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." During the fourth quarter of 2014, EOG completed the sale of substantially all of its Canadian operations. As a result, information relating to EOG's remaining Canadian operations has been included in the Other International segment and prior year amounts have been reclassified to conform to current year presentation.

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; crude oil and condensate, NGL and natural gas prices; 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, which, by analysis of geoscience and engineering data, can be estimated, with reasonable certainty, to be economically producible from a given date forward from known reservoirs under then-existing economic conditions, operating methods and government regulations 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 relatively major expenditure is required for recompletion. 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. EOG has formulated development plans for all drilling locations associated with its PUDs at December 31, 2016. Under these plans, each PUD location will be drilled within five years from the date it was 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.

In making estimates of PUDs, EOG's technical staff, including engineers and geoscientists, perform detailed technical analysis of each potential drilling location within its 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's 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 matrix.

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 producibility 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.

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 Trinidadian reserves to be materially different from that presented.

Estimates of proved reserves at December 31, 2016, 2015 and 2014 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 16 professionals, all of whom hold, at a minimum, bachelor's degrees in engineering, and five of whom are Registered Professional Engineers. The Vice President, Engineering and Acquisitions is the manager of this department and is the primary technical person responsible for this process. The Vice President, Engineering and Acquisitions holds a Bachelor of Science degree in Petroleum Engineering, has 30 years of experience in reserve evaluations and is a Registered Professional Engineer.

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, NGL and natural gas prices, production costs, transportation 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 and Chief Operating Officer; the Executive Vice Presidents, Exploration and Production; and the Executive Vice President and Chief Financial Officer, for approval.

Opinions by D&M for the years ended December 31, 2016, 2015 and 2014 covered producing areas containing 83%, 86% and 76%, 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 30, 2017, 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, 2016, is believed to have caused a material change in the estimates of net proved reserves as of that date.

The following tables set forth EOG's net proved reserves at December 31 for each of the four years in the period ended December 31, 2016, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2016, as estimated by the Engineering and Acquisitions Department of EOG:

NET PROVED RESERVE SUMMARY



	United States		Trinidad		Other International ⁽¹⁾		Total
NET PROVED RESERVES

Crude Oil (MBbl) ⁽²⁾
Net proved reserves at December 31, 2013	880,049		1,590		18,901		900,540
Revisions of previous estimates	28,301		99		(378	)	28,022
Purchases in place	9,705		—		—		9,705
Extensions, discoveries and other additions	319,540		—		14		319,554
Sales in place	(4,967	)	—		(7,656	)	(12,623	)
Production	(102,946	)	(350	)	(2,152	)	(105,448	)
Net proved reserves at December 31, 2014	1,129,682		1,339		8,729		1,139,750
Revisions of previous estimates	(114,924	)	(1	)	—		(114,925	)
Purchases in place	35,922		—		—		35,922
Extensions, discoveries and other additions	141,310		63		13		141,386
Sales in place	(730	)	—		(10	)	(740	)
Production	(103,400	)	(332	)	(65	)	(103,797	)
Net proved reserves at December 31, 2015	1,087,860		1,069		8,667		1,097,596
Revisions of previous estimates	42,040		54		861		42,955
Purchases in place	25,795		—		—		25,795
Extensions, discoveries and other additions	123,441		—		—		123,441
Sales in place	(8,791	)	—		—		(8,791	)
Production	(101,854	)	(284	)	(1,273	)	(103,411	)
Net proved reserves at December 31, 2016	1,168,491		839		8,255		1,177,585

