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Oil and Gas Exploration and Production Industries Disclosures | 12 Months Ended
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Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract] |
Oil and Gas Exploration and Production Industries Disclosures | Oil and Gas Producing Activities The following disclosures are made in accordance with Financial Accounting Standards Board Accounting Standards Update No. 2010-03 "Oil and Gas Reserve Estimates and Disclosures" and the United States Securities and Exchange Commission's (SEC) final rule on "Modernization of Oil and Gas Reporting." Oil and Gas Reserves. Users of this information should be aware that the process of estimating quantities of "proved," "proved developed" and "proved undeveloped" crude oil, natural gas liquids (NGLs) and natural gas reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Although reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. See ITEM 1A. Risk Factors. Proved reserves represent estimated quantities of crude oil, NGLs and natural gas that geoscience and engineering data can estimate, with reasonable certainty, to be economically producible from a given day forward from known reservoirs under then-existing economic conditions, operating methods and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Proved developed reserves are proved reserves expected to be recovered under operating methods being utilized at the time the estimates were made, through wells and equipment in place or if the cost of any required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves (PUDs) are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a significant expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. PUDs can be recorded in respect of a particular undrilled location only if the location is scheduled, under the then-current drilling and development plan, to be drilled within five years from the date that the PUDs are to be recorded, unless specific factors (such as those described in interpretative guidance issued by the Staff of the SEC) justify a longer timeframe. Likewise, absent any such specific factors, PUDs associated with a particular undeveloped drilling location shall be removed from the estimates of proved reserves if the location is scheduled, under the then-current drilling and development plan, to be drilled on a date that is beyond five years from the date that the PUDs were recorded. Estimates for PUDs are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) In making estimates of PUDs, EOG's technical staff, including engineers and geoscientists, perform detailed technical analysis of each potential drilling location within its entire inventory of prospects. In making a determination as to which of these locations would penetrate undrilled portions of the formation that can be judged, with reasonable certainty, to be continuous and contain economically producible crude oil and natural gas, studies are conducted using numerous data elements and analysis techniques. EOG technical staff estimates the hydrocarbons in place, by mapping the entirety of the play in question using seismic techniques, typically employing two-dimensional and three-dimensional data. This analysis is integrated with other static data, including, but not limited to, core analysis, mechanical properties of the formation, thermal maturity indicators, and well logs of existing penetrations. Highly specialized equipment is utilized to prepare rock samples in assessing microstructures which contribute to porosity and permeability. Analysis of dynamic data is then incorporated to arrive at the estimated fractional recovery of hydrocarbons in place. Data analysis techniques employed include, but are not limited to, well testing analysis, static bottom hole pressure analysis, flowing bottom hole pressure analysis, analysis of historical production trends, pressure transient analysis and rate transient analysis. Application of proprietary rate transient analysis techniques in low permeability rocks allow for quantification of estimates of contribution to production from both fractures and rock matrices. The impact of optimal completion techniques is a key factor in determining if prospective locations are reasonably certain of being economically producible. EOG's technical staff estimates recovery improvement that might be achieved when completing horizontal wells with multi-stage fracture stimulation. In the early stages of development of a play, EOG determines the optimal length of the horizontal lateral and multi-stage fracture stimulation using the aforementioned analysis techniques along with pilot drilling programs and gathering of microseismic data. The process of analyzing static and dynamic data, well completion optimization and the results of early development activities provides the appropriate level of certainty as well as support for the economic producibilty of the plays in which PUDs are reflected. EOG has found this approach to be effective based on successful application in analogous reservoirs in low permeability resource plays. EOG has formulated development plans for all drilling locations associated with its PUDs at December 31, 2012. Under EOG's current drilling and development plan, each PUD location will be drilled within five years from the date it was recorded. Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices, production volumes and the length of wells, both vertical and horizontal. Canadian reserves, as presented on a net basis, assume prices and legislated future royalty rates and EOG's estimate of future production volumes. Similarly, certain of EOG's Trinidad reserves are held under production sharing contracts where EOG's interest varies with prices and production volumes. Trinidad reserves, as presented on a net basis, assume prices in existence at the time the estimates were made and EOG's estimate of future production volumes. Future fluctuations in prices, production rates or changes in political or regulatory environments could cause EOG's share of future production from Canadian and Trinidadian reserves to be materially different from that presented. Estimates of proved reserves at December 31, 2012, 2011 and 2010 were based on studies performed by the engineering staff of EOG. The Engineering and Acquisitions Department is directly responsible for EOG's reserve evaluation process and consists of seven professionals, all of whom hold, at a minimum, bachelor's degrees in engineering, and two of whom are Registered Professional Engineers. The Manager, Engineering and Acquisitions is the manager of this department and is the primary technical person responsible for this process. The Manager, Engineering and Acquisitions holds a Bachelor of Science degree in Petroleum Engineering, has 27 years of experience in reserve evaluations and is a Registered Professional Engineer in the State of Texas. EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) EOG's reserves estimation process is a collaborative effort coordinated by the Engineering and Acquisitions Department in compliance with EOG's internal controls for such process. Reserve information as well as models used to estimate such reserves are stored on secured databases. Non-technical inputs used in reserve estimation models, including crude oil, NGLs and natural gas prices, production costs, future capital expenditures and EOG's net ownership percentages are obtained from other departments within EOG. EOG's Internal Audit Department conducts testing with respect to such non-technical inputs. Additionally, EOG engages DeGolyer and MacNaughton (D&M), independent petroleum consultants, to perform independent reserves evaluation of select EOG properties comprising not less than 75% of EOG's estimates of proved reserves. EOG's Board of Directors requires that D&M's and EOG's reserve quantities for the properties evaluated by D&M vary by no more than 5% in the aggregate. Once completed, EOG's year-end reserves are presented to senior management, including the Chairman of the Board and Chief Executive Officer, the President, the Chief Operating Officer, and the Vice President and Chief Financial Officer, for approval. Opinions by D&M for the years ended December 31, 2012, 2011 and 2010 covered producing areas containing 87%, 85% and 77%, respectively, of proved reserves of EOG on a net-equivalent-barrel-of-oil basis. D&M's opinions indicate that the estimates of proved reserves prepared by EOG's Engineering and Acquisitions Department for the properties reviewed by D&M, when compared in total on a net-equivalent-barrel-of-oil basis, do not differ materially from the estimates prepared by D&M. Such estimates by D&M in the aggregate varied by not more than 5% from those prepared by the Engineering and Acquisitions Department of EOG. All reports by D&M were developed utilizing geological and engineering data provided by EOG. The report of D&M dated January 29, 2013, which contains further discussion of the reserve estimates and evaluations prepared by D&M, as well as the qualifications of D&M's technical person primarily responsible for overseeing such estimates and evaluations, is attached as Exhibit 23.2 to this Annual Report on Form 10-K and incorporated herein by reference. No major discovery or other favorable or adverse event subsequent to December 31, 2012, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date. EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The following tables set forth EOG's net proved and proved developed reserves at December 31 for each of the four years in the period ended December 31, 2012, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2012, as estimated by the Engineering and Acquisitions Department of EOG: NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY
| United |  |  |  |  |  | Other |  |
| States |  | Canada |  | Trinidad |  | International (1) |  | Total
NET PROVED RESERVES |  |  |  |  |  |  |  |  |
Crude Oil (MBbl) (2) |  |  |  |  |  |  |  |  |
Net proved reserves at December 31, 2009 | 188,452 |  | 25,586 |  | 5,443 |  | 58 |  | 219,539
| Revisions of previous estimates | (8,313) |  | (104) |  | (754) |  | 20 |  | (9,151)
| Purchases in place | 13 |  | - |  | - |  | - |  | 13
| Extensions, discoveries and other additions | 199,479 |  | 3,198 |  | 1,751 |  | 48 |  | 204,476
| Sales in place | (1,082) |  | (589) |  | - |  | - |  | (1,671)
| Production | (23,092) |  | (2,455) |  | (1,709) |  | (28) |  | (27,284)
Net proved reserves at December 31, 2010 | 355,457 |  | 25,636 |  | 4,731 |  | 98 |  | 385,922
| Revisions of previous estimates | (21,188) |  | (4,611) |  | 18 |  | 25 |  | (25,756)
| Purchases in place | 9 |  | - |  | - |  | - |  | 9
| Extensions, discoveries and other additions | 202,552 |  | 449 |  | - |  | - |  | 203,001
| Sales in place | (4,301) |  | - |  | - |  | - |  | (4,301)
| Production | (37,233) |  | (2,882) |  | (1,242) |  | (25) |  | (41,382)
Net proved reserves at December 31, 2011 | 495,296 |  | 18,592 |  | 3,507 |  | 98 |  | 517,493
| Revisions of previous estimates | 4,105 |  | (2,493) |  | 71 |  | 5 |  | 1,688
| Purchases in place | 1,010 |  | - |  | - |  | - |  | 1,010
| Extensions, discoveries and other additions | 241,171 |  | 5,681 |  | - |  | 8,834 |  | 255,686
