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EOG Resources Reports Fourth Quarter and Full Year 2014 Results and Announces Return-Driven Capital Program for 2015

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FOR IMMEDIATE RELEASE: February 18, 2015

HOUSTON, Feb. 18, 2015 /PRNewswire/ --

  • Realizes 16 Percent ROE and 14 Percent ROCE for 2014
  • Delivers 31 Percent Year-Over-Year Total Company Crude Oil Production Growth and 17 Percent Total Company Production Growth
  • Reports Robust Year-Over-Year Increases in Adjusted Non-GAAP Net Income Per Share and Discretionary Cash Flow
  • Increases Reserves 18 Percent and Replaces 273 Percent of its Production at Low Finding Costs
  • Continues to Achieve Outstanding Performance from the Eagle Ford, Bakken and Delaware Basin
  • Announces Disciplined 2015 Capital Program, Plans to Delay Well Completions and Targets Flat Year-Over-Year Crude Oil Production

EOG Resources, Inc. (NYSE: EOG) (EOG) today reported fourth quarter 2014 net income of $445 million, or $0.81 per share. This compares to fourth quarter 2013 net income of $580 million, or $1.06 per share. For the full year, EOG reported net income of $2,915 million, or $5.32 per share, compared to $2,197 million, or $4.02 per share, for the full year 2013.

Adjusted non-GAAP net income for the fourth quarter 2014 was $432 million, or $0.79 per share, and for the fourth quarter 2013 was $548 million, or $1.00 per share. Adjusted non-GAAP net income for the full year 2014 was $2,716 million, or $4.95 per share, and for the full year 2013 was $2,246 million, or $4.11 per share. Adjusted non-GAAP net income is calculated by matching realizations to settlement months and making certain other adjustments in order to exclude one-time items. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP.)

EOG achieved strong financial metrics for 2014. Adjusted non-GAAP net income per share increased 20 percent and discretionary cash flow increased 14 percent, compared to 2013. For the year, EOG posted ROE of 16 percent and ROCE of 14 percent. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP and for return calculations.)

In the fourth quarter 2014, EOG increased its U.S. crude oil and condensate production by 28 percent, while total company crude oil and condensate production rose by 26 percent, compared to the same prior year period.

For the full year, crude oil and condensate production increased 31 percent year over year, driven by 33 percent growth in the United States. Natural gas liquids (NGLs) production increased 23 percent, while natural gas production was flat. Overall total company production increased 17 percent.

"EOG delivered both high returns and strong growth in 2014, a unique accomplishment in the energy sector," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "Our returns-focused capital discipline has been at the core of EOG's culture since the very beginning. We are confident we will continue to earn healthy returns on our capital program during this commodity down cycle and, more importantly, emerge stronger and poised for significant long-term growth."

2015 Capital Plan

EOG's primary goal for 2015 is to position the company to resume long-term growth once crude oil prices recover. The company is not interested in accelerating crude oil production in a low-price environment.

Capital expenditures for 2015 are expected to range from $4.9 to $5.1 billion, including production facilities and midstream expenditures, and excluding acquisitions. This 40 percent reduction compared to 2014 reflects EOG's commitment to capital discipline in a low crude oil price environment.

Capital will be allocated primarily to EOG's highest rate-of-return oil assets, the Eagle Ford, Delaware Basin and Bakken plays. To further enhance capital efficiency, EOG plans to utilize rigs under existing commitments and delay a significant number of completions. Delaying completions increases returns, adds substantial net present value and prepares the company to resume strong oil growth when commodity prices recover.

Due to reduced capital spending and delayed completions, EOG expects to complete approximately 45 percent fewer wells in 2015 versus 2014. Therefore, the midpoint for 2015 total company crude oil production guidance is essentially flat year over year. Once again, EOG plans to minimize investment in domestic dry natural gas drilling. As a result, its U.S. natural gas production and total company production are expected to decline modestly.

Year after year, EOG has relentlessly focused on advancing its industry-leading completion technology and driving down unit costs through efficiency gains. That will not change in 2015.

Finally, the company expects to use its strong balance sheet to capitalize on unique opportunities created by this low-price environment to add high-quality acreage.

"The downturn in oil prices will drive significant reductions in global supply and the market will rebalance," Thomas said. "Our goal at EOG is to exit this downturn in better shape than we entered it.

"The current environment brings more opportunities to lower our finding costs, improve our returns and add high-quality drilling inventory. As prices recover, EOG will be poised to resume strong U.S. oil growth," Thomas added.

South Texas Eagle Ford

The Eagle Ford continues to drive EOG's long-term crude oil growth. Each year since its operations began five years ago, EOG has improved per-well productivity and successfully downspaced wells through advancements in completion technology. Estimated potential net reserves have grown 250 percent from 900 million barrels of oil equivalent (MMBoe) in 2009 to 3.2 billion barrels of oil equivalent today. EOG has over 5,500 remaining net well locations in the Eagle Ford – over a decade of drilling. This world-class play will continue to be EOG's primary source of returns and growth for years to come.

