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Oil and Gas Exploration and Production Industries Disclosures
 12 Months Ended
Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Oil and Gas Exploration and Production Industries Disclosures
EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

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

Oil and Gas Producing Activities

The following disclosures are made in accordance with Financial Accounting Standards Board Accounting Standards Update No. 2010-03 "Oil and Gas Reserve Estimates and Disclosures" and the United States Securities and Exchange Commission's (SEC) final rule on "Modernization of Oil and Gas Reporting."

Oil and Gas Reserves.  Users of this information should be aware that the process of estimating quantities of "proved," "proved developed" and "proved undeveloped" crude oil, natural gas liquids (NGLs) and natural gas reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir.  The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.  Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time.  Although reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.  See ITEM 1A. Risk Factors.

Proved reserves represent estimated quantities of crude oil, NGLs and natural gas that geoscience and engineering data can estimate, with reasonable certainty, to be economically producible from a given day forward from known reservoirs under then-existing economic conditions, operating methods and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Proved developed reserves are proved reserves expected to be recovered under operating methods being utilized at the time the estimates were made, through wells and equipment in place or if the cost of any required equipment is relatively minor compared to the cost of a new well.

Proved undeveloped reserves (PUDs) are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a significant expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. PUDs can be recorded in respect of a particular undrilled location only if the location is scheduled, under the then-current drilling and development plan, to be drilled within five years from the date that the PUDs are to be recorded, unless specific factors (such as those described in interpretative guidance issued by the Staff of the SEC) justify a longer timeframe.  Likewise, absent any such specific factors, PUDs associated with a particular undeveloped drilling location shall be removed from the estimates of proved reserves if the location is scheduled, under the then-current drilling and development plan, to be drilled on a date that is beyond five years from the date that the PUDs were recorded.  EOG has formulated development plans for all drilling locations associated with its PUDs at December 31, 2013.  Under EOG's current drilling and development plan, 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.

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In making estimates of PUDs, EOG's technical staff, including engineers and geoscientists, perform detailed technical analysis of each potential drilling location within its entire inventory of prospects.  In making a determination as to which of these locations would penetrate undrilled portions of the formation that can be judged, with reasonable certainty, to be continuous and contain economically producible crude oil and natural gas, studies are conducted using numerous data elements and analysis techniques.  EOG technical staff estimates the hydrocarbons in place, by mapping the entirety of the play in question using seismic techniques, typically employing two-dimensional and three-dimensional data.  This analysis is integrated with other static data, including, but not limited to, core analysis, mechanical properties of the formation, thermal maturity indicators, and well logs of existing penetrations.  Highly specialized equipment is utilized to prepare rock samples in assessing microstructures which contribute to porosity and permeability.

Analysis of dynamic data is then incorporated to arrive at the estimated fractional recovery of hydrocarbons in place.  Data analysis techniques employed include, but are not limited to, well testing analysis, static bottom hole pressure analysis, flowing bottom hole pressure analysis, analysis of historical production trends, pressure transient analysis and rate transient analysis.  Application of proprietary rate transient analysis techniques in low permeability rocks allow for quantification of estimates of contribution to production from both fractures and rock 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.

Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices, production volumes and the length of wells, both vertical and horizontal.  Canadian reserves, as presented on a net basis, assume prices and legislated future royalty rates and EOG's estimate of future production volumes.  Similarly, certain of EOG's Trinidad reserves are held under production sharing contracts where EOG's interest varies with prices and production volumes.  Trinidad reserves, as presented on a net basis, assume prices in existence at the time the estimates were made and EOG's estimate of future production volumes.  Future fluctuations in prices, production rates or changes in political or regulatory environments could cause EOG's share of future production from Canadian and Trinidadian reserves to be materially different from that presented.

