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Oil and Gas Exploration and Production Industries Disclosures
 12 Months Ended
Dec. 31, 2014
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 (NGL) 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, NGL and natural gas that geoscience and engineering data are used to 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.  EOG has formulated development plans for all drilling locations associated with its PUDs at December 31, 2014.  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, 2014, 2013 and 2012 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 nine 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 29 years of experience in reserve evaluations and is a Registered Professional Engineer in the State of Texas.

EOG's reserves estimation process is a collaborative effort coordinated by the Engineering and Acquisitions Department in compliance with EOG's internal controls for such process.  Reserve information as well as models used to estimate such reserves are stored on secured databases.  Non-technical inputs used in reserve estimation models, including crude oil, 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 Chief Operating Officer; the Executive Vice Presidents, Exploration and Production; and the Vice President and Chief Financial Officer, for approval.

Opinions by D&M for the years ended December 31, 2014, 2013 and 2012 covered producing areas containing 76%, 82% and 87%, 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 23, 2015, 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, 2014, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

The following tables set forth EOG's net proved and proved developed reserves at December 31 for each of the four years in the period ended December 31, 2014, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2014, as estimated by the Engineering and Acquisitions Department of EOG:

NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY
 
United
States
 
Canada
 
Trinidad
 
Other
International (1)
 
Total
NET PROVED RESERVES
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude Oil (MBbl) (2)
 
 
 
 
 
 
 
 
 
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

Revisions of previous estimates
57,668

 
(5,866
)
 
(991
)
 
(142
)
 
50,669

Purchases in place
1,097

 
—

 
—

 
—

 
1,097

Extensions, discoveries and other additions
230,023

 
673

 
—

 
58

 
230,754

Sales in place
(2,337
)
 
—

 
—

 
—

 
(2,337
)
Production
(77,431
)
 
(2,550
)
 
(447
)
 
(33
)
 
(80,461
)
Net proved reserves at December 31, 2013
880,049

 
10,120

 
1,590

 
8,781

 
900,540

Revisions of previous estimates
28,301

 
(313
)
 
99

 
(65
)
 
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
)
 
(2,126
)
 
(350
)
 
(26
)
 
(105,448
)
Net proved reserves at December 31, 2014
1,129,682

 
25

 
1,339

 
8,704

 
1,139,750

 
 
 
 
 
 
 
 
 
 
Natural Gas Liquids (MBbl) (2)
 

 
 

 
 

 
 

 
 

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

Revisions of previous estimates
12,157

 
(48
)
 
—

 
—

 
12,109

Purchases in place
1,202

 
—

 
—

 
—

 
1,202

Extensions, discoveries and other additions
69,187

 
10

 
—

 
—

 
69,197

Sales in place
(1,471
)
 
—

 
—

 
—

 
(1,471
)
Production
(23,479
)
 
(315
)
 
—

 
—

 
(23,794
)
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


 
United
States
 
Canada
 
Trinidad
 
Other
International (1)
 
Total
Natural Gas (Bcf) (3)
 
 
 
 
 
 
 
 
 
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

Revisions of previous estimates
264.0

 
31.4

 
(17.4
)
 
(0.7
)
 
277.3

Purchases in place
5.7

 
—

 
—

 
—

 
5.7

Extensions, discoveries and other additions
504.7

 
0.1

 
79.5

 
9.8

 
594.1

Sales in place
(69.4
)
 
—

 
—

 
—

 
(69.4
)
Production
(342.3
)
 
(27.7
)
 
(129.6
)
 
(2.8
)
 
(502.4
)
Net proved reserves at December 31, 2013
4,398.7

 
102.1

 
520.7

 
23.3

 
5,044.8

Revisions of previous estimates
252.2

 
9.8

 
12.9

 
(4.3
)
 
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
)
 
(22.3
)
 
(132.5
)
 
(3.1
)
 
(506.3
)
Net proved reserves at December 31, 2014
4,905.5

 
10.9

 
405.6

 
20.6

 
5,342.6

 
 
 
 
 
 
 
 
 
 
Oil Equivalents (MBoe) (2)
 

 
 

 
 

 
 

 
 

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

Revisions of previous estimates
113,823

 
(676
)
 
(3,892
)
 
(265
)
 
