67.215 73.139 73.892 76.133 TOTAL NET 3.495 4.543 6.494 7.700 12.887 25.124 42.039 81.153 146.879 157.189 149.847
4 Not calculated. 7] Ivan River, Lewis River, Pretty Creek, and Stump Lake are computed as a single reservoir. serves" and "Depletion" of that reservoir are assigned to Ivan River. 8] To maintain Swanson River oil production, more gas was injected into the field than was produced. levised 04/13/96
27
TABLE 4 — HISTORICAL GAS PRODUCTION
BILLIONS OF CUBIC FEET PER YEAR
Type [1] 1973 1974 1975 1976 19771978 1979 1980 1981 _1982
NORTH SLOPE East Barrow dry 7 i mn i as a i Tr 0.037 0.717 Endicott csg 7 ni aT aT in 7 a im i aT inj ae ae i 7 a a in oe a a
uk 7 i 7 u 7 = t 7 a 0.615 22.989 Ku cs a - a a a fT bal a . . ail ini? = - ro aa a cs on 0.000 17.822 net = - - 7 - - ia - 0.615 5.166 Lisburne cs - 7 fs 7 a i a ae 0.003 0.374 inj [2] - - on Te 7 an 7 7 7 iz net i i 7 aT a oT - os 0.003 0.374 Milne Point csg - - - - - - i ue ui li
inj = - oa om a a 7 iT mi 7 net 7 = 7 a 7 7 7 7 7 ani Niakuk [3] cs - - - TT a a ai a 7 a inj [2] - - - a i a a 7 - 7 net - - - 7 = ard an 7 i North Prudhoe cs - - - on 7 a ni ae - an Bay State inj [2] oo = Po aR = a a oa - - net - - - oa 7 7 or 7 7 a Point Mcintyre csg - ah = or a | ait eT a? a inj - - - 7 7 a - rT - a
net - tt 7 ay i = ira zh 7 i Prudhoe Bay csg 0.699 2.022 3.046 5.077 94.936 307.966 432.475 597.148 647.768 756.884 i inj = - - a 68.118 271.854 390.136 546.510 595.106 697.812 net 0.699 2.022 3.046 5.077 26.818 36.111 42.339 50.638 52.662 59.071 Sag Delta csg oma a 7 7 = im a if - 7 Sag River csg oa ni in a ai am aT iT - 7
Schrader Bluff csg 7 7 im a a ra ra = 7 re South Barrow dry 0.707 0.765 0.799 0.832 0.879 0.893 0.913 1.027 1.009 0.532 Walak dry oi 7 Tn aT ni TT ili i a rT West Beach cs. iT nt 7 7 " il it a im iT inj [2] = - - oT a oa a 7 - 7 net aT aT in Tl in ni i it in i West Sak csg = fa ne is = zs a a ra al TOTAL GROSS 1.406 2.787 3.845 5.909 95.814 308.859 433.388 598.175 649.431 781.496 TOTAL INJECTED - - 7 Pr 68.118 271.854 390.136 546.510 595.106 715.635 TOTAL NET 1.406 2.787 3.845 = 5.909 27.696 37.004 43.252 51.665 54.325 65.861
COOK INLET Albert Kaloa dry aa 7 oa = 7 - a a re - Beaver Creek csg 0.153 0.130 0.104 0.095 0,090 0.092 0.094 0.091 0.080 0.082 dry 0.054 0.020 0.218 0.166 0113 0.237 0.088 0.090 0.137 0.314 inj - 0.019 - 0.091 0.100 0.144 0.079 0.029 0,020 0.037
net 0.207 0.131 0.322 0.170 0.103 0.185 0.103 0.151 0.197 0.359 Beluga River dry 4.929 5.596 6.980 11.211 13.353 14.253 16.994 17.002 17.248 18.653 Birch Hill dry oa 7 ia ii i aH i - ar ae Cannery Loop dry 7 on 7 fo Ti a oT i oe - Falls Creek dry 7 a = - Sal 7 a _ - - Granite Point csg 4518 3265 3390 3.205 3634 3.860 3.287 3233 3.509 2.780 dr oe TF 7 o 7 a al i rs a net 4518 3265 3.390 3.205 3634 3.860 3.287 3.233 3.509 2.780 Ivan River dry i = a - 7 i 7 aa - = Kenai dry 71.345 68.485 77.175 79.467 81.886 97.290 97.029 98.846 105.800 115.913 Lewis River dry oF ad oe i = a ey oe - - McArthur River csg 14.178 12.739 13.474 12.202 11.969 10.923 8849 8.043 7.651 7.521 dry 4.885 6.861 7.997 6825 7.737 7.662 7.756 7.547 7.555 8.719 net 19.063 19.599 21.471 19.027 19.706 18.585 16.605 15.590 15.206 16.240 Middle Ground csg 4.826 4.260 4.199 4.347 4.108 3.290 2.744 2.628 2.502 2.277 Shoal dry - oT - - 7 oy ay Te i 0.097 net 4826 4260 4.199 4.347 4108 3290 2.744 2628 2.502 2.374 Moquawkie dry om - - - ae = = - - - Nicolai Creek dry 0.006 0.011 0.083 0.108 0,032 - - - - - North Cook Inlet = dry 42.709 44.238 45.622 45.091 47.201 46.757 49.448 41.540 49.486 45.368 North Fork dry i - aT a an im - - - - Pretty Creek dry a a a - mT bg rT - - Redoubt Shoal csg 7 ay oe = - igs ba - - - Sterling dry 0.027 0.032 0.035 0.035 0,029 0.024 0.025 0.026 0.023 0.024 Stump Lake dry = - - - - - - - - - Swanson River <2 74.067 80.869 90.665 101.427 106.911 106.934 1 tewee 118.787 103.592 105.654 Ir - - - - - - 0.1 0.068 os - int 87.482 86.793 97.976 113.279 118.279 114.557 120.268 120.636 106.137 113.023 net (13.415) (5.924) (7.311) (11.852) (11.368) (7.623) (4.002) (1.781) (2.545) (7.369) Trading Bay csg 3.539 3312 2613 2.473 2890 2.427 1.713 1.448 1.232 1,221 dry i a? i ar - - - 0.104 0.192 0.411 net 3.539 3.312 2613 2.473 2890 2.427 1.713 1.551 1.424 1.632 West Fork dry - - - - - 0.052 0.770 0.476 0.030 0.086 W. McArthur River csg - - i oe - - - Tt aa - TOTAL GROSS 225.236 229.817 252.554 266.651 279.955 293.800 305.063 299.929 299.038 309.121 TOTAL INJECTED 87.482 86.812 97.976 113.370 118.379 114.701 120.347 120.665 106.157 113.060 TOTAL NET it 137.754 143.005 154.578 153.281 161.575 179.099 184.716 179.264 192.881 196.062
STATE TOTAL GROSS 226.642 232.604 256.399 272.560 375.769 602.659 738.451 898.104 948.469 1,090.617 TOTAL INJECTED 87.482 86.812 97.976 113.370 186.497 386.555 510.482 667.175 701.263 828.695 __ TOTAL NET 139.160 145.792 158.423 159.190 189.272 216.104 227.969 230.929 247.206 261.922
28
Type [1] 1983 1984 1985 1986 1987 1988 1989 1990
NORTH SLOPE East Barrow dry 0.689 0.693 0.632 0.589 0.590 0.661 0.475 0.488
Endicott esg ir 0.195 8.237 34.834 41.194 42.490
inj = = = i 5.615 28.023 33.033 35.523
net — 0.195 2.622 6.812 8.161 6.967
Kuparuk csg 44.391 57.389 104.279 114.889 125.089 119.883 107.519 116.579 inj 38.277 47.930 85.909 90.449 89.191 87.906 83.323 91.273 net 6.114 9.459 18.370 24.440 35.898 31.977 24.196 25.306
Lisburne c 0.154 0.343 1.902 8.677 64.906 94.670 104.746 107.592 inj [2] = - - 56.741 87.815 102.248 101.542 net 0.154 0.343 1.902 8 677 8.164 6.855 2.498 6.049
Milne Point csg - 0.253 1.644 0.011 - 0.978 2.718 inj io - - 0.197 = - 0.320 1.401
net | - 0.253 1.447 0.011 i 0.658 1.318
Niakuk [3] csi - - ~ oD a a
inj [2] = - = 7 ra a — = net 7 - - - - = a = North Prudhoe cc 7 7 = - e 7 eg = Bay State ine} a - oa = = = = ai net = - = = i = = = Point Mcintyre csg = = = = = - = oat inj - - - - = - i = net = = — 7 - = ost Prudhoe Bay csg 818.993 846.674 936.613 970.290 1,228.527 1,404.992 1,412.853 1,481.462 inj 754.044 768.899 846.786 882.882 1,105.023 1,248.094 1,244.284 1,317.106 net 64.950 77.776 89.827 87.407 123.503 156.898 168.568 164.356 Sag Delta csg = i - - - 0.236 1.416
Sag River csg - - - - - - 7 = Schrader Bluff csg - - - - - - = South Barrow dry 0.541 0.650 0.678 0.589 0.622 0.598 0.758 0.733 Walak, dry - - - - - - = West ich a i 7 = - 5 = = BEING HEI E HEHE net - = 7 7 7 - = = West Sak 0.005 0.079 0.134 0.108 = = - - TOTAL GROSS 864.775 905.828 1,044.491 1,096.981 1,427,982 1,655.639 1,668.758 1,753.478 TOTAL INJECTED 792.321 816.829 932.695 973.528 1,256.570 1,451.837 1,463.208 1,546.845 TOTAL NET 72.454 89.000. 111.796 123.453 171.411 203.801 205.550 206.633
COOK INLET Albert Kaloa dry - - - - - - - - Beaver Creek csg 0.092 0.101 0.094 0.078 0.053 0.039 0.064 0.058 dr ost 9.234 10.833 17.694 15.475 14.307 12.257 12.416 inj . = = = 7 - - - net 8.313 9.335 10.927 17.773 15.528 14.346 12.321 12.474 Beluga River dry 18.084 19.833 22.571 25.357 23.971 25.586 30.126 39.512 Birch Hill dry - - > - - - i Cannery Loop dry i - 7 - - 9.400 11.255 12.502
Falls Creek dry - - - - - - Granite Point csa 2.578 2.340 2.147 2.415 2.431 2.543 2.251 1.431 ry - = = = - - net 2.578 2.340 2.147 2.415 2.431 2.543 2.251 1.431 Ivan River dry - - - - - 0.676 Kenai dry 112.978 110.109 115.842 82.470 90.014 76.299 65.706 38.393 Lewis River dry oe 0.696 1.644 1.338 0.345 0.045 0.095 1.485 McArthur River csg 6.444 5.834 4.073 4.397 3.393 4.120 4.317 2.559 dry 7.931 9.242 6.603 9.163 9.884 12.603 26.683 48.897
net 14.375 15.076 10.676 13.560 13.277 16.722 31.000 51.456 Middle Ground csg 2.293 2.212 2.129 1.199 1.274 1.223 1.250 1.334 Shoal dry 0.371 0.514 0.493 0.394 0.312 0.411 0.715 1.246 net 2.663 2.726 2.622 1.593 1.586 1.635 1.965 2.579 Moquawkie dry - - - - - - - - Nicolai Creek dry - - - - - -
North Cook Inlet — dry 47.877 46.981 45.819 43.838 42.889 44.989 45.287 45.014 North Fork dry - - - - - Pretty Creek dry I i - 0.067 0.776 0.871 0.641 0.607 Redoubt Shoal csg - - - - - -
Sterling dry 0.022 0.018 0.012 0.002 i mal i = Stump Lake dry - - - - - 0.528 Swanson River csg 97.507 96.710 92.104 95.083 83.508 101.685 102.910 101.685 dry ae = = i 0.555 0.915 1.184 2.710
inj 95.353 93.687 89.025 93.602 87.013 99.734 107.802 106.031 net 2.154 3.023 3.079 1.481 (2.949) 2.866 (3.709) (1.636) Trading Bay csg 0.925 0.934 1.415 0.994 0.991 1.120 1.291 0.465 dry 0.631 0.626 0.417 0.385 0.443 0.191 0.141 0.003 net 1.556 1.560 1.532 1.379 1.434 1.311 1.432 0.467 West Fork dry 0.067 0.037 0.022 - = = i - W. McArthur River cs: oad — - - - = - - TOTAL GROSS 306.051 305.421 305.919 284.874 276.314 296.347 306.173 311.519 TOTAL INJECTED 95.384 93.687 89.025 93.602 87.013 99.734 107.802 106.031 TOTALNET (210.667 211.733 216.893 191.272 189.302 196.614 198.370 205.488
STATE TOTAL GROSS 1,170,826 1,211.249 1,350.410 1,381.855 1,704.296 1,951.986 1,974.931 2,064.996 TOTAL INJECTED 887.705 910.516 1,021.720 1,067.130 1,343.583 1,551.571 1,571.011 1,652.875 TOTAL NET 283.121 300.733 328.690 = 314.725 360.713 = 400.415 = 403.920 412.121
29
TABLE 4 — HISTORICAL GAS PRODUCTION
BILLIONS OF CUBIC FEET PER YEAR Cumulative Reserves Field Type [1] 1991 1992 1993 1994 1995 (BCF) (BCF) Depletion
NORTH SLOPE East Barrow dry 0.583 0.439 0.259 0.223 0.099 7.174 6 54% Endicott csg 60.246 97.047 120.116 116.810 127.191 648.362 inj 51.136 85.082 100.682 102.534 113.839 555.468 net 9.110 11.964 19.434 14.276 13.352 92.894 894 [4] 9% Kuparuk csg 123.207. 122.767 120.599 120.273 112.418 1,412.887 inj 95.982 96.625 94.339 93.288 84.317 — 1,096.630 net 27.225 26.141 26.260 26.986 28.101 316.254 682 32% Lisburne csi 124.360 154.468 130.882 101.260 80.866 975.202 inj [2] 112.457 141.598 120.937 92.968 74.054 889.916 net 11.903 12.870 9.945 8.292 6.812 84.842 277 23% Milne Point csg 3.515 3.015 2.967 3.524 4.358 22.984 inj 1.704 1.632 1,836 2.305 3.399 12.794 net 1.811 1.383 1.131 1.219 0.959 10.190 13 [5] 44% Niakuk [3] = - - 2.471 7.241 9.712 33 23% inj [2] — = - 2.270 6.651 8.921 net = = = 0.201 0.590 0.791 North Prudhoe c - - 1.103 2.646 2.482 6.231 [6] Bay State inj [2] = = 1.015 2.424 2.261 5.696 net - = 0.088 0.222 0,221 0.535 Point Mcintyre esg = = 5.392 38.795 46.637 90.823 inj - = 4.480 35.522 42.583 83.033 net - = 1.413 4.334 23.701 29.448 300 9% Prudhoe Bay csg 1,768.837 1,951.156 2,116.808 2,402.584 2,716.959 22,907.595 inj 1,583.472 1,764.648 1,921.633 2,204.235 2,497.702 20,705.093 net 185.365 186.508 195.175 198.349 217.872 2,202.502 26,000 8% Sag Delta csg 2.347 0.703 0.529 0.259 0.143 5.607 4 Sag River csg — Ee = Se 0.098 0.098 5] Schrader Bluff csg 0.244 0.536 0.518 0.515 0.652 2.465 5) South Barrow dry 0.662 0.628 0.441 0.261 0.052 21.957 4 85% Walak; dry - 0.252 0.585 0.858 1.109 2.804 28 9% West Beach c - = 0.592 1.119 0.446 2.156 [6] inj [2] - = 0.537 1.025 0.409 1.997 net - - 0.055 0.094 0.037 0.159 West Sak csg = = = = = 0.326 [6] TOTAL GROSS 2,084,001 2,331.009 2,500.789 2,791.598 3,100.751 26,116.384 TOTAL INJECTED 1,844.751 2,089.585 2,245.459 2,536.571 2,825.215 23,359.548 TOTAL NET 239.250 241.424 = 255.330 255.028 = 275.536 ~—-2, 756.835
COOK INLET Albert Kaloa dry = 3 = = = 0.143 [6] Beaver Creek csg 0.049 0.048 0.042 0.038 0.035 1.804 dry 10.354 7.320 6.294 1.266 1.880 129.019 inj - - - - - 0.550 net 10.403 7.368 6.336 1.304 1.914 130.271 144 47% Beluga River dry 38.494 36.534 31.739 34.212 35.645 525.026 488 52% Birch Hill dry - = - = = 0.065 11 1% Cannery Loop dry 12.318 10.635 9.516 6.361 5.535 77.521 50 61%
Falls Creek dry - = = = — 0.019 13 0% Granite Point csg 1,586 2.246 2.435 2.077 1.882 108.749 dry = — 0.009 = 0.048 0.057 net 1,586 2.246 2.444 2.077 1.828 108.806 29 79% Ivan River dry 2.132 1.774 8.238 15.996 12.027 40.843 75 [7] 35% Kenai dry 25.581 24.187 23.826 18.853 16.484 2,116.409 174 92% Lewis River dry 1.420 0.706 0.383 0.244 0.126 8.527 (7 McArthur River csg 5.121 5.175 4.107 4.205 4.403 227.803 dry 56.075 64.895 58.406 45.821 50.511 497.434 | net 61.196 70.070 62.512 50.027 54.994 725.237 600 55% Middle Ground csg 1.074 1.015 0.937 1.188 0.901 85.654 Shoal dry 0.513 1.362 2.004 1.835 1.237 11.505
net 1.587 2.377 2.941 3.023 2.188 97.159 14 87% Moquawkie dry - - = = = 0.985 [6] | Nicolai Creek dry - = - = - 1.269 North Cook Inlet = dry 44.695 44.411 45.529 52.689 53.541 — 1,196.452 1,000 54% North Fork dry = = = = = 0.105 12 1% Pretty Creek dry 0.742 0.762 0.333 0.203 0.256 5.258 7 Redoubt Shoal csg = = - = - <.001 6] Sterling dry = = 0.007 0.224 0.184 2.503 23 10% Stump Lake dry 1.608 1.504 0.778 0.454 0.288 5.159 7 Swanson River csg 102.113 101.619 96.013 123.016 100.368 2,580.453 8}
dry 2.944 2.915 2.206 1.919 1.413 28.863 inj 105.157 104.724 93.052 97.148 73.086 2,802.932 | net (0.100) (0.191) 5.167 27.787 28.786 (193.616) 155 Trading Bay csg 0.944 0.705 0.619 0.641 0.541 66.877 dry - = = = a 3.543 net 0.944 0.705 0.619 0.641 0.606 70.420 28 72% West Fork __ dry 0.460 1.364 0.625 0.206 0.016 4.212 3 58% W. McArthur River csg - <.001 0.031 0.216 0.231 0.479 1 32% TOTAL GROSS 308.224 309.176 294.075 311.666 287.552 7,726.736 TOTAL INJECTED 105.157 104.724 93.052 97.148 73.086 2,803.482 TOTAL NET 203.067 204.452 201.024 214.519 214.466 ~—-4,923.254 _ _
STATE TOTAL GROSS 2,392.225 2,640.185 2,794.864 3,103.265 3,388.303 33,843.119 TOTAL INJECTED 1,949.908 2,194.309 2,338.511 2,633.719 2,898.301 26,163.030 TOTAL NET 442.317 445.876 456.354 469.546 490.002 _7,680.089
30
Figure 4-1 - Gross Production of State Gas
Billions of Cubic Feet per Year
STATE, NORTH SLOPE Pru sn ts
Point Mcint) Milne South Barrow Niakuk East Barrow
N Prudhoe Bay State ‘Sag Delta (Ivishak)
Schrader Bluff
West Beach GY West Niakuk 1995 West Sak Sag River COOK ILET
Figure 4-2 - Gross Production of Cook Inlet Gas
Billions of Cubic Feet per Year
100
COOK INLET ‘Swanson River_ Kenai North Cook Inlet 5 McArthur River = Ss Beluga River : Beaver Creek SS Granite Point Middle Ground Shoal Cannery Loop Trading Bay Ivan River Lewis River Pretty Creek ‘Stump Lake West Fork Sterling Nicolai Creek Moquawkie West McArthur River tes 1970
31
Figure 4-3 - Net Production of North Slope Gas
Billions of Cubic Feet per Year
400
300
200
100
0
COOK INLET NORTH SLOPE Prudhoe Bay Kuparuk ‘Nndicott Lisbume Point Mcintyre
South Barrow
Milne Point
N Prudhoe Bay State ——
;
West Beach tas 1990
1975 1980
1970 1965 West Sak
1960 Sag River toa 1955
Figure 4-4 - Net Production of Cook inlet Gas
Billions of Cubic Feet per Year
COOK INLET fe luga rf eh at Ne i re Bie Lewis River Pretty Creek Stump Lake st Fork Sterling Nicolai Creek Moquawkie
West McArthur River
Albert Kaloa North Fork 1995
Falls Creek 1980 alls Redoubt Shoal a
32
5 HISTORICAL CONSUMPTION OF OIL
All of the oil consumed in Alaska is in the form
of refined fuels, and no significant amount of
crude oil has ever been consumed in the state
for manufacturing or commercial use other than
refining. Much of Alaska’s fuel demand is sup-
plied by four in-state refineries and five topping
plants, the balance is imported from West Coast
refineries. The proportion of fuels refined in-
state and out-of-state can not be calculated
from public data.