Estimates of proved reserves at December 31, 2013, 2012 and 2011 were based on studies performed by the engineering staff of EOG.  The Engineering and Acquisitions Department is directly responsible for EOG's reserve evaluation process and consists of seven professionals, all of whom hold, at a minimum, bachelor's degrees in engineering, and two of whom are Registered Professional Engineers.  The Manager, Engineering and Acquisitions is the manager of this department and is the primary technical person responsible for this process.  The Manager, Engineering and Acquisitions holds a Bachelor of Science degree in Petroleum Engineering, has 28 years of experience in reserve evaluations and is a Registered Professional Engineer in the State of Texas.
EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

EOG's reserves estimation process is a collaborative effort coordinated by the Engineering and Acquisitions Department in compliance with EOG's internal controls for such process.  Reserve information as well as models used to estimate such reserves are stored on secured databases.  Non-technical inputs used in reserve estimation models, including crude oil, NGLs and natural gas prices, production costs, 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, 2013, 2012 and 2011 covered producing areas containing 82%, 87% and 85%, 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 31, 2014, 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, 2013, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.


EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following tables set forth EOG's net proved and proved developed reserves at December 31 for each of the four years in the period ended December 31, 2013, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2013, 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, 2010
  
355,457
   
25,636
   
4,731
   
98
   
385,922
 
Revisions of previous estimates
  
(21,188
)
  
(4,611
)
  
18
   
25
   
(25,756
)
Purchases in place
  
9
   
-
   
-
   
-
   
9
 
Extensions, discoveries and other additions
  
202,552
   
449
   
-
   
-
   
203,001
 
Sales in place
  
(4,301
)
  
-
   
-
   
-
   
(4,301
)
Production
  
(37,233
)
  
(2,882
)
  
(1,242
)
  
(25
)
  
(41,382
)
Net proved reserves at December 31, 2011
  
495,296
   
18,592
   
3,507
   
98
   
517,493
 
Revisions of previous estimates
  
4,105
   
(2,493
)
  
71
   
5
   
1,688
 
Purchases in place
  
1,010
   
-
   
-
   
-
   
1,010
 
Extensions, discoveries and other additions
  
241,171
   
5,681
   
-
   
8,834
   
255,686
 
Sales in place
  
(15,921
)
  
(1,343
)
  
-
   
-
   
(17,264
)
Production
  
(54,632
)
  
(2,574
)
  
(550
)
  
(39
)
  
(57,795
)
Net proved reserves at December 31, 2012
  
671,029
   
17,863
   
3,028
   
8,898
   
700,818
 
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
 
 
                    
Natural Gas Liquids (MBbl) (2)
                    
Net proved reserves at December 31, 2010
  
150,434
   
1,475
   
-
   
-
   
151,909
 
Revisions of previous estimates
  
35,999
   
43
   
-
   
-
   
36,042
 
Purchases in place
  
17
   
-
   
-
   
-
   
17
 
Extensions, discoveries and other additions
  
65,288
   
-
   
-
   
-
   
65,288
 
Sales in place
  
(10,008
)
  
-
   
-
   
-
   
(10,008
)
Production
  
(15,144
)
  
(316
)
  
-
   
-
   
(15,460
)
Net proved reserves at December 31, 2011
  
226,586
   
1,202
   
-
   
-
   
227,788
 
Revisions of previous estimates
  
47,293
   
563
   
-
   
-
   
47,856
 
Purchases in place
  
612
   
-
   
-
   
-
   
612
 
Extensions, discoveries and other additions
  
71,396
   
178
   
-
   
-
   
71,574
 
Sales in place
  
(7,300
)
  
(77
)
  
-
   
-
   
(7,377
)
Production
  
(20,181
)
  
(309
)
  
-
   
-
   
(20,490
)
Net proved reserves at December 31, 2012
  
318,406
   
1,557
   
-
   
-
   
319,963
 
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
 



EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


 
 
United
States
  
Canada
  
Trinidad
  
Other
International (1)
  
Total
 
 
 
  
  
  
  
 
Natural Gas (Bcf) (3)
 
  
  
  
  
 
Net proved reserves at December 31, 2010
  
6,491.5
   
1,133.8
   
827.6
   
17.3
   
8,470.2
 
Revisions of previous estimates
  
(344.0
)
  
