v2.4.0.6

Supplemental Information On Oil And Gas Operations | 12 Months Ended
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Dec. 31, 2011
Supplemental Information On Oil And Gas Operations [Abstract] |
Supplemental Information On Oil And Gas Operations | 22. Supplemental Information on Oil and Gas Operations (Unaudited) Supplemental unaudited information regarding Devon's oil and gas activities is presented in this note. The information is provided separately by country and continent. Additionally, the costs incurred and reserves information for the U.S. is segregated between Devon's onshore and offshore operations. Unless otherwise noted, this supplemental information excludes amounts for all periods presented related to Devon's discontinued operations. Costs Incurred The following tables reflect the costs incurred in oil and gas property acquisition, exploration, and development activities.
| Year Ended December 31, 2011
| U.S. Onshore | U.S. Offshore | Total U.S. | Canada | North America
| (In millions)
Property acquisition costs: |
Proved properties | $ 34 | $ — | $ 34 | $ 14 | $ 48
Unproved properties | 851 | — | 851 | 88 | 939
Exploration costs | 272 | — | 272 | 266 | 538
Development costs | 4,130 | — | 4,130 | 1,288 | 5,418
Costs incurred | $ 5,287 | $ — | $ 5,287 | $ 1,656 | $ 6,943
| Year Ended December 31, 2010
| U.S. Onshore | U.S. Offshore | Total U.S. | Canada | North America
| (In millions)
Property acquisition costs: |
Proved properties | $ 29 | $ — | $ 29 | $ 4 | $ 33
Unproved properties | 592 | 2 | 594 | 590 | 1,184
Exploration costs | 339 | 89 | 428 | 260 | 688
Development costs | 3,126 | 297 | 3,423 | 1,216 | 4,639
Costs incurred | $ 4,086 | $ 388 | $ 4,474 | $ 2,070 | $ 6,544
| Year Ended December 31, 2009
| U.S. Onshore | U.S. Offshore | Total U.S. | Canada | North America
| (In millions)
Property acquisition costs: |
Proved properties | $ 17 | $ — | $ 17 | $ 18 | $ 35
Unproved properties | 52 | 11 | 63 | 72 | 135
Exploration costs | 122 | 260 | 382 | 152 | 534
Development costs | 2,011 | 537 | 2,548 | 835 | 3,383
Costs incurred | $ 2,202 | $ 808 | $ 3,010 | $ 1,077 | $ 4,087
Pursuant to the full cost method of accounting, Devon capitalizes certain of its general and administrative expenses that are related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $337 million, $311 million and $332 million in the years 2011, 2010 and 2009, respectively. Also, Devon capitalizes interest costs incurred and attributable to unproved oil and gas properties and major development projects of oil and gas properties. Capitalized interest expenses, which are included in the costs shown in the preceding tables, were $45 million, $37 million and $74 million in the years 2011, 2010 and 2009, respectively. Capitalized Costs The following tables reflect the aggregate capitalized costs related to oil and gas activities.
| December 31, 2011
| U.S | Canada | North America
| (In millions)
Proved properties | $ 41,397 | $ 20,299 | $ 61,696
Unproved properties | 2,347 | 1,635 | 3,982
Total oil & gas properties | 43,744 | 21,934 | 65,678
Accumulated DD&A | (29,742) | (14,585) | (44,327)
Net capitalized costs | $ 14,002 | $ 7,349 | $ 21,351
| December 31, 2010
| U.S | Canada | North America
| (In millions)
Proved properties | $ 36,301 | $ 19,711 | $ 56,012
Unproved properties | 2,156 | 1,278 | 3,434
Total oil & gas properties | 38,457 | 20,989 | 59,446
Accumulated DD&A | (28,546) | (14,130) | (42,676)
Net capitalized costs | $ 9,911 | $ 6,859 | $ 16,770
The following is a summary of Devon's oil and gas properties not subject to amortization as of December 31, 2011.