The Department of Revenue (DOR) taxes cer-
tain fuel sales and accordingly collects data on
how much fuel is sold within the state. DOR
33
compiled its fuel categories for tax purposes,
not to record fuel use patterns. Consequently,
some categories do not describe end use well.
A major caveat is that the category, “Other
Diesel/Exported as Cargo” is primarily residual
oil from Tesoro refinery sold to West Coast or
Pacific Rim refineries and so, under most defi-
nitions, is not consumed in Alaska. In 1995,
after subtracting “Other Diesel/Exported as
Cargo” from total fuel sales, Alaska consumed
1.7 billion gallons of fuel, including 808 million
gallons of aviation jet fuel, 623 million gallons of
diesel, and 273 million gallons of gasoline.
TABLE 5A — HISTORICAL OIL CONSUMPTION
MILLIONS OF GALLONS PER YEAR
1977 1978 1979 1980s: 1981 1982 1983 1984 1985 1986
FUEL SALES
Aviation Gas 16.770 15.830 16.925 16.912 18.754 16.596 15.244 17.399 17.997 17.815
Exempt 1.521 0.685 0.552 0.558 0.574 0.589 0.498 0.574 0.515 0.858
Taxable 15.249 15.145 16.373 16.354 18.180 16.007 14.746 16.825 17.482 16.957
Aviation Jet 330.744 363.607 415.164 416.184 400.177 432.366 517.575 611.314 518.092 592.620
Exempt 227.581 250.601 288.974 286.110 247.619 99.957 242.815 311.820 223.635 280.654
Taxable 103.163 113.006 126.190 130.074 152.558 332.409 274.760 299.494 294.457 311.966
Marine Gas 11.766 7.714 8.296 7.598 7.602 7.878 8.568 8.955 14.664 10.464
Exempt 5.707 0.554 0.292 0.025 0.085 0.032 0.052 0.120 0.251 0.291
Taxable 6.059 7.160 8.004 7.573 7.517 7.846 8.516 8.835 14.413 10.173
Marine Diesel 38.613 51.985 59.492 67.711 72.282 99.443 147.569 124.416 98.675 105.218
Exempt 6.396 10.116 6.325 5.370 5.153 30.443 75.395 50.874 9.724 10.097
Taxable 32.217 41.869 53.167 62.341 67.129 69.000 72.174 73.542 88.951 95.121
Other Gas 186.213 187.359 181.329 177.353 186.446 210.644 197.968 223.178 235.081 234.482
Exempt 5.094 8.290 7.527 8.162 9.084 12.809 10.887 11.028 15.353 21.558
Taxable 181.119 179.069 173.802 169.191 177.362 197.835 187.081 212.150 219.728 212.924
Other Diesel 165.752 184.876 269.377 302.647 326.440 411.125 420.279 436.308 643.430 897.970
Exempt 46.160 54.050 120.960 120.939 117.074 187.856 178.494 190.891 369.279 559.413
Taxable 119.592 130.826 148.417 181.708 209.366 223.269 241.785 245.113 274.151 338.557
TOTAL 749.858 811.371 950.583 988.405 1,011.701 1,178.052 1,307.203 1,421.570 1,527.939 1,858.569
1987 1988 1989 1990 1991 1992 1993 1994 1995 Est.
FUEL SALES
Aviation Gas 18.492 19.314 19.309 20.807 19.555 20.228 18.831 22.009 24.554
Exempt 0.384 0.743 0.816 1.019 0.673 0.747 0.368 0.454 0.397
Taxable 18.108 18.571 18.493 19.788 18.882 19.481 18.463 21.555 24.157
Aviation Jet 644.477 684.910 682.239 873.336 716.737 753.220 745.482 818.461 808.291
Exempt 318.349 333.703 311.805 423.583 342.262 373.772 399.433 473.436 452.259
Taxable 326.128 351.207 370.434 449.753 374.475 379.448 346.049 345.025 356.032
Marine Gas 11.510 10.554 10.202 10.477 10.269 13.082 10.994 10.343 8.918
Exempt 0.183 0.075 0.194 0.239 0.607 0.144 0.459 0.170 0.145
Taxable 11.327 10.479 10.008 10.238 9.662 12.938 10.535 10.173 8.773
Marine Diesel 171.769 159.027 176.361 198.301 193.194 198.553 172.252 162.104 148.154
Exempt 83.120 43.828 28.636 15.701 14.852 10.512 10,026 7.259 8.317
Taxable 88.649 115.199 147.725 182.600 178.342 188.041 162.226 154.845 139.837 Other Gas 221.259 222.162 215.462 244.488 217.039 245.690 242.251 261.235 239.325
Exempt 17.541 15.040 15.445 9.331 7.811 13.304 16.291 9.237 70.282
Taxable 203.718 207.122 200.017 235.157 209.228 232.386 225.960 251.998 169.043
Other Diesel 843.045 858.228 956.127 843.652 756.671 655.217 626.939 432.710 519.687
Exempt 583.305 576.131 674.692 570.569 471.046 382.923 396.638 229.001 257.049
Taxable 259.740 282.097 281.435 273.083 285.625 272.294 230.301 203.709 262.638 TOTAL _1,910.552 1,954.195 2,059.700 2,191.061 1,913.465 1,885.990 1,816.749 1,706.862 1,748.929
Source: Alaska Department of Revenue, "Report of Motor Fuel Sold or Distributed in Alaska." Revised 02/25/96
34
TABLE 5B — ESTIMATED FUEL SOLD OR DISTRIBUTED
IN ALASKA IN 1995 MILLIONS OF GALLONS PER YEAR
Aviation Aviation Marine Marine Other Other TOTAL
Gas Jet Gas Diesel Gas Diesel
EXEMPT ;
Sold for heating use = 0.084 = a 0.218 157.206 157.508
Federal government 0.186 21.434 0.077 1.643 1.589 4.826 29.755
State/local government 0.199 0.709 0.039 6.564 2.910 10.447 20.868
Charitable institution 0.005 = 0.022 0.090 0.067 0.300 0.484
Pub. util./non—profit power assoc. - - - - 0.172 12.004 12.176
Exempt power plant oa - = - 1.424 25.893 27.317
Jet ee flights - 376.581 - - - - 376.581
Consigned to foreign countries - - - - 0.004 0.035 0.039
Expoi as Cargo 0.008 84,273 0.006 0.020 1.938 45.479 131.724
Gasohol 2 = i — 61.289 = 61.289
Actual losses > - = - - - -
Other ce (30.822) 0.002 <.001 0.671 0.859 (29.290)
TOTAL EXEMPT 0.398 452.259 0.146 8.317 70.282 257.049 788.451
TOTAL TAXABLE 24.157 356.032 8.773 139.837 169.043 262.638 960.480
TOTAL EXEMPT + TAXABLE 24.555 808.291 8.919 148.154 239.325 519.687 _1,748.931
Source: Alaska Department of Revenue, "Report of Motor Fuel Sold Or Distributed in Alaska."
Revised 02/25/96
Table 5A - Historical Oil Consumption
Millions of Gallons per Year
3000
2000
1000
0
TOTAL FUEL SALES
Aviation Jet
Other Diesel
Other Gas
Marine Diesel
Aviation Gas 1995
35
6 HISTORICAL CONSUMPTION OF NATURAL GAS
NORTH SLOPE
At present, the only market for North Slope gas,
excluding NGLs, is as fuel for oil production
facilities and oil field related activities. Conse-
quently, 91% of the extracted gas is injected
back into the fields to maintain reservoir pres-
sure and to conserve the gas resources. Of the
estimated 267 billion cubic feet that were con-
sumed in 1995, 83% went to field related activi-
ties of which the largest consumers were the
gas handling and gas injection systems. A fur-
ther 11% was reported as NGL and 4% was sold
to TAPS for fuel. The volume of gas consumed
on the North Slope to produce oil is larger than
the combined Anchorage and Kenai domestic,
commercial and industrial markets.
37
COOK INLET
Anchorage and Kenai markets and exports con-
sume all the gas extracted from Cook Inlet fields
except for a small amount injected each year
into Swanson River field to maintain oil reservoir
pressure. Some Swanson River gas is now
sold off unit. Of an estimated 187 billion cubic
feet consumed in 1995, 40% went to Phillips-
Marathon’s LNG plant for combined fuel use
and product, 29% went to Union’s ammonia-
urea plant for both energy and feed stock, 17%
to power generation, 14% to utility gas, and 10%
to field operations.
TABLE 6 — HISTORICAL GAS CONSUMPTION
BILLIONS OF CUBIC FEET PER YEAR
1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983
NORTH SLOPE
Field Operations [1] ND ND ND 2.650 2.808 3.856 24.444 29.231 33.763 39.697 41.607 51.921 58.210
Vented and Flared ND ND ND 1.076 1.061 1.254 10.882 2.313 1.840 1.801 2.485 3.490 2.524
Used on Lease ND ND ND 1.556 1.747 2.602 13.562 18.826 23.559 28.967 29.642 37.864 44.837
Shrinkage ND ND ND = oa = a a a - ae a
Other ND ND ND 0.018 ai ah a 8.092 8.364 8.929 9.480 10.567 10.849
Sold [1] ND ND ND 0.136 1.037 2.054 3.347 7.802 9.512 12.007 12.791 14.000 14.589
Power generation [2] ND ND ND ND ND ND ND 0.219 0.235 0.235 0.315 0.404 0.482
Gas Utilities [2] ND ND ND ND ND ND ND 0.291 0.317 0.400 0.435 0.539 0.407
TAPS [3] = = 7 a a a 1.754 6.949 8.648 10.686 11.106 11.952 13.277
NGL [4] - - - - - - - - - 0.254 0.450 0.500 0.311
Unaccounted [5] ND ND ND ND ND ND ND 0.343 0.312 0.432 0.485 0.605 0.112
TOTAL ND ND ND 2.786 3.845 5.910 27.791 37.033 43.275 51.704 54.398 65.921 72.799
COOK INLET
Field Operations [1] 45.250 36.560 20.900 49.834 28.830 24.467 24.416 25.949 24.101 22.304 20.559 20.957 19.380
Vented and Flared 33.180 20.980 6.930 7.978 9.496 5.421 4.848 3.870 2.710 3.045 3.175 3.494 2.560
Used on Leases 10.960 14.860 12.420 39.845 16.215 15.822 16.404 16.228 14.564 14.608 14.950 14.861 14.056
Shrinkage 1.110 0.720 1.550 2.011 3.119 3.224 3.145 3.426 2.847 2.438 2.434 2.602 2.726
Other [11] os a i a we cei 0.019 2.425 3.980 2.213 0.000 0.000 0.038
Sold [1] [11] 121.717 123.717 130.937 130.509 140.717 143.710 152.437 164.300 168.106 162.201 178.082 185.913 192.578
Power generation 16.529 19.253 21.752 22.801 25.461 27.628 28.717 29.883 33.166 33.526 33.632 34.943 36.143
Public [6] 9.980 12.780 15.683 17.117 19.619 22.204 23.717 24.757 28.180 28.763 29.071 30.113 31.547
Military [7] 6.549 6.473 6.069 5.684 5.842 5.424 5.000 5.126 4.986 4.763 4.561 4.830 4.596
Gas Utiliti 10.238 13.099 14.757 15.128 12.092 12.551 12.683 13.454 14.045 15.521 15.778 19.025 19.111
Residential [7] 5.440 6.027 6.519 6.717 5.548 5.916 6.010 6.536 6.911 7.773 7.950 9.981 10.202
Commercial [7] 4.798 7.072 8.238 8.411 6.544 6.635 6.673 6.918 7.134 7.748 7.828 9.044 8.909
LNG [8] 63.240 57.133 60.570 61.656 63.904 62.090 65.449 60.102 62.231 51.915 67.943 62.853 66.042
Amonia-— Urea [9] 19.490 20.580 20.640 22.100 23.888 24.257 28.620 48.879 51.657 54.699 53.836 55.220 50.338
Rental Gas [10] ND 13.400 12.590 10.410 12.477 11.588 6.703 10.523 6.958 5.190 5.601 11.383 12.698
Unaccounted [5] 12.220 0.252 0.628 -—1.586 2.895 5.596 10.265 1.459 0.049 1.350 1.292 2.489 8.246
TOTAL 166.967 160.277 151.837 180.343 169.547 168.177 176.853 190.249 192.207 184.505 198.641 206.870 211.958
STATE
Field Operations [1] 45.250 36.560 20.900 52.484 31.638 28.323 48.860 55.180 57.864 62.001 62.166 72.878 77.590
Vented and Fiared 33.180 20.980 6.930 9.054 10.557 6.675 15.730 6.183 4.550 4.846 5.660 6.984 5.084
Used on Leases 10.960 14.860 12.420 41.401 17.962 18.424 29.966 35.054 38.123 43.575 44.592 52.725 58.893
Shrinkage 1.110 0.720 1.550 2.011 3.119 3.224 3.145 3.426 2.847 2.438 2.434 2.602 2.726
Other = Zz a 0.018 0.000 0.000 0.019 10.517 12.344 11.142 9.480 10.567 10.887
Sold [1] 121.717 123.717 130.937 130.645 141.754 145.764 155.784 172.102 177.618 174.208 190.873 199.913 207.167
Power generation 16.529 19.253 21.752 22.801 25.461 27.628 28.717 30.102 33.401 33.761 33.947 35.347 36.625
Public [2] [6] 9.980 12.780 15.683 17.117 19.619 22.204 23.717 24.976 28.415 28.998 29.386 30.517 32.029
Military [7] 6.549 6.473 6.069 5.684 5.842 5.424 5.000 5.126 4.986 4.763 4.561 4.830 4.596
Gas Utilities 10.238 13.099 14.757 15.128 12.092 12.551 12.683 13.745 14.362 15.921 16.213 19.564 19.518
Residential [2] [7] 5.440 6.027 6.519 6.717 5.548 5.916 6.010 6.827 7.228 8.173 8.385 10.520 10.609
Commercial [7] 4.798 7.072 8.238 8.411 6.544 6.635 6.673 6.918 7.134 7.748 7.828 9.044 8.909
LNG [8] 63.240 57.133 60.570 61.656 63.904 62.090 65.449 60.102 62.231 51.915 67.943 62.853 66.042
Amonia-—Urea [9] 19.490 20.580 20.640 22.100 23.888 24.257 28.620 48.879 51.657 54.699 53.836 55.220 50.338
Rental Gas [10] ND 13.400 12.590 10.410 12.477 11.588 6.703 10.523 6.958 5.190 5.601 11.383 12.698
TAPS [3] = a = = aa a 1.754 6.949 8.648 10.686 11.106 11.952 13.277
NGL [4] a a a oT a Ti 1 a a 0.254 0.450 0.500 0.311
Unaccounted [5] 12.220 0.252 0.628 -1.586 2.895 5.596 10.265 1.802 0.361 1.782 777, 3.094 8.358
L__TOTAL 166.967 160.277 151.837 183.129 173.392 174.087 204644 227.282 235.482 236.209 253.039 272.791 284.757
ND = No Data [1] Alaska Oil and Gas Conservation Commission, “Report of Gas Disposition,” monthly reports [2] Barrow Utilities and Electric Cooperative Inc..
[3] Royalty reports from Arco to Division of Oil and Gas, sales to TAPS from Prudhoe Bay field [4] Alaska Oil and Gas Conservatian Commission, "Alaska Production Summary by Field and Pool", monthly reports
[5] Calculated difference between "Sold" and sum of listed "Sold" items.
[6] 1971-1991: Alaska Energy Authority, “Alaska Electric Power Statistics, 1960-1991"
1992-95: Chugach Electric and Municipal Light & Power.