108,990

Purchases in place
3,241

 
—

 
—

 
—

 
3,241

Extensions, discoveries and other additions
383,324

 
693

 
13,245

 
1,703

 
398,965

Sales in place
(15,375
)
 
—

 
—

 
—

 
(15,375
)
Production
(157,955
)
 
(7,482
)
 
(22,049
)
 
(490
)
 
(187,976
)
Net proved reserves at December 31, 2013
1,989,166

 
28,339

 
88,364

 
12,674

 
2,118,543

Revisions of previous estimates
97,782

 
1,316

 
2,245

 
(775
)
 
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
)
 
(6,080
)
 
(22,430
)
 
(551
)
 
(219,126
)
Net proved reserves at December 31, 2014
2,414,202

 
1,973

 
68,937

 
12,144

 
2,497,256

 
(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, NGL and natural gas. Oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or NGL to 6.0 thousand cubic feet of natural gas.
(3)
Billion cubic feet.
During 2014, EOG added 519 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 and the Rocky Mountain area.  Approximately 79% of the 2014 reserve additions were crude oil and condensate and NGL, 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.

During 2013, EOG added 399 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Bakken, Permian Basin and Barnett Combo shale plays.  Approximately 75% of the 2013 reserve additions were crude oil and condensate and NGL, and over 96% were in the United States.  Sales in place of 15 MMBoe were primarily related to the disposition of certain producing natural gas assets in South Texas, the Barnett Shale and the Permian Basin.  Positive revisions of previous estimates of 109 MMBoe for 2013 included a positive revision of 61 MMBoe primarily due to an increase in the average natural gas price used in the December 31, 2013 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.

During 2012, EOG added 407 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 NGL, 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.  Negative revisions of previous estimates of 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.


 
United
States
 
Canada
 
Trinidad
 
Other
International (1)
 
Total
NET PROVED DEVELOPED RESERVES
 
 
 
 
 
 
 
 
 
Crude Oil (MBbl)
 
 
 
 
 
 
 
 
 
December 31, 2011
213,872

 
8,128

 
2,657

 
98

 
224,755

December 31, 2012
281,167

 
6,853

 
2,377

 
253

 
290,650

December 31, 2013
382,517

 
6,871

 
1,505

 
163

 
391,056

December 31, 2014
493,694

 
25

 
1,339

 
90

 
495,148

Natural Gas Liquids (MBbl)
 

 
 

 
 

 
 

 
 

December 31, 2011
124,271

 
1,092

 
—

 
—

 
125,363

December 31, 2012
161,482

 
1,111

 
—

 
—

 
162,593

December 31, 2013
199,964

 
896

 
—

 
—

 
200,860

December 31, 2014
264,611

 
138

 
—

 
—

 
264,749

Natural Gas (Bcf)
 

 
 

 
 

 
 

 
 

December 31, 2011
3,235.0

 
295.8

 
606.3

 
18.5

 
4,155.6

December 31, 2012
2,387.5

 
98.3

 
476.7

 
17.0

 
2,979.5

December 31, 2013
2,597.3

 
102.1

 
494.6

 
19.4

 
3,213.4

December 31, 2014
3,102.8

 
10.9

 
396.9

 
17.7

 
3,528.3

Oil Equivalents (MBoe)
 

 
 

 
 

 
 

 
 

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

December 31, 2013
1,015,359

 
24,782

 
83,933

 
3,402

 
1,127,476

December 31, 2014
1,275,447

 
1,973

 
67,484

 
3,043

 
1,347,947

NET PROVED UNDEVELOPED RESERVES
 

 
 

 
 

 
 

 
 

Crude Oil (MBbl)
 

 
 

 
 

 
 

 
 

December 31, 2011
281,424

 
10,464

 
850

 
—

 
292,738

December 31, 2012
389,862

 
11,010

 
651

 
8,645

 
410,168

December 31, 2013
497,532

 
3,249

 
85

 
8,618

 
509,484

December 31, 2014
635,988

 
—

 
—

 
8,614

 
644,602

Natural Gas Liquids (MBbl)
 

 
 

 
 

 
 

 
 

December 31, 2011
102,315

 
110

 
—

 
—

 
102,425

December 31, 2012
156,924

 
446

 
—

 
—

 
157,370

December 31, 2013
176,038

 
308

 
—

 
—

 
176,346

December 31, 2014
202,319

 
—

 
—

 
—

 
202,319

Natural Gas (Bcf)
 