Natural Gas Liquids (MBbl) ⁽²⁾
Net proved reserves at December 31, 2013	376,002		—		1,204		377,206
Revisions of previous estimates	27,450		—		(7	)	27,443
Purchases in place	1,812		—		—		1,812
Extensions, discoveries and other additions	91,683		—		—		91,683
Sales in place	(956	)	—		(823	)	(1,779	)
Production	(29,061	)	—		(236	)	(29,297	)
Net proved reserves at December 31, 2014	466,930		—		138		467,068
Revisions of previous estimates	(113,290	)	—		68		(113,222	)
Purchases in place	8,251		—		—		8,251
Extensions, discoveries and other additions	49,147		—		—		49,147
Sales in place	(84	)	—		(187	)	(271	)
Production	(28,079	)	—		(19	)	(28,098	)
Net proved reserves at December 31, 2015	382,875		—		—		382,875
Revisions of previous estimates	53,771		—		—		53,771
Purchases in place	1,284		—		—		1,284
Extensions, discoveries and other additions	41,862		—		—		41,862
Sales in place	(33,548	)	—		—		(33,548	)
Production	(29,878	)	—		—		(29,878	)
Net proved reserves at December 31, 2016	416,366		—		—		416,366



	United States		Trinidad		Other International ⁽¹⁾		Total
Natural Gas (Bcf) ⁽³⁾
Net proved reserves at December 31, 2013	4,398.7		520.7		125.4		5,044.8
Revisions of previous estimates	252.2		12.9		5.5		270.6
Purchases in place	17.1		—		—		17.1
Extensions, discoveries and other additions	638.3		4.5		4.7		647.5
Sales in place	(52.4	)	—		(78.7	)	(131.1	)
Production	(348.4	)	(132.5	)	(25.4	)	(506.3	)
Net proved reserves at December 31, 2014	4,905.5		405.6		31.5		5,342.6
Revisions of previous estimates	(1,453.1	)	16.8		5.6		(1,430.7	)
Purchases in place	72.3		—		—		72.3
Extensions, discoveries and other additions	306.3		21.7		4.4		332.4
Sales in place	(3.9	)	—		(11.1	)	(15.0	)
Production	(337.3	)	(127.5	)	(10.9	)	(475.7	)
Net proved reserves at December 31, 2015	3,489.8		316.6		19.5		3,825.9
Revisions of previous estimates	298.4		29.5		5.2		333.1
Purchases in place	91.5		—		—		91.5
Extensions, discoveries and other additions	202.1		59.9		—		262.0
Sales in place	(752.0	)	—		—		(752.0	)
Production	(308.6	)	(125.1	)	(8.9	)	(442.6	)
Net proved reserves at December 31, 2016	3,021.2		280.9		15.8		3,317.9

Oil Equivalents (MBoe) ⁽²⁾
Net proved reserves at December 31, 2013	1,989,166		88,364		41,013		2,118,543
Revisions of previous estimates	97,782		2,245		541		100,568
Purchases in place	14,367		—		—		14,367
Extensions, discoveries and other additions	517,613		758		796		519,167
Sales in place	(14,661	)	—		(21,602	)	(36,263	)
Production	(190,065	)	(22,430	)	(6,631	)	(219,126	)
Net proved reserves at December 31, 2014	2,414,202		68,937		14,117		2,497,256
Revisions of previous estimates	(470,401	)	2,802		995		(466,604	)
Purchases in place	56,215		—		—		56,215
Extensions, discoveries and other additions	241,513		3,682		736		245,931
Sales in place	(1,467	)	—		(2,039	)	(3,506	)
Production	(187,701	)	(21,578	)	(1,896	)	(211,175	)
Net proved reserves at December 31, 2015	2,052,361		53,843		11,913		2,118,117
Revisions of previous estimates	145,542		4,978		1,722		152,242
Purchases in place	42,330		—		—		42,330
Extensions, discoveries and other additions	198,973		9,990		—		208,963
Sales in place	(167,669	)	—		—		(167,669	)
Production	(183,145	)	(21,150	)	(2,755	)	(207,050	)
Net proved reserves at December 31, 2016	2,088,392		47,661		10,880		2,146,933


(1)	Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.


(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 a 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.