(49.8
)
  
(24.2
)
  
1.3
   
(416.7
)
Purchases in place
  
3.0
   
-
   
-
   
-
   
3.0
 
Extensions, discoveries and other additions
  
634.6
   
-
   
74.7
   
4.5
   
713.8
 
Sales in place
  
(323.6
)
  
-
   
-
   
-
   
(323.6
)
Production
  
(415.7
)
  
(48.1
)
  
(127.4
)
  
(4.6
)
  
(595.8
)
Net proved reserves at December 31, 2011
  
6,045.8
   
1,035.9
   
750.7
   
18.5
   
7,850.9
 
Revisions of previous estimates
  
(1,736.0
)
  
(894.5
)
  
(24.1
)
  
1.6
   
(2,653.0
)
Purchases in place
  
14.8
   
-
   
-
   
-
   
14.8
 
Extensions, discoveries and other additions
  
477.8
   
-
   
-
   
0.3
   
478.1
 
Sales in place
  
(386.2
)
  
(8.5
)
  
-
   
-
   
(394.7
)
Production
  
(380.2
)
  
(34.6
)
  
(138.4
)
  
(3.4
)
  
(556.6
)
Net proved reserves at December 31, 2012
  
4,036.0
   
98.3
   
588.2
   
17.0
   
4,739.5
 
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
 
 
                    
Oil Equivalents (MBoe) (2)
                    
Net proved reserves at December 31, 2010
  
1,587,806
   
216,084
   
142,669
   
2,976
   
1,949,535
 
Revisions of previous estimates
  
(42,526
)
  
(12,865
)
  
(4,011
)
  
239
   
(59,163
)
Purchases in place
  
521
   
-
   
-
   
-
   
521
 
Extensions, discoveries and other additions
  
373,602
   
448
   
12,455
   
750
   
387,255
 
Sales in place
  
(68,247
)
  
-
   
-
   
-
   
(68,247
)
Production
  
(121,648
)
  
(11,219
)
  
(22,484
)
  
(787
)
  
(156,138
)
Net proved reserves at December 31, 2011
  
1,729,508
   
192,448
   
128,629
   
3,178
   
2,053,763
 
Revisions of previous estimates
  
(237,936
)
  
(151,015
)
  
(3,953
)
  
283
   
(392,621
)
Purchases in place
  
4,098
   
-
   
-
   
-
   
4,098
 
Extensions, discoveries and other additions
  
392,196
   
5,860
   
-
   
8,876
   
406,932
 
Sales in place
  
(87,588
)
  
(2,832
)
  
-
   
-
   
(90,420
)
Production
  
(138,170
)
  
(8,657
)
  
(23,616
)
  
(611
)
  
(171,054
)
Net proved reserves at December 31, 2012
  
1,662,108
   
35,804
   
101,060
   
11,726
   
1,810,698
 
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
 

(1)Other International includes EOG's United Kingdom, China and Argentina operations.
(2)Thousand barrels or thousand barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGLs and natural gas. Oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas.
(3)Billion cubic feet.
 
EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

During 2013, EOG added 399 million barrels of oil equivalent (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 NGLs 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.  Revisions of previous estimates of positive 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 NGLs and over 96% were in the United States.  Sales in place of 90 MMBoe were primarily related to the disposition of certain producing natural gas assets on the Gulf Coast, outside-operated crude oil properties in the Rocky Mountain area and other producing basins in the United States.  Revisions of previous estimates of negative 393 MMBoe for 2012 included a negative revision of 531 MMBoe primarily due to a decrease in the average natural gas price used in the December 31, 2012 reserves estimation as compared to the price used in the prior year estimate. The primary plays affected were the Horn River, Haynesville, Barnett Shale and Marcellus Shale.  Revisions other than price resulted from revisions for certain crude oil and natural gas properties in the United States.

