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Oil and Gas Exploration and Production Industries Disclosures (Notes)
 12 Months Ended
Dec. 31, 2017
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; 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.  For related discussion, 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, 2017.  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 the 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, 2017, 2016 and 2015 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 13 professionals, all of whom hold, at a minimum, bachelor's degrees in engineering, and four 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 31 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; the 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, 2017, 2016 and 2015 covered producing areas containing 79%, 83% and 86%, 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.  Specifically, 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, 2018, 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 99.1 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, 2017, 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, 2017, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2017, 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, 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

Revisions of previous estimates
57,935

 
80

 
(179
)
 
57,836

Purchases in place
1,111

 
—

 
—

 
1,111

Extensions, discoveries and other additions
207,137

 
301

 
119

 
207,557

Sales in place
(8,393
)
 
—

 
—

 
(8,393
)
Production
(122,210
)
 
(322
)
 
(191
)
 
(122,723
)
Net proved reserves at December 31, 2017
1,304,071

 
898

 
8,004

 
1,312,973

 
 
 
 
 
 
 
 
Natural Gas Liquids (MBbl) (2)
 

 
 

 
 

 
 

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

Revisions of previous estimates
46,843

 
—

 
—

 
46,843

Purchases in place
421

 
—

 
—

 
421

Extensions, discoveries and other additions
75,003

 
—

 
—

 
75,003

Sales in place
(2,887
)
 
—

 
—

 
(2,887
)
Production
(32,273
)
 
—

 
—

 
(32,273
)
Net proved reserves at December 31, 2017
503,473

 
—

 
—

 
503,473

 
United
States
 
Trinidad
 
Other
International (1)
 
Total
Natural Gas (Bcf) (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

Revisions of previous estimates
602.8

 
(27.4
)
 
8.6

 
584.0

Purchases in place
4.8

 
—

 
—

 
4.8

Extensions, discoveries and other additions
619.3

 
174.2

 
35.9

 
829.4

Sales in place
(56.4
)
 
—

 
—

 
(56.4
)
Production
(293.2
)
 
(114.3
)
 
(9.1
)
 
(416.6
)
Net proved reserves at December 31, 2017
3,898.5

 
313.4

 
51.2

 
4,263.1

 
 
 
 
 
 
 
 
Oil Equivalents (MBoe) (2)
 

 
 

 
 

 
 

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

Revisions of previous estimates
205,262

 
(4,493
)
 
1,249

 
202,018

Purchases in place
2,332

 
—

 
—

 
2,332

Extensions, discoveries and other additions
385,354

 
29,340

 
6,104

 
420,798

Sales in place
(20,687
)
 
—

 
—

 
(20,687
)
Production
(203,351
)
 
(19,366
)
 
(1,707
)
 
(224,424
)
Net proved reserves at December 31, 2017
2,457,302

 
53,142

 
16,526

 
2,526,970

 
(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 2017, EOG added 421 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 Eagle Ford, the Rocky Mountain area and Trinidad.  Approximately 67% of the 2017 reserve additions were crude oil and condensate and NGLs, and 92% were in the United States.  Sales in place of 21 MMBoe were primarily related to the sale or exchange of certain producing assets. Revisions of previous estimates of 202 MMBoe for 2017 included an upward revision of 154 MMBoe primarily due to increases in the average crude oil and natural gas prices used in the December 31, 2017, reserves estimation as compared to the prices used in the prior year estimate. The primary plays affected were in the Rocky Mountain area, the Eagle Ford and the Permian Basin. Positive revisions other than price of 48 MMBoe resulted primarily from improved well performance in the Permian Basin and lower production costs. Purchases in place of 2 MMBoe were primarily related to the Permian Basin.

During 2016, EOG added 209 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.


 
United
States
 
Trinidad
 
Other
International (1)
 
Total
NET PROVED DEVELOPED RESERVES
 
 
 
 
 
 
 
Crude Oil (MBbl)
 
 
 
 
 
 
 
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

December 31, 2017
605,405

 
898

 
7,933

 
614,236

Natural Gas Liquids (MBbl)
 

 
 

 
 

 
 

December 31, 2014
264,611

 
—

 
138

 
264,749

December 31, 2015
205,898

 
—

 
—

 
205,898

December 31, 2016
230,219

 
—

 
—

 
230,219

December 31, 2017
286,872

 
—

 
—

 
286,872

Natural Gas (Bcf)
 

 
 

 
 

 
 

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

December 31, 2017
2,450.8

 
299.2

 
29.3

 
2,779.3

Oil Equivalents (MBoe)
 

 
 

 
 

 
 