During the fourth quarter of 2014, the Eagle Ford continued to deliver impressive well results across EOG's acreage. The Korth Unit 6H through 9H had initial production rates ranging from 3,955 to 5,480 barrels of oil per day (Bopd), 355 to 535 barrels per day (Bpd) of NGLs and 2.1 to 3.1 million cubic feet per day (MMcfd) of natural gas. This four-well pattern drilled in Karnes County initially produced over 19,000 Bopd, 1,700 Bpd of NGLs and 10 MMcfd of natural gas, collectively.

On the western side of EOG's Eagle Ford acreage in La Salle County, the Naylor Jones Unit 14-1H and 15-1H had initial production rates of 2,460 and 2,850 Bopd, plus 165 and 190 Bpd of NGLs and 975 thousand cubic feet per day (Mcfd) and 1.1 MMcfd of natural gas, respectively. In McMullen County, the Los Compadres Unit 1H was brought online at an initial production rate of 2,535 Bopd, with 180 Bpd of NGLs and 1.1 MMcfd of natural gas.

In 2015, EOG will execute a balanced drilling program across the length of its Eagle Ford acreage. Due to advancements achieved in the western acreage during the last two years, returns are competitive with the east and a balanced drilling program will maximize operational efficiencies. EOG plans to complete about 345 net wells in the Eagle Ford compared to 534 in 2014.

Delaware Basin

In 2014, EOG expanded activity in the Delaware Basin resulting in the identification of considerable new potential across three separate targets. EOG's technical understanding of the basin advanced, confirmed by a series of impressive well results in the second half of the year. With lower costs and improved well productivity, EOG's drilling program across the Delaware Basin is now consistently generating rates-of-return which are on par with the Eagle Ford and Bakken plays.

In the Second Bone Spring Sand, EOG applied advanced completion techniques and determined that at least 90,000 net acres of its leasehold are prospective in the oil window. In the Leonard, the company continued to make technical progress. EOG piloted multiple downspacing tests which could eventually increase the size of its crude oil drilling inventory in the Leonard play.

In the Delaware Basin Wolfcamp, EOG made significant advancements in well productivity, breaking its own record initial production rates with each successive well. Most recently, EOG completed three wells in Reeves County. The State Harrison Ranch 57 #1501H and #2101H and the State Apache 57 #202H had initial production rates ranging from 1,500 to over 2,000 Bopd, with 550 to 700 Bpd of NGLs and 4.0 to 4.5 MMcfd of natural gas.

Also in 2014, EOG confirmed that 90,000 net acres of its total 140,000 net-acre Wolfcamp position are in the oil window.

In 2015, capital expenditures will increase in the Permian Basin as EOG expects to complete about 95 net wells, a 53 percent increase compared to 2014. Capital will be directed to development drilling in the northern Delaware Basin targeting EOG's three highest-return plays – the Leonard, the Second Bone Spring Sand and the Wolfcamp. Ongoing technical work will determine the most efficient approach to develop these three plays and enable EOG to test additional prospective zones.

North Dakota Bakken

In 2014, EOG's drilling activity in North Dakota was directed to two key areas, the Bakken Core and the Antelope Extension. The focus this past year has been to drive down drilling costs and further advance completions to improve well performance and allow for additional downspacing. In the fourth quarter, EOG completed a six-well pattern in the Bakken Core area spaced at 700 feet between wells which delivered a combined initial production rate of 9,450 Bopd and 5 MMcfd of rich natural gas. Initial results from these completion and downspacing pilots are very encouraging, and additional pilots and testing in 2015 are designed to uncover the best long-term development plan for this crude oil growth play.  

Also in 2014, EOG stepped out from the Bakken to test the Three Forks formation, particularly in the Antelope Extension, with some notable well results. Due to the low-price crude oil environment, additional development of this high-potential target will be put on hold.

Capital allocated to the Bakken will decrease significantly in 2015. EOG expects to complete about 25 net wells compared to 59 in 2014. 

Wyoming Rockies

2014 was a big year for exploration in Wyoming as EOG announced four Rockies plays, the Codell and Niobrara in the DJ Basin, and the Parkman and Turner in the Powder River Basin. All four plays generated strong rates of return and consistent well results in 2014.

EOG completed several excellent wells in the fourth quarter in these emerging plays. In the DJ Basin Codell, the Windy 515-1819H and Windy 509-1806H had initial production rates of 1,490 and 1,355 Bopd, with 145 and 110 Bpd of NGLs, and 515 and 375 Mcfd of natural gas, respectively.