|  | Costs Incurred In
|  | 2011 | 2010 | 2009 | Prior to 2009 | Total
|  | (In millions)
Acquisition costs | $ 894 | $ 1,101 | $ 112 | $ 1,037 | $ 3,144
Exploration costs | 234 | 81 | 6 | 11 | 332
Development costs | 359 | 72 | 1 | 9 | 441
Capitalized interest | 43 | 22 | — | — | 65
Total oil and gas properties not subject to amortization | $ 1,530 | $ 1,276 | $ 119 | $ 1,057 | $ 3,982
Results of Operations The following tables include revenues and expenses directly associated with Devon's oil and gas producing activities, including general and administrative expenses directly related to such producing activities. They do not include any allocation of Devon's interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of Devon's oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil, gas and NGL sales after deducting costs, including depreciation, depletion and amortization and after giving effect to permanent differences.
| Year Ended December 31, 2011
| United States | Canada | North America
| (In millions)
Oil, gas and NGL sales | $ 5,418 | $ 2,897 | $ 8,315
Lease operating expenses | (925) | (926) | (1,851)
Depreciation, depletion and amortization | (1,201) | (786) | (1,987)
General and administrative expenses | (132) | (119) | (251)
Taxes other than income taxes | (357) | (45) | (402)
Accretion of asset retirement obligations | (34) | (57) | (91)
Income tax expense | (1,005) | (250) | (1,255)
Results of operations | $ 1,764 | $ 714 | $ 2,478
Depreciation, depletion and amortization per Boe | $ 6.94 | $ 11.74 | $ 8.28
| Year Ended December 31, 2010
| United States | Canada | North America
| (In millions)
Oil, gas and NGL sales | $ 4,742 | $ 2,520 | $ 7,262
Lease operating expenses | (892) | (797) | (1,689)
Depreciation, depletion and amortization | (998) | (677) | (1,675)
General and administrative expenses | (133) | (83) | (216)
Taxes other than income taxes | (319) | (40) | (359)
Accretion of asset retirement obligations | (42) | (50) | (92)
Income tax expense | (849) | (246) | (1,095)
Results of operations | $ 1,509 | $ 627 | $ 2,136
Depreciation, depletion and amortization per Boe | $ 6.11 | $ 10.51 | $ 7.36
| Year Ended December 31, 2009
| United States | Canada | North America
| (In millions)
Oil, gas and NGL sales | $ 3,958 | $ 2,139 | $ 6,097
Lease operating expenses | (997) | (673) | (1,670)
Depreciation, depletion and amortization | (1,247) | (585) | (1,832)
General and administrative expenses | (145) | (74) | (219)
Taxes other than income taxes | (258) | (35) | (293)
Reduction of carrying value of oil and gas properties | (6,408) | — | (6,408)
Accretion of asset retirement obligations | (53) | (38) | (91)
Income tax benefit | 1,800 | (210) | 1,580
Results of operations | $ (3,350) | $ 524 | $ (2,836)
Depreciation, depletion and amortization per Boe | $ 7.47 | $ 8.84 | $ 7.86
Proved Reserves The following tables present Devon's estimated proved reserves by product for each significant country.
| Oil (MMBbls)
| U.S. Onshore | U.S. Offshore | Total U.S. | Canada | North America
Proved developed and undeveloped reserves: |  |  |  |  |
December 31, 2008 | 133 | 34 | 167 | 134 | 301
Revisions due to prices | 9 | 2 | 11 | 291 | 302
Revisions other than price | — | 1 | 1 | (8) | (7)
Extensions and discoveries | 9 | 2 | 11 | 122 | 133
Production | (12) | (5) | (17) | (25) | (42)
Sale of reserves | — | (1) | (1) | — | (1)
December 31, 2009 | 139 | 33 | 172 | 514 | 686
Revisions due to prices | 4 | 1 | 5 | (24) | (19)
Revisions other than price | 2 | 2 | 4 | 9 | 13
Extensions and discoveries | 19 | 1 | 20 | 59 | 79