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

December 31, 2017
1,300,758

 
50,779

 
12,798

 
1,364,335

NET PROVED UNDEVELOPED RESERVES
 

 
 

 
 

 
 

Crude Oil (MBbl)
 

 
 

 
 

 
 

December 31, 2014
635,988

 
—

 
8,614

 
644,602

December 31, 2015
643,790

 
—

 
8,604

 
652,394

December 31, 2016
660,690

 
—

 
—

 
660,690

December 31, 2017
698,666

 
—

 
71

 
698,737

Natural Gas Liquids (MBbl)
 

 
 

 
 

 
 

December 31, 2014
202,319

 
—

 
—

 
202,319

December 31, 2015
176,977

 
—

 
—

 
176,977

December 31, 2016
186,147

 
—

 
—

 
186,147

December 31, 2017
216,601

 
—

 
—

 
216,601

Natural Gas (Bcf)
 

 
 

 
 

 
 

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

December 31, 2017
1,447.7

 
14.2

 
21.9

 
1,483.8

Oil Equivalents (MBoe)
 

 
 

 
 

 
 

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

December 31, 2017
1,156,544

 
2,363

 
3,728

 
1,162,635

 
(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 2017, 2016 and 2015 (in MBoe):
 
2017
 
2016
 
2015
 
 
 
 
 
 
Balance at January 1
1,053,027

 
1,045,640

 
1,149,309

Extensions and Discoveries
237,378

 
138,101

 
205,152

Revisions
33,127

 
64,413

 
(241,973
)
Acquisition of Reserves
—

 
—

 
54,458

Sale of Reserves
(8,253
)
 
(45,917
)
 
—

Conversion to Proved Developed Reserves
(152,644
)
 
(149,210
)
 
(121,306
)
Balance at December 31
1,162,635

 
1,053,027

 
1,045,640



For the twelve-month period ended December 31, 2017, total PUDs increased by 110 MMBoe to 1,163 MMBoe.  EOG added approximately 38 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-38 and F-39 of this Annual Report on Form 10-K), EOG added 199 MMBoe.  The PUD additions were primarily in the Permian Basin and, to a lesser extent, the Eagle Ford and the Rocky Mountain area, and 74% of the additions were crude oil and condensate and NGLs.  During 2017, EOG drilled and transferred 153 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,440 million.  Revisions of PUDs totaled positive 33 MMBoe, primarily due to updated type curves resulting from improved performance of offsetting wells in the Permian Basin, the impact of increases in the average crude oil and natural gas prices used in the December 31, 2017, reserves estimation as compared to the prices used in the prior year estimate, and lower costs.  During 2017, EOG sold or exchanged 8 MMBoe of PUDs primarily in the Permian Basin. All PUDs, including 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, 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, 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.

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, 2017 and 2016:
 
2017
 
2016
 
 
 
 
Proved properties
$
48,845,672

 
$
45,751,965

Unproved properties
3,710,069

 
3,840,126

Total
52,555,741

 
49,592,091

Accumulated depreciation, depletion and amortization
(29,191,247
)
 
(26,247,062
)
Net capitalized costs
$
23,364,494

 
$
23,345,029



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, 2017, 2016 and 2015:
 
United
States
 
Trinidad
 
Other
International (1)
 
Total
2017
 
 
 
 
 
 
 
Acquisition Costs of Properties
 
 
 
 
 
 
 
Unproved (2)
$
424,118

 
$
2,422

 
$
—

 
$
426,540

Proved (3)
72,584

 
—

 
—

 
72,584

Subtotal
496,702

 
2,422

 
—

 
499,124

Exploration Costs
144,499

 
62,547

 
16,553

 
223,599

Development Costs (4)
3,590,899

 
109,491

 
16,297

 
3,716,687

Total
$
4,232,100

 
$
174,460

 
$
32,850

 
$
4,439,410

2016
 

 
 

 
 

 
 

Acquisition Costs of Properties
 

 
 

 
 

 
 

Unproved (5)
$
3,216,598

 
$
—

 
$
36

 
$
3,216,634

Proved (6)
749,023

 
—

 
—

 
749,023

Subtotal
3,965,621

 
—

 
36

 
3,965,657

Exploration Costs
156,295

 
2,695

 
6,761

 
165,751

Development Costs (7)
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 (8)
3,847,813

 
102,715

 
110,589

 
4,061,117

Total
$
4,669,045

 
$
125,552

 
$
133,686

 
$
4,928,283

 
(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 $256 million related to property exchanges.
(3)
Includes non-cash proved property acquisition costs of $26 million related to property exchanges.
(4)
Includes Asset Retirement Costs of $50 million, $2 million and $4 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment.
(5)
Includes non-cash unproved leasehold acquisition costs of $3,102 million related to the Yates transaction.
(6)
Includes non-cash proved property acquisition costs of $732 million related to the Yates transaction.
(7)
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.
(8)
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.



