Oil and Gas Exploration and Production Industries Disclosures

12 Months Ended

Dec. 31, 2011

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Gas Exploration and Production Industries Disclosures

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands, Except Per Share Data Unless Otherwise Indicated)

(Unaudited)

Oil and Gas Producing Activities

In December 2008, the United States Securities and Exchange Commission (SEC) released a final rule, "Modernization of Oil and Gas Reporting," which amended the oil and gas reporting requirements effective January 1, 2010.  The key revisions include:

�   using a 12-month average price to determine reserves;

�   including nontraditional resources in reserves if they are intended to be upgraded to synthetic oil and gas;

�   the ability to use reliable technologies to determine and estimate reserves;

�   permitting the optional disclosure of probable and possible reserves;

�   reporting the independence and qualifications of the reserve preparer or auditor and filing a report as an exhibit when a third party is relied upon to prepare reserve estimates or conduct reserve audits; and

�   disclosing the development of any proved undeveloped reserves, including the total quantity of proved undeveloped reserves at year-end, material changes to proved undeveloped reserves during the year, investments and progress toward the development of proved undeveloped reserves and an explanation of the reasons why material concentrations of proved undeveloped reserves have remained undeveloped for five years or more after disclosure as proved undeveloped reserves

In January 2010, the Financial Accounting Standards Board (FASB) issued FASB Accounting Standards Update (ASU) No. 2010-03, "Oil and Gas Reserve Estimations and Disclosures" (ASU 2010-03).  ASU 2010-03 aligns the current oil and gas reserve estimation and disclosure requirements of the Extractive Industries - Oil and Gas topic of the FASB Accounting Standards Codification (ASC Topic 932) with the changes required by the SEC final rule, "Modernization of Oil and Gas Reporting."  ASU No. 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009.

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 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, natural gas liquids 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 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 are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major 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. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.  Estimates for proved undeveloped reserves 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.

In making estimates of proved undeveloped reserves, 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 and analysis techniques employed include, but are not limited to, well testing, static bottom hole pressure, flowing bottom hole pressure, historical production trends using extant completion techniques (typically from vertical wells), pressure transient analysis and rate transient analysis.  Application of proprietary rate transient analysis techniques 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 employing horizontal wells with multi-stage fracture stimulation.  In the early stages of development, EOG determines the optimal length of the horizontal lateral and multi-stage fracture stimulation using the aforementioned analysis techniques along with pilot drilling programs.

The process of analyzing static and dynamic data, well completion optimization and the results of early development provides the appropriate level of certainty as well as support for the economic producibilty of the plays in which proved undeveloped reserves are reflected.  EOG has found that this approach has been proven effective based on successful application in analogous reservoirs in resource plays.

EOG has formulated development plans for all locations related to its proved undeveloped reserves. 

Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices, production volumes and the length, both vertical and horizontal, of wells.  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, 2011, 2010 and 2009 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 three 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 26 years of experience in reserve evaluations and is a Registered Professional Engineer in the State of Texas.

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, natural gas liquids 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 of not less than 75% 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, 2011, 2010 and 2009 covered producing areas containing 85%, 77% and 81%, 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 February 1, 2012, 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, 2011 is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

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, 2011, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2011, 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, 2008		133,362	7,498	8,326	65	149,251
	Revisions of previous estimates	4,402	(183)	(1,760)	17	2,476
	Purchases in place	15,666	-	-	-	15,666
	Extensions, discoveries and other additions	58,258	19,783	-	-	78,041
	Sales in place	(5,742)	(20)	-	-	(5,762)
	Production	(17,494)	(1,492)	(1,123)	(24)	(20,133)
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
Natural Gas Liquids (MBbl) (2)
Net proved reserves at December 31, 2008		72,484	3,297	-	-	75,781
	Revisions of previous estimates	6,109	(926)	-	-	5,183
	Purchases in place	5,801	-	-	-	5,801
	Extensions, discoveries and other additions	18,546	24	-	-	18,570
	Sales in place	(3,231)	(30)	-	-	(3,261)
	Production	(8,220)	(393)	-	-	(8,613)
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

		United			Other
		States	Canada	Trinidad	International (1)	Total
Natural Gas (Bcf) (3)
Net proved reserves at December 31, 2008		4,889.0	1,237.2	1,198.1	14.9	7,339.2
	Revisions of previous estimates	(378.0)	(447.2)	(104.9)	3.0	(927.1)
	Purchases in place	450.8	-	-	-	450.8
	Extensions, discoveries and other additions	1,925.0	846.5	-	-	2,771.5
	Sales in place	(114.4)	(5.1)	-	-	(119.5)
	Production	(422.3)	(81.9)	(107.4)	(5.2)	(616.8)
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
Oil Equivalents (MBoe) (2)
Net proved reserves at December 31, 2008		1,020,671	217,002	208,013	2,548	1,448,234
	Revisions of previous estimates	(52,487)	(75,638)	(19,250)	515	(146,860)
	Purchases in place	96,605	-	-	-	96,605
	Extensions, discoveries and other additions	397,642	160,882	-	-	558,524
	Sales in place	(28,032)	(898)	-	-	(28,930)
	Production	(96,107)	(15,540)	(19,016)	(891)	(131,554)
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

(1) Other International includes EOG's United Kingdom and China operations.