Production | (14) | (2) | (16) | (25) | (41)
Sale of reserves | (2) | (35) | (37) | — | (37)
December 31, 2010 | 148 | — | 148 | 533 | 681
Revisions due to prices | 2 | — | 2 | (15) | (13)
Revisions other than price | (1) | — | (1) | 11 | 10
Extensions and discoveries | 36 | — | 36 | 36 | 72
Production | (17) | — | (17) | (28) | (45)
December 31, 2011 | 168 | — | 168 | 537 | 705
Proved developed reserves as of: |  |  |  |  |
December 31, 2008 | 111 | 22 | 133 | 110 | 243
December 31, 2009 | 119 | 21 | 140 | 149 | 289
December 31, 2010 | 131 | — | 131 | 126 | 257
December 31, 2011 | 146 | — | 146 | 163 | 309
Proved developed-producing reserves as of: |  |  |  |  |
December 31, 2008 | 103 | 9 | 112 | 91 | 203
December 31, 2009 | 112 | 12 | 124 | 137 | 261
December 31, 2010 | 123 |  | 123 | 116 | 239
December 31, 2011 | 139 | — | 139 | 155 | 294
Proved undeveloped reserves as of: |  |  |  |  |
December 31, 2008 | 22 | 12 | 34 | 24 | 58
December 31, 2009 | 20 | 12 | 32 | 365 | 397
December 31, 2010 | 17 | — | 17 | 407 | 424
December 31, 2011 | 22 | — | 22 | 374 | 396
| Gas (Bcf)
| U.S. Onshore | U.S. Offshore | Total U.S. | Canada | North America
Proved developed and undeveloped reserves: |  |  |  |  |
December 31, 2008 | 7,979 | 390 | 8,369 | 1,510 | 9,879
Revisions due to prices | (661) | (4) | (665) | (29) | (694)
Revisions other than price | 119 | (62) | 57 | (14) | 43
Extensions and discoveries | 1,387 | 64 | 1,451 | 67 | 1,518
Purchase of reserves | 1 | — | 1 | 6 | 7
Production | (698) | (45) | (743) | (223) | (966)
Sale of reserves | — | (1) | (1) | (29) | (30)
December 31, 2009 | 8,127 | 342 | 8,469 | 1,288 | 9,757
Revisions due to prices | 449 | 2 | 451 | 21 | 472
Revisions other than price | 105 | (26) | 79 | (17) | 62
Extensions and discoveries | 1,088 | 7 | 1,095 | 131 | 1,226
Purchase of reserves | 12 | — | 12 | 9 | 21
Production | (699) | (17) | (716) | (214) | (930)
Sale of reserves | (17) | (308) | (325) | — | (325)
December 31, 2010 | 9,065 | — | 9,065 | 1,218 | 10,283
Revisions due to prices | (1) | — | (1) | (60) | (61)
Revisions other than price | (243) | — | (243) | (38) | (281)
Extensions and discoveries | 1,410 | — | 1,410 | 58 | 1,468
Purchase of reserves | 16 | — | 16 | 20 | 36
Production | (740) | — | (740) | (213) | (953)
Sale of reserves | — | — | — | (6) | (6)
December 31, 2011 | 9,507 | — | 9,507 | 979 | 10,486
Proved developed reserves as of: |  |  |  |  |
December 31, 2008 | 6,469 | 212 | 6,681 | 1,357 | 8,038
December 31, 2009 | 6,447 | 185 | 6,632 | 1,213 | 7,845
December 31, 2010 | 7,280 | — | 7,280 | 1,144 | 8,424
December 31, 2011 | 7,957 | — | 7,957 | 951 | 8,908
Proved developed-producing reserves as of: |  |  |  |  |
December 31, 2008 | 5,787 | 64 | 5,851 | 1,194 | 7,045
December 31, 2009 | 5,860 | 137 | 5,997 | 1,075 | 7,072
December 31, 2010 | 6,702 | — | 6,702 | 1,031 | 7,733
December 31, 2011 | 7,409 | — | 7,409 | 862 | 8,271
Proved undeveloped reserves as of: |  |  |  |  |
December 31, 2008 | 1,510 | 178 | 1,688 | 153 | 1,841
December 31, 2009 | 1,680 | 157 | 1,837 | 75 | 1,912
December 31, 2010 | 1,785 | — | 1,785 | 74 | 1,859
December 31, 2011 | 1,550 | — | 1,550 | 28 | 1,578
| Natural Gas Liquids (MMBbls)
| U.S. Onshore | U.S. Offshore | Total U.S. | Canada | North America
Proved developed and undeveloped reserves: |  |  |  |  |
December 31, 2008 | 315 | 2 | 317 | 35 | 352
Revisions due to prices | (11) | — | (11) | 2 | (9)
Revisions other than price | 36 | 1 | 37 | — | 37
Extensions and discoveries | 70 | — | 70 | 1 | 71