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, 2017, 2016 and 2015:
 
United
States
 
Trinidad
 
Other
International (2)
 
Total
2017
 
 
 
 
 
 
 
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues
$
7,570,768

 
$
284,673

 
$
52,450

 
$
7,907,891

Other
81,610

 
59

 
(59
)
 
81,610

Total
7,652,378

 
284,732

 
52,391

 
7,989,501

Exploration Costs
113,334

 
26,245

 
5,763

 
145,342

Dry Hole Costs
91

 
—

 
4,518

 
4,609

Transportation Costs
737,403

 
1,885

 
1,064

 
740,352

Production Costs
1,446,333

 
27,839

 
88,038

 
1,562,210

Impairments
477,223

 
—

 
2,017

 
479,240

Depreciation, Depletion and Amortization
3,157,056

 
115,174

 
24,536

 
3,296,766

Income (Loss) Before Income Taxes
1,720,938

 
113,589

 
(73,545
)
 
1,760,982

Income Tax Provision (Benefit)
625,562

 
24,882

 
(1,342
)
 
649,102

Results of Operations
$
1,095,376

 
$
88,707

 
$
(72,203
)
 
$
1,111,880

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
(2,128,183
)
 
43,739

 
(2,111
)
 
(2,086,555
)
Results of Operations
$
(3,747,220
)
 
$
145,573

 
$
(259,310
)
 
$
(3,860,957
)
 
(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, 2017.
(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, 2017, 2016 and 2015:
 
United
States
 
Trinidad
 
Other
International (1)
 
Composite
 
 
 
 
 
 
 
 
Year Ended December 31, 2017
$
4.58

 
$
1.39

 
$
50.86

 
$
4.66

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

 
(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 2017, 2016 and 2015.  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, 2017, 2016 and 2015:
 
United
States
 
Trinidad
 
Other
International (1)
 
Total
2017
 
 
 
 
 
 
 
Future cash inflows (2)
$
83,652,363

 
$
904,141

 
$
664,560

 
$
85,221,064

Future production costs
(32,018,812
)
 
(239,213
)
 
(311,383
)
 
(32,569,408
)
Future development costs
(13,395,873
)
 
(84,379
)
 
(58,543
)
 
(13,538,795
)
Future income taxes
(5,948,453
)
 
(195,855
)
 
(16,233
)
 
(6,160,541
)
Future net cash flows
32,289,225

 
384,694

 
278,401

 
32,952,320

Discount to present value at 10% annual rate
(14,532,290
)
 
(52,267
)
 
(40,103
)
 
(14,624,660
)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves
$
17,756,935

 
$
332,427

 
$
238,298

 
$
18,327,660

2016
 

 
 

 
 

 
 

Future cash inflows (3)
$
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 (4)
$
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

 
(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 2017 future cash inflows for the United States, Trinidad and Other International were $49.21, $41.87 and $50.06, respectively. Estimated NGL price used to calculate 2017 future cash inflows for the United States was $23.51. Estimated natural gas prices used to calculate 2017 future cash inflows for the United States, Trinidad and Other International were $1.96, $2.76 and $5.16, respectively.
(3)
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.
(4)
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.


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, 2017:
 
United
States
 
Trinidad
 
Other
International (1)
 
Total
 
 
 
 
 
 
 
 
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

Sales and transfers of oil and gas produced, net of production costs
(5,387,031
)
 
(254,948
)
 
36,649

 
(5,605,330
)
Net changes in prices and production costs
6,606,908

 
436,969

 
77,668

 
7,121,545

Extensions, discoveries, additions and improved recovery, net of related costs
3,644,041

 
270,255

 
43,952

 
3,958,248

Development costs incurred
1,435,600

 
4,700

 
—

 
1,440,300

Revisions of estimated development cost
(114,464
)
 
9,683

 
(20,096
)
 
(124,877
)
Revisions of previous quantity estimates
2,460,498

 
(58,373
)
 
36,146

 
2,438,271

Accretion of discount
849,373

 
24,066

 
13,268

 
886,707

Net change in income taxes
(1,918,989
)
 
(114,575
)
 
(10,099
)
 
(2,043,663
)
Purchases of reserves in place
30,362

 
—

 
—

 
30,362

Sales of reserves in place
(76,527
)
 
—

 
—

 
(76,527
)
Changes in timing and other
1,733,437

 
(171,100
)
 
(71,870
)
 
1,490,467

December 31, 2017
$
17,756,935

 
$
332,427

 
$
238,298

 
$
18,327,660

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