Oil and Gas Exploration and Production Industries Disclosures

12 Months Ended

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.