During 2011, EOG added 387 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Barnett Combo and Bakken shale plays.  Approximately 69% of the 2011 reserve additions were crude oil and condensate and NGLs and over 96% were in the United States.  Sales in place of 68 MMBoe were primarily related to the disposition of certain producing natural gas assets in East Texas, the Rocky Mountain area and other producing basins in the United States. Revisions of previous estimates of negative 59 MMBoe for 2011 included a negative revision of 16 MMBoe primarily due to a decrease in the average natural gas price used in the December 31, 2011 reserves estimation as compared to the price used in the prior year estimate.  Revisions other than price resulted from negative revisions for certain crude oil and natural gas properties in the United States, Canada and Trinidad.


EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 
 
United
States
  
Canada
  
Trinidad
  
Other
International (1)
  
Total
 
 
 
  
  
  
  
 
NET PROVED DEVELOPED RESERVES
 
  
  
  
  
 
 
 
  
  
  
  
 
Crude Oil (MBbl)
 
  
  
  
  
 
December 31, 2010
  
161,907
   
11,283
   
3,852
   
98
   
177,140
 
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
 
Natural Gas Liquids (MBbl)
                    
December 31, 2010
  
91,401
   
1,475
   
-
   
-
   
92,876
 
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
 
Natural Gas (Bcf)
                    
December 31, 2010
  
3,519.7
   
401.6
   
519.2
   
17.3
   
4,457.8
 
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
 
Oil Equivalents (MBoe)
                    
December 31, 2010
  
839,928
   
79,701
   
90,382
   
2,976
   
1,012,987
 
December 31, 2011
  
877,301
   
58,524
   
103,710
   
3,178
   
1,042,713
 
December 31, 2012
  
840,564
   
24,348
   
81,826
   
3,081
   
949,819
 
December 31, 2013
  
1,015,359
   
24,782
   
83,933
   
3,402
   
1,127,476
 
 
                    
 
                    
NET PROVED UNDEVELOPED RESERVES
                    
 
                    
Crude Oil (MBbl)
                    
December 31, 2010
  
193,550
   
14,353
   
879
   
-
   
208,782
 
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
 
Natural Gas Liquids (MBbl)
                    
December 31, 2010
  
59,033
   
-
   
-
   
-
   
59,033
 
December 31, 2011
  
102,315
   
110
   
-
   
-
   
102,425
 
December 31, 2012
  
156,924
   
446
   
-
   
-
   
157,370
 
December 31, 2013
  
176,038
   
308
   
-
   
-
   
176,346
 
Natural Gas (Bcf)
                    
December 31, 2010
  
2,971.8
   
732.2
   
308.4
   
-
   
4,012.4
 
December 31, 2011
  
2,810.8
   
740.1
   
144.4
   
-
   
3,695.3
 
December 31, 2012
  
1,648.5
   
-
   
111.5
   
-
   
1,760.0
 
December 31, 2013
  
1,801.4
   
-
   
26.1
   
3.9
   
1,831.4
 
Oil Equivalents (MBoe)
                    
December 31, 2010
  
747,878
   
136,383
   
52,287
   
-
   
936,548
 
December 31, 2011
  
852,207
   
133,924
   
24,919
   
-
   
1,011,050
 
December 31, 2012
  
821,544
   
11,456
   
19,234
   
8,645
   
860,879
 
December 31, 2013
  
973,807
   
3,557
   
4,431
   
9,272
   
991,067
 

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

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the twelve-month period ended December 31, 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 (see discussion of technology employed on page F-36 of this Annual Report on Form 10-K), 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 NGLs.  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 NGLs.  During 2012, EOG drilled and transferred 138 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,764 million.  Revisions of PUDs totaled negative 293 MMBoe, primarily due to removal of certain natural gas PUDs due to lower average natural gas prices.  The primary plays affected were the Horn River, Haynesville, Barnett Shale and Marcellus Shale.  During 2012, EOG sold 19 MMBoe of PUDs.