Production | (25) | (1) | (26) | (4) | (30)
December 31, 2009 | 385 | 2 | 387 | 34 | 421
Revisions due to prices | 14 | — | 14 | (1) | 13
Revisions other than price | 13 | 3 | 16 | (1) | 15
Extensions and discoveries | 68 | — | 68 | 2 | 70
Production | (28) | — | (28) | (4) | (32)
Sale of reserves | (3) | (5) | (8) | — | (8)
December 31, 2010 | 449 | — | 449 | 30 | 479
Revisions due to prices | 4 | — | 4 | (1) | 3
Revisions other than price | 1 | — | 1 | — | 1
Extensions and discoveries | 102 | — | 102 | 2 | 104
Purchase of reserves | 2 | — | 2 | — | 2
Production | (33) | — | (33) | (4) | (37)
December 31, 2011 | 525 | — | 525 | 27 | 552
Proved developed reserves as of: |  |  |  |  |
December 31, 2008 | 260 | 1 | 261 | 31 | 292
December 31, 2009 | 293 | 1 | 294 | 32 | 326
December 31, 2010 | 353 | — | 353 | 28 | 381
December 31, 2011 | 402 | — | 402 | 26 | 428
Proved developed-producing reserves as of: |  |  |  |  |
December 31, 2008 | 230 | — | 230 | 29 | 259
December 31, 2009 | 265 | 1 | 266 | 28 | 294
December 31, 2010 | 318 | — | 318 | 26 | 344
December 31, 2011 | 372 | — | 372 | 24 | 396
Proved undeveloped reserves as of: |  |  |  |  |
December 31, 2008 | 55 | 1 | 56 | 4 | 60
December 31, 2009 | 92 | 1 | 93 | 2 | 95
December 31, 2010 | 96 | — | 96 | 2 | 98
December 31, 2011 | 123 | — | 123 | 1 | 124
| Total (MMBoe) (1)
| U.S. Onshore | U.S. Offshore | Total U.S. | Canada | North America
Proved developed and undeveloped reserves: |  |  |  |  |
December 31, 2008 | 1,777 | 101 | 1,878 | 421 | 2,299
Revisions due to prices | (113) | 1 | (112) | 289 | 177
Revisions other than price | 57 | (8) | 49 | (11) | 38
Extensions and discoveries | 311 | 12 | 323 | 135 | 458
Purchase of reserves | — | — | — | 1 | 1
Production | (154) | (13) | (167) | (66) | (233)
Sale of reserves | — | (1) | (1) | (6) | (7)
December 31, 2009 | 1,878 | 92 | 1,970 | 763 | 2,733
Revisions due to prices | 92 | 1 | 93 | (21) | 72
Revisions other than price | 32 | 1 | 33 | 5 | 38
Extensions and discoveries | 269 | 2 | 271 | 83 | 354
Purchase of reserves | 2 | — | 2 | 2 | 4
Production | (158) | (5) | (163) | (65) | (228)
Sale of reserves | (8) | (91) | (99) | (1) | (100)
December 31, 2010 | 2,107 | — | 2,107 | 766 | 2,873
Revisions due to prices | 6 | — | 6 | (27) | (21)
Revisions other than price | (41) | — | (41) | 6 | (35)
Extensions and discoveries | 374 | — | 374 | 47 | 421
Purchase of reserves | 5 | — | 5 | 3 | 8
Production | (173) | — | (173) | (67) | (240)
Sale of reserves | — | — | — | (1) | (1)
December 31, 2011 | 2,278 | — | 2,278 | 727 | 3,005
Proved developed reserves as of: |  |  |  |  |
December 31, 2008 | 1,449 | 59 | 1,508 | 367 | 1,875
December 31, 2009 | 1,486 | 53 | 1,539 | 383 | 1,922
December 31, 2010 | 1,696 | — | 1,696 | 346 | 2,042
December 31, 2011 | 1,875 | — | 1,875 | 348 | 2,223
Proved developed-producing reserves as of: |  |  |  |  |
December 31, 2008 | 1,298 | 20 | 1,318 | 319 | 1,637
December 31, 2009 | 1,354 | 35 | 1,389 | 344 | 1,733
December 31, 2010 | 1,557 | — | 1,557 | 314 | 1,871
December 31, 2011 | 1,746 | — | 1,746 | 323 | 2,069
Proved undeveloped reserves as of: |  |  |  |  |
December 31, 2008 | 328 | 42 | 370 | 54 | 424
December 31, 2009 | 392 | 39 | 431 | 380 | 811
December 31, 2010 | 411 | — | 411 | 420 | 831
December 31, 2011 | 403 | — | 403 | 379 | 782
____________________________ (1) Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to Boe on a one-to-one basis with oil. Proved Undeveloped Reserves The following table presents the changes in our total proved undeveloped reserves during 2011 (in MMBoe).