 
 

 
 

 
 

 
 

December 31, 2011
2,810.8

 
740.1

 
144.4

 
—

 
3,695.3

December 31, 2012
1,648.5

 
—

 
111.5

 
—

 
1,760.0

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

Oil Equivalents (MBoe)
 

 
 

 
 

 
 

 
 

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

December 31, 2013
973,807

 
3,557

 
4,431

 
9,272

 
991,067

December 31, 2014
1,138,755

 
—

 
1,453

 
9,101

 
1,149,309

 
(1)
Other International includes EOG's United Kingdom, China and Argentina operations.
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 (see discussion of technology employed on page F-32 of this Annual Report on Form 10-K), EOG added 354 MMBoe.  The PUD additions were primarily in the Eagle Ford and Permian Basin shale plays, and 80% of the additions were crude oil and condensate and NGL.  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.

For the twelve-month period ended December 31, 2013, total PUDs increased by 130 MMBoe to 991 MMBoe.  EOG added approximately 28 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 263 MMBoe.  The PUD additions were primarily in the Eagle Ford, Bakken and Permian Basin shale plays, and over 80% of the additions were crude oil and condensate and NGL.  During 2013, EOG drilled and transferred 160 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,874 million.  Revisions of PUDs totaled  negative 1 MMBoe.  During 2013, EOG did not sell any PUD reserves.

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, 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 NGL.  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.

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, 2014 and 2013:
 
2014
 
2013
 
 
 
 
Proved properties
$
45,169,101

 
$
41,377,303

Unproved properties
1,334,431

 
1,444,500

Total
46,503,532

 
42,821,803

Accumulated depreciation, depletion and amortization
(20,212,748
)
 
(18,880,611
)
Net capitalized costs
$
26,290,784

 
$
23,941,192



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, 2014, 2013 and 2012:
 
United
States
 
Canada
 
Trinidad
 
Other
International (1)
 
Total
2014
 
 
 
 
 
 
 
 
 
Acquisition Costs of Properties
 
 
 
 
 
 
 
 
 
Unproved
$
365,915

 
$
4,499

 
$
—

 
$
—

 
$
370,414

Proved
138,772

 
349

 
—

 
(20
)
 
139,101

Subtotal
504,687

 
4,848

 
—

 
(20
)
 
509,515

Exploration Costs
332,703

 
13,010

 
2,794

 
47,466

 
395,973

Development Costs (2)
6,638,192

 
101,634

 
89,555

 
169,900

 
6,999,281

Total
$
7,475,582

 
$
119,492

 
$
92,349

 
$
217,346

 
$
7,904,769

2013
 

 
 

 
 

 
 

 
 

Acquisition Costs of Properties
 

 
 

 
 

 
 

 
 

Unproved
$
411,556

 
$
2,565

 
$
—

 
$
—

 
$
414,121

Proved
120,220

 
(6
)
 
—

 
—

 
120,214

Subtotal
531,776

 
2,559

 
—

 
—

 
534,335

Exploration Costs
273,788

 
19,660

 
16,060

 
67,671

 
377,179

Development Costs (3)
5,573,260

 
149,426

 
124,231

 
239,460

 
6,086,377

Total
$
6,378,824

 
$
171,645

 
$
140,291

 
$
307,131

 
$
6,997,891

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 (4)
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

 
(1)
Other International primarily consists of EOG's United Kingdom, China and Argentina operations.
(2)
Includes Asset Retirement Costs of $149 million, $31 million, $14 million and $2 million for the United States, Canada, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.
(3)
Includes Asset Retirement Costs of $84 million, $13 million and $37 million for the United States, Canada and Other International, respectively.  Excludes other property, plant and equipment.
(4)
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.