[7] 1971-82: Annual reports from Alaska Pipeline Co., ENSTAR and Kenai Utility Service Co. to Alaska Public Utilities Commission
1983-95: Enstar Natural Gas Co. [8] Phillips Petroleum Co. [9] 1971-74: Stanford Research Institute, "Natural Gas Demand and Supply to the Year 2000 in the Cook Inlet Basin of South Central Alaska,”
Nov. 1977.
1975-79: Sum of 1) sales from Kenai and Beaver Creek gas fields to Collier Chemical in: Alaska Oil and Gas Conservation Commission, “Kenai Gas
Sales," and 2) sales from McArthur River gas field in: Alaska Oil and Gas Conservation Commission, “Monthly Report of Gas Disposition.” 1980-88: Royalty reports from producers to Division of Oil and Gas.
1989-95: Unocal Corp. [10] 1972-1990: Royalty reports from Unocal to Division of Oil and Gas, item: Swanson River Rental Gas 1991-93: Unocal Corp.
Kenai field gas "rented" to Swanson River field to maintain reservoir pressure was accounted, until 1992, as "Sold." Swanson River fields now
produces gas but this gas is accounted as “Field Operations, Other."
Revised 04/13/96
38
1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995
Est.
NORTH SLOPE
Field Operations [1] 74.732 91.388 101.722 138.581 192.846 172.625 169.343 183.711 196.055 208.539 211.020 221.611
Vented and Flared 5.814 3.437 5.802 12.952 5.747 6.792 8.753 6.795 10.092 19.081 10.585 7.178
Used on Lease 53.884 70.683 71.338 109.127 132.245 136.576 137.981 154.038 160.902 164.089 175.639 207.122
Shrinkage 0.000 0.000 0.000 0.000 40.759 9.678 1.099 1.547 1.940 2.026 1.930 i
Other 15.034 17.268 24.582 16.502 14.095 19.579 21.510 21.331 23.121 23.343 22.866 7.311
Sold [1] 15.088 20.089 20.001 42.719 48.287 39.546 37.067 45.475 48.402 46.202 44.190 45.363
Power generation [2] 0.480 0.486 0.559 0.544 0.620 0.620 0.644 0.667 0.721 0.676 0.712 0.614
Gas Utilities [2] 0.508 0.453 0.486 0.493 0.519 0.484 0.495 0.486 0.530 0.508 0.541 0.520
TAPS [3] 12.856 14.381 15.166 16.624 17.855 16.147 14.543 15.349 14.583 12.342 12.017 11.402
NGL [4] 0.317 0.817 1.302 16.328 21.029 18.864 18.171 23.861 26.897 26.841 25.915 29.632
Unaccounted [5] 0.927 3.952 2.488 8.730 8.264 3.431 3.214 5.112 5.671 5.835 5.005 3.195
TOTAL 89.820 111.477 121.723 181.300 241.133 212.171 206.410 229.186 244.457 254.741 255.210 266.97:
COOK INLET
Field Operations [1] 22.468 18.637 18.408 18.529 19.143 19.353 15.570 20.256 21.014 20.705 43.521 18.020
Vented and Flared 3.260 2.893 3.095 2.746 3.244 2.940 2.214 3.900 4.088 3.419 2.727 1.861
Used onL es 14.597 13.971 13.845 14.651 14.636 14.317 12.260 14.476 14.970 14.176 15.099 15.013
Shrinkage 2.657 1.773 1.468 1.130 1.263 2.096 1.064 1.843 1.956 1.369 1.227 =
Other 1.954 0.000 0.000 0.002 0.000 0.000 0.032 0.037 0.000 1.741 24.468 1.146
Sold [1] 192.752 199.311 174563 177.660 177.471 185.767 194.877 186.366 187.233 179.801 170.481 169.153
Power generation 35.909 38.724 38.774 36.240 36.854 37.933 38.858 35.329 33.504 32.045 33.045 34.000
Public [6] 31.571 34.194 34.243 31.583 32.038 32.917 33.918 30.629 28.549 27.361 28.360 29.255
Military [7] 4.338 4.530 4.531 4.657 4.816 5.016 4.940 4.700 4.955 4.684 4.685 4.745
Gas Utilities 20.903 24.419 23.235 23.063 23.249 25.238 25.892 24.700 25.946 24.242 26.607 26.718
Residential [7] 10.999 12.445 11.935 12.027 12.292 13.564 13.968 13.440 14.333 13.413 14.769 14.847
Commercial [7] 9.904 11.974 11.300 11.036 10.957 11.674 11.924 11.260 11.613 10.829 11.838 11.871
LNG [8] 64.229 63.926 61.062 60.111 62.168 63.836 65.135 65.429 66.219 67.328 76.651 78.144
Amonia - Urea [9] 50.083 50.688 35.733 45.230 41.882 54.495 54495 54.750 55.000 56.600 55.400 54.000
Rental Gas [10] 18.362 21.532 14.785 16.733 8.722 6.705 3.182 3.683 3.719 - - =
Unaccounted [5] 3.266 0.022 0.974 -3.717 4.596 -2.440 7.315 2.475 2.845 -0.414 21.222 —23.709
TOTAL 215.220 217.948 192.971 196.189 196.614 205.120 210.447 206.622 208.247 200.506 214.002 187.173
STATE
Field Operations [1] 97.200 110.025 120.130 157.110 211.989 191.978 184.913 203.967 217.069 229.244 254.541 239.631
Vented and Flared 9.074 6.330 8.897 15.698 8.991 9.732 10.967 10.695 14.180 22.500 13.312 9.039
Used on Leases 68.481 84.654 85.183 123.778 146.881 150.893 150.241 168514 175.872 178.265 190.738 222.135
Shrinkage 2.657 1.773 1.468 1.130 42.022 11.774 2.163 3.390 3.896 3.395 3.157 0.000
Other 16.988 17.268 24.582 16.504 14.095 19.579 21.542 21.368 23.121 25.084 47.334 8.457
Sold [1] 207.840 219.400 194564 220.379 225.758 225.313 231.944 231.841 235.635 226.003 214.671 214.516
Power generation 36.389 39.210 39.333 36.784 37.474 38.553 39.502 35.996 34.225 32.721 33.757 34.614
Public [2)[6] 32.051 34.680 34.802 32.127 32.658 33.537 34.562 31.296 29.270 28.037 29.072 29.869
Military [7] 4.338 4.530 4.531 4.657 4.816 5.016 4.940 4.700 4.955 4.684 4.685 4.745
Gas Utilities 21.411 24.872 23.721 23.556 23.768 25.722 26.387 25.186 26.476 24.750 27.148 27.238
Residential (2][7] 11.507 12.898 12.421 12.520 12.811 14.048 14.463 13.926 14.863 13.921 15.310 15.367
Commercial [7] 9.904 11.974 11.300 11.036 10.957 11.674 11.924 11.260 11.613 10.829 11.838 11.871
LNG [8] 64.229 63.926 61.062 60.111 62.168 63.836 65.135 65.429 66.219 67.328 76.651 78.144
Amonia— Urea [9] 50.083 50.688 35.733 45.230 41.882 54.495 54.495 54.750 55.000 56.600 55.400 54.000
Rental Gas [10] 18.362 21.532 14.785 16.733 8.722 6.705 3.182 3.683 3.719 - - -
TAPS [3] 12.856 14.381 15.166 16624 17.855 16.147 14543 15.349 14583 12.342 12.017 11.402
NGL [4] 0.317 0.817 1.302 16.328 21.029 18.864 18.171 23.861 26.897 26.841 25.915 29.632
Unaccounted [5] 4.193 3.974 3.462 5.013 12.860 0.991 10.529 7.587 8.516 5.421 -16.217 -20.514
TOTAL 305.040 329.425 314.694 377.489 437.747 417.291 416.857 435.808 452.704 455.247 469.212 454.147
39
See S SSeorllll <b
TAPS
SE a
SS
1985
NGL
Power generation
oyna mT FREER LLUU li L NR nn UT.
Amonia-Urea Power generation
Field Operations
40
Kalgin
Island
Falls Creek ¢
Falls Creek Unit
North Fork #North Fork Unit
\ Chevron Refinery coat)
Pipeline
Terminal Port Nikiski \ Rig> |
Tenders}
Inc. \ ‘ Nikiski
Wharf
a SC
S * " } LNG. 4, Dock *
= Zz =
= =
| PORT NIKISKI
au | DETAIL MAP:
| 0 1000 ft. AMH Tesoro
Petroleum Refinery
Seward
Plant
bal Gulf of Alaska
The State of Alaska makes no expressed or implied warranties (including warranties of merchantability and fitness) with respect to the character, function, or capabilities of this product or its appropriateness for any user's purposes. In no event will the State of Alaska be liable for any incidental, indirect, special, consequential or other damages suffered by the user or any other person or entity whether from use of the product, any failure thereof or otherwise, and in no event will the State of Alaska’s liability to you or anyone else exceed the fee paid for the product.
NORTH SLOPE OIL & GAS MAP
ALASKA DEPARTMENT OF NATURAL RESOURCES
DIVISION OF OIL AND GAS
APRIL 1996 Map Area
Pool Boundaries
Unit Boundaries
T i H en.) Discovery / Accumulation
Tie Pump Station #1 ee
0
Milne Pt. Unit
Kuukpik Unit ; M are 72
National
Petroleum
Reserve-
Alaska
The State of Alaska makes no expressed or implied warranties (including warranties of merchantability and fitness) with respect to the character, function, or capabilities of this product or its appropriateness for any user's purposes. In no event will the State of Alaska be liable for any incidental, indirect, special, consequential or other damages suffered by the user or any other person or entity whether from use of the product, any failure thereof or otherwise, and in no event will the State of Alaska's liability to you or anyone else exceed the fee paid for the product.
ilne Pt. - @Sandpiper
Beaufort Sea
tar Unit
itar/Seal Is
Ay
Pt. Mcintyre -North Prudhoe Bay West Beach ~~ Niakuk
Sag Delta North = "> Endicott -_ By lammerhead
d X a Duck Island Unit
ae) Zz » Tern = Pt. Thomson Unit fond SLisburne ®@istand Badami Unit Pt. Thomson f Flaxman Island aa
TR BAL
nN
Mikkelson” § —_
Sourdough 2
\ Arctic National
\ Wildlife Refuge
COOK INLET OIL & GAS MAP
ALASKA DEPARTMENT OF NATURAL RESOURCES %
DIVISION OF OIL AND GAS G
APRIL 1996
oe Pool Boundaries
Unit Boundaries
& Oil Field / Accumulation
@ Gas Field / Accumulation
rh
Platform
== Pipelines oe
a i ili 0 5 Production Facility a
=
Lewis River pe sikh & § Lewis River Unity “~~ + &
a gimp Lake ppg Pretty Creek / fee
Pretty Creek a Stump Lake Unit Go
nid
Ivan River Fi Ivan River Unit a @anciioRace
North Cook Inlet
North Cook Inlet Unit
N \ 7
Beluga River
Beluga River Unit
Nicolai Creek
Nicolai Creek Unit _
a : se Girdwood Trading Bay - i Granite Point Ny
North Trading Bay Unit of fi yi
McArthur Ri Rive eNorth Middle Ground Shoal Trading Bay Unit i} LZ @Birch Hill i: LLP W. McArthur River’ “ie middle Ground shgat”Ppirch Hill Unit Whittier
W. McArthur River Unit South Middle Ground Swanson River Unit ?
West Forelands Me ee Swanson River )
aha Soldotna Creek Unit
Beaver Creek i
Redoubt Shoal a BPrcaver Creek Unit i
West Forkg---: Se
pot BINGE Cannery Loop years, Be eds >< STERLING Cannery Loop Unit =Sterling eo HWY n —— n
7 PROJECTED CONSUMPTION OF OIL AND NATURAL
GAS
The consumption projection in the 1992 issue
of this report was a thorough revision of an
earlier projection prepared by the Institute of
Social and Economic Research (ISER). The
ISER projection was derived from the Energy
Demand Model (ENDMOD). ENDMOD esti-
mated future demand as a function of popula-
tion and the availability of alternate energy
sources. The 1992 DO&G revision applied to
ENDMOD a new ISER forecast of state and
local population, new data on electrical genera-
tion and vehicle fuel use, and new assumptions
about petroleum industry trends. The projec-
tion in the 1993 report was adjusted to actual
1992 fuel sales and these adjusted figures were
repeated in the 1994 and 1995 reports. How-
ever, after a few years, annual adjustments only
41
reveal discrepancies between projection as-
sumptions and actual events and do not inspire
confidence in the later years of the forecast .
Consequently, Table 7 is an unadjusted repeat
of the 1992 projection. Actual 1995 fuel con-
sumption was probably 20% less than antici-
pated, probably due to lower than expected
diesel consumption. Projections of aviation jet
fuel and gasoline, however, were very close to
actual sales. Other major categories of fuel
consumption and projection tables are similar
but not comparable. The gas projection for
1995 compares quite well with actual 1995 con-
sumption, though the volume of gas actually
used for petroleum production was higher than
forecast.
TABLE 7A — PROJECTED DEMAND FOR OIL
MILLIONS OF GALLONS PER YEAR
1996 1997 1998 1999 2000 2001 2002 2003 2004 —
STATE Vehicle Transportation 1,539 1,571 1,601 1,632 1,659 1,682 1,704 1,730 1,756
Jet Fuel 773 795 818 841 862 884 904 927 950
Civilian Domestic 445 464 483 503 521 539 556 575 595
Military and International 328 331 335 338 341 345 348 352 355 Gasoline 259 262 263 264 265 264 264 264 263
Aviation 17 18 18 18 18 18 18 18 18
Highway 233 235 236 237 238 237 237 237 236 Marine 9 9 9 9 9 9 9 9 9 Diesel 507 514 520 527 532 534 536 539 543
Highway 288 290 291 293 294 293 292 292 292
Marine 219 224 229 234 238 241 244 247 251 Space Heat 134 135 135 138 140 140 141 142 142
Utility Generation 44 43 43 45 47 48 48 49 48
Industry 72 67 63 59 56 53 49 46 44
Pipeline Fuel 53 49 45 42 39 36 33 30 28 Electricity Generation 19 18 18 17 17 17 16 16 16
TOTAL _ 1,789 1,816 1,842 1874 1,902 1,923 1,942 1,967_ 1,990
2005 2006 2007 2008 2009 2010 TOTAL ANNUAL
GROWTH
STATE Vehicle Transportation 1,785 1,815 1,851 1,891 1,931 1,973 26,120 0% Jet Fuel 975 1,000 1,029 1,060 1,091 1,125 14,034 3%
Civilian Domestic 616 638 663 690 718 748 98,754 4%
Military and International 359 362 366 370 373 377 = 5,280 1%
Gasoline 263 264 265 267 269 270 3,966 1% Aviation 18 18 19 19 19 19 273 1%
Highway 236 237 237 239 240 241 3,556 0%
Marine 9 9 9 9 10 10 137 1%
Diesel 547 551 557 564 $71 578 8,120 1% Highway 292 292 293 295 296 298 4,391 0% Marine 255 259 264 269 275 280 3,729 2% Space Heat 142 143 144 145 146 147 2,114 1% Utility Generation 48 48 48 48 49 48 704 2%
Industry 41 39 37 36 33 32 727 -6% Pipeline Fuel 26 24 22 21 19 18 485 -7% Electricity Generation 15 15 15 15 14 14 242 -2% TOTAL 2,016 2,045 2,080 2,120 2,159 2,200 29,665 1%
TABLE 7B — PROJECTED DEMAND FOR GAS
BILLION CUBIC FEET PER YEAR _ 1996 1997 1998 1999 2000 2001 2002 2003
STATE Space Heat 27.6 27.7 27.7 27.0 27.5 27.5 27.6 27.6
Utility Generation 39.2 39.9 40.6 41.2 417 41.9 42.1 42.4
Industry 302.6 296.8 291.1 2856 280.1 2750 270.0 265.2 Ammonia—Urea Production 54.5 54.5 54.5 54.5 54.5 54.5 54.5 54.5 Military Power Generation 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 Petroleum Production 243.1 237.3 2316 2261 2206 2155 2105 205.7 Pipeline Fuel 9.1 8.4 7.8 7.2 6.6 6.2 5.7 5.3 Miscellaneous 234.0 2289 2238 218: 214.0 2093 2048 200.4 __ TOTAL - 369.4 364.4 3594 3538 349.3 344.4 339.7 335.2
2004 2005 = -2006~=—2007_—S 2008~=— 2009 = 2010 TOTAL
STATE
Space Heat _ 27.7 27.9 28.0 28.1 28.1 28.3 28.4 417 Utility Generation 42.8 43.2 43.7 44.3 44.9 45.7 46.5 640
Industry 260.3 254.2 2498 245.4 241.2 237.1 233.0 3,987 Ammonia—Urea Production 54.5 54.5 54.5 54.5 54.5 54.5 54.5 818 Military Power Generation 5.0 5.0 5.0 5.0 5.0 5.0 5.0 75 Petroleum Production 2008 194.7 1903 185.9 181.7 1776 173.5 3,095 Pipeline Fuel 49 45 4.2 3.9 3.6 3.3 3.0 84 Miscellaneous 195.9 190.2 186.1 182.0 1781 1743 170.5 3,011 — TOTAL 830.8 = 325.3 321.5 317.8 314.2 311.1 307.9 5,044|
Revised 02/25/96
42
8 ROYALTY IN-KIND VOLUMES
The state can take its royalty share of oil in kind and 8B show the RIK volumes that have been
(barrels) or in value (money). Over the years, taken and the buyers of the oil, from 1979 to
the state has taken a portion of its royalty oil in present.