| U.S. Onshore | Canada | North America
Proved undeveloped reserves as of December 31, 2010 | 411 | 420 | 831
Extensions and discoveries | 118 | 30 | 148
Revisions due to prices | (2) | (14) | (16)
Revisions other than price | (56) | 5 | (51)
Conversion to proved developed reserves | (68) | (62) | (130)
Proved undeveloped reserves as of December 31, 2011 | 403 | 379 | 782
At December 31, 2011, Devon had 782 MMBoe of proved undeveloped reserves. This represents a 6% decrease as compared to 2010 and represents 26% of its total proved reserves. Drilling activities increased Devon's proved undeveloped reserves 148 MMBoe and resulted in the conversion of 130 MMBoe, or 16%, of the 2010 proved undeveloped reserves to proved developed reserves. Additionally, revisions other than price decreased Devon's proved undeveloped reserves 51 MMBoe primarily due to its evaluation of certain U.S. onshore dry-gas areas, which it does not expect to develop in the next five years. The largest revisions relate to the dry-gas areas at Carthage in east Texas and the Barnett Shale in north Texas. A significant amount of Devon's proved undeveloped reserves at the end of 2011 largely related to its Jackfish operations. At December 31, 2011 and 2010, Devon's Jackfish proved undeveloped reserves were 367 MMBoe and 396 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their 35,000 barrel daily facility capacity. Processing plant capacity is controlled by factors such as total steam processing capacity, steam-oil ratios and air quality discharge permits. As a result, these reserves are classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends though the year 2025. Price Revision s 2011 - Reserves decreased 21 MMBoe due to lower gas prices and higher oil prices. The higher oil prices increased Devon's Canadian royalty burden, which reduced Devon's oil reserves. 2010 - Reserves increased 72 MMBoe due to higher gas prices, partially offset by the effect of higher oil prices. The higher oil prices increased Devon's Canadian royalty burden, which reduced Devon's oil reserves. Of the 72 MMBoe price revisions, 43 MMBoe related to the Barnett Shale and 22 MMBoe related to the Rocky Mountain area. 2009 – Reserves increased 177 MMBoe due to higher oil prices, partially offset by lower gas prices. The increase in oil reserves primarily related to Devon's Jackfish thermal heavy oil reserves in Canada. At the end of 2008, 331 MMBoe of reserves related to Jackfish were not considered proved. However, due to higher prices, these reserves were considered proved as of December 31, 2009. Significantly lower gas prices caused Devon's reserves to decrease 116 MMBoe, which primarily related to its U.S reserves. Revisions Other Than Price Total revisions other than price for 2011 primarily related to Devon's evaluation of certain dry gas regions noted in the proved undeveloped reserves discussion above. Total revisions other than price for 2010 and 2009 primarily related to Devon's drilling and development in the Barnett Shale. Extensions and Discoveries 2011 – Of the 421 MMBoe of 2011 extensions and discoveries, 162 MMBoe related to the Cana-Woodford Shale in western Oklahoma, 115 MMBoe related to the Barnett Shale, 39 MMBoe related to the Permian Basin, 30 MMBoe related to Jackfish, 19 MMBoe related to the Rocky Mountain area and 17 MMBoe related to the Granite Wash area in the Texas panhandle and western Oklahoma. The 2011 extensions and discoveries included 168 MMBoe related to additions from Devon's infill drilling activities, including 80 MMBoe at the Cana-Woodford Shale and 77 MMBoe at the Barnett Shale. 2010 – Of the 354 MMBoe of 2010 extensions and discoveries, 101 MMBoe related to the Cana-Woodford Shale, 87 MMBoe related to the Barnett Shale, 55 MMBoe related to Jackfish, 19 MMBoe related to the Permian Basin, 15 MMBoe related to the Rocky Mountain area and 14 MMBoe related to the Carthage area. The 2010 extensions and discoveries included 107 MMBoe related to additions from Devon's infill drilling activities, including 43 MMBoe at the Barnett Shale and 47 MMBoe at the Cana-Woodford Shale. 