(2) Thousand barrels or thousand barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas.  Crude oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas.

(3) Billion cubic feet.

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 natural gas liquids 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 region 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 performance 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 natural gas liquids 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 performance 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.

During 2009, EOG added 558 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Haynesville, Horn River, Barnett, Bakken and Marcellus shale plays.  Approximately 82% of the 2009 reserve additions were natural gas.  EOG's revisions of previous estimates for 2009 of negative 147 MMBoe included negative revisions of approximately 131 MMBoe, which were primarily due to the decrease in the average natural gas price used in the December 31, 2009 reserves estimation as compared to the price used in the prior year estimate.  Purchases in place include the reserves acquired in the Rocky Mountain property exchange and the acquisition of certain Barnett Shale Combo Assets in Montague and Cooke Counties, Texas.  Sales in place primarily include reserves from the properties relinquished in the Rocky Mountain property exchange and from the California asset sale.  See Note 16 to Consolidated Financial Statements.

		United			Other
		States	Canada	Trinidad	International (1)	Total
NET PROVED DEVELOPED RESERVES
Liquids (MBbl) (2)
	December 31, 2008	159,607	10,416	6,756	65	176,844
	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
Natural Gas (Bcf) (3)
	December 31, 2008	3,544.7	1,103.7	889.0	14.9	5,552.3
	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
Oil Equivalents (MBoe) (2)
	December 31, 2008	750,389	194,360	154,939	2,548	1,102,236
	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
NET PROVED UNDEVELOPED RESERVES
Liquids (MBbl) (2)
	December 31, 2008	46,239	379	1,570	-	48,188
	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
Natural Gas (Bcf) (3)
	December 31, 2008	1,344.3	133.6	309.0	-	1,786.9
	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
Oil Equivalents (MBoe) (2)
	December 31, 2008	270,282	22,642	53,074	-	345,998
	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

(1) Other International includes EOG's United Kingdom and China operations.

(2) Thousand barrels or thousand barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas.  Crude oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas.

(3) Billion cubic feet.

For the twelve-month period ended December 31, 2011, total proved undeveloped reserves (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 (see discussion of technology employed on page F-34 of this Annual Report on Form 10-K), EOG added 199 MMBoe.  The proved undeveloped reserve additions were primarily in the Eagle Ford and Barnett Combo shale plays, and over 78% of the additions were crude oil and condensate and natural gas liquids.  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 (see discussion of technology employed on page F-34 of this Annual Report on Form 10-K), EOG added 218 MMBoe.  The proved undeveloped reserve 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 natural gas liquids.  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.

For the twelve-month period ended December 31, 2009, total PUDs increased by 474 MMBoe to 820 MMBoe.  Based on the definition of PUDs and its applicability to large resource plays (see discussion of technology employed on page F-34 of this Annual Report on Form 10-K), EOG added 445 MMBoe of PUDs, primarily in the Haynesville, Horn River, Barnett Combo and Marcellus shale plays.  Purchases in place included 70 MMBoe of PUDs from the Rocky Mountain property exchange and the acquisition of Barnett Combo assets (see Note 16 to Consolidated Financial Statements).  During 2009, EOG drilled and transferred approximately 29 MMBoe of PUDs to proved developed reserves at a total capital cost of $280 million.  Revisions of PUDs totaled negative 9 MMBoe.

As of December 31, 2011, EOG did not have a material amount of reserves that have remained undeveloped for five years or more.

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, 2011 and 2010:

	2011			2010
Proved properties	$	32,353,380		$	27,693,700
Unproved properties		1,311,055			1,570,109
Total		33,664,435			29,263,809
Accumulated depreciation, depletion and amortization		(13,981,143	)		(11,859,870	)
Net capitalized costs	$	19,683,292		$	17,403,939

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.

The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended December 31, 2011, 2010 and 2009:

	United							Other
	States		Canada			Trinidad		International (1)			Total
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 (2)		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 (3)		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
2009
Acquisition Costs of Properties
Unproved	$	648,331	$	17,806		$	800	$	(311	)	$	666,626
Proved (4)		464,362		(33	)		-		-			464,329
Subtotal		1,112,693		17,773			800		(311	)		1,130,955
Exploration Costs		473,489		51,164			14,263		71,872			610,788
Development Costs (5)		1,898,859		237,613			27,369		1,914			2,165,755
Total	$	3,485,041	$	306,550		$	42,432	$	73,475		$	3,907,498

(1) Other International primarily consists of EOG's United Kingdom and China operations.