For the twelve-month period ended December 31, 2011, total PUDs increased by 75 MMBoe to 1,011 MMBoe.  EOG added approximately 36 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion.  Based on the technology employed by EOG to identify and record PUDs, EOG added 199 MMBoe.  The PUD additions were primarily in the Eagle Ford and Barnett Combo shale plays, and over 78% of the additions were crude oil and condensate and NGLs.  During 2011, EOG drilled and transferred 144 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,619 million.  Revisions of PUDs totaled negative 7 MMBoe, primarily due to removal of certain natural gas PUDs from the five-year drilling plan.  During 2011, EOG sold 9 MMBoe of PUDs.


EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Capitalized Costs Relating to Oil and Gas Producing Activities.  The following table sets forth the capitalized costs relating to EOG's crude oil and natural gas producing activities at December 31, 2013 and 2012:

 
 
2013
  
2012
 
 
 
  
 
Proved properties
 
$
41,377,303
  
$
36,872,434
 
Unproved properties
  
1,444,500
   
1,253,864
 
Total
  
42,821,803
   
38,126,298
 
Accumulated depreciation, depletion and amortization
  
(18,880,611
)
  
(16,849,068
)
Net capitalized costs
 
$
23,941,192
  
$
21,277,230
 


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.

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended December 31, 2013, 2012 and 2011:

 
 
United
States
  
Canada
  
Trinidad
  
Other
International (1)
  
Total
 
 
 
  
  
  
  
 
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 (2)
  
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 (3)
  
5,657,378
   
278,995
   
32,609
   
147,568
   
6,116,550
 
Total
 
$
6,462,996
  
$
351,086
  
$
53,164
  
$
200,944
  
$
7,068,190
 
 
                    
2011
                    
Acquisition Costs of Properties
                    
Unproved
 
$
295,160
  
$
6,216
  
$
-
  
$
(604
)
 
$
300,772
 
Proved
  
4,219
   
28
   
-
   
-
   
4,247
 
Subtotal
  
299,379
   
6,244
   
-
   
(604
)
  
305,019
 
Exploration Costs
  
311,369
   
31,472
   
2,549
   
18,164
   
363,554
 
Development Costs (4)
  
5,410,378
   
302,564
   
138,905
   
78,744
   
5,930,591
 
Total
 
$
6,021,126
  
$
340,280
  
$
141,454
  
$
96,304
  
$
6,599,164
 

(1)Other International primarily consists of EOG's United Kingdom, China and Argentina operations.
(2)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.
(3)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.
(4)Includes Asset Retirement Costs of $52 million, $70 million, $7 million and $4 million for the United States, Canada, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.




EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Results of Operations for Oil and Gas Producing Activities (1). The following table sets forth results of operations for oil and gas producing activities for the years ended December 31, 2013, 2012 and 2011:

          
 
 
United
States
  
Canada
  
Trinidad
  
Other
International (2)
  
Total
 
 
 
  
  
  
  
 
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
 
 
                    
2011
                    
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues
 
$
5,814,942
  
$
459,853
  
$
555,143
  
$
28,250
  
$
6,858,188
 
Other
  
32,329
   
258
   
586
   
-
   
33,173
 
Total
  
5,847,271
   
460,111
   
555,729
   
28,250
   
6,891,361
 
Exploration Costs
  
148,199
   
10,479
   
2,520
   
10,460
   
171,658
 
Dry Hole Costs
  
30,521
   
432
   
-
   
22,277
   
53,230
 
Transportation Costs
  
421,060
   
5,969
   
1,620
   
1,673
   
430,322
 
Production Costs
  
1,096,955
   
174,973
   
49,318
   
10,964
   
1,332,210
 
Impairments
  
575,976
   
452,103
   
-
   
2,958
   
1,031,037
 
Depreciation, Depletion and Amortization
  
2,011,080
   
258,772
   
106,802
   
17,160
   
2,393,814
 
Income (Loss) Before Income Taxes
  
1,563,480
   
(442,617
)
  
395,469
   
(37,242
)
  
1,479,090
 
Income Tax Provision (Benefit)
  
569,153
   
(121,044
)
  
202,815
   
(13,056
)
  
637,868
 
Results of Operations
 
$
994,327
  
$
(321,573
)
 
$
192,654
  
$
(24,186
)
 
$
841,222
 

(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, 2013.
(2)Other International primarily consists of EOG's United Kingdom, China and Argentina operations.


EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table sets forth production costs per barrel of oil equivalent, excluding severance/production and ad valorem taxes, for the years ended December 31, 2013, 2012 and 2011:

 
 
United
States
  
Canada
  
Trinidad
  
Other
International (1)
  
Composite
 
 
 
  
  
  
  
 
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
 
 
                    
Year Ended December 31, 2011
 
$
6.19
  
$
14.26
  
$
0.78
  
$
13.82
  
$
6.03
 

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

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves.  The following information has been developed utilizing procedures prescribed by the Extractive Industries - Oil and Gas Topic of the ASC and based on crude oil, NGLs and natural gas reserves and production volumes estimated by the Engineering and Acquisitions Department of EOG.  The estimates were based on a 12-month average for commodity prices for the years 2013, 2012 and 2011.  The following information  may be useful for certain comparison purposes, but should not be solely relied upon in evaluating EOG or its performance.  Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of EOG.

The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections.  It is expected that material revisions to some estimates of crude oil, NGLs and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions.  Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table sets forth the standardized measure of discounted future net cash flows from projected production of EOG's oil and gas reserves for the years ended December 31, 2013, 2012 and 2011:

 
 
United
States
  
Canada
  
Trinidad
  
Other
International (1)
  
Total
 
 
 
  
  
  
  
 
2013
 
  
  
  
  
 
Future cash inflows (2)
 
$
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 (3)
 
$
89,324,274
  
$
1,816,369
  
$
2,408,116
  
$
1,063,854
  
$
94,612,613
 
Future production costs
  
(35,892,997
)
  
(751,113
)
  
(342,113
)
  
(198,609
)
  
(37,184,832
)
Future development costs
  
(15,825,040
)
  
(813,061
)
  
(171,737
)
  
(221,893
)
  
(17,031,731
)
Future income taxes
  
(10,247,007
)
  
-
   
(691,109
)
  
(212,626
)
  
(11,150,742
)
Future net cash flows
  
27,359,230
   
252,195
   
1,203,157
   
430,726
   
29,245,308
 
Discount to present value at 10% annual rate
  
(12,177,896
)
  
146,954
   
(242,087
)
  
(56,807
)
  
(12,329,836
)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves
 
$
15,181,334
  
$
399,149
  
$
961,070
  
$
373,919
  
$
16,915,472
 
2011
                    
Future cash inflows (4)
 
$
84,518,638
  
$
5,056,501
  
$
2,851,545
  
$
103,853
  
$
92,530,537
 
Future production costs
  
(33,294,343
)
  
(2,315,110
)
  
(388,199
)
  
(62,938
)
  
(36,060,590
)
Future development costs
  
(13,811,449
)
  
(1,566,917
)
  
(149,884
)
  
(331
)
  
(15,528,581
)
Future income taxes
  
(10,539,182
)
  
(81,590
)
  
(794,856
)
  
(2,457
)
  
(11,418,085
)
Future net cash flows
  
26,873,664
   
1,092,884
   
1,518,606
   
38,127
   
29,523,281
 
Discount to present value at 10% annual rate
  
(12,498,010
)
  
(456,537
)
  
(334,399
)
  
(9,054
)
  