During 2016, EOG added 209 million barrels of oil equivalent (MMBoe) of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin, the Rocky Mountain area and the Eagle Ford. Approximately 79% of the 2016 reserve additions were crude oil and condensate and NGLs, and 95% were in the United States. Sales in place of 168 MMBoe were primarily related to the disposition of certain producing natural gas assets in the Barnett Shale and Haynesville plays and marginal liquids plays in the Permian Basin and Rocky Mountain area. Revisions of previous estimates of 152 MMBoe for 2016 included a downward revision of 101 MMBoe primarily due to decreases in the average crude oil and natural gas prices used in the December 31, 2016, reserves estimation as compared to the prices used in the prior year estimate. The primary plays affected were the Eagle Ford, the Uinta basin in the Rocky Mountain area, the Permian Basin and the Barnett Shale. Positive revisions other than price of 253 MMBoe resulted primarily from lower production costs and improved performance in the Delaware Basin. Purchases in place of 42 MMBoe were primarily related to the Yates transaction.

During 2015, EOG added 246 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin, the Rocky Mountain area and the Eagle Ford. Approximately 77% of the 2015 reserve additions were crude oil and condensate and NGLs, and 98% were in the United States. Sales in place of 4 MMBoe were primarily related to the disposition of certain producing natural gas assets in Canada, the Permian Basin and the Upper Gulf Coast. Negative revisions of previous estimates of 467 MMBoe for 2015 included a negative revision of 574 MMBoe primarily due to decreases in the average crude oil and natural gas prices used in the December 31, 2015, reserves estimation as compared to the prices used in the prior year estimate. The primary plays affected were the Uinta and Green River basins in the Rocky Mountain area, the Permian Basin and the Barnett Shale. Revisions other than price resulted primarily from improved recovery in the Eagle Ford.

During 2014, EOG added 519 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Permian Basin and the Rocky Mountain area. Approximately 79% of the 2014 reserve additions were crude oil and condensate and NGLs, and nearly 100% were in the United States. Sales in place of 36 MMBoe were primarily related to the disposition of certain producing natural gas assets in Canada, the Upper Gulf Coast and other producing basins in the United States. Positive revisions of previous estimates of 101 MMBoe for 2014 included a positive revision of 52 MMBoe primarily due to an increase in the average natural gas price used in the December 31, 2014 reserves estimation as compared to the price used in the prior year estimate. The primary plays affected were the Barnett Shale, the Uinta and Green River basins in the Rocky Mountain area and the Haynesville Shale play. Revisions other than price resulted primarily from improved recovery in the Eagle Ford and improved recoveries and reduced operating costs in the Permian Basin.



	United States	Trinidad	Other International ⁽¹⁾	Total
NET PROVED DEVELOPED RESERVES
Crude Oil (MBbl)
December 31, 2013	382,517	1,505	7,034	391,056
December 31, 2014	493,694	1,339	115	495,148
December 31, 2015	444,070	1,069	63	445,202
December 31, 2016	507,531	839	8,255	516,625
Natural Gas Liquids (MBbl)
December 31, 2013	199,964	—	896	200,860
December 31, 2014	264,611	—	138	264,749
December 31, 2015	205,898	—	—	205,898
December 31, 2016	230,219	—	—	230,219
Natural Gas (Bcf)
December 31, 2013	2,597.3	494.6	121.5	3,213.4
December 31, 2014	3,102.8	396.9	28.6	3,528.3
December 31, 2015	2,211.2	297.6	19.5	2,528.3
December 31, 2016	1,804.4	262.2	15.8	2,082.4
Oil Equivalents (MBoe)
December 31, 2013	1,015,359	83,933	28,184	1,127,476
December 31, 2014	1,275,447	67,484	5,016	1,347,947
December 31, 2015	1,018,491	50,677	3,309	1,072,477
December 31, 2016	1,038,483	44,543	10,880	1,093,906
NET PROVED UNDEVELOPED RESERVES
Crude Oil (MBbl)
December 31, 2013	497,532	85	11,867	509,484
December 31, 2014	635,988	—	8,614	644,602
December 31, 2015	643,790	—	8,604	652,394
December 31, 2016	660,960	—	—	660,960
Natural Gas Liquids (MBbl)
December 31, 2013	176,038	—	308	176,346
December 31, 2014	202,319	—	—	202,319
December 31, 2015	176,977	—	—	176,977
December 31, 2016	186,147	—	—	186,147
Natural Gas (Bcf)
December 31, 2013	1,801.4	26.1	3.9	1,831.4
December 31, 2014	1,802.7	8.7	2.9	1,814.3
December 31, 2015	1,278.6	19.0	—	1,297.6
December 31, 2016	1,216.8	18.7	—	1,235.5
Oil Equivalents (MBoe)
December 31, 2013	973,807	4,431	12,829	991,067
December 31, 2014	1,138,755	1,453	9,101	1,149,309
December 31, 2015	1,033,870	3,166	8,604	1,045,640
December 31, 2016	1,049,909	3,118	—	1,053,027