kind (RIK) and sold it to third parties. Tables 8A
43
TABLE 8A — STATE RIK SALE VOLUMES BY FIELD
MILLIONS OF BARRELS PER YEAR
1979 1980 1981 1982 1983 1984 1985 1986 1987
PRUDHOE BAY Charter (Alpetco) - 12.021 26.670 0.899 = - - - -
Mapco (North Pole) 0.447 5.976 8.808 9.632 11.724 13.093 13.261 13.168 14.095
Chevron = 0.882 0.860 = 3.964 6.734 6.820 6.772 7.251
Tesoro - 3.427 1.661 0.037 13.505 14.851 18.203 27.089 28.858
GVEA = 0.398 0.765 1.208 1.871 1.929 1.881 2.014
ARCO Products _ ~_ 1.848 = = = 7 - -
Oasis Petroleum 7 = 0.802 aa i 7 - - -
SOHIO 7 - 3.072 0.577 < - - - -
Shell (NP_& Priority) - - 4.007 0.184 - - - - -
Union (NP & Priority) - - 3.695 0.634 = = - - -
Chevron 4 i = om = = 7 5.254 1.406 =
Texaco 2 = = = = - = 10.030 2.343 - US Refining - - - - - - 2.865 0.937 -
TOTAL 0.447 22.307 51.822 12.728 30.401 36.548 58.362 53.598 52.217 KUPARUK Chevron = - - - - - 2.729 0.497 7
Union = = = = = = 1.479 0.372 ad US Oil & Refining - = - i - - 0.916 0.993 -
Petro Star = = = - i i - 0.083 1.012
Chevron - - 7 7 - = 7 0.132 1.612
TOTAL = = = = i = 5.123 2.077 2.624 COOK INLET
Tesoro 4.850 4.094 3.561 3.065 2.719 2.432 1.383 i -
Chinese Petroleum — = = = = 7 - = 0.615 TOTAL 4.850 «4.094 3.561 3.065 2.719 = 2.432 1.383 - 0.615
TABLE 8B — STATE RIK SALE VOLUMES BY SALE TYPE
MILLIONS OF BARRELS PER YEAR
1979 1980 1981 1982 1983 1984 1985 1986 1987
LONG TERM RIK VOLUMES — PRUDHOE BAY Charter (Alpetco) - 12.021 26.670 0.899 - = = = -
Mapco (North Pole) 0.447 5.976 8.808 9.632 11.724 13.093 13.261 13.168 14.095
Chevron i 0.882 0.860 3.964 6.734 6.820 6.772 7.251
Tesoro = 2.550 0.801 0.037 13.505 14.851 18.203 27.089 28.858
GVEA - = 0.398 0.765 1.208 1.871 1.929 1.881 2.014
TOTAL 0.447 21.429 37.537 11.332 30.401 36.548 40.213 48.911 52.217 LONG TERM RIK VOLUMES — KUPARUK Petro Star = - = = = 0.083 1.012 Chevron a = = - = = = 0.132 1.612
TOTAL = = = 0.215 2.624 LONG AND SHORT TERM RIK VOLUMES — cook INLET
Tesoro 4.850 4.094 3.561 3.065 2.719 2.432 1.383 - = Chinese Petroleum - - - - - - 7 - 0.615
TOTAL 4.850 4.094 3.561 3.065 2.719 2.432 1.383 = 0.615 1984 1 YEAR COMPETITIVE | RIK PURCHASERS - PRUDHOE BAY Chevron 4 = = 4.298 1.406 - Texaco 2 - oa - - - = 7.163 2.343 -
US Oil Ref i = i - as = 2.865 0.937 -
TOTAL — 14.326 4.687 - 1984 6 MONTH COMPETITIVE RIK PURCHASERS — PRUDHOE BAY Texaco 1 = — 2.867 - - Chevron 5 - = 7 - = 7 0.956 - - SOHIO - = - - - - 0.956 - - TOTAL = oo 4.779 - - 1984 6 MONTH COMPETITIVE PURCHASERS — — KUPARUK Chevron 6 - - - - 1.136 - - Chevron 7 = - = - = = 1.136 - - Union 2 = - > - Se - 1.136 - - Chevron 8 = = = - = = 0.458 0.497 -
US Oil & Ref - = - - ea - 0.916 0.993 -
Union 3 = = i i =~ - 0.343 0.372 -
TOTAL - - i - = - 5.123 1.862 - SHORT TERM RIK VOLUMES — PRUDHOE BAY Tesoro - 0.877 0.860 - - - - - - ARCO Products - = 1.848 = - - - - - Oasis Petroleum - - 0.802 - - - - - -
SOHIO = i 3.072 0.577 = = = — i Shell (NP_& Priority) - - 4.007 0.184 - - - - -
Union (NP & Priority) - - 3.695 0.634 - - - - -
TOTAL eT 0.877 14.284 1.395 - = i en
Revised 02/22/96
44
1988 1989 1990 1991 1992 1993 1994 1995 TOTAL PRUDHOE BAY ait Charter (Alpetco) - - - - - - - - 39.589
Mapco (North Pole) 13.815 12529 12.7385 11.183 6.285 9.086 11.812 12.680 180.330 Chevron 7.094 6.450 6.014 4.040 7 i — cS 56.882
Tesoro 28.601 25.685 20.480 15.336 14.412 9.814 10.312 13.704 245.977 GVEA 1982 1.785 1.670 1.671 0.802 - - - 17.975 ARCO Products = 7 = = a - 1.848 Oasis Petroleum = a — = a) om a 7 0.802 SOHIO = - - - - - - - 3.650 Shell (NP_& Priority) - = = = 2 = a a 4.191
Union (NP & Priority) - - =- a a sa ai 1 4.329
Chevron 4 - - = = = = = 6.660 Texaco 2 ad = = = a = = Zz 12.374 US Refining - - - - - - - 3.803
TOTAL 51.491 46.449 40.900 32.231 21.499 18.901 22.124 26.384 578.409 KUPARUK Chevron 7 = = - = — — = 3.225 Union = = 7 —_ — = = — 1.851 US Oil & Refining - - - = = = 1.909
Petro Star 1.080 1.065 1.041 1.103 0.191 — = a 5.574
Chevron 1.733 1.704 1.666 1.765 = — — = 8.611
TOTAL 2.812 2.769 2.707 2.868 0.191 om = 20.401 COOK INLET - 0.000 Tesoro st = Ea a — = oa = 22.104 Chinese Petroleum 0.800 1.274 0.567 0.331 a = a = 3.587
TOTAL 0.800 1.274 0.567 0.331 a = = ee 25.691
1988 1989 1990 1991 1992 1993 1994 1995 = TOTAL LONG TERM RIK VOLUMES — PRUDHOE BAY Charter (Alpetco) a oat oad = 7 39.589 Mapco (North Pole) 13815 12529 12735 11.183 6.285 9.086 11.812 12.68 180.330
Chevron 7.094 6.450 6.014 4.040 = a ca = 56.882
Tesoro 28.601 25.685 20.480 15.336 14.412 9.814 10.312 13.704 244.240
GVEA 1.982 1.785 1.670 1.671 0.802 = a ad 17.975
TOTAL 51.491 46.449 40.900 32.231 21.499 18.901 22.124 26.384 539.016 LONG TERM RIK VOLUMES — KUPARUK
Petro Star 1,080 1.065 1.041 1.103 0.191 a — oa 5.574
Chevron 1.733 1.704 1.666 1.765 m a — = 8.611
TOTAL 2.812 2.769 2.707 2.868 0.191 = a = 14.185 LONG AND SHORT TERM RIK VOLUMES — COOK INLET Tesoro = = = - 22.104 Chinese Petroleum 0. 800 al 274 0. 567 0. 331 a a7 — a 3.587
TOTAL 0.800 1.274 0.567 0.331 = ad = 25.691 1984 1 YEAR COMPETITIVE RIK PURCHASERS — PRUDHOE BAY _ Chevron 4 a 7 a 5.704 Texaco 2 - - - = - - - - 9.507 US Oil Ref - - - - - - - - 3.803 TOTAL = - - - 19.013 1984 6 MONTH COMPETITIVE RIK PURCHASERS — PRUDHOE BAY Texaco 1 = — 2.867 Chevron 5 — = — = = a a a 0.956
SOHIO = = = a — = = 0.956 TOTAL - - - = = 4.779 1984 6 MONTH COMPETITIVE PURCHASERS — KUPARUK Chevron 6 — = — - — = 1.136 Chevron 7 - = - - - - - = 1.136
Union 2 on a a = — a I 1.136 Chevron 8 a z as a = a — 0.954 US Oil & Ref - = - =- = = 7 = 1.909 Union 3 a r = a = a a at 0.716 | TOTAL - a 7 7 = = a 6.985 | SHORT TERM RIK VOLUMES — PRUDHOE BAY |
Tesoro = a a a = = - 1.737 | ARCO Products - - - - - - = - 1.848 | Oasis Petroleum = = a = 7 a = = 0.802
SOHIO = = a Cs a 7 7 = 3.650
Shell (NP_& Priority) = = = = - - - - 4.191 | Union (NP & Priority) - - - - - - - - 4.329 TOTAL = ce ce = oz ee ELLEN EN —___16.557
45
9 U.S. AND ALASKAN OIL PRODUCTION, IMPORTS
AND OIL AND GAS PRICES
TABLE 9 — U.S. AND ALASKAN OIL PRODUCTION, IMPORTS
AND OIL AND GAS PRICES
PRODUCTION AND IMPORTS: MILLIONS OF BARRELS PER YEAR
OIL PRICES: DOLLARS PER BARREL
GAS PRICES: CENTS PER THOUSAND CUBIC FEET
1947 1948 1949 1950 1951 1952 1953 1954 1955 1956 1957 1958 1959 1960 1961 1962
OIL PRODUCTION AND IMPORTS — enn
US. 1,857 2,020 1,841 1,973 2,247 2,289 2,357 2,315 2,484 2,617 2,616 2,449 2,574 2,574 2,621 2,676
Alaska 0 1 6 40
Imports 97 129 153 177 179 209 236 239 285 341 373 348 352 371 381 411
OIL PRICES
US. 1.93 26 254 251 253 253 268 2.78 277 279 3.03 3.01 29 288 2.89 29
Alaska 1.58 2.2 2.79 3.04
GAS PRICES
U.S. 6 6.5 6.3 6.5 7.3 78 9.2 10.1 104 108 113 119 129 14 15.1 155 Alaska 12.12 122 204 214
1963 1964 1965 1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978
OIL PRODUCTION AND IMPORTS
US. 2,752 2,786 2,848 3,027 3,215 3,329 3,371 3,517 3,453 3,455 3,360 3,202 3,056 2,976 3,009 3,178
Alaska nd 11 at 14 29 66 74 84 79 73 72 71 70 63 169 449
Impors 412 438 452 447 411 472 514 583 613 811 1,183 1,269 1,498 1,935 2,406 2,261
OIL PRICES
US. 289 288 286 288 292 294 3.09 318 339 339 389 674 7.56 815 857 9
Alaska 3.04 3.04 3.06 3.06 313 282 29 3.01 3.24 3.23 362 492 522 503 614 5.23
GAS PRICES
US. 158 154 156 15.7 16 164 16.7 17.1 182 186 216 30.4 44.5 58 79 «90.5
Alaska 24.7 276 248 248 25 253 259 246 147 147 149 17. 30.2 3989 40.2 52.1
1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993
OIL PRODUCTION AND IMPORTS
US. 3,121 3,146 3,128 3,156 3,171 3,249 3,274 3,168 3,047 2,979 2,778 2,684 2,707 2,625 2,499
Alaska 511 592 587 619 626 630 666 681 716 738 684 647 656 627
Imports 2,355 1,910 1,511 1,213 1,129 1,181 1,125 1,507 1,679 1,850 2,112 2,141 2,110 2,222 2,472
OIL PRICES
U.S. 12.6 216 318 285 262 259 241 125 154 126 15.7 20.0 165 160 14.2
Alaska 10.3 165 23.6 20.1 179 181 17.1 67 108 84 11.9 156 10.2 109
GAS PRICES
US. 118 159 198 246 259 266 251 194 167 169 169 171 164 186 197
AK 51.8 73.2 62 63 73 73 74 50 94 127 136 1388 146
Source: American Petroleum Institute, "Basic Petroleum Data Book," v.13, n.3, September 1994. Revised 02/23/95
47
10 COOK INLET GAS, VOLUME AND VALUE
Table 10 — Cook Inlet Gas Monthly Averages of
Produced Volume, Royalty Volume, and Value
July — December, 1995
Sold Royalty Value (MCF) (MCF) ($/MC
COOK INLET
Beluga 2,976,893 224,905 $1.23176
Cannery Loop 367,984 25,732 $1.64114
Granite Point 60,849 7,606 $1.29907
Ivan River 876,903 155,274 $1.45000
Kenai 830,437 17,181 $1.58412
Lewis River 6,791 849 $1.45000
Middle Ground Shoal 73,062 9,133 $1.44829
North Cook Inlet 4,675,631 584,454 $1.63355
Pretty Creek 22,206 3,174 $1.45000
South Middle Ground Shoal 755 95 $1.45000
Sterling 8,049 125 $1.38639
Stump Lake 17,704 4,384 $1.45000
Trading Bay 3,530,038 441,255 $1.41463
| TOTAL 13,447,302 1,474,165 $1.47074
48
APPENDIX A OIL AND GAS FIELD DATA
ALBERT KALOA (Gas) Location Cook Inlet, west side, onshore Operator CIRI Production suspended State of Alaska has no leases in this field
BADAMI Location North Slope, onshore Operator BP Production exploration underway
BEAVER CREEK (Oil and Gas) Location Cook Inlet, east side, onshore Operator Marathon Production began 1973 State of Alaska has no leases in this field
BELUGA RIVER (Gas) Location Cook Inlet, west side, onshore Operator Arco Production began 1968
BIRCH HILL (Gas) Location Cook Inlet, east side, onshore Operator Arco Production shut-in 1965 State of Alaska has no leases in this field
CANNERY LOOP (Gas) Location Cook Inlet, east side, onshore Operator Marathon Production began 1988
CASCADE (Oil) Location North Slope, onshore Operator BP Production development underway
EAST BARROW (Gas) Location —_North Slope, onshore, near Barrow Operator North Slope Borough Production began 1981 State of Alaska has no leases in this field.
EAST UMIAT (Gas)
Location lorth Slope, onshore Operator UMC Petroleum Production shut-in, no production State of Alaska has no leases in this field.
ENDICOTT (Oil and Gas) Location —_ North Slope, offshore Operator BP Production began 1987
FALLS CREEK (Gas) Location Cook Inlet, east side, onshore Operator Arco
Production shut-in 1961
GRANITE POINT (Oil and Gas) Location Cook Inlet, west side, offshore Operator Unocal Production began 1967 Platforms Anna, Bruce, Granite Point
GWYDYR BAY (Oil) Location rth Slope, onshore and offshore Operator none Production unit terminated
HEMI SPRINGS og | Location North Slope, onshore Operator none Production unit terminated
IVAN RIVER ote Location Cook Inlet, west side, onshore Operator Unocal Production began 1990
KATALLA (Oil) Location Gulf of Alaska Production abandoned 1933 State of Alaska has no leases in this field
KAVIK (Gas) Location —_ North Slope, onshore Operator Arco Production shut-in State of Alaska has no leases in this field
KEMIK (Gas) Location North Slope, onshore Operator BP Production shut-in 1972 State of Alaska has no leases in this field
KENAI (Gas)
Location Cook Inlet, east side, onshore Operator Marathon Production began 1961
KUPARUK (Oil and Gas) Location North Slope, onshore Operator Arco Production began 1981
KUUKPIK (Oil and Gas) Location North Slope, onshore and offshore Operator Arco Production exploration underway
LEWIS RIVER (Gas) Location ‘00k Inlet, west side, onshore Operator Unocal Production began 1984
LISBURNE (Oil and Gas)
Location North Slope, onshore Operator Arco Production began 1981
McARTHUR RIVER (Oil and Gas) Location Cook Inlet, west side, offshore Operator Unocal Production began 1967
Platforms Grayling, King Salmon, Dolly Varden, Steelhead
49
MIDDLE GROUND SHOAL (Oil and Gas)
Location Cook Inlet, east side, offshore Operator AandC platforms: Shell Baker and Dillon platforms: Unocal Production began 1967 Platforms A, Baker, C, Dillon
MILNE POINT (Oil and Gas)
Location lorth Slope, onshore Operator BP Production began 1985, suspended 1/88—2/89, resumed 2/89
MOQUAWKIE (Gas) Location ‘ook Inlet, west side, onshore Operator IRI Production shut-in 1979 State of Alaska has no leases in this field.
NIAKUK (Oil) Location —_North Slope, offshore, Prudhoe Bay Unit
Operator Arco Production began 1994
NIAKUK 27 (Oil and Gas)
Location North Slope, offshore, within Prudhoe Bay Unit Operator Arco Production began 1995
NICOLAI CREEK (Gas) Location Cook Inlet, west side, onshore and offshore Operator Unocal Production began 1968, now shut-in
NORTH COOK INLET (Gas) Location Cook Inlet, mid channel, offshore Operator Phillips Production began 1970 Platform Phillips A
NORTH FORK (Gas)
Location Cook Inlet, east side, onshore Operator Unocal Production shut—in 1965
NORTH MIDDLE GROUND SHOAL (Gas) Location Cook Inlet, offshore Operator Shell and Unocal, one well each
Production abandoned
NORTH PRUDHOE BAY (Oil and Gas) Location North Slope, onshore, Prudhoe Bay Unit Operator Arco Production began 1993
NORTH STAR (OIL and GAS) Location lorth Slope, offshore Operator BP Production drilling islands abandoned
POINT McINTYRE (Oil)
Location —_North Slope, offshore, Prudhoe Bay Unit Operator Arco Production began 1993
PRUDHOE BAY (Oil and Gas) Location North Slope, onshore Operator Western Operating Area: BP Eastern Operating Area: Arco Production began 1977
REDOUBT SHOAL (Oil) Location Cook Inlet, west side, offshore Operator Danco Production abandoned SAG DELTA (Oil) Location North Slope, offshore, Duck Island Unit Operator BP Production began 1989
SAG RIVER (Oil and Gas) Location —_ North Slope, onshore, within Milne Pt. unit Operator BP Production began 1994
SCHRADER BLUFF (Oil) Location North Slope, onshore, Milne Point Unit Operator BP Production began 1991
SOUTH BARROW (Gas) Location _—_North Slope, onshore, near Barrow Operator North Slope Borough Production began 1950 State of Alaska has no leases in this field.
STERLING (Gas)
Location Cook Inlet, east side, onshore Operator Marathon Production began 1962, shut—in 1986, resumed 1994
STUMP LAKE (Gas) Location ‘ook Inlet, west side, onshore
Operator Unocal Production began 1990
SUNFISH (Oil) Location Cook Inlet, offshore Operator Arco and Phillips Production Activities suspended
SWANSON RIVER (Oil and Gas) Location Cook Inlet, east side, onshore Operator Unocal Production began 1958 State of Alaska has no leases in this field
THETIS ISLAND (Oil and Gas) Location North Slope, offshore
Operator Exxon Production unit terminated
TRADING BAY (Oil and Gas) Location Cook Inlet, west side, offshore Operator Unocal: Monopod; Marathon: Spur and Spark Production began 1967 Platforms Monopod; Spark and Spur shut-in
UMIAT (Oil) Location North Slope, onshore Operator US Dpt. of Interior POINT THOMSON and FLAXMAN ISLAND (Oil and Gas) Production shut-in Location _North Slope, onshore and offshore Operator Exxon Production shut-in
PRETTY CREEK (Gas) Location Cook Inlet, west side, onshore Operator Unocal Production began 1986
State of Alaska has no leases in this field
WALAKPA (Gas) Location North Slope, onshore, near Barrow Operator North Slope Borough Production began 1992 State of Alaska has no leases in this field
50
WEST BEACH (Oil and Gas) WEST McARTHUR RIVER (Oil and Gas) Location North Slope, onshore, Prudhoe Bay Unit Location Cook Inlet, west side, onshore Operator Arco Operator Stewart Petroleum
Production began 1993 Production began 1993
WEST FORELANDS (Gas) WEST SAK (oi Location Cook Inlet, west side, onshore and offshore Location lorth Slope, onshore Operator Phillips Operator Arco Production shut-in 1962 Production Pilot study 1984—1986, now shut—in
WEST FORK (Gas) Location Cook Inlet, east side, onshore Operator IRI Production began 1992
51
APPENDIX B_ LEASE DATA
NOTE: This table lists only those state leases that have ever produced oil or gas as of
September 29, 1995.