| Sales in place | (15,921) |  | (1,343) |  | - |  | - |  | (17,264)
| Production | (54,632) |  | (2,574) |  | (550) |  | (39) |  | (57,795)
Net proved reserves at December 31, 2012 | 671,029 |  | 17,863 |  | 3,028 |  | 8,898 |  | 700,818
Natural Gas Liquids (MBbl) (2) |  |  |  |  |  |  |  |  |
Net proved reserves at December 31, 2009 | 91,489 |  | 1,972 |  | - |  | - |  | 93,461
| Revisions of previous estimates | 27,490 |  | (196) |  | - |  | - |  | 27,294
| Purchases in place | - |  | - |  | - |  | - |  | -
| Extensions, discoveries and other additions | 42,221 |  | 21 |  | - |  | - |  | 42,242
| Sales in place | (2) |  | (6) |  | - |  | - |  | (8)
| Production | (10,764) |  | (316) |  | - |  | - |  | (11,080)
Net proved reserves at December 31, 2010 | 150,434 |  | 1,475 |  | - |  | - |  | 151,909
| Revisions of previous estimates | 35,999 |  | 43 |  | - |  | - |  | 36,042
| Purchases in place | 17 |  | - |  | - |  | - |  | 17
| Extensions, discoveries and other additions | 65,288 |  | - |  | - |  | - |  | 65,288
| Sales in place | (10,008) |  | - |  | - |  | - |  | (10,008)
| Production | (15,144) |  | (316) |  | - |  | - |  | (15,460)
Net proved reserves at December 31, 2011 | 226,586 |  | 1,202 |  | - |  | - |  | 227,788
| Revisions of previous estimates | 47,293 |  | 563 |  | - |  | - |  | 47,856
| Purchases in place | 612 |  | - |  | - |  | - |  | 612
| Extensions, discoveries and other additions | 71,396 |  | 178 |  | - |  | - |  | 71,574
| Sales in place | (7,300) |  | (77) |  | - |  | - |  | (7,377)
| Production | (20,181) |  | (309) |  | - |  | - |  | (20,490)
Net proved reserves at December 31, 2012 | 318,406 |  | 1,557 |  | - |  | - |  | 319,963
EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| United |  |  |  |  |  | Other |  |
| States |  | Canada |  | Trinidad |  | International (1) |  | Total
Natural Gas (Bcf) (3) |  |  |  |  |  |  |  |  |
Net proved reserves at December 31, 2009 | 6,350.1 |  | 1,549.5 |  | 985.8 |  | 12.7 |  | 8,898.1
| Revisions of previous estimates | (222.7) |  | (29.9) |  | (88.6) |  | 1.9 |  | (339.3)
| Purchases in place | - |  | - |  | - |  | - |  | -
| Extensions, discoveries and other additions | 821.3 |  | 3.4 |  | 63.0 |  | 7.9 |  | 895.6
| Sales in place | (34.6) |  | (316.2) |  | - |  | - |  | (350.8)
| Production | (422.6) |  | (73.0) |  | (132.6) |  | (5.2) |  | (633.4)
Net proved reserves at December 31, 2010 | 6,491.5 |  | 1,133.8 |  | 827.6 |  | 17.3 |  | 8,470.2
| Revisions of previous estimates | (344.0) |  | (49.8) |  | (24.2) |  | 1.3 |  | (416.7)
| Purchases in place | 3.0 |  | - |  | - |  | - |  | 3.0
| Extensions, discoveries and other additions | 634.6 |  | - |  | 74.7 |  | 4.5 |  | 713.8
| Sales in place | (323.6) |  | - |  | - |  | - |  | (323.6)
| Production | (415.7) |  | (48.1) |  | (127.4) |  | (4.6) |  | (595.8)
Net proved reserves at December 31, 2011 | 6,045.8 |  | 1,035.9 |  | 750.7 |  | 18.5 |  | 7,850.9
| Revisions of previous estimates | (1,736.0) |  | (894.5) |  | (24.1) |  | 1.6 |  | (2,653.0)
| Purchases in place | 14.8 |  | - |  | - |  | - |  | 14.8
| Extensions, discoveries and other additions | 477.8 |  | - |  | - |  | 0.3 |  | 478.1
| Sales in place | (386.2) |  | (8.5) |  | - |  | - |  | (394.7)
| Production | (380.2) |  | (34.6) |  | (138.4) |  | (3.4) |  | (556.6)
Net proved reserves at December 31, 2012 | 4,036.0 |  | 98.3 |  | 588.2 |  | 17.0 |  | 4,739.5
Oil Equivalents (MBoe) (2) |  |  |  |  |  |  |  |  |
Net proved reserves at December 31, 2009 | 1,338,292 |  | 285,808 |  | 169,747 |  | 2,172 |  | 1,796,019
| Revisions of previous estimates | (17,945) |  | (5,288) |  | (15,513) |  | 342 |  | (38,404)
| Purchases in place | 14 |  | - |  | - |  | - |  | 14
| Extensions, discoveries and other additions | 378,582 |  | 3,789 |  | 12,250 |  | 1,363 |  | 395,984
| Sales in place | (6,860) |  | (53,288) |  | - |  | - |  | (60,148)
| Production | (104,277) |  | (14,937) |  | (23,815) |  | (901) |  | (143,930)
Net proved reserves at December 31, 2010 | 1,587,806 |  | 216,084 |  | 142,669 |  | 2,976 |  | 1,949,535
| Revisions of previous estimates | (42,526) |  | (12,865) |  | (4,011) |  | 239 |  | (59,163)
| Purchases in place | 521 |  | - |  | - |  | - |  | 521
| Extensions, discoveries and other additions | 373,602 |  | 448 |  | 12,455 |  | 750 |  | 387,255
| Sales in place | (68,247) |  | - |  | - |  | - |  | (68,247)
| Production | (121,648) |  | (11,219) |  | (22,484) |  | (787) |  | (156,138)
Net proved reserves at December 31, 2011 | 1,729,508 |  | 192,448 |  | 128,629 |  | 3,178 |  | 2,053,763
| Revisions of previous estimates | (237,936) |  | (151,015) |  | (3,953) |  | 283 |  | (392,621)
| Purchases in place | 4,098 |  | - |  | - |  | - |  | 4,098
| Extensions, discoveries and other additions | 392,196 |  | 5,860 |  | - |  | 8,876 |  | 406,932
| Sales in place | (87,588) |  | (2,832) |  | - |  | - |  | (90,420)
| Production | (138,170) |  | (8,657) |  | (23,616) |  | (611) |  | (171,054)
Net proved reserves at December 31, 2012 | 1,662,108 |  | 35,804 |  | 101,060 |  | 11,726 |  | 1,810,698
(1) | Other International includes EOG's United Kingdom, China and Argentina operations.
(2) | Thousand barrels or thousand barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGLs and natural gas. Oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas.
(3) | Billion cubic feet.
EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) During 2012, EOG added 407 million barrels of oil equivalent (MMBoe) of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Permian Basin, Bakken and Barnett Combo shale plays. Approximately 80% of the 2012 reserve additions were crude oil and condensate and NGLs and over 96% were in the United States. Sales in place of 90 MMBoe were primarily related to the disposition of certain producing natural gas assets on the Gulf Coast, outside-operated crude oil properties in the Rocky Mountain area and other producing basins in the United States. Revisions of previous estimates of negative 393 MMBoe for 2012 included a negative revision of 531 MMBoe primarily due to a decrease in the average natural gas price used in the December 31, 2012 reserves estimation as compared to the price used in the prior year estimate. The primary plays affected were the Horn River, Haynesville, Barnett Shale and Marcellus Shale. Revisions other than price resulted from revisions for certain crude oil and natural gas properties in the United States. During 2011, EOG added 387 million barrels of oil equivalent (MMBoe) of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Barnett Combo and Bakken shale plays. Approximately 69% of the 2011 reserve additions were crude oil and condensate and NGLs and over 96% were in the United States. Sales in place of 68 MMBoe were primarily related to the disposition of certain producing natural gas assets in East Texas, the Rocky Mountain area and other producing basins in the United States. Revisions of previous estimates of negative 59 MMBoe for 2011 included a negative revision of 16 MMBoe primarily due to a decrease in the average natural gas price used in the December 31, 2011 reserves estimation as compared to the price used in the prior year estimate. Revisions other than price resulted from negative revisions for certain crude oil and natural gas properties in the United States, Canada and Trinidad. During 2010, EOG added 396 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Bakken, Barnett Combo and Haynesville shale plays. Approximately 62% of the 2010 reserve additions were crude oil and condensate and NGLs and over 95% were in the United States. Sales in place of 60 MMBoe were primarily related to the Canadian shallow natural gas assets and certain producing natural gas assets in East Texas. Revisions of previous estimates of negative 38 MMBoe for 2010 included a positive revision of 28 MMBoe primarily due to an increase in the average natural gas price used in the December 31, 2010 reserves estimation as compared to the price used in the prior year estimate. Revisions other than price resulted from negative revisions for certain natural gas properties in the United States, Canada and Trinidad and the removal of proved undeveloped natural gas drilling locations from the five-year drilling plan to focus on crude oil and liquids-rich drilling as part of EOG's overall strategy. EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| United |  |  |  |  |  | Other |  |
| States |  | Canada |  | Trinidad |  | International (1) |  | Total
NET PROVED DEVELOPED RESERVES |  |  |  |  |  |  |  |  |
Liquids (MBbl) |  |  |  |  |  |  |  |  |
| December 31, 2009 | 189,322 |  | 10,831 |  | 3,966 |  | 58 |  | 204,177
| December 31, 2010 | 253,308 |  | 12,758 |  | 3,853 |  | 98 |  | 270,017
| December 31, 2011 | 338,144 |  | 9,220 |  | 2,657 |  | 97 |  | 350,118
| December 31, 2012 | 442,648 |  | 7,963 |  | 2,378 |  | 253 |  | 453,242
Natural Gas (Bcf) |  |  |  |  |  |  |  |  |
| December 31, 2009 | 3,330.1 |  | 681.0 |  | 609.4 |  | 12.7 |  | 4,633.2
| December 31, 2010 | 3,519.7 |  | 401.6 |  | 519.2 |  | 17.3 |  | 4,457.8
| December 31, 2011 | 3,234.9 |  | 295.8 |  | 606.3 |  | 18.6 |  | 4,155.6
| December 31, 2012 | 2,387.5 |  | 98.3 |  | 476.7 |  | 17.0 |  | 2,979.5
Oil Equivalents (MBoe) |  |  |  |  |  |  |  |  |
| December 31, 2009 | 744,339 |  | 124,323 |  | 105,540 |  | 2,172 |  | 976,374
| December 31, 2010 | 839,928 |  | 79,701 |  | 90,382 |  | 2,976 |  | 1,012,987
| December 31, 2011 | 877,301 |  | 58,524 |  | 103,710 |  | 3,178 |  | 1,042,713
| December 31, 2012 | 840,564 |  | 24,348 |  | 81,826 |  | 3,081 |  | 949,819
NET PROVED UNDEVELOPED RESERVES |  |  |  |  |  |  |  |  |
Liquids (MBbl) |  |  |  |  |  |  |  |  |
| December 31, 2009 | 90,619 |  | 16,727 |  | 1,477 |  | - |  | 108,823
| December 31, 2010 | 252,583 |  | 14,352 |  | 879 |  | - |  | 267,814
| December 31, 2011 | 383,739 |  | 10,574 |  | 850 |  | - |  | 395,163
| December 31, 2012 | 546,786 |  | 11,456 |  | 651 |  | 8,645 |  | 567,538
Natural Gas (Bcf) |  |  |  |  |  |  |  |  |
| December 31, 2009 | 3,020.0 |  | 868.5 |  | 376.4 |  | - |  | 4,264.9
| December 31, 2010 | 2,971.7 |  | 732.2 |  | 308.5 |  | - |  | 4,012.4
| December 31, 2011 | 2,810.8 |  | 740.1 |  | 144.4 |  | - |  | 3,695.3
| December 31, 2012 | 1,648.5 |  | - |  | 111.5 |  | - |  | 1,760.0
Oil Equivalents (MBoe) |  |  |  |  |  |  |  |  |
| December 31, 2009 | 593,953 |  | 161,486 |  | 64,207 |  | - |  | 819,646
| December 31, 2010 | 747,878 |  | 136,383 |  | 52,287 |  | - |  | 936,548
| December 31, 2011 | 852,207 |  | 133,924 |  | 24,919 |  | - |  | 1,011,050
| December 31, 2012 | 821,544 |  | 11,456 |  | 19,234 |  | 8,645 |  | 860,879
(1) | Other International includes EOG's United Kingdom, China and Argentina operations.
EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) For the twelve-month period ended December 31, 2012, total PUDs decreased by 150 MMBoe to 861 MMBoe. EOG added approximately 32 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion. Based on the technology employed by EOG to identify and record PUDs (see discussion of technology employed on page F-33 of this Annual Report on Form 10-K), EOG added 268 MMBoe. The PUD additions were primarily in the Eagle Ford, Permian Basin, Bakken and Barnett Combo shale plays, and nearly 84% of the additions were crude oil and condensate and NGLs. During 2012, EOG drilled and transferred 138 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,764 million. Revisions of PUDs totaled negative 293 MMBoe, primarily due to removal of certain natural gas PUDs due to lower average natural gas prices. The primary plays affected were the Horn River, Haynesville, Barnett Shale and Marcellus Shale. During 2012, EOG sold 19 MMBoe of PUDs. For the twelve-month period ended December 31, 2011, total PUDs increased by 75 MMBoe to 1,011 MMBoe. EOG added approximately 36 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion. Based on the technology employed by EOG to identify and record PUDs, EOG added 199 MMBoe. The PUD additions were primarily in the Eagle Ford and Barnett Combo shale plays, and over 78% of the additions were crude oil and condensate and NGLs. During 2011, EOG drilled and transferred 144 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,619 million. Revisions of PUDs totaled negative 7 MMBoe, primarily due to removal of certain natural gas PUDs from the five-year drilling plan. During 2011, EOG sold 9 MMBoe of PUDs. For the twelve-month period ended December 31, 2010, total PUDs increased by 117 MMBoe to 937 MMBoe. EOG added approximately 37 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion. Based on the technology employed by EOG to identify and record PUDs, EOG added 218 MMBoe. The PUD additions were primarily in the Eagle Ford, Bakken, Barnett Combo and Haynesville shale plays, and nearly 73% of the additions were crude oil and condensate and NGLs. During 2010, EOG drilled and transferred 118 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,280 million. Revisions of PUDs totaled negative 12 MMBoe, primarily due to removal of certain natural gas PUDs from the five-year drilling plan. During 2010, EOG sold 8 MMBoe of PUDs. As of December 31, 2012, EOG did not have any reserves that have remained undeveloped for five or more years. EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Capitalized Costs Relating to Oil and Gas Producing Activities. The following table sets forth the capitalized costs relating to EOG's crude oil and natural gas producing activities at December 31, 2012 and 2011:
|  | 2012 |  | 2011
Proved properties | $ | 36,872,434 | $ | 32,353,380
Unproved properties |  | 1,253,864 |  | 1,311,055
| Total |  | 38,126,298 |  | 33,664,435
Accumulated depreciation, depletion and amortization |  | (16,849,068) |  | (13,981,143)
| Net capitalized costs | $ | 21,277,230 | $ | 19,683,292
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities. The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in the Extractive Industries - Oil and Gas Topic of the ASC. Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include additions to exploratory wells, including those in progress, and exploration expenses. Development costs include additions to production facilities and equipment and additions to development wells, including those in progress. EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended December 31, 2012, 2011 and 2010:
|  | United |  |  |  |  |  | Other |  |
|  | States |  | Canada |  | Trinidad |  | International (1) |  | Total
2012 |  |  |  |  |  |  |  |  |  |
Acquisition Costs of Properties |  |  |  |  |  |  |  |  |  |
| Unproved | $ | 471,345 | $ | 33,561 | $ | 1,000 | $ | (603) | $ | 505,303
| Proved |  | 739 |  | - |  | - |  | - |  | 739
|  | Subtotal |  | 472,084 |  | 33,561 |  | 1,000 |  | (603) |  | 506,042
Exploration Costs |  | 333,534 |  | 38,530 |  | 19,555 |  | 53,979 |  | 445,598
Development Costs (2) |  | 5,657,378 |  | 278,995 |  | 32,609 |  | 147,568 |  | 6,116,550
|  | Total | $ | 6,462,996 | $ | 351,086 | $ | 53,164 | $ | 200,944 | $ | 7,068,190
2011 |  |  |  |  |  |  |  |  |  |
Acquisition Costs of Properties |  |  |  |  |  |  |  |  |  |
| Unproved | $ | 295,160 | $ | 6,216 | $ | - | $ | (604) | $ | 300,772
| Proved |  | 4,219 |  | 28 |  | - |  | - |  | 4,247
|  | Subtotal |  | 299,379 |  | 6,244 |  | - |  | (604) |  | 305,019
Exploration Costs |  | 311,369 |  | 31,472 |  | 2,549 |  | 18,164 |  | 363,554
Development Costs (3) |  | 5,410,378 |  | 302,564 |  | 138,905 |  | 78,744 |  | 5,930,591
|  | Total | $ | 6,021,126 | $ | 340,280 | $ | 141,454 | $ | 96,304 | $ | 6,599,164
2010 |  |  |  |  |  |  |  |  |  |
Acquisition Costs of Properties |  |  |  |  |  |  |  |  |  |
| Unproved | $ | 403,509 | $ | 13,956 | $ | - | $ | (107) | $ | 417,358
| Proved |  | - |  | - |  | - |  | - |  | -
|  | Subtotal |  | 403,509 |  | 13,956 |  | - |  | (107) |  | 417,358
Exploration Costs |  | 454,379 |  | 38,604 |  | 23,386 |  | 86,784 |  | 603,153
Development Costs (4) |  | 3,892,403 |  | 417,176 |  | 114,986 |  | 13,429 |  | 4,437,994
|  | Total | $ | 4,750,291 | $ | 469,736 | $ | 138,372 | $ | 100,106 | $ | 5,458,505
(1) | Other International primarily consists of EOG's United Kingdom, China and Argentina operations.
(2) | Includes Asset Retirement Costs of $80 million, $33 million, $2 million and $12 million for the United States, Canada, Trinidad and Other International, respectively. Excludes other property, plant and equipment.
(3) | Includes Asset Retirement Costs of $52 million, $70 million, $7 million and $4 million for the United States, Canada, Trinidad and Other International, respectively. Excludes other property, plant and equipment.
(4) | Includes Asset Retirement Costs of $71 million, $2 million, $(3) million and $2 million for the United States, Canada, Trinidad and Other International, respectively. Excludes other property, plant and equipment.
EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Results of Operations for Oil and Gas Producing Activities (1). The following table sets forth results of operations for oil and gas producing activities for the years ended December 31, 2012, 2011 and 2010:
|  | United |  |  |  |  |  | Other |  |
|  | States |  | Canada |  | Trinidad |  | International (2) |  | Total
2012 |  |  |  |  |  |  |  |  |  |
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues | $ | 7,048,572 | $ | 321,597 | $ | 565,030 | $ | 23,177 | $ | 7,958,376
Other |  | 40,780 |  | 367 |  | 15 |  | - |  | 41,162
|  | Total |  | 7,089,352 |  | 321,964 |  | 565,045 |  | 23,177 |  | 7,999,538
Exploration Costs |  | 162,152 |  | 13,350 |  | 2,262 |  | 7,805 |  | 185,569
Dry Hole Costs |  | 1,772 |  | 1,570 |  | - |  | 11,628 |  | 14,970
Transportation Costs |  | 591,547 |  | 7,511 |  | 1,104 |  | 1,269 |  | 601,431
Production Costs |  | 1,264,633 |  | 154,509 |  | 37,792 |  | 11,694 |  | 1,468,628
Impairments |  | 294,172 |  | 976,563 |  | - |  | - |  | 1,270,735
Depreciation, Depletion and Amortization |  | 2,637,500 |  | 222,366 |  | 146,690 |  | 17,958 |  | 3,024,514
Income (Loss) Before Income Taxes |  | 2,137,576 |  | (1,053,905) |  | 377,197 |  | (27,177) |  | 1,433,691
Income Tax Provision (Benefit) |  | 761,459 |  | (136,105) |  | 119,442 |  | (21,890) |  | 722,906
Results of Operations | $ | 1,376,117 | $ | (917,800) | $ | 257,755 | $ | (5,287) | $ | 710,785
2011 |  |  |  |  |  |  |  |  |  |
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues | $ | 5,814,942 | $ | 459,853 | $ | 555,143 | $ | 28,250 | $ | 6,858,188
Other |  | 32,329 |  | 258 |  | 586 |  | - |  | 33,173
|  | Total |  | 5,847,271 |  | 460,111 |  | 555,729 |  | 28,250 |  | 6,891,361
Exploration Costs |  | 148,199 |  | 10,479 |  | 2,520 |  | 10,460 |  | 171,658
Dry Hole Costs |  | 30,521 |  | 432 |  | - |  | 22,277 |  | 53,230
Transportation Costs |  | 421,060 |  | 5,969 |  | 1,620 |  | 1,673 |  | 430,322
Production Costs |  | 1,096,955 |  | 174,973 |  | 49,318 |  | 10,964 |  | 1,332,210
Impairments |  | 575,976 |  | 452,103 |  | - |  | 2,958 |  | 1,031,037
Depreciation, Depletion and Amortization |  | 2,011,080 |  | 258,772 |  | 106,802 |  | 17,160 |  | 2,393,814
Income (Loss) Before Income Taxes |  | 1,563,480 |  | (442,617) |  | 395,469 |  | (37,242) |  | 1,479,090
Income Tax Provision (Benefit) |  | 569,153 |  | (121,044) |  | 202,815 |  | (13,056) |  | 637,868
Results of Operations | $ | 994,327 | $ | (321,573) | $ | 192,654 | $ | (24,186) | $ | 841,222
2010 |  |  |  |  |  |  |  |  |  |
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues | $ | 3,928,240 | $ | 477,416 | $ | 447,852 | $ | 27,707 | $ | 4,881,215
Other |  | 19,886 |  | (31) |  | 3,696 |  | - |  | 23,551
|  | Total |  | 3,948,126 |  | 477,385 |  | 451,548 |  | 27,707 |  | 4,904,766
Exploration Costs |  | 156,252 |  | 17,597 |  | 2,277 |  | 11,255 |  | 187,381
Dry Hole Costs |  | 30,927 |  | 14,875 |  | 5,000 |  | 21,684 |  | 72,486
Transportation Costs |  | 372,466 |  | 9,892 |  | 1,348 |  | 1,483 |  | 385,189
Production Costs |  | 763,769 |  | 174,667 |  | 51,125 |  | 8,504 |  | 998,065
Impairments |  | 271,466 |  | 451,703 |  | 1,465 |  | 418 |  | 725,052
Depreciation, Depletion and Amortization |  | 1,430,408 |  | 314,663 |  | 70,553 |  | 15,399 |  | 1,831,023
Income (Loss) Before Income Taxes |  | 922,838 |  | (506,012) |  | 319,780 |  | (31,036) |  | 705,570
Income Tax Provision (Benefit) |  | 375,855 |  | (151,315) |  | 140,413 |  | (14,245) |  | 350,708
Results of Operations | $ | 546,983 | $ | (354,697) | $ | 179,367 | $ | (16,791) | $ | 354,862
(1) | Excludes gains or losses on the mark-to-market of financial commodity derivative contracts, gains or losses on sales of reserves and related assets, interest charges and general corporate expenses for each of the three years in the period ended December 31, 2012.
(2) | Other International primarily consists of EOG's United Kingdom, China and Argentina operations.
EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The following table sets forth production costs per barrel of oil equivalent, excluding severance/production and ad valorem taxes, for the years ended December 31, 2012, 2011 and 2010:
|  | United |  |  |  |  |  | Other |  |
|  | States |  | Canada |  | Trinidad |  | International (1) |  | Composite
Year Ended December 31, 2012 | $ | 5.96 | $ | 16.42 | $ | 0.98 | $ | 18.97 | $ | 5.85
Year Ended December 31, 2011 | $ | 6.19 | $ | 14.26 | $ | 0.78 | $ | 13.82 | $ | 6.03
Year Ended December 31, 2010 | $ | 5.00 | $ | 10.28 | $ | 0.65 | $ | 9.34 | $ | 4.85
(1) Other International primarily consists of EOG's United Kingdom, China and Argentina operations. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves. The following information has been developed utilizing procedures prescribed by the Extractive Industries - Oil and Gas Topic of the ASC and based on crude oil, NGLs and natural gas reserves and production volumes estimated by the Engineering and Acquisitions Department of EOG. The estimates were based on a 12-month average for commodity prices for the years 2012, 2011 and 2010. The following information may be useful for certain comparison purposes, but should not be solely relied upon in evaluating EOG or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of EOG. The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil, NGLs and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated. EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The following table sets forth the standardized measure of discounted future net cash flows from projected production of EOG's oil and gas reserves for the years ended December 31, 2012, 2011 and 2010:
|  | United |  |  |  |  |  | Other |  |