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, 2014, 2013 and 2012:
 
United
States
 
Canada
 
Trinidad
 
Other
International (2)
 
Total
2014
 
 
 
 
 
 
 
 
 
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues
$
11,771,777

 
$
290,291

 
$
512,675

 
$
18,174

 
$
12,592,917

Other
49,950

 
4,257

 
37

 
—

 
54,244

Total
11,821,727

 
294,548

 
512,712

 
18,174

 
12,647,161

Exploration Costs
162,434

 
11,877

 
2,185

 
7,892

 
184,388

Dry Hole Costs
25,408

 
—

 
—

 
23,082

 
48,490

Transportation Costs
957,522

 
12,618

 
617

 
1,419

 
972,176

Production Costs
1,940,074

 
158,882

 
38,301

 
12,770

 
2,150,027

Impairments
331,792

 
15,879

 
—

 
395,904

 
743,575

Depreciation, Depletion and Amortization
3,571,313

 
104,462

 
188,250

 
17,695

 
3,881,720

Income (Loss) Before Income Taxes
4,833,184

 
(9,170
)
 
283,359

 
(440,588
)
 
4,666,785

Income Tax Provision (Benefit)
1,722,914

 
(2,360
)
 
74,588

 
25,962

 
1,821,104

Results of Operations
$
3,110,270

 
$
(6,810
)
 
$
208,771

 
$
(466,550
)
 
$
2,845,681

2013
 

 
 

 
 

 
 

 
 

Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues
$
9,897,701

 
$
319,880

 
$
517,482

 
$
20,583

 
$
10,755,646

Other
51,713

 
4,770

 
24

 
—

 
56,507

Total
9,949,414

 
324,650

 
517,506

 
20,583

 
10,812,153

Exploration Costs
141,286

 
11,203

 
2,345

 
6,512

 
161,346

Dry Hole Costs
14,276

 
9,579

 
4,478

 
46,322

 
74,655

Transportation Costs
841,567

 
9,694

 
659

 
1,124

 
853,044

Production Costs
1,494,791

 
154,947

 
43,279

 
13,205

 
1,706,222

Impairments
178,718

 
84,934

 
14,274

 
9,015

 
286,941

Depreciation, Depletion and Amortization
3,122,858

 
179,520

 
181,637

 
13,995

 
3,498,010

Income (Loss) Before Income Taxes
4,155,918

 
(125,227
)
 
270,834

 
(69,590
)
 
4,231,935

Income Tax Provision (Benefit)
1,486,445

 
(32,295
)
 
103,313

 
(66,931
)
 
1,490,532

Results of Operations
$
2,669,473

 
$
(92,932
)
 
$
167,521

 
$
(2,659
)
 
$
2,741,403

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

 
(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, 2014.
(2)
Other International primarily consists of EOG's United Kingdom, China and Argentina operations.

The following table sets forth production costs per barrel of oil equivalent, excluding severance/production and ad valorem taxes, for the years ended December 31, 2014, 2013 and 2012:
 
United
States
 
Canada
 
Trinidad
 
Other
International (1)
 
Composite
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2014
$
6.44

 
$
24.76

 
$
1.34

 
$
22.83

 
$
6.46

Year Ended December 31, 2013
$
5.78

 
$
19.98

 
$
1.36

 
$
26.77

 
$
5.88

Year Ended December 31, 2012
$
5.96

 
$
16.42

 
$
0.98

 
$
18.97

 
$
5.85

 
(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, 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 2014, 2013 and 2012.  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, 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 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, 2014, 2013 and 2012:
 
United
States
 
Canada
 
Trinidad
 
Other
International (1)
 
Total
2014
 
 
 
 
 
 
 
 
 
Future cash inflows (2)
$
144,355,692

 
$
50,116

 
$
1,615,280

 
$
929,133

 
$
146,950,221

Future production costs
(51,112,604
)
 
(25,561
)
 
(277,844
)
 
(217,284
)
 
(51,633,293
)
Future development costs
(20,270,439
)
 
(32,016
)
 
(84,576
)
 
(107,734
)
 
(20,494,765
)
Future income taxes
(22,725,618
)
 
—

 
(460,096
)
 
—

 
(23,185,714
)
Future net cash flows
50,247,031

 
(7,461
)
 
792,764

 
604,115

 
51,636,449

Discount to present value at 10% annual rate
(23,542,990
)
 
11,217

 
(110,228
)
 
(71,030
)
 
(23,713,031
)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves
$
26,704,041

 
$
3,756

 
$
682,536

 
$
533,085

 
$
27,923,418

2013
 

 
 

 
 

 
 

 
 

Future cash inflows (3)
$
119,644,713

 
$
1,199,251

 
$
2,082,195

 
$
1,073,340

 
$
123,999,499

Future production costs
(49,099,393
)
 