(1)	Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.

Net Proved Undeveloped Reserves. The following table presents the changes in EOG's total proved undeveloped reserves during 2016, 2015 and 2014 (in MBoe):



	2016		2015		2014

Balance at January 1	1,045,640		1,149,309		991,067
Extensions and Discoveries	138,101		205,152		403,713
Revisions	64,413		(241,973	)	(79,630	)
Acquisition of Reserves	—		54,458		4,239
Sale of Reserves	(45,917	)	—		(10,176	)
Conversion to Proved Developed Reserves	(149,210	)	(121,306	)	(159,904	)
Balance at December 31	1,053,027		1,045,640		1,149,309

For the twelve-month period ended December 31, 2016, total PUDs increased by 7 MMBoe to 1,053 MMBoe. EOG added approximately 21 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 pages F-35 and F-36 of this Annual Report on Form 10-K), EOG added 117 MMBoe. The PUD additions were primarily in the Permian Basin and, to a lesser extent, the Rocky Mountain area, and 82% of the additions were crude oil and condensate and NGLs. During 2016, EOG drilled and transferred 149 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,230 million. Revisions of PUDs totaled positive 64 MMBoe, primarily due to improved well performance, primarily in the Delaware Basin, and lower production costs, partially offset by the impact of decreases in the average crude oil and natural gas prices used in the December 31, 2016, reserves estimation as compared to the prices used in the prior year estimate. During 2016, EOG sold 46 MMBoe of PUDs primarily in the Haynesville play. All PUDs for drilled but uncompleted wells (DUCs) are scheduled for completion within five years of the original reserve booking.

For the twelve-month period ended December 31, 2015, total PUDs decreased by 104 MMBoe to 1,046 MMBoe. EOG added approximately 52 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 153 MMBoe. The PUD additions were primarily in the Permian Basin and, to a lesser extent, the Eagle Ford and the Rocky Mountain area, and 80% of the additions were crude oil and condensate and NGLs. During 2015, EOG drilled and transferred 121 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,349 million. Revisions of PUDs totaled negative 242 MMBoe, primarily due to decreases in the average crude oil and natural gas prices used in the December 31, 2015, reserves estimation as compared to the prices used in the prior year estimate. During 2015, EOG did not sell any PUDs and acquired 54 MMBoe of PUDs.

For the twelve-month period ended December 31, 2014, total PUDs increased by 158 MMBoe to 1,149 MMBoe. EOG added approximately 50 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 354 MMBoe. The PUD additions were primarily in the Eagle Ford and Permian Basin, and 80% of the additions were crude oil and condensate and NGLs. During 2014, EOG drilled and transferred 160 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,655 million. Revisions of PUDs totaled negative 80 MMBoe, primarily due to removal of certain natural gas PUDs. During 2014, EOG sold 10 MMBoe and acquired 4 MMBoe of PUDs.