|  | States |  | Canada |  | Trinidad |  | International (1) |  | Total
2012 |  |  |  |  |  |  |  |  |  |
| Future cash inflows (2) | $ | 89,324,274 | $ | 1,816,369 | $ | 2,408,116 | $ | 1,063,854 | $ | 94,612,613
| Future production costs |  | (35,892,997) |  | (751,113) |  | (342,113) |  | (198,609) |  | (37,184,832)
| Future development costs |  | (15,825,040) |  | (813,061) |  | (171,737) |  | (221,893) |  | (17,031,731)
| Future income taxes |  | (10,247,007) |  | - |  | (691,109) |  | (212,626) |  | (11,150,742)
| Future net cash flows |  | 27,359,230 |  | 252,195 |  | 1,203,157 |  | 430,726 |  | 29,245,308
| Discount to present value at 10% annual rate |  | (12,177,896) |  | 146,954 |  | (242,087) |  | (56,807) |  | (12,329,836)
| Standardized measure of discounted future net cash flows relating to proved oil and gas reserves | $ | 15,181,334 | $ | 399,149 | $ | 961,070 | $ | 373,919 | $ | 16,915,472
2011 |  |  |  |  |  |  |  |  |  |
| Future cash inflows (3) | $ | 84,518,638 | $ | 5,056,501 | $ | 2,851,545 | $ | 103,853 | $ | 92,530,537
| Future production costs |  | (33,294,343) |  | (2,315,110) |  | (388,199) |  | (62,938) |  | (36,060,590)
| Future development costs |  | (13,811,449) |  | (1,566,917) |  | (149,884) |  | (331) |  | (15,528,581)
| Future income taxes |  | (10,539,182) |  | (81,590) |  | (794,856) |  | (2,457) |  | (11,418,085)
| Future net cash flows |  | 26,873,664 |  | 1,092,884 |  | 1,518,606 |  | 38,127 |  | 29,523,281
| Discount to present value at 10% annual rate |  | (12,498,010) |  | (456,537) |  | (334,399) |  | (9,054) |  | (13,298,000)
| Standardized measure of discounted future net cash flows relating to proved oil and gas reserves | $ | 14,375,654 | $ | 636,347 | $ | 1,184,207 | $ | 29,073 | $ | 16,225,281
2010 |  |  |  |  |  |  |  |  |  |
| Future cash inflows (4) | $ | 62,063,123 | $ | 6,040,422 | $ | 2,760,819 | $ | 91,805 | $ | 70,956,169
| Future production costs |  | (22,616,039) |  | (2,711,415) |  | (384,147) |  | (48,953) |  | (25,760,554)
| Future development costs |  | (9,596,005) |  | (1,716,734) |  | (198,072) |  | (334) |  | (11,511,145)
| Future income taxes |  | (8,503,301) |  | (129,816) |  | (850,699) |  | (3,598) |  | (9,487,414)
| Future net cash flows |  | 21,347,778 |  | 1,482,457 |  | 1,327,901 |  | 38,920 |  | 24,197,056
| Discount to present value at 10% annual rate |  | (10,718,854) |  | (736,222) |  | (339,035) |  | (11,121) |  | (11,805,232)
| Standardized measure of discounted future net cash flows relating to proved oil and gas reserves | $ | 10,628,924 | $ | 746,235 | $ | 988,866 | $ | 27,799 | $ | 12,391,824
(1) | Other International includes EOG's United Kingdom, China and Argentina operations.
(2) | Estimated crude oil prices used to calculate 2012 future cash inflows for the United States, Canada, Trinidad and Other International were $99.78, $84.77, $94.46 and $109.94, respectively. Estimated NGLs prices used to calculate 2012 future cash inflows for the United States and Canada were $36.95 and $47.80, respectively. Estimated natural gas prices used to calculate 2012 future cash inflows for the United States, Canada, Trinidad and Other International were $2.63, $2.22, $3.61 and $5.04, respectively.
(3) | Estimated crude oil prices used to calculate 2011 future cash inflows for the United States, Canada, Trinidad and Other International were $97.75, $90.70, $92.50 and $102.86, respectively. Estimated NGLs prices used to calculate 2011 future cash inflows for the United States and Canada were $51.77 and $46.97, respectively. Estimated natural gas prices used to calculate 2011 future cash inflows for the United States, Canada, Trinidad and Other International were $4.03, $3.28, $3.37, and $5.07, respectively.
(4) | Estimated crude oil prices used to calculate 2010 future cash inflows for the United States, Canada, Trinidad and Other International were $76.38, $72.59, $69.56 and $73.88, respectively. Estimated NGLs prices used to calculate 2010 future cash inflows for the United States and Canada were $43.85 and $26.56, respectively. Estimated natural gas prices used to calculate 2010 future cash inflows for the United States, Canada, Trinidad and Other International were $4.36, $3.67, $2.94 and $5.02, respectively.
EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Changes in Standardized Measure of Discounted Future Net Cash Flows. The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 2012:
|  | United |  |  |  |  |  | Other |  |
|  | States |  | Canada |  | Trinidad |  | International |  | Total
December 31, 2009 | $ | 5,822,916 | $ | 1,037,244 | $ | 665,563 | $ | 15,295 | $ | 7,541,018
| Sales and transfers of oil and gas produced, net of production costs |  | (2,792,005) |  | (292,857) |  | (395,379) |  | (17,720) |  | (3,497,961)
| Net changes in prices and production costs |  | 2,468,907 |  | (559) |  | 721,796 |  | 7,259 |  | 3,197,403
| Extensions, discoveries, additions and improved recovery, net of related costs |  | 4,319,659 |  | 75,162 |  | 183,453 |  | - |  | 4,578,274
| Development costs incurred |  | 864,700 |  | 175,100 |  | 67,300 |  | - |  | 1,107,100
| Revisions of estimated development cost |  | (257,360) |  | 260,290 |  | (767) |  | 9 |  | 2,172
| Revisions of previous quantity estimates |  | (164,748) |  | (38,382) |  | (175,002) |  | 4,006 |  | (374,126)
| Accretion of discount |  | 755,001 |  | 102,022 |  | 101,549 |  | 1,778 |  | 960,350
| Net change in income taxes |  | (1,171,384) |  | 101,966 |  | (258,354) |  | 2,469 |  | (1,325,303)
| Purchases of reserves in place |  | 265 |  | - |  | - |  | - |  | 265
| Sales of reserves in place |  | (54,057) |  | (290,592) |  | - |  | - |  | (344,649)