Lease/Tract Participating Area % Royalty % NPSL % Owner Ownership %
Oil Gas
BELUGA
17592 = 8.0024000 12.5 ARCO 33.3333333
CHEVRON 33.3333333 SHELL 33.3333334 17599 - 5.0210000 12.5 ARCO 33.3333333
CHEVRON 33.3333333
SHELL 33.3333334 17658 cd 12.7251000 12.5 ARCO 33.3333333
CHEVRON 33.3333333 SHELL 33.3333334 21126 = 0.7855000 12.5 ARCO 33.3333333
CHEVRON 33.3333333 SHELL 33.3333334 21127 = 9.4019000 12.5 ARCO 33.3333333
CHEVRON 33.3333333 SHELL 33.3333334
21128 = 14.5560000 12.5 ARCO 33.3333333 CHEVRON 33.3333333
SHELL 33.3333334 21129 = 0.5803000 12.5 ARCO. 33.3333333
CHEVRON 33.3333333 SHELL 33.3333334 58815 28 = 0.0162000 12.5 ARCO 33.3333333
CHEVRON 33.3333333 SHELL 33.3333334 58820 29 = 1.5889000 12.5 ARCO 33.3333333
CHEVRON 33.3333333 SHELL 33.3333334 58831 30 7 7.7629000 12.5 ARCO 33.3333333
CHEVRON 33.3333333
_ SHELL 33.3333334
CANNERY LOOP BELUGA
002397 5A i 5.1844565 12.5 CIRI 6.2500000 MARATHON _ 93.7500000
324602 4A = 16.3008805 12.5 CIRI 9.3750000 MARATHON — 90.6250000 324604 5B = 0.1470714 12.5 CIRI 70.0000000
UNION 30.0000000 359153 7 = 6.3585128 12.5 CIRI 33.3330000 MARATHON _ 66.6670000
364395 7C = 1.8936392 12.5 CIRI 33.3330000 MARATHON _ 66.6670000
365454 12 = 0.4381660 16.7 CIRI 33.3330000 MARATHON _ 66.6670000
373302 14 i 3.9605254 12.5 CIRI 100.0000000 373302 19 = 0.1905070 12.5 CIRI 100.0000000
373302 20 ~ 0.4271166 12:5 CIRI 100.0000000
TYONEK DEEP 002397 5A = 5.4125000 12.5 CIRI 6.2500000 MARATHON — 50.0000000 UNION 43.7500000 324602 4A = 29.2068900 125 CIRI 9.3750000 MARATHON — 25.0000000 UNION 65.6250000 359153 7 i 13.5137500 12.5 CIRI 33.3330000 MARATHON _— 33.3330000
UNION 33.3340000 UPPER TYONEK
53
54
002397 5A 7.3449200 7.3449200 12.5 CIRI 6.2500000 MARATHON — 50.0000000 UNION 43.7500000 324602 4A 29.8726200 29.8726200 12.5 CIRI 9.3750000 MARATHON —_ 25.0000000 UNION 65.6250000 3591537 13.5705700 13.5705700 12.5 CIRI 33.3330000 MARATHON _ 33.3330000 UNION 33.3340000 36545412 1.3091500 — 1.8091500 16.7 CIRI 33.3330000 MARATHON 33.3330000 UNION 33.3340000 OTHER 47.9027356 OTHER 100
| DUCK ISLAND UNIT ENDICOTT 34633 13 26.7609000 26.7609000 12.5 BP 100.0000000 34634 12 0.0675000 — 0.0675000 12.5 BP 100.0000000 34636 14 5.2911000 —5.2911000 12.5 BP 4100.0000000 475021 22.3357000 223357000 12.5 AMOCO 25.0000000 EXXON 50.0000000 UNION 25.0000000 475032 19.6233000 19.6233000 12.5 AMOCO 25,0000000 EXXON 50.0000000 UNION 25.0000000 475043 0.0036000 — 0.0036000 12.5 EXXON 100.0000000 47505 4 0.0140000 — 0.0140000 12.5 EXXON 400.0000000 47506 5 0.0084000 — 0,0084000 12.5 AMOCO 50.0000000 UNION 50.0000000 312828 15 25.8252000 25.8252000 20.0 79.5935000 BP 95.5000000 CIR 2.5000000 DOYON 0.5000000 NANA 1.5000000 312834 16 0.0703000 — 0.0703000 20.0 48.8703100 ARCO 33.3400000 EXXON 33.3300000 UNION 33.3300000 SAG DELTA 34633 13 6.3656000 —_ 6.6356000 12.5 BP 4100.0000000 312828 15 93.3644000 93.3644000 20.0 BP 95.5000000 CIRI 2.5000000 1d DOYON 0.5000000 |
GRANITE POINT GRANITE POINT 4 18761 100.0000000 100.0000000 12.5 MOBIL 75.0000000 GRANITE POINT 2 UNION 25.0000000 17586 100.0000000 100.0000000 12.5 UNION 100.0000000 17587 4100.0000000 100.0000000 12.5 UNION 100.0000000 18742 _ 100,0000000_100.0000000 12.5 UNION 100.0000000
IVAN RIVER 17600 1 - 6.5064900 12.5 UNION 100.0000000 17600 1A - 5.8516900 12.5 UNION 400.0000000 302282 6 - 3.4922500 12.5 UNION 100.0000000 302284 5 - 18.7468100 12.5 UNION 100.0000000 326058 7 - 10.4767400 62.2 UNION 4100.0000000 32930 2 - 25.8426100 12.5 UNION 100.0000000 32930 2A - 7.9348200 12.5 UNION 100.0000000 32930 2B - 13.1103200 125 UNION 100.0000000 336373 - 8.4686900 125 UNION 400.0000000 33727 40 = 5.4212700 125 —————CdUNION 100.0000000
KENAI 588 175 - 6.7607000 12.5 MARATHON —_50.0000000 UNION 50.0000000 593 176 - 7.4430000 12.5 MARATHON —_50.0000000 UNION 50.0000000 594 177 - 0.6717000 12.5 MARATHON —_50.0000000 UNION 50.0000000 2411 178 - 0.7608000 12.5 MARATHON —_ 50.0000000 UNION 50.0000000
308223 166 Ti 0.0083000 12.5 MARATHON — 50.0000000 UNION 50.0000000 324598 014 - 0.9065000 12.5 MARATHON — 50.0000000
UNION 50.0000000
KUPARUK RIVER 25512 2 1.4735860 1.4735860 12.5 ARCO 50.0000000
BP 50.0000000 25513 3 1.5236360 1.5264080 12.5 ARCO 50.0000000
BP 50.0000000 25519 4 1.9116500 1.1938260 12.5 ARCO 50.0000000
BP 50.0000000 25520. 5 1.4607080 1.4633820 12.5 ARCO 50.0000000 BP 50.0000000 25521 6 1.3352840 1.3377160 12.5 ARCO 50.0000000
BP 50.0000000 25522 1 0.4698620 0.4707200 12.5 ARCO 50.0000000
BP 50.0000000 25523 7 1.2821780 1.2845220 12.5 ARCO 50.0000000
BP 50.0000000 25524 8 0.6061440 0.6073260 12.5 ARCO 50.0000000
BP 50.0000000 25531 11 1.3929870 =1.4118300 12.5 ARCO 33.3300000
BP 33.3400000 UNION 33.3300000 25532 10 0.3695580 0.3745770 12.5 ARCO 33.3300000
BP 33.3400000
UNION 33.3300000 25546 25 0.0096480 0.0097770 12.5 ARCO 33.3300000
BP 33.3400000 UNION 33.3300000
25547 24 1.1384040 1.1537730 12.5 ARCO 33.3300000 BP 33.3400000
UNION 33.3300000 25548 29 0.6795600 0.6886410 125 ARCO 33.3300000
BP 33.3400000 UNION 33.3300000 25549 28 0.0217470 0.0220380 125 ARCO 33.3300000 BP 33.3400000
UNION 33.3300000 25568 45 0.5314530 0.5386140 125 ARCO 33.3300000
BP 33.3400000 UNION 33.3300000 25569 44 1.3048920 1.3224420 12.5 ARCO 33.3300000
BP 33.3400000 UNION 33.3300000 25570 50 2.3393670 2.3709780 12.5 ARCO 33.3300000
BP 33.3400000
UNION 33.3300000 25571 49 1.0792860 1.1120730 12.5 ARCO 33.3300000
BP 33.3400000 UNION 33.3300000 25585 69 0.1280070 0.1297290 12.5 ARCO 33.3300000
BP 33.3400000 UNION 33.3300000
25586 68 1.2058890 1.2221160 12.5 ARCO 33.3300000 BP 33.3400000
UNION 33.3300000 25587 67 1.4199780 1.4390430 12.5 ARCO 33.3300000 BP 33.3400000
UNION 33.3300000 25588 76 1.0910610 1.1056650 12.5 ARCO 33.3300000 BP 33.3400000 UNION 33.3300000 25589 75 0.9073680 0.9195330 125 ARCO 33.3300000 BP 33.3400000 UNION 33.3300000 25590 74 0.3004800 = 0.3045000 12.5 ARCO 33.3300000 BP 33.3400000 UNION 33.3300000
25603 90 0.0594180 0.0602130 12.5 ARCO 33.3300000
55
25604
25605
25607
25608
25627
25628
25629
25630
25631
25632
25633
25634
25635
25636
25637
25638 25639
25640
25641
25642
25643
25644
25645
25646
25647 25648
25649 25650
25651 25652
25653
25654
25655
25656
25657
25658
25659
89
88
95
16
15
14
13
12
23
22
21
20
19
18
35
34
33
32
31
43
42
41
40 39 38 56 55 54
53
52
51
66
65
63
0.3232440
0.3342240
0.2166180
0.1778400
0.1184060
0.8091100
1.4903880
1.6485780
1.2009180
2.7594980
1.9153360
1.7157940
1.6856780
0.3644340
0.0000080
0.2902760
1.1359980
2.9568520
3.1257620
3.5743240
3.0342260
2.8728060
4.3588520
3.8375640
2.4399560
1.5166970
1.1124560
1.3828370
2.3755260
2.8477940
2.8243460
2.2380640
2.9259080
1.7669080
1.9730720
1.7151400
2.0741840
0.3275640
0.3386940
0.2166180
0.1778400
0.1186420
0.8106060
1.4931320
1.6516080
1.2031160
2.7649440
1.9189380
1.7190340
1.6889100
0.3651640
0.0000080
0.2915260 1.1407940 2.9628780
3.1319620
3.5814540
3.0403020
2.8784420
4.3676360
3.8452920
2.4501690
15230730 1.1172230
1,3887620 2.3854910 2.8533180
2.8298240
2.2423640
2.9315920
1.7701820
1.9766800
1.7182860
2.0512600
56
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
125
12.5
UNION ARCO
UNION ARCO
UNION ARCO
UNION ARCO
UNION ARCO
ARCO
ARCO
ARCO
ARCO
ARCO
ARCO
ARCO
ARCO
ARCO
ARCO
ARCO ARCO ARCO
ARCO
ARCO
ARCO
ARCO
ARCO
ARCO
ARCO ARCO ARCO ARCO ARCO ARCO
ARCO
ARCO
ARCO
ARCO
ARCO
ARCO
ARCO
33.3400000
33.3300000 33.3300000
33.3400000 33.3300000
33.3300000 33.3400000 33.3300000 50.0000000
33.3333330 16.6666670 50.0000000
33.3333330 16.6666670 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000
100.0000000 100.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000
100.0000000 100.0000000
100.0000000 100.0000000 100.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000
50.0000000 50.0000000
50.0000000
50.0000000 50.0000000
50.0000000
BP 50.0000000
25660 62 1.6401410 = 1.6471110 12.5 ARCO 100.0000000
25661 61 0.9257080 0.9296650 12.5 ARCO 100.0000000
25662 82 0.0341340 0.0341360 12.5 ARCO 50.0000000 EXXON 50.0000000
25663 81 0.6849940 0.6877920 12.5 ARCO 100.0000000
25664 80 1.1201700 1.1249040 12.5 ARCO 100.0000000
25665 79 0.8569900 0.8587160 12.5 ARCO 50.0000000 BP 50.0000000
25666 78 0.6524580 0.6536860 12.5 ARCO 50.0000000 BP 50.0000000
25667 77 1.1007180 = 1.1027280 12.5 ARCO 50.0000000 BP 50.0000000
25668 87 0.1838680 0.1842180 12.5 ARCO 50.0000000 BP 50,0000000
25670 85 0.1036620 0.1036620 12.5 ARCO 50.0000000 EXXON 50.0000000
25671 84 0.1425000 0.1424920 12.5 ARCO 50.0000000 EXXON 50.0000000
28242 37 0.1226720 0.1226760 12.5 ARCO 50.0000000 BP 50.0000000
28243 «57 0.5124000 0.5124000 12.5 ARCO 32.9672400 BP. 17.0327600
MOBIL 50.0000000
28244 58 0.0316320 0.0316340 125 ARCO 50.0000000 EXXON 50.0000000
28248 60 0.1377010 0.1382940 12.5 ARCO 100.0000000
355023 122 0.5238680 0.5259540 12.5 30.0000000 ARCO 100.0000000 355024 123 0.0720740 0.0723610 12.5 30.0000000 ARCO 100.0000000 355030 124 0.0007270 0.0007300 12.5 30.0000000 ARCO 100.0000000
355032 125 0.1747880 0.1755130 12.5 30.0000000 ARCO 100.0000000 355501 126 0.0235130 0.0236150 12.5 ARCO 100.0000000
373301 122 0.2854090 0.2859290 12.5 ARCO 59.2286800 BP 40.7713200 47449 36 0.2172000 0.2172000 125 CHEVRON 50.0000000
I i i MOBIL 50.0000000
LEWIS RIVER PARTICIPATING AREA 1
58798 a7 16.6670000 12.5 LPARTNER 100.0000000 58801 = 61.1110000 12.5 LPARTNER 100.0000000 58802 = 22.2220000 12.5 LPARTNER 100.0000000
PARTICIPATING AREA 2 58798 = 76.1905000 12.5 LPARTNER 100.0000000 58801 i 14.2857000 12.5 LPARTNER = 100.0000000
58802 = 9.5238000 12.5 LPARTNER __100.0000000
McARTHUR RIVER HEMLOCK OIL POOL PARTICIPATING AREA
17579 12.9480000 12.9480000 12.5 UNOCAL 100.0000000 17594 28.6480000 28.6480000 12.5 MARATHON — 50.0000000 UNION 50.0000000
17602 3.7000000 =3.7000000 12.5 UNOCAL 100.0000000
18716 2.6730000 2.6730000 12.5 UNOCAL 100.0000000 18729 17.8330000 17.8330000 12.5 MARATHON _ 50.0000000 UNION 50.0000000
18730 16.6480000 16.6480000 12.5 MARATHON _ 50.0000000 UNION 50.0000000 18758 2.7750000 = 2.7750000 12.5 UNOCAL 100.0000000
18772 9.2490000 9.2490000 12.5 UNOCAL 100.0000000 18777 4.6010000 4.6010000 12.5 UNOCAL 100.0000000
21068 0.9250000 0.9250000 12.5 UNOCAL 100.0000000
HEMLOCK K-26 WELL TRACT OPERATION
17579 12.9480000 12.9480000 12.5 UNION 100.0000000
17594 28.6480000 28.6480000 12.5 UNION 100.0000000
17602 3.7000000 = 3.7000000 12.5 UNION 100.0000000
18716 2.6730000 2.6730000 12.5 UNION 100.0000000
18729 17.8330000 17.8330000 12.5 UNION 100.0000000
18730 16.6480000 16.6480000 12.5 UNION 100.0000000
57
18758 2.7750000 2.750000 12.5 UNION 100,0000000 18772 9.2490000 —_9.2490000 12.5 UNION 100,0000000 18777 4.6010000 — 4,.6010000 12.5 UNION 100,0000000 21068 0.9250000 — 0.9250000 12.5 UNION 100.0000000 MIDDLE KENAI 17594 26.6700000 26.6700000 12.5 MARATHON — 51.0000000 UNION 49.0000000 18729 34.8100000 34,8100000 12.5 MARATHON __ 51,0000000 UNION 49.0000000 18730 32,5900000 32.5900000 12.5 MARATHON — 51.0000000 UNION 49.0000000 18772 5.9300000 —_5.9300000 12.5 MARATHON — 51.0000000 UNION 49.0000000 GRAYLING 17594 3 - 38.5542200 12.5 MARATHON — 50.0000000 UNION 50.0000000 18729 10 - 27.7108400 12.5 MARATHON — 50.0000000 UNION 50.0000000 18730 11 - 33.7349400 12.5 MARATHON —_ 50.0000000 UNION 50.0000000 STEELHEAD JURASSIC 18730 11 100.0000000 100.0000000 12.5 MARATHON — 50.0000000 UNION 50.0000000 WEST FORELAND 17594 30.2500000 30.2500000 12.5 MARATHON — 51.0000000 UNION 49.0000000 18729 29.4100000 29.4100000 12.5 MARATHON —_51.0000000 UNION 49.0000000 18730 33.6200000 33,6200000 12.5 MARATHON — 51.0000000 UNION 49.0000000 18772 6.7200000 — 6.7200000 12.5 MARATHON — 51.0000000 - UNION 49.0000000
MIDDLE GROUND SHOAL MIDDLE GROUND SHOAL 1 17595 100.0000000 100.0000000 12.5 UNION 100.0000000 MIDDLE GROUND SHOAL 2 18754 100.0000000 100.0000000 12.5 SHELL 100.0000000 MIDDLE GROUND SHOAL 3 18756 100.0000000 100.0000000 12.5 SHELL 100.0000000 SOUTH MIDDLE GROUND SHOAL UNIT 18744 1 6.8965520 6.8965520 12.5 UNION 100.0000000 18746 _ 93.1034480 93.1034480 12.5 __UNION 100.0000000
MILNE POINT KUPARUK PARTICIPATING AREA 25509 10 14.6741200 14.6741200 12.5 BPXA 26.8100000 BPXO 64.3800000 OXY 8.8100000 25515 12 0.0244000 0.0244000 12.5 BPXA 26.8100000 BPXO 64.3800000 OXY 8.8100000 25516 4 1.6815000 —1.6815000 12.5 BPXA 26.8100000 BPXO 64.3800000 OXY 8.8100000 25518 9 0.7905300 —0.7905300 12.5 BPXA 26.8100000 BPXO 64.3800000 OXY 8.8100000 28231 8 3.5356800 3.5356800 12.5 BPXA 26.8100000 BPXO 64.3800000 OXY 8.8100000 315848 4A 0.1194100 0.1194100 12.5 BPXA 26.8100000 BPXO 64.3800000 OXY 8.8100000 355017 15 10.0328700 10.0328700 125 BPXA 26.8100000 BPXO 64.3800000 OXY 8.8100000 355018 16 13.3765600 13.3765600 125 BPXA 26.8100000