2009 – Of the 458 MMBoe of 2009 extensions and discoveries, 204 MMBoe related to the Barnett Shale, 118 MMBoe related to Jackfish, 49 MMBoe related to the Cana-Woodford Shale, 14 MMBoe related to the Rocky Mountain area, 11 MMBoe related to Deepwater Production in the Gulf, 8 MMBoe related to the Carthage area and 7 MMBoe related to the Haynesville Shale area in east Texas. The 2009 extensions and discoveries included 371 MMBoe related to additions from Devon's infill drilling activities, including 203 MMBoe at the Barnett Shale, 118 MMBoe at Jackfish and 24 MMBoe at the Cana-Woodford Shale. Sale of Reserves The 2010 total primarily relates to the divestiture of Devon's Gulf of Mexico properties. SEC's Modernization of Oil and Gas Reporting At the end of 2009, Devon adopted the SEC's Modernization of Oil and Gas Reporting, as well as the conforming rule changes issued by the Financial Accounting Standards Board. Upon adoption, the two primary rule changes that impacted Devon's year-end reserves estimates were those related to assumptions for pricing and reasonable certainty. The SEC's prior rules required proved reserve estimates to be calculated using prices as of the end of the period and held constant over the life of the reserves. The revised rules require reserves estimates to be calculated using an average of the first-day-of-the-month price for the preceding 12-month period. The revised rules amend the definition of proved reserves to permit the use of reliable technologies to establish the reasonable certainty of proved reserves. This revision includes provisions for establishing levels of lowest known hydrocarbons and highest known oil through reliable technology other than well penetrations. This revision also allows proved reserves to be claimed beyond development spacing areas that are immediately adjacent to developed spacing areas if economic producibility can be established with reasonable certainty based on reliable technologies. As a result of adopting these provisions of the new rules, Devon's 2009 reserves increased approximately 65 MMBoe, or 2%. This increase is included in the 2009 extensions and discoveries total. Standardized Measure The tables below reflect Devon's standardized measure of discounted future net cash flows from its proved reserves.
| Year Ended December 31, 2011
| U.S | Canada | North America
| (In millions)
Future cash inflows | $ 69,305 | $ 36,786 | $ 106,091
Future costs: |  |  |
Development | (6,817) | (4,678) | (11,495)
Production | (26,217) | (15,063) | (41,280)
Future income tax expense | (11,432) | (3,763) | (15,195)
Future net cash flows | 24,839 | 13,282 | 38,121
10% discount to reflect timing of cash flows | (13,492) | (6,785) | (20,277)
Standardized measure of discounted future net cash flows | $ 11,347 | $ 6,497 | $ 17,844
| Year Ended December 31, 2010
| U.S | Canada | North America
| (In millions)
Future cash inflows | $ 58,093 | $ 35,948 | $ 94,041
Future costs: |  |  |
Development | (6,220) | (4,526) | (10,746)
Production | (24,223) | (12,249) | (36,472)
Future income tax expense | (8,643) | (4,209) | (12,852)
Future net cash flows | 19,007 | 14,964 | 33,971
10% discount to reflect timing of cash flows | (10,164) | (7,455) | (17,619)
Standardized measure of discounted future net cash flows | $ 8,843 | $ 7,509 | $ 16,352
| Year Ended December 31, 2009
| U.S | Canada | North America
| (In millions)
Future cash inflows | $ 44,571 | $ 28,442 | $ 73,013
Future costs: |  |  |
Development | (6,814) | (4,132) | (10,946)
Production | (22,184) | (9,847) | (32,031)
Future income tax expense | (3,572) | (3,408) | (6,980)
Future net cash flows | 12,001 | 11,055 | 23,056
10% discount to reflect timing of cash flows | (6,121) | (5,532) | (11,653)
Standardized measure of discounted future net cash flows | $ 5,880 | $ 5,523 | $ 11,403