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, 2016 and 2015:



	2016			2015

Proved properties	$	45,751,965		$	49,623,518
Unproved properties	3,840,126			989,723
Total	49,592,091			50,613,241
Accumulated depreciation, depletion and amortization	(26,247,062		)	(28,877,593		)
Net capitalized costs	$	23,345,029		$	21,735,648

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 Accounting Standards Codification (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, 2016, 2015 and 2014:



	United States		Trinidad		Other International ⁽¹⁾			Total
2016
Acquisition Costs of Properties
Unproved ⁽²⁾	$	3,216,598	$	—	$	36		$	3,216,634
Proved ⁽³⁾	749,023		—		—			749,023
Subtotal	3,965,621		—		36			3,965,657
Exploration Costs	156,295		2,695		6,761			165,751
Development Costs ⁽⁴⁾	2,252,713		72,147		(10,984		)	2,313,876
Total	$	6,374,629	$	74,842	$	(4,187	)	$	6,445,284
2015
Acquisition Costs of Properties
Unproved	$	133,801	$	—	$	56		$	133,857
Proved	480,617		—		—			480,617
Subtotal	614,418		—		56			614,474
Exploration Costs	206,814		22,837		23,041			252,692
Development Costs ⁽⁵⁾	3,847,813		102,715		110,589			4,061,117
Total	$	4,669,045	$	125,552	$	133,686		$	4,928,283
2014
Acquisition Costs of Properties
Unproved	$	365,915	$	—	$	4,499		$	370,414
Proved	138,772		—		329			139,101
Subtotal	504,687		—		4,828			509,515
Exploration Costs	332,703		2,794		60,476			395,973
Development Costs ⁽⁶⁾	6,638,192		89,555		271,534			6,999,281
Total	$	7,475,582	$	92,349	$	336,838		$	7,904,769


(1)	Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.


(2)	Includes non-cash unproved leasehold acquisition costs of $3,102 million related to the Yates transaction.


(3)	Includes non-cash proved property acquisition costs of $732 million related to the Yates transaction.


(4)	Includes Asset Retirement Costs of $25 million, $(3) million and $(42) million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment.


(5)	Includes Asset Retirement Costs of $32 million, $15 million and $6 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment.


(6)	Includes Asset Retirement Costs of $149 million, $14 million and $33 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment.

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, 2016, 2015 and 2014:



	United States			Trinidad			Other International ⁽²⁾			Total
2016
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	5,177,989		$	243,708		$	75,046		$	5,496,743
Other	81,386			(8		)	25			81,403
Total	5,259,375			243,700			75,071			5,578,146
Exploration Costs	115,990			2,647			6,316			124,953
Dry Hole Costs	10,529			—			128			10,657
Transportation Costs	753,791			1,181			9,134			764,106
Production Costs	1,163,827			27,113			63,073			1,254,013
Impairments	611,297			7,773			1,197			620,267
Depreciation, Depletion and Amortization	3,249,792			145,440			42,052			3,437,284
Income (Loss) Before Income Taxes	(645,851		)	59,546			(46,829		)	(633,134		)
Income Tax Provision (Benefit)	(230,377		)	5,526			(1,562		)	(226,413		)
Results of Operations	$	(415,474	)	$	54,020		$	(45,267	)	$	(406,721	)
2015
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	5,962,753		$	381,761		$	58,744		$	6,403,258
Other	47,464			(3		)	448			47,909
Total	6,010,217			381,758			59,192			6,451,167
Exploration Costs	139,753			2,071			7,670			149,494
Dry Hole Costs	956			5,635			8,155			14,746
Transportation Costs	838,428			1,290			9,601			849,319
Production Costs	1,486,189			28,862			66,080			1,581,131
Impairments	6,402,908			—			210,638			6,613,546
Depreciation, Depletion and Amortization	3,017,386			154,588			18,469			3,190,443
Income (Loss) Before Income Taxes	(5,875,403		)	189,312			(261,421		)	(5,947,512		)
Income Tax Provision (Benefit)	(2,128,183		)	43,739			(2,111		)	(2,086,555		)
Results of Operations	$	(3,747,220	)	$	145,573		$	(259,310	)	$	(3,860,957	)
2014
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	11,771,777		$	512,675		$	308,465		$	12,592,917
Other	49,950			37			4,257			54,244
Total	11,821,727			512,712			312,722			12,647,161
Exploration Costs	162,434			2,185			19,769			184,388
Dry Hole Costs	25,408			—			23,082			48,490
Transportation Costs	957,522			617			14,037			972,176
Production Costs	1,940,074			38,301			171,652			2,150,027
Impairments	331,792			—			411,783			743,575
Depreciation, Depletion and Amortization	3,571,313			188,250			122,157			3,881,720
Income (Loss) Before Income Taxes	4,833,184			283,359			(449,758		)	4,666,785
Income Tax Provision	1,722,914			74,588			23,602			1,821,104
Results of Operations	$	3,110,270		$	208,771		$	(473,360	)	$	2,845,681