(540,188
)
 
(315,483
)
 
(211,424
)
 
(50,166,488
)
Future development costs
(17,753,860
)
 
(529,788
)
 
(112,050
)
 
(153,653
)
 
(18,549,351
)
Future income taxes
(15,763,089
)
 
—

 
(603,786
)
 
(49,512
)
 
(16,416,387
)
Future net cash flows
37,028,371

 
129,275

 
1,050,876

 
658,751

 
38,867,273

Discount to present value at 10% annual rate
(17,451,470
)
 
202,379

 
(174,236
)
 
(110,514
)
 
(17,533,841
)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves
$
19,576,901

 
$
331,654

 
$
876,640

 
$
548,237

 
$
21,333,432

2012
 

 
 

 
 

 
 

 
 

Future cash inflows (4)
$
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

 
(1)
Other International includes EOG's United Kingdom, China and Argentina operations.
(2)
Estimated crude oil prices used to calculate 2014 future cash inflows for the United States, Canada, Trinidad and Other International were $97.51, $95.11, $80.60 and $94.09, respectively. Estimated NGL prices used to calculate 2014 future cash inflows for the United States and Canada were $34.29 and $27.03, respectively. Estimated natural gas prices used to calculate 2014 future cash inflows for the United States, Canada, Trinidad and Other International were $3.71, $4.79, $3.71 and $5.34, respectively.
(3)
Estimated crude oil prices used to calculate 2013 future cash inflows for the United States, Canada, Trinidad and Other International were $105.91, $91.47, $94.30 and $107.36, respectively. Estimated NGL prices used to calculate 2013 future cash inflows for the United States and Canada were $29.42 and $40.88, respectively.  Estimated natural gas prices used to calculate 2013 future cash inflows for the United States, Canada, Trinidad and Other International were $3.50, $2.95, $3.71 and $5.67, respectively.
(4)
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 NGL 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.

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, 2014:
 
United
States
 
Canada
 
Trinidad
 
Other
International
 
Total
 
 
 
 
 
 
 
 
 
 
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

Sales and transfers of oil and gas produced, net of production costs
(7,561,343
)
 
(155,239
)
 
(473,544
)
 
(6,254
)
 
(8,196,380
)
Net changes in prices and production costs
1,734,058

 
(438,982
)
 
(12,050
)
 
(25,173
)
 
1,257,853

Extensions, discoveries, additions and improved recovery, net of related costs
5,449,531

 
33,901

 
—

 
—

 
5,483,432

Development costs incurred
2,792,400

 
95,400

 
67,100

 
1,000

 
2,955,900

Revisions of estimated development cost
892,803

 
48,906

 
(3,539
)
 
52,226

 
990,396

Revisions of previous quantity estimates
1,887,062

 
(23,915
)
 
(60,419
)
 
(8,530
)
 
1,794,198

Accretion of discount
1,895,503

 
39,915

 
147,099

 
51,212

 
2,133,729

Net change in income taxes
(2,772,267
)
 
—

 
56,373

 
137,644

 
(2,578,250
)
Purchases of reserves in place
66,359

 
—

 
—

 
—

 
66,359

Sales of reserves in place
(140,652
)
 
—

 
—

 
—

 
(140,652
)
Changes in timing and other
152,113

 
332,519

 
194,550

 
(27,807
)
 
651,375

December 31, 2013
19,576,901

 
331,654

 
876,640

 
548,237

 
21,333,432

Sales and transfers of oil and gas produced, net of production costs
(8,874,180
)
 
(118,791
)
 
(473,757
)
 
(3,986
)
 
(9,470,714
)
Net changes in prices and production costs
1,481,668

 
(94,315
)
 
(12,079
)
 
(112,097
)
 
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

 
200

 
12,800

 
3,300

 
2,835,100

Revisions of estimated development cost
1,696,916

 
63,978

 
9,981

 
31,860

 
1,802,735

Revisions of previous quantity estimates
1,741,918

 
42,000

 
35,001

 
(6,387
)
 
1,812,532

Accretion of discount
2,612,286

 
33,165

 
133,019

 
54,880

 
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

 
34,936

 
6,380

 
10,527

 
1,242,348

December 31, 2014
$
26,704,041

 
$
3,756

 
$
682,536

 
$
533,085

 
$
27,923,418