(13,298,000
)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves
 
$
14,375,654
  
$
636,347
  
$
1,184,207
  
$
29,073
  
$
16,225,281
 

(1)Other International includes EOG's United Kingdom, China and Argentina operations.
(2)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 NGLs 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.
(3)Estimated crude oil prices used to calculate 2012 future cash inflows for the United States, Canada, Trinidad and Other International were $99.78, $84.77, $94.46 and $109.94, respectively.  Estimated NGLs prices used to calculate 2012 future cash inflows for the United States and Canada were $36.95 and $47.80, respectively. Estimated natural gas prices used to calculate 2012 future cash inflows for the United States, Canada, Trinidad and Other International were $2.63, $2.22, $3.61, and $5.04, respectively.
(4)Estimated crude oil prices used to calculate 2011 future cash inflows for the United States, Canada, Trinidad and Other International were $97.75, $90.70, $92.50 and $102.86, respectively. Estimated NGLs prices used to calculate 2011 future cash inflows for the United States and Canada were $51.77 and $46.97, respectively. Estimated natural gas prices used to calculate 2011 future cash inflows for the United States, Canada, Trinidad and Other International were $4.03, $3.28, $3.37 and $5.07, respectively.


EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Changes in Standardized Measure of Discounted Future Net Cash Flows.  The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 2013:

 
 
United
States
  
Canada
  
Trinidad
  
Other
International
  
Total
 
December 31, 2010
  
10,628,924
   
746,235
   
988,866
   
27,799
   
12,391,824
 
Sales and transfers of oil and gas produced, net of production costs
  
(4,296,926
)
  
(278,910
)
  
(504,205
)
  
(15,614
)
  
(5,095,655
)
Net changes in prices and production costs
  
716,682
   
(57,545
)
  
331,196
   
3,328
   
993,661
 
Extensions, discoveries, additions and improved recovery, net of related costs
  
6,223,552
   
22,591
   
102,548
   
-
   
6,348,691
 
Development costs incurred
  
1,422,500
   
48,200
   
74,800
   
-
   
1,545,500
 
Revisions of estimated development cost
  
(210,919
)
  
64,001
   
(14,074
)
  
2
   
(160,990
)
Revisions of previous quantity estimates
  
(482,496
)
  
(70,718
)
  
(56,884
)
  
801
   
(609,297
)
Accretion of discount
  
1,352,740
   
62,725
   
159,715
   
2,782
   
1,577,962
 
Net change in income taxes
  
(1,049,641
)
  
(118,988
)
  
9,511
   
13
   
(1,159,105
)
Purchases of reserves in place
  
5,241
   
-
   
-
   
-
   
5,241
 
Sales of reserves in place
  
(658,468
)
  
-
   
-
   
-
   
(658,468
)
Changes in timing and other
  
724,465
   
218,756
   
92,734
   
9,962
   
1,045,917
 
December 31, 2011
  
14,375,654
   
636,347
   
1,184,207
   
29,073
   
16,225,281
 
Sales and transfers of oil and gas produced, net of production costs
  
(5,192,392
)
  
(159,577
)
  
(526,134
)
  
(10,214
)
  
(5,888,317
)
Net changes in prices and production costs
  
(393,585
)
  
(67,964
)
  
162,600
   
(2,283
)
  
(301,232
)
Extensions, discoveries, additions and improved recovery, net of related costs
  
5,517,945
   
79,529
   
-
   
484,648
   
6,082,122
 
Development costs incurred
  
2,042,300
   
23,600
   
23,500
   
5,200
   
2,094,600
 
Revisions of estimated development cost
  
1,987,330
   
383,215
   
(28,835
)
  
(234
)
  
2,341,476
 
Revisions of previous quantity estimates
  
(3,286,943
)
  
(396,408
)
  
(62,285
)
  
2,809
   
(3,742,827
)
Accretion of discount
  
1,832,377
   
63,635
   
178,298
   
2,907
   
2,077,217
 
Net change in income taxes
  
174,418
   
-
   
88,853
   
(138,206
)
  
125,065
 
Purchases of reserves in place
  
64,317
   
-
   
-
   
5,623
   
69,940
 
Sales of reserves in place
  
(869,534
)
  
(44,227
)
  
-
   
-
   
(913,761
)
Changes in timing and other
  
(1,070,553
)
  
(119,001
)
  
(59,134
)
  
(5,404
)
  
(1,254,092
)
December 31, 2012
  
15,181,334
   
399,149
   
961,070
   
373,919
   
16,915,472
 
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