(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, 2016.


(2)	Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.

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, 2016, 2015 and 2014:



	United States		Trinidad		Other International ⁽¹⁾		Composite

Year Ended December 31, 2016	$	4.58	$	1.23	$	22.43	$	4.48
Year Ended December 31, 2015	$	5.81	$	1.29	$	33.78	$	5.85
Year Ended December 31, 2014	$	6.44	$	1.34	$	24.60	$	6.46


(1)	Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.

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, NGL 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 2016, 2015 and 2014. The following information may be useful for certain comparative 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, NGL 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 reserves 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, 2016, 2015 and 2014:



	United States			Trinidad			Other International ⁽¹⁾			Total
2016
Future cash inflows ⁽²⁾	$	57,913,314		$	524,523		$	402,587		$	58,840,424
Future production costs	(27,625,833		)	(165,757		)	(227,293		)	(28,018,883		)
Future development costs	(12,602,699		)	(103,631		)	(35,602		)	(12,741,932		)
Future income taxes	(3,151,319		)	(60,001		)	—			(3,211,320		)
Future net cash flows	14,533,463			195,134			139,692			14,868,289
Discount to present value at 10% annual rate	(6,039,736		)	(9,384		)	(7,012		)	(6,056,132		)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	8,493,727		$	185,750		$	132,680		$	8,812,157
2015
Future cash inflows ⁽³⁾	$	67,242,928		$	954,779		$	522,941		$	68,720,648
Future production costs	(31,707,743		)	(183,607		)	(169,505		)	(32,060,855		)
Future development costs	(15,579,923		)	(140,541		)	(65,347		)	(15,785,811		)
Future income taxes	(4,400,542		)	(215,659		)	—			(4,616,201		)
Future net cash flows	15,554,720			414,972			288,089			16,257,781
Discount to present value at 10% annual rate	(6,589,253		)	(33,848		)	(13,284		)	(6,636,385		)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	8,965,467		$	381,124		$	274,805		$	9,621,396
2014
Future cash inflows ⁽⁴⁾	$	144,355,692		$	1,615,280		$	979,249		$	146,950,221
Future production costs	(51,112,604		)	(277,844		)	(242,845		)	(51,633,293		)
Future development costs	(20,270,439		)	(84,576		)	(139,750		)	(20,494,765		)
Future income taxes	(22,725,618		)	(460,096		)	—			(23,185,714		)
Future net cash flows	50,247,031			792,764			596,654			51,636,449
Discount to present value at 10% annual rate	(23,542,990		)	(110,228		)	(59,813		)	(23,713,031		)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	26,704,041		$	682,536		$	536,841		$	27,923,418


(1)	Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.

(2)

Estimated crude oil prices used to calculate 2016 future cash inflows for the United States, Trinidad and Other International were $40.70, $34.79 and $39.55, respectively. Estimated NGL price used to calculate 2016 future cash inflows for the United States was $14.69. Estimated natural gas prices used to calculate 2016 future cash inflows for the United States, Trinidad and Other International were $1.40, $1.76 and $4.84, respectively.