(2) 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.

(3) 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.

(4) Includes non-cash acquisition costs of $353 million related to a property exchange transaction in the Rocky Mountain area.

(5) Includes Asset Retirement Costs of $60 million, $18 million, $6 million and zero for the United States, Canada, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.

Results of Operations for Oil and Gas Producing Activities (1).  The following tables set forth results of operations for oil and gas producing activities for the years ended December 31, 2011, 2010 and 2009:

	United							Other
	States		Canada			Trinidad		International (2)			Total
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
2009
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	2,732,088	$	413,910		$	229,649	$	23,826		$	3,399,473
Other		9,692		(15	)		3,500		-			13,177
Total		2,741,780		413,895			233,149		23,826			3,412,650
Exploration Costs		137,696		18,675			5,107		8,114			169,592
Dry Hole Costs		39,570		1,461			-		10,212			51,243
Transportation Costs		270,940		9,317			1,141		1,931			283,329
Production Costs		556,236		145,292			27,616		9,452			738,596
Impairments		272,195		32,996			-		641			305,832
Depreciation, Depletion and Amortization		1,188,243		210,509			46,608		7,966			1,453,326
Income (Loss) Before Income Taxes		276,900		(4,355	)		152,677		(14,490	)		410,732
Income Tax Provision (Benefit)		106,537		(1,276	)		58,681		(6,067	)		157,875
Results of Operations	$	170,363	$	(3,079	)	$	93,996	$	(8,423	)	$	252,857

(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, 2011.

(2) Other International primarily consists of EOG's United Kingdom and China operations.

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, 2011, 2010 and 2009:

	United						Other
	States		Canada		Trinidad		International (1)		Composite
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
Year Ended December 31, 2009	$	4.43	$	8.41	$	0.74	$	10.52	$	4.40

(1)      Other International primarily consists of EOG's United Kingdom and China 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, natural gas liquids 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 2011, 2010 and 2009.  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, natural gas liquids 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.

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, 2011, 2010 and 2009:

	United									Other
	States			Canada			Trinidad			International (1)			Total
2011
Future cash inflows (2)	$	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 (3)	$	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
2009
Future cash inflows (4)	$	34,506,336		$	6,887,530		$	2,133,778		$	52,738		$	43,580,382
Future production costs		(11,977,152	)		(2,537,001	)		(398,318	)		(27,791	)		(14,940,262	)
Future development costs		(5,696,619	)		(2,255,088	)		(264,104	)		(346	)		(8,216,157	)
Future income taxes		(5,307,041	)		(249,986	)		(525,873	)		(4,276	)		(6,087,176	)
Future net cash flows		11,525,524			1,845,455			945,483			20,325			14,336,787
Discount to present value at 10% annual rate		(5,702,608	)		(808,211	)		(279,920	)		(5,030	)		(6,795,769	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	5,822,916		$	1,037,244		$	665,563		$	15,295		$	7,541,018

(1) Other International includes EOG's United Kingdom and China operations.

(2) 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 natural gas liquids 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.

(3) 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 natural gas liquids 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.

(4) Estimated crude oil prices used to calculate 2009 future cash inflows for the United States, Canada, Trinidad and Other International were $53.64, $56.85, $51.35 and $52.87, respectively.  Estimated natural gas liquids prices used to calculate 2009 future cash inflows for the United States and Canada were $28.75 and $19.31, respectively.  Estimated natural gas prices used to calculate 2009 future cash inflows for the United States, Canada, Trinidad and Other International were $3.43, $3.50, $1.88 and $3.92, respectively.

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, 2011:

	United									Other
	States			Canada			Trinidad			International			Total
December 31, 2008	$	6,307,712		$	1,751,152		$	601,053		$	19,984		$	8,679,901
Sales and transfers of oil and gas produced, net of production costs		(1,904,912	)		(259,301	)		(200,892	)		(12,443	)		(2,377,548	)
Net changes in prices and production costs		(1,482,778	)		(902,629	)		338,053			(13,868	)		(2,061,222	)
Extensions, discoveries, additions and improved recovery, net of related costs		1,702,471			259,305			-			-			1,961,776
Development costs incurred		344,500			14,200			-			-			358,700
Revisions of estimated
development cost		595,875			68,883			(3,380	)		4,555			665,933
Revisions of previous quantity estimates		(422,294	)		(425,018	)		(124,222	)		1,016			(970,518	)
Accretion of discount		829,631			199,330			84,521			3,232			1,116,714
Net change in income taxes		261,513			259,169			(105,766	)		9,847			424,763
Purchases of reserves in place		209,130			-			-			-			209,130
Sales of reserves in place		(264,482	)		(13,912	)		-			-			(278,394	)
Changes in timing and other		(353,450	)		86,065			76,196			2,972			(188,217	)
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