| Changes in timing and other |  | 837,030 |  | (383,159) |  | 78,707 |  | 14,703 |  | 547,281
December 31, 2010 |  | 10,628,924 |  | 746,235 |  | 988,866 |  | 27,799 |  | 12,391,824
| Sales and transfers of oil and gas produced, net of production costs |  | (4,296,926) |  | (278,910) |  | (504,205) |  | (15,614) |  | (5,095,655)
| Net changes in prices and production costs |  | 716,682 |  | (57,545) |  | 331,196 |  | 3,328 |  | 993,661
| Extensions, discoveries, additions and improved recovery, net of related costs |  | 6,223,552 |  | 22,591 |  | 102,548 |  | - |  | 6,348,691
| Development costs incurred |  | 1,422,500 |  | 48,200 |  | 74,800 |  | - |  | 1,545,500
| Revisions of estimated development cost |  | (210,919) |  | 64,001 |  | (14,074) |  | 2 |  | (160,990)
| Revisions of previous quantity estimates |  | (482,496) |  | (70,718) |  | (56,884) |  | 801 |  | (609,297)
| Accretion of discount |  | 1,352,740 |  | 62,725 |  | 159,715 |  | 2,782 |  | 1,577,962
| Net change in income taxes |  | (1,049,641) |  | (118,988) |  | 9,511 |  | 13 |  | (1,159,105)
| Purchases of reserves in place |  | 5,241 |  | - |  | - |  | - |  | 5,241
| Sales of reserves in place |  | (658,468) |  | - |  | - |  | - |  | (658,468)
| Changes in timing and other |  | 724,465 |  | 218,756 |  | 92,734 |  | 9,962 |  | 1,045,917
December 31, 2011 |  | 14,375,654 |  | 636,347 |  | 1,184,207 |  | 29,073 |  | 16,225,281
| Sales and transfers of oil and gas produced, net of production costs |  | (5,192,392) |  | (159,577) |  | (526,134) |  | (10,214) |  | (5,888,317)
| Net changes in prices and production costs |  | (393,585) |  | (67,964) |  | 162,600 |  | (2,283) |  | (301,232)
| Extensions, discoveries, additions and improved recovery, net of related costs |  | 5,517,945 |  | 79,529 |  | - |  | 484,648 |  | 6,082,122
| Development costs incurred |  | 2,042,300 |  | 23,600 |  | 23,500 |  | 5,200 |  | 2,094,600
| Revisions of estimated development cost |  | 1,987,330 |  | 383,215 |  | (28,835) |  | (234) |  | 2,341,476
| Revisions of previous quantity estimates |  | (3,286,943) |  | (396,408) |  | (62,285) |  | 2,809 |  | (3,742,827)
| Accretion of discount |  | 1,832,377 |  | 63,635 |  | 178,298 |  | 2,907 |  | 2,077,217
| Net change in income taxes |  | 174,418 |  | - |  | 88,853 |  | (138,206) |  | 125,065
| Purchases of reserves in place |  | 64,317 |  | - |  | - |  | 5,623 |  | 69,940
| Sales of reserves in place |  | (869,534) |  | (44,227) |  | - |  | - |  | (913,761)
| Changes in timing and other |  | (1,070,553) |  | (119,001) |  | (59,134) |  | (5,404) |  | (1,254,092)
December 31, 2012 | $ | 15,181,334 | $ | 399,149 | $ | 961,070 | $ | 373,919 | $ | 16,915,472
EOG RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded) Unaudited Quarterly Financial Information (In Thousands, Except Per Share Data)
Quarter Ended |  | Mar 31 |  | Jun 30 |  | Sep 30 |  | Dec 31
2012 |  |  |  |  |  |  |  |
| Net Operating Revenues | $ | 2,806,651 | $ | 2,909,319 | $ | 2,954,855 | $ | 3,011,811
| Operating Income (Loss) | $ | 559,772 | $ | 692,339 | $ | 605,747 | $ | (378,061)
| Income (Loss) Before Income Taxes | $ | 520,134 | $ | 646,239 | $ | 560,189 | $ | (445,822)
| Income Tax Provision |  | 196,125 |  | 250,461 |  | 204,698 |  | 59,177
| Net Income (Loss) (1) | $ | 324,009 | $ | 395,778 | $ | 355,491 | $ | (504,999)
| Net Income (Loss) Per Share (2) |  |  |  |  |  |  |  |
|  | Basic | $ | 1.22 | $ | 1.48 | $ | 1.33 | $ | (1.88)
|  | Diluted | $ | 1.20 | $ | 1.47 | $ | 1.31 | $ | (1.88)
| Average Number of Common Shares |  |  |  |  |  |  |  |
|  | Basic |  | 266,674 |  | 266,874 |  | 267,941 |  | 268,941
|  | Diluted |  | 270,242 |  | 269,985 |  | 270,982 |  | 268,941
2011 |  |  |  |  |  |  |  |
| Net Operating Revenues | $ | 1,897,106 | $ | 2,570,250 | $ | 2,885,744 | $ | 2,773,015
| Operating Income | $ | 272,451 | $ | 588,253 | $ | 950,030 | $ | 302,575
| Income Before Income Taxes | $ | 225,722 | $ | 543,224 | $ | 899,221 | $ | 241,632
| Income Tax Provision |  | 91,749 |  | 247,650 |  | 358,343 |  | 120,934
| Net Income | $ | 133,973 | $ | 295,574 | $ | 540,878 | $ | 120,698
| Net Income Per Share (1) |  |  |  |  |  |  |  |
|  | Basic | $ | 0.52 | $ | 1.11 | $ | 2.03 | $ | 0.45
|  | Diluted | $ | 0.52 | $ | 1.10 | $ | 2.01 | $ | 0.45
| Average Number of Common Shares |  |  |  |  |  |  |  |
|  | Basic |  | 255,200 |  | 265,830 |  | 266,053 |  | 266,277
|  | Diluted |  | 258,819 |  | 269,332 |  | 269,292 |  | 269,524
(1) | Fourth quarter 2012 results include the impact of pretax impairments of $1,020 million, primarily related to proved and unproved natural gas properties in Canada and the United States as well as an additional income tax provision of $135 million related to valuation allowances recorded to reduce the value of Canadian deferred tax assets.
(2) | The sum of quarterly net income (loss) per share may not agree with total year net income (loss) per share as each quarterly computation is based on the weighted average of common shares outstanding.

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Namespace Prefix: | us-gaap_
Data Type: | xbrli:stringItemType
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- Definition The entire disclosure for oil and gas producing industries. + References Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Accounting Standards Codification -Topic 932 -SubTopic 235 -Section 50 -URI http://asc.fasb.org/section&trid=2145543 Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 19 -Paragraph 59A-59Z, 59AA, 59BB, 59CC -LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy. + Details
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