(3)

Estimated crude oil prices used to calculate 2015 future cash inflows for the United States, Trinidad and Other International were $49.58, $38.83 and $47.76, respectively. Estimated NGL price used to calculate 2015 future cash inflows for the United States was $15.17. Estimated natural gas prices used to calculate 2015 future cash inflows for the United States, Trinidad and Other International were $2.15, $2.88 and $5.60, respectively.

(4)

Estimated crude oil prices used to calculate 2014 future cash inflows for the United States, Trinidad and Other International were $97.51, $80.60 and $94.09, respectively. Estimated NGL prices used to calculate 2014 future cash inflows for the United States and Other International were $34.29 and $27.03, respectively. Estimated natural gas prices used to calculate 2014 future cash inflows for the United States, Trinidad and Other International were $3.71, $3.71 and $5.14, 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, 2016:



	United States			Trinidad			Other International ⁽¹⁾			Total

December 31, 2013	$	19,576,901		$	876,640		$	879,891		$	21,333,432
Sales and transfers of oil and gas produced, net of production costs	(8,874,180		)	(473,757		)	(122,777		)	(9,470,714		)
Net changes in prices and production costs	1,481,668			(12,079		)	(206,412		)	1,263,177
Extensions, discoveries, additions and improved recovery, net of related costs	8,074,550			3,113			6,189			8,083,852
Development costs incurred	2,818,800			12,800			3,500			2,835,100
Revisions of estimated development cost	1,696,916			9,981			95,838			1,802,735
Revisions of previous quantity estimates	1,741,918			35,001			35,613			1,812,532
Accretion of discount	2,612,286			133,019			88,045			2,833,350
Net change in income taxes	(3,743,300		)	91,438			562			(3,651,300		)
Purchases of reserves in place	317,785			—			—			317,785
Sales of reserves in place	(189,808		)	—			(289,071		)	(478,879		)
Changes in timing and other	1,190,505			6,380			45,463			1,242,348
December 31, 2014	26,704,041			682,536			536,841			27,923,418
Sales and transfers of oil and gas produced, net of production costs	(3,685,600		)	(351,606		)	16,489			(4,020,717		)
Net changes in prices and production costs	(29,993,699		)	(370,503		)	(305,148		)	(30,669,350		)
Extensions, discoveries, additions and improved recovery, net of related costs	1,028,410			47,613			19,875			1,095,898
Development costs incurred	2,135,800			500			1,400			2,137,700
Revisions of estimated development cost	4,087,093			(34,647		)	26,935			4,079,381
Revisions of previous quantity estimates	(4,084,572		)	33,285			(587		)	(4,051,874		)
Accretion of discount	3,699,330			104,464			53,685			3,857,479
Net change in income taxes	9,550,847			177,576			—			9,728,423
Purchases of reserves in place	123,542			—			—			123,542
Sales of reserves in place	(23,424		)	—			(13,664		)	(37,088		)
Changes in timing and other	(576,301		)	91,906			(61,021		)	(545,416		)
December 31, 2015	8,965,467			381,124			274,805			9,621,396
Sales and transfers of oil and gas produced, net of production costs	(3,260,372		)	(215,414		)	(2,839		)	(3,478,625		)
Net changes in prices and production costs	(3,352,802		)	(182,876		)	(143,924		)	(3,679,602		)
Extensions, discoveries, additions and improved recovery, net of related costs	865,066			42,201			—			907,267
Development costs incurred	1,207,000			3,900			19,100			1,230,000
Revisions of estimated development cost	2,092,769			22,596			6,343			2,121,708
Revisions of previous quantity estimates	1,013,753			36,648			2,619			1,053,020
Accretion of discount	970,388			56,566			27,481			1,054,435
Net change in income taxes	738,416			129,622			—			868,038
Purchases of reserves in place	377,872			—			—			377,872
Sales of reserves in place	(375,793		)	—			—			(375,793		)
Changes in timing and other	(748,037		)	(88,617		)	(50,905		)	(887,559		)
December 31, 2016	$	8,493,727		$	185,750		$	132,680		$	8,812,157


(1)	Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.