58
474383, 2 5.3246700 5.3246700
47433 2A 0.5144200 0.5144200 47434 3 23.8137600 23.8137600
47434 3A 2.3006800 2.3006800 47437 5 16.9686000 16.9686000
47437 5A 1.6393600 1.6393600
47438 6 4.7450200 4.7450200
47438 6A 0.4584200 0.4584200
SCHRADER BLUFF PARTICIPATING AREA 25509 10 1.0053900 1.0053900
25514 11 4.9181500 4.9181500
25515 12 10.3360400 10.3360400
25516 4 6.3159600 6.3159600
25518 9 19.0431900 19.0431900
25906 14 25.6086200 25.6086200
28231 8 5.0879600 5.0879600
315848 4A 6.3159600 6.3159600
47432 1 0.0090363 0.0090363
47432 1A 0.0008737 0.0008737
47433, 2 1.3448800 1.3448800
47433 2A 0.1184839 0.1184839 47434 3 3.2386800 3.2386800
47434 3A 0.2853277 = 0.2853277 47437 5 13.3041900 13.3041900
47437 5A 1.1720991 1.1720991 47438 6 3.4210700 = 3.4210700
47438 6A 0.3013963 0.3013963
E-—9 TRACT OPERATION
28231 8 100.0000000 100.0000000
E-—13 TRACT OPERATION
25516 4 5.2631600 5.2631600
47437 5 86.3905200 86.3905200
47437 SA 8.3463200 8.3463200
E-—22 TRACT OPERATION
28231 8 100.0000000 100.0000000
59
20.0
12.5 20.0
12.5
20.0
12.5
20.0
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
20.0
12.5
20.0
12.5 20.0
12.5 20.0
12.5
20.0
12.5
12.5
12.5
12.5
12.5
12.5
BPXO
OXY BPXA BPXO OXY BPXA BPXO OXY BPXA BPXO OXY BPXA BPXO OXY
BPXA BPXO
OXY BPXA BPXO OXY BPXA BPXO OXY BPXA BPXO OXY BPXA BPXO OXY BPXA BPXO OXY BPXA BPXO OXY BPXA BPXO OXY BPXA BPXO OXY BPXA BPXO OXY BPXA BPXO OXY BPXA BPXO OXY BPXA BPXO OXY
BPXA
BPXO
OXY
BPXA
BPXO
OXY
BPXA
BPXO
OXY
BPXA
BPXO
64.3800000
8.8100000 26.8100030 73.1899970
100.0000000 26.8100030
73.1899970 100.0000000
26.8100030 73.1899970
100.0000000 26.8100030
73.1899970 100.0000000
26.8100000 64.3800000 8.8100000
26.8100000 64.3800000 8.8100000
26.8100000 64.3800000 8.8100000
26.8100000 64.3800000
8.8100000 26.8100000
64.3800000 8.8100000
26.8100000 64.3800000
8.8100000 26.8100000 64.3800000 8.8100000
26.8100000 64.3800000 8.8100000
29.4001535 70.5998465
100.0000000 29.4001535
70.5998465 100.0000000
29.4001535 70.5998465 100.0000000
29.4001535 70.5998465 100.0000000
29.4001535 70.5998465
100.0000000
26.8100000
64.3800000
8.8100000
26.8100000
64.3800000
8.8100000
29.4002000
70.5998000
100.0000000
26.8100000
64.3800000
J-—6 TRACT OPERATION
315848 4A
J—10 TRACT OPERATION
25906 14
L—12 TRACT OPERATION
25509 10 14.6741200
25515 12 0.0244000
25516 4 1.6815000
25518 9 0.7905300
28231 8 3.5356800
315848 4A 0.1194100
355017 15 10.0328700
47433 2 5.3246700
47433 2A 0.5142200
47434 3 23.8137600
47434 3A 2.3006800
47437 5 16.9686000
47437 5A 1.6393600
47438 6 4.7450200
47438 6A 0.4584200
L-—13 TRACT OPERATION
25509 10 19.1591700
25515 12 0.0318600
25516 4 2.1954400
25518 9 1.0321500
28231 8 4.6163400
315848 4A 0.1559100
47433 2 6.7060846
47433 2A 0.9176854
47434 3 29.9919507
47434 3A 4.1042093
47437 5 21.3708886
100.0000000 100.0000000
100.0000000 100.0000000
14.6741200
0.0244000
1.6815000
0.7905300
3.5356800
0.1194100
10.0328700
5.3246700
0.5142200
23.8137600
2.3006800
16.9686000
1.6393600
4.7450200
0.4584200
19.1591700
0.0318600
2.1954400
1.0321500
4.6163400
0.1559100
6.7060846
0.9176854
29.9919507
4.1042093
21.3708886
60
12.5
12.5
125
12.5
125
125
12.5
12.5
12.5
20.0
12.5
20.0
12.5
20.0
12.5
20.0
12.5
12.5
12.5
12.5
12.5
12.5
12.5
20.0
12.5
20.0
12.5
20.0
OXY
BPXA
BPXO
OXY
BPXA
BPXO
OXY
BPXO
OXY
BPXO
OXY
BPXO
OXY
BPXO
OXY
BPXO
OXY
BPXO
OXY
BPXO
OXY
BPXO
OXY
BPXO
OXY
BPXO
OXY
BPXO
OXY
BPXA
BPXO
OXY
BPXA
BPXO
OXY
BPXA
BPXO
OXY
BPXA
BPXO
OXY
BPXA
BPXO
OXY
BPXA
BPXO
OXY
BPXA
BPXO
OXY
BPXA
BPXO
OXY
BPXA
8.8100000
26.8100000
64.3800000
8.8100000
26.8100000
64.3800000
8.8100000
91.1900000
8.8100000
91.1900000
8.8100000
91.1900000
8.8100000
91.1900000
8.8100000
91.1900000
8.8100000
91.1900000
8.8100000
91.1900000
8.8100000
100.0000000
100.0000000
100.0000000
100.0000000
100.0000000
100.0000000
100.0000000
100.0000000
23.5828400
64.3800000
12.0371600
23.5828400
64.3800000
12.0371600
23.5828400
64.3800000
12.0371600
23.5828400
64.3800000
12.0371600
23.5828400
64.3800000
12.0371600
23.5828400
64.3800000
12.0371600
26.8100030
73.1899970
100.0000000
26.8100030
73.1899970
100.0000000
26.8100030
BPXO 73.1899970 47437 5A 29244714 2.9244714 125 Oxy 100.0000000 47438 «6 59760546 5.9760546 20.0 BPXA 26.8100030 BPXO 73.1899970 47438 6A 0.8177854 _0.8177854 12.5 OXY 100.0000000
NORTH TRADING BAY 17597 50.0000000 50.0000000 12.5 MARATHON —_50.0000000 UNION 50.0000000 18776 28.5700000 28.5700000 12.5 MARATHON — 100.0000000 35431 21.4300000 _ 21.4300000 12.5 ___ MARATHON _ 100.0000000
NORTH COOK INLET 175892 - 44.7324000 12.5 PHILLIPS — 100.0000000 17590 3 - 6.5430000 125 PHILLIPS 100.0000000 18740 7 - 8.1787000 125 PHILLIPS 100.0000000 18741 8 - 6.5429000 125 PHILLIPS — 100.0000000 3783111 - 34,0030000 125 PHILLIPS __100.0000000
NORTH FORELAND 17589 100.0000000 100.0000000 125 ARCO 60.0000000 PHILLIPS 40.0000000
PRETTY CREEK 58810 2 - 23.8984800 12.5 UNION 100.0000000 58813 4 - 20.8695700 125 UNION 100.0000000 58814. 5 - 10.4347800 12.5 UNION 400.0000000 63047 10 - 6.0869600 16.7 UNION 4100.0000000 63048 11 - 27.8260800 16.7 UNION 100.0000000 63049 12 - 10.4347800 16.7 UNION 100.0000000 Other 0.4493500 UNION 400.0000000
PRUDHOE BAY NIAKUK PARTICIPATING AREA 34625 4 5,0700000 — 5.0700000 12.5 BPX 100.0000000 34630 31 40.5700000 40.5700000 125 BPX 100.0000000 34634 33 5.4600000 — 5.4600000 125 BPX 100.0000000 34635 32 — 48.9000000 48.9000000 125 BPX 100.0000000 NIAKUK WELL NK27 TRACT OPERATION 34629 30 — 100.0000000 100.0000000 12.5 ARCO 50.0000000 EXXON 50.0000000 OIL RIM PARTICIPATING AREA 25637 16 0.0046309 —_0.0046309 12.5 ARCO 50.0000000 BP 50.0000000 28238 19 0.0163822 — 0.0163822 12.5 ARCO 50.0000000 EXXON 50.0000000 28239 18 0.0614364 0.061464 12.5 ARCO 50.0000000 EXXON 50.0000000 28240 50 0.0913318 — 0.0913318 125 ARCO 50.0000000 EXXON 50.0000000 28241 51 0.0486990 —_ 0.0486990 125 MOBIL 50.0000000 PHILLIPS 50.0000000 28244 52 0.0000124 — 0.0000124 125 ARCO 50.0000000 EXXON 50.0000000 28245 53 0.1486696 0.1486696 12.5 ARCO 50.0000000 EXXON 50.0000000 28246 82 0.0007026 + 0,0007026 12.5 ARCO 50.0000000 EXXON 50.0000000 28257 22 1.7767068 1.767068 12.5 MOBIL 50.0000000 PHILLIPS 50.0000000 28258 21 0.4599204 —0.4599204 12.5 ARCO 50.0000000 EXXON 50.0000000 28259 20 0.0076616 — 0.0076616 12.5 ARCO 50.0000000 EXXON 50.0000000 28260 47 1.4815529 1.4815529 125 BP 4100.0000000 28261 48 0.0888936 0.088936 125 MOBIL 50.0000000 PHILLIPS 50.0000000 28262 54 0.2968897 _0.2968897 12.5 CHEVRON —_100.0000000
61
28262
28263
28263
28264
28265
28275
28276
28277 28278
28279 28280 28281
28282
28283 28284
28285 28286 28287 28288
28289
28290
28299
28300
28302
28303
28304
28305 28306
28307
28308
28309
28310 28311
28312 28313
28314
28315 28316
28316
28320 28321
28322
28323
28324
54A
55
55A
79
112
113
105
26
27
41
42
61
62
73
74
75
89 8B
102
101 O7A
107 2 88 65
70
0.0772452
0.1338160
0.2071833
0.1174944
0.0364292
0.0133022
0.0000864
0.8421396
1.0400165 1.2989359
3.8981682 3.3705436
3.0429668 1.5634829 3.3026290
3.9964449 2.6691922
1.2578240 0.3601455
0.1312435
0.0024590
0.9307902
1.0365258
0.3106250
1.9447402
3.2449752
3.6765194
2.9343182
1.8596860
3.9394274
3.8650657 3.9334322
3.6619111 2.8963363
1.5538656
0.4588814
1.2192336 0.0565330
0.0088125
0.3566616
1.1125780
1.0995790
0.7714806
2.0837850
0.0772452
0.1338160
0.2071833
0.1174944
0.0364292
0.0133022
0.0000864
0.8421396 1.0400165 1.2989359 3.8981682 3.3705436 3.0429668 1.5634829 3.3026290 3.9964449 2.6691922 1.2578240 0.3601455
0.1312435
0,0024590
0.9307902
1,0365258
0.3106250
1.9447402
3.2449752
3.6765194
2.9343182
1.8596860
3.9394274
3.8650657
3.9334322 3.6619111
2.8963363 1.5538656
0.4588814
1.2192336
0.0565330
0.0088125
0.3566616
1.1125780
1.0995790
0.7714806
2.0837850
62
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5 12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
125
12.5
125
12.5
125
CHEVRON MOBIL PHILLIPS MOBIL PHILLIPS CHEVRON MOBIL PHILLIPS ARCO EXXON ARCO EXXON
EXXON é SSVIISISISB : PHILLIPS MOBIL PHILLIPS ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON BP ARCO EXXON ARCO EXXON ARCO EXXON BP BP BP BP ARCO EXXON MOBIL PHILLIPS BP CHEVRON MOBIL PHILLIPS CHEVRON
BP ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON
33.3333333 33.3333334 33.3333333
50.0000000 50.0000000
33.3333333 33.3333334 33.3333333
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000
100.0000000 100.0000000
100.0000000 100.0000000 100.0000000
100.0000000 100.0000000
100.0000000
100.0000000 100.0000000 100.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
100.0000000 50.0000000
50.0000000 50.0000000
50.0000000
50.0000000 50.0000000 100.0000000
100.0000000 100.0000000
100.0000000 50.0000000
50.0000000 50.0000000
50.0000000 100.0000000 33.3333333
33.3333334 33.3333333
100.0000000 100.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000
50.0000000
50.0000000
50.0000000
28325 71 2.7773702
28326 72 3.1133992
28327 93 2.7730980
28328 92 4.09001 28
28329 91 4.1555298
28330 100 1.4812197 28331 99 1.5486835 28332 98 1.6240684
28333 110 0.0691 187 28334 O9A 0.1303563
28334 109 0.0179622
28335 108 0.0667905 28339 66 0.0001956
28343 69 0.1342393 28345 94 0.5812244
28346 97 0.2982834
28349 111 0.0092138 34631 39 0.2490770
34632 40 0.1146214
47446 15 0.0099777
47447 14 0.0049708
47448 10 0.0010848
47449 17 0.0064355
47450 49 0.0468606
47451 56 0.1902328
47452 80 0.2232645
47453 81 0.1144260
47454 83 0.0200389
47469 9 0.0307565
47471 86 0.3000685
47472 87 0.8139925
47475 103 0.1996175
47476 104 0.0028061
80595 106 0.0000019
GAS CAP PARTICIPATING AREA
2.7773702
3.1133992
2.7730980
4.0900128
4.1555298
1.4812197 1.5486835 1.6240684
0.0691187 0.1303563
0.0179622
0.0667905 0.0001956 0.1342393
0.5812244
0.2982834
0.0092138 0.2490770
0.1146214
0.0099777
0.0049708
0.0010848
0.0064355
0.0468606
0.1902328
0.2232645
0.1144260
0.0200389
0.0307565
0.3000685
0.8139925
0.1996175
0.0028061
0.0000019
63
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON BP BP ARCO EXXON BP CHEVRON MOBIL PHILLIPS MOBIL PHILLIPS BP BP BP ARCO EXXON ARCO EXXON BP ARCO EXXON ARCO EXXON CHEVRON MOBIL CHEVRON MOBIL MOBIL PHILLIPS CHEVRON MOBIL CHEVRON MOBIL PHILLIPS CHEVRON MOBIL PHILLIPS CHEVRON MOBIL PHILLIPS CHEVRON MOBIL PHILLIPS CHEVRON MOBIL PHILLIPS MOBIL PHILLIPS AMERADA LL&E SHELL TEXACO AMERADA TEXACO AMERADA MARATHON SHELL TEXACO ARCO EXXON ARCO EXXON
50.0000000
50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000
100.0000000 100.0000000 50.0000000
50.0000000 100.0000000 33.3333333 33.3333334
33.3333333 50.0000000 50.0000000
100.0000000 100.0000000 100.0000000
50.0000000 50.0000000
50.0000000
50.0000000 100.0000000 50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
66.6666667 33.3333333 50.0000000
50.0000000
33.3333333 33.3333334
33.3333333 33.3333333
33.3333334 33.3333333 33.3333333
33.3333334
33.3333333 33.3333333
33.3333334 33.3333333
33.3333333 33.3333334 33.3333333
50.0000000
50.0000000 27.0000000
13.2500000 29.2500000 30.5000000
50.0000000 50.0000000
25.0000000
25.0000000 25.0000000
25.0000000
50.0000000 50.0000000
50.0000000 50.0000000
25637
28238
28239
28240
28241
28244
28245
28246
28257
28258
28259
28260
28261
28262
28262
28263
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
16
19
18
51
52
82
22
21
47 48
54A
55
55A
79
112
113
25
24 23
45
57
59
76 Ue
78
85
105
26
27
28
41
42
0.0046309
0.0163822
0.0614364
0.0913318
0.0486990
0.0000124
0.1486696
0.0007026
1.7767068
0.4599204
0.0076616
1.4815529
0.0888936
0.2968897 0.0772452
0.1338160
0.2071833
0.1174944
0.0364292
0.0133022
0.0000864
0.8421396 1,0400165
1.2989359
3.8981682 3.3705436 3.0429668 1.5634829
3.3026290 3.9964449 2.6691922
1.2578240 0.3601455
0.1312435
0.0024590
0.9307902
1.0365258
0.3106250
1.9447402
3.2449752
3.6765194
0.0003024
0.0061712
0.0913424
0.0496376
0.0399457
0.0000110
0.1805920
0.0003490
0.1101259
0.0000012
0.0777251 0.0005248
0.2995913 0.1111367
0.0511793
0.1539450
0.0120620
0.0003882
0.1111558 0.0331538
0.0190207 1.7631780
1.1061331 0.4341463 0.1013091 0.6687738
1.8633126 0.2432039
0.0132529
0.0668830
2.7462020
5.4070880
8.5730840
6.1308134
2.9898184
3.1854789
64
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
ARCO BP ARCO EXXON ARCO EXXON ARCO EXXON MOBIL PHILLIPS ARCO EXXON ARCO EXXON ARCO EXXON MOBIL PHILLIPS ARCO EXXON ARCO EXXON BP. MOBIL PHILLIPS CHEVRON CHEVRON MOBIL PHILLIPS MOBIL PHILLIPS CHEVRON MOBIL PHILLIPS ARCO BBSVSSSIBBS MOBIL PHILLIPS MOBIL PHILLIPS MOBIL PHILLIPS ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON BP
50.0000000
50.0000000 50.0000000 50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 100.0000000 50.0000000