Future cash inflows, development costs and production costs were computed using the same assumptions for prices and costs that were used to estimate Devon's proved oil and gas reserves at the end of each year. For 2011, the prices averaged $67.31 per barrel of oil, $3.51 per Mcf of gas and $39.28 per barrel of natural gas liquids. Of the $11.5 billion of future development costs as of the end of 2011, $1.6 billion, $1.4 billion and $1.1 billion are estimated to be spent in 2012, 2013 and 2014, respectively. Future development costs include not only development costs, but also future asset retirement costs. Included as part of the $11.5 billion of future development costs are $2.2 billion of future asset retirement costs. Future production costs include general and administrative expenses directly related to oil and gas producing activities. Future income tax expenses are computed by applying the appropriate statutory tax rates to the future pre-tax net cash flows relating to proved reserves, net of the tax basis of the properties involved. The future income tax expenses give effect to permanent differences and tax credits but do not reflect the impact of future operations. The p rincipal changes in Devon's standardized measure of discounted future net cash flows are as follows:
| Year Ended December 31,
| 2011 | 2010 | 2009
| (In millions)
Beginning balance | $ 16,352 | $ 11,403 | $ 9,393
Oil, gas and NGL sales, net of production costs | (5,794) | (4,982) | (3,915)
Net changes in prices and production costs | 1,875 | 7,423 | (1,672)
Extensions and discoveries, net of future development costs | 3,714 | 3,048 | 2,378
Purchase of reserves, net of future development costs | 57 | 23 | 6
Development costs incurred that reduced future development costs.. | 1,302 | 1,559 | 1,012
Revisions of quantity estimates | (668) | 287 | 4,051
Sales of reserves in place | (2) | (815) | (37)
Accretion of discount | 2,248 | 1,487 | 1,281
Net change in income taxes | (929) | (2,663) | (51)
Other, primarily changes in timing and foreign exchange rates | (311) | (418) | (1,043)
Ending balance | $ 17,844 | $ 16,352 | $ 11,403
The following table presents Devon's estimated pretax cash flow information related to its proved reserves.
| Year Ended December 31, 2011
| U.S | Canada | North America
Pre-Tax Future Net Revenue (1) | (In millions)
Proved Developed Reserves | $ 30,473 | $ 7,757 | $ 38,230
Proved Undeveloped Reserves | 5,798 | 9,288 | 15,086
Total Proved Reserves | $ 36,271 | $ 17,045 | $ 53,316
Pre-Tax 10% Present Value (1) |  |  |
Proved Developed Reserves | $ 15,165 | $ 5,830 | $ 20,995
Proved Undeveloped Reserves | 1,404 | 2,508 | 3,912
Total Proved Reserves | $ 16,569 | $ 8,338 | $ 24,907
____________________________ (1) Estimated pre-tax future net revenue represents estimated future revenue to be generated from the production of proved reserves, net of estimated production and development costs and site restoration and abandonment charges. The amounts shown do not give effect to depreciation, depletion and amortization, or to non-property related expenses such as debt service and income tax expense. The present value of after-tax future net revenues discounted at 10% per annum ("standardized measure") was $17.8 billion at the end of 2011. Included as part of standardized measure were discounted future income taxes of $7.1 billion. Excluding these taxes, the present value of our pre-tax future net revenue ("pre-tax 10% present value") was $24.9 billion. Devon believes the pre-tax 10% present value is a useful measure in addition to the after-tax standardized measure. The pre-tax 10% present value assists in both the determination of future cash flows of the current reserves as well as in making relative value comparisons among peer companies. The after-tax standardized measure is dependent on the unique tax situation of each individual company, while the pre-tax 10% present value is based on prices and discount factors, which are more consistent from company to company.

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