50.0000000 100.0000000
33.3333334 33.3333333
33.3333333 50.0000000
50.0000000 33.3333334 33.3333333 33.3333333
50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 100.0000000
100.0000000 100.0000000
100.0000000 100.0000000
100.0000000
100.0000000 100.0000000 100.0000000
100.0000000 100.0000000
50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000
50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000
50.0000000
50.0000000 50.0000000
100.0000000
28306
28307
28308
28309
28310 28311 28312 28313
28314
28315
28316
28316 28320 28321
28322
28323
28324
28325
28326
28327
28328
28329
28330 28331
28332
28333
61
62
73
74 75
89
102
101
O7A
107 88 70
aA
72
93
92
91
100
110
28334 O9A
28334
28335 28339
28343 28345
28346
28349 34628
34629
34630 34631
34632
47446
47447
47448
47449
109
108
69
94
97
111
31 39
40
15
14
10
17
2.9343182
1.8596860
3.9394274
3.8650657 3.9334322
3.6619111 2.8963363 1.5538656
0.4588814
1.2192336
0.0565330
0.0088125 0.3566616 1.1125780
1.0995790
0.7714806
2.0837850
2.7773702
3.1133992
2.7730980
4.0900128
4.1555298
1.4812197
15486835
1.6240684
0.0691 187
0.1303563
0.0179622
0.0667905 0.0001956
0.1342393 0.5812244
0.2982834
0.0092138
0.2490770
0.1146214
0.0099777
0.0049708
0.0010848
0.0064355
5.4649446
7.4776622
4.1071874
2.2068838
1.1675071 0.3709048 0.1007911 0.0066790
0.3216998
7.2610510
4.2486128
0.4529448
0.3609044
3.3036918
5.0566434
0.0132526
0.7489948
0.7143628
4.9026960
2.3763262
0.0521132
4.4211250
7.9580580
0.0211926
0.0011970
0.0204696
65
12.5
12.5
12.5
12.5 12.5
12.5 12.5 12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
125
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
ARCO EXXON
EXXON ARCO EXXON BP BP BP BP ARCO EXXON MOBIL PHILLIPS BP CHEVRON MOBIL PHILLIPS CHEVRON BP ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON ARCO
EXXON BP BP. ARCO EXXON BP CHEVRON MOBIL PHILLIPS MOBIL PHILLIPS BP BP BP ARCO EXXON ARCO EXXON BP ARCO EXXON ARCO EXXON BP ARCO EXXON ARCO EXXON CHEVRON MOBIL CHEVRON MOBIL MOBIL PHILLIPS CHEVRON
50.0000000
50.0000000 50.0000000 50.0000000 50.0000000
50.0000000 100.0000000
100.0000000 100.0000000
100.0000000 50.0000000 50.0000000 50.0000000
50.0000000
100.0000000 33.3333334 33.3333333
33.3333333 100.0000000 100.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000
50.0000000 50.0000000
50.0000000 50.0000000 50.0000000 50.0000000
100.0000000 100.0000000
50.0000000
50.0000000 100.0000000 33.3333333
33.3333334 33.3333333
50.0000000 50.0000000
100.0000000 100.0000000 100.0000000 50.0000000
50.0000000 50.0000000
50.0000000 100.0000000
50.0000000 50.0000000
50.0000000 50.0000000 100.0000000
50.0000000 50.0000000
50.0000000
50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 66.6666667
33.3333333 50.0000000
47450 49 0.0468606
47451 56 0.1902328
47452 80 0.2232645
4745381 0.1144260
47454 83 0.0200389
47469 9 0.0307565
47471 86 0.3000685
47472 87 0.8139925
47475 103 0.1996175
47476 104 0.0028061
80595 106 0.0000019
LISBURNE PARTICIPATING AREA 28277 25 0.0170000 28280 44 0.0380000 28285 59 0.0300000 28299 26 0.1870000
28300 27 1.7170000
28301 28 2.4440000
28302 41 5.4180000
28303 42 2.2490000
28304 43 0.5380000 28305 60 0.1450000 28306 61 0.9190000
28307 62 3.5270000
28308 73 0.2460000
28309 74 0.0890000 28320 38 6.7190000 28321 63 8.5540000
28322 64 10.0680000
28323 65 11,0800000
28324 70 4.3250000
28325 71 3.7180000
28326 72 1.9750000
28327 93 0.0400000
28328 92 0.0260000
0.0193851
0.0042712
0.1575467
0.0384943
0.0013684
66
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
12.5
MOBIL CHEVRON MOBIL PHILLIPS CHEVRON MOBIL. PHILLIPS CHEVRON MOBIL PHILLIPS CHEVRON MOBIL. PHILLIPS CHEVRON MOBIL PHILLIPS MOBIL PHILLIPS AMERADA LL&E SHELL TEXACO AMERADA TEXACO AMERADA MARATHON SHELL TEXACO ARCO EXXON ARCO EXXON
BP BP BP ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON ARCO
ARCO EXXON ARCO EXXON ARCO EXXON
ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON ARCO EXXON
50.0000000 33.3333333 33.3333334
33.3333333 33.3333333 33.3333334 33.3333333
33.3333333 33.3333334
33.3333333 33.3333333 33.3333334
33.3333333 33.3333333 33.3333334
33.3333333
50.0000000 50.0000000
27.0000000 13.2500000
29.2500000 30.5000000 50.0000000
50.0000000 25.0000000
25.0000000 25.0000000 25.0000000
50.0000000 50.0000000
50.0000000 50.0000000
100.0000000
100.0000000 100.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 100.0000000
50.0000000
50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
100.0000000 100.0000000
50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000
50.0000000 50.0000000 50.0000000
28329 91 0.0190000 - 12.5 ARCO 50.0000000 EXXON 50.0000000 28337 36 0.6590000 - 12.5 BP 400.0000000
28338 37 0.8960000 - 12.5 BP 100.0000000
28339 66 3.1550000 - 12.5 BP 100.0000000
28339 66A 1.0830000 = 12.5 BP 100.0000000 28340 67 0.0300000 = 125 BP 400.0000000 28340 67A 0.200000 - 125 BP 400.0000000 28342 114 0.5690000 - 125 BP 400.0000000
28343 69 2.4130000 - 12.5 BP 100.0000000
28343 69A 1.1160000 - 12.5 BP 100.0000000
28344 95 0.0250000 - 12.5 ARCO 50.0000000
EXXON 50.0000000
28345 94 0.1170000 = 12.5 ARCO 50.0000000 EXXON 50.0000000
34628 29 3.3300000 - 12.5 ARCO 50.0000000 EXXON 50.0000000
34629 30 3.5260000 - 12.5 ARCO 50.0000000 EXXON 50.0000000
34630 31 1.3770000 - 12.5 BP 100.0000000
34631 39 8.6100000 i 12.5 ARCO 50.0000000
EXXON 50.0000000 34632 40 7.3420000 - 12.5 ARCO 50.0000000
EXXON 50.0000000
34634 33 0.6490000 - 12.5 BP 100.0000000
34635 32 0.8150000 = 12.5 BP 100.0000000
NORTH PRUDHOE BAY STATE PARTICIPATING AREA
28297 100.0000000 100.0000000 5.0 ARCO 50.0000000
EXXON 50.0000000
POINT McINTYRE PARTICIPATING AREA
28297 8 21.4790000 21.4790000 5.0 ARCO 50.0000000 EXXON 50.0000000
28297 8A 0.4210000 0.4210000 5.0 ARCO 50.0000000
EXXON 50.0000000
28298 115 0.1000000 0.1000000 12.5 ARCO 50.0000000
EXXON 50.0000000
34622 116 7.6000000 7.6000000 12.5 EXXON 100.0000000
34624 7 28.8590000 28.8590000 12.5 ARCO 50.0000000
EXXON 50.0000000
34624 7A 2.3410000 2.3410000 12.5 ARCO 50.0000000
EXXON 50.0000000 34627 6 3.8460000 3.8460000 12.5 ARCO 50.0000000
EXXON 50.0000000
34627 6A 3.1540000 3.1540000 12.5 ARCO 50.0000000 EXXON 50.0000000 365548 117 32.2000000 32.2000000 «16.6 BP 100.0000000
WEST BEACH PARTICIPATING AREA
28301 28 19.1460000 19.1460000 12.5 ARCO 50.0000000
EXXON 50.0000000
34624 7 12.7640000 12.7640000 12.5 ARCO 50.0000000
EXXON 50.0000000
34626 5 6.3820000 6.3820000 12.5 ARCO 50.0000000 EXXON 50.0000000
34627 6 24.4520000 24.4520000 12.5 ARCO 50.0000000 EXXON 50.0000000
34628 29 24.4920000 24.4920000 12.5 ARCO 50.0000000 EXXON 50.0000000
34629 30 12.7640000 12.7640000 12.5 ARCO 50.0000000 _ EXXON 50.0000000
STERLING 2497 134 - 36282900 12.5 DANCO 50.0000000 MARATHON — 50.0000000
320912 155 = 2.3611800 12.5 DANCO 50.0000000 MARATHON — 50.0000000 324599 152 - 64473700 12.5 DANCO 50.0000000 MARATHON — 50.0000000
67
OTHER = 87.5631600 DANCO 50.0000000
MARATHON __50.0000000
STUMP LAKE
17600 1 = 2.4424100 12.5 UNION 100.0000000
326059 17A ad 8.1967200 64.4 UNION 100.0000000
326060 17B = 15.5737800 64.1 UNION 100.0000000
58789 11 — 11.4754100 12.5 OXY 60.0000000
UNION 40.0000000
58789 11A - 9.8360700 12.5 OXY 100.0000000 58790 12 - 22.6442700 12.5 UNION 100.0000000
58791 13 = 18.8524600 12.5 OXY 10.0000000
UNION 90.0000000 58792 14 - 3.2786800 12.5 UNION 100.0000000
58794 15 = 4.0983600 12.5 UNION 100.0000000
58795 16 —_ 3.6018400 12.5 OXY 10.0000000 a UNION 90.0000000
TRADING BAY MONOPOD A-15
18731 100.0000000 100.0000000 12.5 MARATHON — 50.0000000 UNION 50.0000000 MONOPOD A-6
18731 100.0000000 100.0000000 125 MARATHON _— 50.0000000 UNION 50.0000000 MONOPOD NON-POOL
18731 100.0000000 100.0000000 12.5 MARATHON _50.0000000
WEST MCARTHUR RIVER 359111 50.0000000 - 12.5 STEWART — 100.0000000
359112 50.0000000 = 12.5 STEWART 100.0000000
Revised 01/29/96
68
APPENDIXC CRUDE OILANALYSES _
COOK INLET
DRIFT NIKISKI
RIVER CRUDE Gravity,°API@ 60°F 35.3 34.6
Spec.Grav.@ 60°F 0.8483 0.8519
Kin.Vis. @ 65 °F 6.94 7.34
@ 90 °F 6.77 7.A7
@122 °F 3.39 3.55 Sulfur, wt% 0.09 0.10 Nitrogen wt% 0.13 0.14
Carbon wt% 86.83 87.09
Hydrogen wt% 12.81 12.80 Oxygen wt% 0.09 0.15 Sed. and water, vol% 0.05 0.1 Water, by dist., vol% Nil 0.05 RVP, psi 75 7.85 Pour Pt, °F 0 -5 Flash Pt., PMCC, °F <0 <0 BADGER DISTILATION C5 AND LIGHTER Yield, vol% 0.4 0.7 Composition Methane 0.02 Traces
Ethane 11.07 7.75
Propane 61.74 59.81 lso—Butane 11.72 12.46 Normal Butane 13.00 16.83 lso—Pentane 1.52 2.03 Normal Pentane 0.93 tA2 IBP — 120 °F
Yield vol% 1.3 2.0
120 — 374 °F
Yield vol% 31.4 29.5 Gravity, AP| @ 60 °F 59.3 57.2 374 — 440 °F Yield vol% 6.0 65 Gravity, AP| @ 60 °F 40.9 40.6
440 — 610 °F Yield vol% 17.6 15.7 Gravity, API @ 60 °F 35.3 35.5 610 + Resid Yield vol% 41.3 43.9 Gravity, AP| @ 60 °F 18. 18.2 DISTILATION CURVE, VOL, %
IBP 86 84
2% 131 120
4% 134 130
6% 140 145 8% 150 165 10% 163 195
12% 192 213
14% 211 219
16% 220 239
18% 240 254 20% 257 272
22% 273 292
24% 292 307
26% 309 324
28% 325 341
30% 340 361
32% 361 390
34% 395 420
36% 420 430
38% 430 440
40% 440 460
42% 455 475 44% 475 490 46% 495 510
48% 510 525
50% 525 540
52% 545 555 54% 601 = 56% 607 =
NORTH SLOPE (at VALDEZ)
Nominal Recalc. API Gravity 27.40 27.48
Hy Gravity 0.8905 0.8905
.%S 1.1600 1.1600
LIGHT ENDS AND BTX ANALYSIS
LV.% Wt%
C1 0.0000 0.0000
c2 0.0200 0.0080
C3 0.2000 0.1140 IC4 0.2500 0.1531 NC4 0.1500 0.7547
TOTAL 1.6200 1.0348
Ics 0.1165 0.2923
NC5 0.9299 0.6592
C5 & Ltr. 2.9665 1.9842
IC6 0.5000
NC6 1.3400 C6 Olefins 0.0000 MCP 0.5004 Cyclo—Hexane 0.5400 Benzene 0.0360
Paraffins Olefins Naphthenes Aromatics
C7 1.5800 0.0000 1.5900 0.6300
c8 1.5600 0.0000 0.9970 0.6000
Co+ 1.2875 0.0000 1.3544 0.1285
MOTOR FUEL BLENDING DATA
Yield RON MON RVP
LV.% Clear Clear PSI
NAPTHA, C5—200 6.5 69.3 68.3 75
NAPTHA, C5—400 21.9 62.2 58.7 2.9
Continued on next page
69
NORTH SLOPE (at VALDEZ), Continued RESIDUUM
Range, IVT—FVT, °F
L.V.% of Crude Wt.% of Crude .Gravity | Gravity Sulfur, Wt.% Paraffins, L.V.% Olefins, L.V.% Naphthenes, L.V.% Aromatics, L.V.% N+2A, L.V.%
Pour Point, °F Cloud Point, °F Kin. Visc., 100 °F Kin. Visc., 122 °F Smoke Point, MM
Cetane Index Carbon Resedue Rams, Wt.% Con, Wt.% Nitrogen Total Nitrogen, PPM Basic Nitrogen, PPM Calc. Refractive Index Aniline Point, °F UOPK Factor Neut. Number Mercaptan Sulpher, PPM Freeze Point, ° Flash Point, °F RON Clear MON Clear Rvp, PSI Iron
Nickel Vanadium
Range, IVT—FVT, °F
L.V.% of Crude Wt.% of Crude Spec.Gravity | Gravity Sulfur, Wt.% Paraffins, L.V.% Olefins, L.V.% Naphthenes, L.V.% Aromatics, L.V.% N+2A, L.V.% Pour Point, °F Cloud Point, °F Kin. Visc., 100 °F Kin. Visc., 122 °F Smoke Point, MM Cetane Index Carbon Resedue Rams, Wt.% Con, Wt.% Nitrogen Total Nitrogen, PPM
Basic Nitrogen, PPM Calc. Refractive Index Aniline Point, °F UOPK Factor Neut. Number Mercaptan Sulfur, PPM Freeze Point, °F Flash Point, °F RON Clear MON Clear Rvp, PSI lron Nickel Vanadium _
o- 82- 82 200
1.62 6.50 1.03 5.04 0.5688 0.6903 117.26 73.49 0.0000 0.0011 69.62 0 27.35 3.03 33.41 -219.3 207.8 0.30 0.24
1.3868
12.22
550- 650— 650 700
10.03 4.63 9.94 4.68 0.8825 0.9005 28.84 25.63 0.7481 1.0024 45.31 0 0 22.45 32.24
19.7 38.4 12.4 50.1 5.84 13.89 4.27 9.18 11.62 44.95 42.07
0.09 0.05
104.32 606.21
51.37 = 175.73
1.4940 1.5040
150.45 160.28 11.55 11.58 0.06 0.07 3.8 75 —49.7 —19.5 160.00 232.00
200—
7.49 6.44 0.7656 53.32 0.0025 41.26
42.76 15.98 74.72 162.7 — 162.6 0.45 0.35
10.64
1.4290
11.65
6.8
700—
8.72 8.97 0.9158 23.00 1.1974
350
3.88 3.45 0.7924 47.07 0.0110 35.99
44.02
19.99
84.00 heed
—115.5
0.80 0.67 16.44
28.40 I ak it) anor Na pus 298 ~83 WN: wow oo 87.8
92.81 48.28
22.15
0.33 0.33
112140 453.23 1.5204
350— 400
4.04 3.69 0.8116 42.85 0.0178 38.26
41.84 19.89 81.63 —101.9 —105.7 peu 1.09 15.60 35.10
1.4544 122.25 11.60
41 —168.5
62.6 59.1 0.8
1050
11.30 12.11 0.9549 16.68 1.5883
108.6
618.74 253.29
0.69 0.86
1813.78 666.56 1.5339 181.21 11.81
0.32
400—
8.71 8.25 0.8430 36.36 0.1704 60.09 0 27.00
12.91
52.81 -50.5 —44.6
1.81
1.48 14.23
40.02
4.99
1.4721
133.35 11.49
0.03
3.6
—139.7 70.00
57.6
52.5 0.1
650+
52.96 57.56 0.9674 14.77 1.8295
1503.14 556.10
7.92 7.93
2977.06
1.5411
11.81
443.00 o°090 aes 500—
550
4.76 4.63 0.8648 32.13 0.4256 62.40
20.92 16.68
-16.7 12.0 3.07 2.38 13.00 44.04
1050+
24.12 23.21 1.0271 6.26 2.5467
11647220 1820244
19.08 19.16
5529.00
1.5764
11.60
524.00
APPENDIX D ALASKA REFINERIES AND
PROCESSING PLANTS
Unit Capacity Products Market Area
OIL REFINERIES Alyeska poppy pants along the TAPS pipeline, at Pump Stations 6, 8 and 10, distill fuel for the pipeline pumps.
Arco, Kuparuk Distillaton 12,000 Bbi/d Arctic Heating Fuel/Diesel #2 Kuparuk
Arco, Prudhoe ey istillaton 15,000 Bbi/d Chae Heating Fuel/Diesel #2 Prudhoe Bay
t
Mapco, North Pole 1977 Two crude 130,000 Bbi/d Gasoline Alaska units total JP 4 Alaska Jet A Alaska Diesel #1 Alaska Diesel #2 Alaska Diesel #4 Alaska Asphalt Alaska
Tesoro, Nikiski 1969 Crude 80,000 Bbl/d Propane Alaska Hydrocracker 9,000 Bbl/d Gasoline Alaska PowerFormer 12,000 Bbi/d Gasoline, premium Alaska
PRIP 4,000 Bbl/d Jet A LPG 2,800 Bbl/d Diesel #1 Alaska Hydrogen 13 MMcf/d Diesel #2 Alaska Sulfur 15 T/d Fuel Oil #6 export Sulfur lower 48
Petrostar, Valdez 1992 Crude 32,000 Bbi/d Jet A Alaska Marine Diesel Alaska Heating/Diesel #1 Alaska Heating/Diesel #2 Alaska
Petrostar, North Pole 1985 Crude 10,500 Bbl/d Kerosene Alaska Heating/Diesel #1 Alaska Heating/Diesel #2 Alaska JetA Alaska _
GAS PROCESSING PLANTS Phillips—Marathon LNG Plant, Nikiski 1969 LNG 235,000 Mcf/d LNG Japan
550,000 Bbi/10 days Unocal Chemical Plant, Nikiski 1969 Two Ammonia 1,300,000 T/yr Anhydrous Ammonia half of ammonia production units total is used to produce urea, other half is exported as
ammonia. | Urea 1,200,000 T/yr Urea prills and granules West Coast and exported.
Revised 03/21/96
71
OPERATING REFINERIES IN THE U.S.
THOUSANDS OF BARRELS PER CALENDAR DAY
Charge Copecity Production Capacity Hydro. Coke No. Crude Vac. Therm. it it Cat Cat Cat Alk. Aram. s Asph. (MMcf) (t) Plants Dist. Ops. Crack ReformHydro Hydro Hydro Poly. Isom.
sone = Crack Refin Treat =
Alabama 3 130 38 12 = 26 = 26 46 a 7 - 20 12 350 Alaska 6 272 23 2 - 12 9 - 12 = 6 - = 13 - Arco, Kuparuk 12 = 12 = = = > — = - - = - - Arco, Prudhoe Bay 16 = 16 - - - = = oS - - - - -
Mapco, North Pole 130 - - - - - - a = - - - - - Petrostar, North Pole 12 = oe = = = = — = = = = = Petrostar, Valdez 30,0 - = = = = = Sa a — = a - = Tesoro, Kenai 72 16 - - 12 9 - 12 = 4 = = 13 = Arizona 1 6 2 = = = = - = = - - 1 - -
Arkansas 3 61 31 = 18 12 a = 32 5 6 = 9 2 =
California 24 1,916 1,092 487 612 448 382 355 1,111 119 51 29 56 1004 17,231 Colorado 2 80 29 = 27 19 = - 44 3 - - 8 - - Delaware 1 140 85 41 63 49 16 = 111 17 1 - = 40 2,000 Georga 2 35 = & m & oH = = = a 2 24 = a
Hawaii 2 149 69 13 21 13 iz = 13 5 1 = 2 19 =
Illinois 7 967 377 106 347 274 58 - 617 91 30 5 52 73 5,876
Indiana 4 489 257 28 176 102 = 89 222 38 37 6 65 33 1,430 Kansas 4 285 105 104 95 79 3 44 195 30 45 = 2 = 2,128 Kentucky 2 219 89 57 97 43 = 39 «173 13 21 8 29 - =
Louisiana 18 2,330 973 306 871 457 153 141 1,160 209 103 37 47 187 14,145
Michigan 4 125 37 a 46 28 a = 88 10 5 a 18 7 =
Minnesota 2 297 191 65 94 70 = 62 258 21 23 = 38 89 3,600
Mississippi 4 337 251 71 63 71 58 84 146 15 14 6 25 213 3,800
Montana 4 142 60 20 55 34 4 36 «119 14 6 — 16 72 960 Nevada fl L 6 a = a = = ey = = S i = -
New Jersey 6 598 249 31 261 76 = 146 146 30 18 8 69 30 1,227 New Mexico 3 96 19 = 35 28 = 13 48 13 4 - 6 - -
North Dakota 1 58 = = 25 12 = = 18 4 5 oa = = =
Ohio 4 488 163 39 165 153 70 64 167 28 40 = 26 102 1,600
Oklahoma 7 404 114 28 139 96 5 25 204 34 38 i 17 62 1,260 Oregon 1 a 14 = = a a = = = = S 10 a = Pennsylvania 7 754 307 - 256 166 45 39 409 50 30 7 43 50 - Tennessee 1 90 12 - 42 15 - 35 18 6 4 a = - -
Texas 29 3,896 1,709 404 1,558 1,159 364 694 2,585 342 359 76 53 838 15,818 Utah 6 159 46 7 49 32 4 4 62 14 8 = 2 1 280 Virginia 1 53 27 15 26 11 - - 26 2 - - = = 730
Washington 7 561 256 74 123 124 50 20 215 29 4 a 15 80 3,500 West Virginia 1 10 Came a 3 4. - 4 = a 44 = 1 oS Wisconsin 1 33 19 = 10 8 = 6 8 2 2 a 12 = - Wyoming 4 128 62 10 50 2 - 24 67 9 2 - 16 6 -
Source: Oil & Gas Journal, "Worldwide Refining," December 19, 1994, p. 56. Revised 01/31/95
72
APPENDIX E CONVERSION FACTORS
ABBREVIATIONS ACRONYMS ;
acre ac AOGCC Alaska Oil and Gas Conservation Commission
barrel - bbl API American Petroleum Institute
British thermal unit btu DNR Alaska Department of Natural Resources
calorie cal DO&G __ Division of Oil and Gas
cubic foot cf DOR Alaska Department of Revenue
thousand cubic feet Mcf ISER Institute of Social and Economic Research
million cubic feet MMcf LNG liquid natural gas
billion cubic feet Bef LPG liquid petroleum gas
trillion cubic feet Tef NGL natural gas liquids
day d TAPS Trans Alaska Pipeline System
calendar day cd
stream day sd foot ft gallon, US gal US gallon, UK gal UK
hectar ha
inch in
kilogram kg
kilolitre kl
kilometer km
litre |
meter m
mile mi
nautical mile naut mi
pound Ib
ton, long (UK) tUK
ton, short (US) tUS
tonne (metric) tn
LENGTH ft mis naut mi m km
1 ft = 1 0.00019 0.00016 0.3048 0.00305
1mi = 5280 1 0.8684 1609.34 1.60934
1nautmi = 6076.12 1.1516 1 1852 1.852
im = 3.2808 0.00062 0.00054 1 1000
1km = 3280.8 0.62137 0.5396 0.001 1
AREA ft? m? ac ha km? mi?
1 ft = 1 0.0929 0.00002
1m? = 10.7639 1 0.00025 0.0001 1000 K
1ac = 43560 4046.86 4 0.40469 0.00405 0.0016
tha = 107636 10000 2.47105 1 0.01 0.00386
1 km? = 1E+07 1000000 247.105 100 1 0.3861
1 mi? = 3E+07 2589990 640 258.999 2.58999 1
VOLUME f® galUS = gal UK bbi m®
1 ft® = 1 7.48052 6.22883 0.17811 0.02832
igalUS = 0.13368 1 0.83267 0.02381 0.00379
1galUK = 0.16054 1.20095 1 0.02859 0.00455
1 bbl = 5.6146 42 34.9726 1 0.15899
1m? = 35.3147 264172 219.969 6.28981 1
WEIGHT Ib tus tUK kg tn
1 Ib = 1 0.0005 0.00037 0.45359 0.00045
1tUS = 2000 1 0.89287 907.185 0.90719
1tUK = 2240 are 1 1016.05 1.01605
1kg = 2.20462 0.0011 0.00098 1 0.001
1tn = 2204.62 1.10231 0.98421 1000 1
73
CRUDE OIL WEIGHT Based on average Arabian Light, 33.5 API. galUS gal UK
1galUS = 1 0.833 1galUK = 1.201 1 1tUK = 313 261 1tn = 308 256 1 bbl = 42 35
tUK
0.00319 0.00383 1
0.134
tn
0.00325 0.00391
1.016 1 0.136
bbl
0.0238 0.0286 7.45 7.31
WEIGHT EQIVALENTS OF PETROLEUM AND PETROLEUM PRODUCTS Average gal US/Ib Ib/gal US
Gravity
@60 °F crude oil, foreign 25.6 crude oil, domestic 36.0
asoline and naptha 59.5
‘erosene 43.0 fuel oil, distillate 31.3 fuel oil, residual 18.0 asphalt 5.6 liquid petroleum gas
APPROXIMATE HEAT CONTENTS OF FUELS AND PETROLEUM PRODUCTS
Million BTU
per Barrel asphalt . 66 aviation gasoline crude oil fuel oil, distillate fuel oil, residual
jet fuel, kerosene type jet fuel, naptha type ‘erosene ethane ropane utane pentanes plus PALOOUTAAGGOAGAA D®OuANERNBDDO VOLUME CONVERSIONS: LIQUID NATURAL GAS TO NATURAL GAS
LNG Natural Gas @ —260 °F ft?
1 Ib 21.082
1 gal 79.814
1 ft 597
1 bbl 3,352
1m? 21,085
1tn 46,477
0.13333 0.14217 0.16215 0.14812 0.13817 0.12687 0.11634 0.22104
7.500 7.034 6.167 6.751 7.237 7.882 8.596 4.524
Ib/bbI
315 295 259 284 304
331 361 190
Thousand BTU
per Gallon
74
120 138 138 150 136 129 136 74 90 102 110
bbi/
tUS
6.349 6.770 7.721 7.053 6.580 6.041
5.540 10.526
bbi/
6.998 7.463
8.511 7.775 7.253
6.660 6.106 11.603
APPENDIX F 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 make of oil and gas surplus to the state’s
needs. These key terms are: 1) “oil and gas,” 2)
“export,” 3) “present,” 4) “projected,” 5) “domes-
tic,” 6) “industrial,” 7) “intrastate,” and 8) “how
these needs are to be met.” Each key term
affects the size of the estimated need 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 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.” The 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 light hydrocarbons are
methane (CH4), ethane (C2H6), propane
(C3H8), butanes (C4H10), and pentanes
(C5H12). In these representations the letter C
represents a carbon atom and the letter H rep-
resents a hydrogen atom. The gaseous com-
ponent 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 reduc-
tion), absorption, or other means, it is classified
by the American Gas Association (AGA) as a
natural gas liquid (NGL). Natural gas liquids
also 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
75
pressure under normal temperatures. LPG
usually refers to propane and butane. A second
related term is condensate, which refers to LPG
plus heavier NGL components, often referred to
as natural gasoline. The lightest hydrocarbon
fraction is methane, which is almost never re-
covered as a liquid, and which makes up the
bulk of pipeline gas. If a natural gas stream
contains few hydrocarbons which are commer-
cially recoverable as liquids, itis considered “dry
gas” or “lean gas.” The distinction between
“wet” and “dry” is usually a legal one, which
varies from state to state. “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 liq-
uids. Non-associated gas is natural gas froma
reservoir where the gas is neither in contact with
nor dissolved in crude oil. Associated gas oc-
curs in contact with crude oil, but is not dis-
solved in it. A gas cap on a crude oil reservoir
is a typical example of associated gas. Dis-
solved gas is gas 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 “dry.”
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 ex-
ample, propane is produced in Alaska and sold
in Alaska as bottled gas for residential, commer-
cial, and limited transportation uses, while bu-
tane is used for blending in gasoline and military
jet fuel and as a refinery fuel. Potential uses for
NGL also include the enriching (“spiking”) of
pipeline gas and crop drying. Several years ago
the Dow-Shell Petrochemical Group and Exxon
studied the feasibility of utilizing the NGL con-
tained 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 sec-
ond definition would treat the markets for LPG
and ethane separately from those for gas. This
requires a separate estimate of LPG consump-
tion and gas liquids reserves. In this report,
demand for LPG and ethane is estimated sepa-
rately 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 shipment of oil and gas out of the
state. However, when one considers the fact
that much of Alaska’s industrial use of oi! and
gas is directly tied to export markets, the mean-
ing of export versus “intrastate” is not so obvi-
ous. For example, it appears that processing of
gas into another product, e.g., anhydrous am-
monia or urea, would probably be an “industrial”
use rather than “export” of gas, even though the
ammonia and urea is mostly exported. Liquifi-
cation to change the phase of the gas is a less
obvious case. The liquification of natural gas,
that is, the Phillips-Marathon LNG operation, is
considered a transportation process in this re-
port. 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 “industrial” use in
state? Or is it really “export” 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,
ALPETCO (later, Alaska Oil Company) made a
top dollar offer for royalty oil ultimately destined
(as petrochemical products) for out-of-state
markets. Though they made the offer, they did
not proceed with the project nor did they make
payments in full. Also, the state once commit-
ted royalty gas to the El Paso gas pipeline
proposal for export of Prudhoe Bay gas, which
involved liquification. Neither proposal was
clearly for in-state industrial use. In this report,
industrial demand is treated with multiple defi-
nitions as outlined later in the chapter to show
how different definitions of “export” follow after
the estimate of total consumption in Alaska.
Present
The problem here is that the term “present” may
mean “later year” consumption, “average recent
year” consumption, “weather-adjusted” con-
76
sumption, or “worst case” consumption. In the
residential and commercial sector particularly,
each definition gives a somewhat different an-
swer because of the variability of weather.
The “worst case” consumption calculation
cases result in considerable higher gas con-
sumption 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 intra-
state residential consumption of natural gas
which assume worst case forecasts for every
year, it may be prudent in practice to reserve
part of the State’s gas and oil supply for bad
weather, For forecasting, the starting value for
consumption is based on average weather
years. For the remainder of the state, trended
per capita consumption is used, which approxi-
mates 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, fuel
switching, and relative energy prices are key
features of any consumption forecast, but as-
sumptions concerning any of these variables
are necessarily controversial. This report de-
scribes a range of possible consumption figures
under precisely articulated definitions of con-
sumption and varying paces of economic, popu-
lation, and fuel price growth.
Domestic
Domestic consumption appears to mean Alaska
residential consumption. As we saw above un-
der the subheading “present”, it is not at all
obvious which definition of domestic consump-
tion is the most appropriate, even when the
identity of the customer is notin dispute. Some
multi-family residential use may be described as
“commercial”, obscuring the definition of the
customer and causing forecasting problems for
natural gas. The definition of “domestic” con-
sidered in this report includes multi-family resi-
dential in “residential” or “domestic” use.
Industrial
As described above, “industrial” energy use has
a number of potential definitions. Since one
over export uses of royalty oil and gas seems to
encourage in-state economic activity, a day-to-
day working definition of this industrial priority is
that the royalty reserves be 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 “industrial”
in the 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 con-
sumption of natural gas, petroleum, or their
products in combustion (except that required to
export oil or gas); or the chemical transforma-
tion of natural gas, petroleum, or their products
from refineries, as well as uses which merely
change the physical form of the product (gas
conditioning or liquidization) 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. This definition counts feed-
stocks for petrochemical plants and refineries
as industrial consumption. It also counts en-
ergy consumed by an LNG facility as industrial
consumption. It excludes the feedstocks of
LNG plants; and fuel consumption by condition-
ing plants, pump stations, fuel used on lease,
shrinkage, injection and flared gas.
Definition 3: Industrial use consists of any con-
sumption of natural gas, crude oil, or their prod-
ucts in combustion (except in oil and gas
transport and extraction) or their chemical trans-
formation 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 chemi-
cally different products. This definition permits
77
feedstocks of refineries to be counted as indus-
trial consumption, as well as energy consump-
tion in conditioning plants an pump stations. It
excludes injected gas, which is ultimately recov-
erable for other uses, and LNG processing,
which is considered an export. Definition 4 will
be used for the purposes of this report.
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 “con-
sumed.”
Intrastate
It is unclear what is meant by intrastate con-
sumption. 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 transpor-
tation which are not obviously within Alaska.
These categories include in fuel burned in ma-
tine vessels such as cargo vessels, ferries, and
fishing boats, and fuel burned in international
and interstate air travel. There are multiple
ways to approach the definition of this consump-
tion. The firstis a sales definition: the fuel used
in transportation which is sold in Alaska. The
second approach is to base consumption on
fuel used in Alaska or related to Alaska’s econ-
omy and population, regardless of the point of
sale. This results in three logical definitions,
described below:
Definition 1: Intrastate consumption in trans-
portation includes all sales of fuels to motor
vehicles, airplanes, and vessels in Alaska, in-
cluding bonded fuels. It excludes fuel con-
sumed 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.
Itincludes use of fuel by American fishing boats
in Alaskan waters regardless of where the fuel
was purchased, use of fuel purchased in Wash-
ington 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 compro-
mise 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 basis definitions in this report is the third
definition. By excluding bonded and exempt jet
fuel, the report also approximates Definition 2.
78
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 ex-
tensions of proven reserves, and imports of
crude oil, petroleum products, and (in theory)
natural gas.
ACKNOWLEDGMENTS
Staff of the State of Alaska, Department of Natural Resources, Division of Oil and Gas prepared this
report:
Dick Beasley, Geologist and Principal Document Editor
Ken Boyd, Director
Bill VanDyke, Petroleum Manager
Mike Pritchard, Cartographer
Dan Smith, Cartographer
Nancy Cress, Accountant
Don Gerwin, Management Analyst
Merlin Wibbenmeyer, Operations Research Analyst
Dianna Lewis, Administration Clerk
Judy Stanek, NRO
Tom Rauba, Programmer
Staffs of other state agencies helped us prepare this report and we want to thank them for their
assistance:
Alaska Oil and Gas Conservation Commission
Alaska Department of Revenue
79
STATE OF ALASKA
DEPT. OF NATURAL RESOURCES
DIVISION OF OIL & GAS
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ANCHORAGE, AK 99503-5948 BOUND PRINTED MATERIAL
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