In the Powder River Basin, three recently completed Parkman wells, the Mary's Draw 4-0310H, 26-0310H and 209-0310H, had initial production rates of 1,160, 1,425 and 1,205 Bopd, with 460, 525, 1,015 Mcfd of rich natural gas, respectively. Two Turner completions are the Mary's Draw 7-24H and 8-24RH with initial production rates of 915 Bopd and 1.9 MMcfd of rich natural gas, and 925 Bopd and 1.9 MMcfd of rich natural gas, respectively.

EOG does not plan significant development of its DJ Basin or Powder River Basin assets until crude oil prices improve.

"EOG continues to demonstrate its leadership in growing high-return drilling inventory organically," Thomas said. "Last year at this time, we announced an increase to the reserves and drilling inventory in the Eagle Ford. A quarter later, we announced four plays in the Rockies. By the third quarter, we had delineated the Second Bone Spring Sand and identified the Wolfcamp oil window in the Delaware Basin. As in years past, we added more high-return inventory than we drilled during the year."

Reserves

Driven almost entirely by strong liquids reserves growth in the United States, EOG increased total company net proved reserves 18 percent in 2014. At year-end, total company net proved reserves were 2,497 MMBoe, comprised of 46 percent crude oil and condensate, 19 percent NGLs and 35 percent natural gas.

Net proved reserve additions replaced 273 percent of EOG's 2014 production at a finding and development cost of $12.16 per barrel of oil equivalent (Boe). Excluding reserve revisions due to commodity price changes, the replacement ratio was 249 percent at a cost of $13.25 per Boe. (For more reserves detail, including calculation of reserve replacement ratios and reserve replacement costs, please refer to the attached tables.)

For the 27th consecutive year, internal reserve estimates were within 5 percent of estimates independently prepared by DeGolyer and MacNaughton.

Hedging Activity

For February 1 through June 30, 2015, EOG has crude oil financial price swap contracts in place for 47,000 Bopd at a weighted average price of $91.22 per barrel. For July 1 through December 31, 2015, EOG has crude oil financial price swap contracts in place for 10,000 Bopd at a weighted average price of $89.98 per barrel, excluding unexercised options.

For March 1 through December 31, 2015, EOG has natural gas financial price swap contracts in place for approximately 182,000 million British thermal units per day at a weighted average price of $4.51 per million British thermal units, excluding unexercised options. (For a comprehensive summary of crude oil and natural gas derivative contracts, please refer to the attached tables.)

Capital Structure

During 2014, EOG's cash flows from operating activities exceeded total capital expenditures. Total proceeds from asset sales were $569 million.

At December 31, 2014, EOG's total debt outstanding was $5,910 million for a debt-to-total capitalization ratio of 25 percent. Taking into account cash on the balance sheet of $2,087 million at year-end, EOG's net debt was $3,823 million for a net debt-to-total capitalization ratio of 18 percent, down from 23 percent at year-end 2013. (Please refer to the attached tables for the reconciliation of non-GAAP debt measures to GAAP.)

Dividend

The board of directors declared a dividend of $0.1675 per share on EOG's Common Stock, payable April 30, 2015, to stockholders of record as of April 16, 2015. The indicated annual rate is $0.67 per share.

Conference Call February 19, 2015

EOG's fourth quarter and full year 2014 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Thursday, February 19, 2015. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through March 5, 2015.

This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements.  EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements.  In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate income or cash flows or pay dividends are forward-looking statements.  Forward-looking statements are not guarantees of performance.  Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct.  Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control.  Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

  • the timing, extent and duration of changes in prices for, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;
  • the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
  • the extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and optimize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;
  • the extent to which EOG is successful in its efforts to market its crude oil, natural gas and related commodity production;
  • the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, transportation and refining facilities;
  • the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses and leases;
  • the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations; environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
  • EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;
  • the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;
  • competition in the oil and gas exploration and production industry for employees and other personnel, facilities, equipment, materials and services;
  • the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) and services;
  • the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
  • weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression and transportation facilities;
  • the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
  • EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
  • the extent and effect of any hedging activities engaged in by EOG;
  • the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
  • political conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates;
  • the use of competing energy sources and the development of alternative energy sources;
  • the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
  • acts of war and terrorism and responses to these acts;
  • physical, electronic and cyber security breaches; and
  • the other factors described under Item 1A, "Risk Factors", on pages 13 through 20 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2014 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the extent of their impact on our actual results.  Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

 

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves).  Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines.  Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2014, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov.  In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.

Investors
Cedric W. Burgher
(713) 571-4658
David J. Streit
(713) 571-4902
Kimberly M. Ehmer
(713) 571-4676

Media
K Leonard
(713) 571-3870

 

EOG RESOURCES, INC.

FINANCIAL REPORT

(Unaudited; in millions, except per share data)

 
 

Three Months Ended

 

Twelve Months Ended

 

December 31,

 

December 31,

 

2014

 

2013

 

2014

 

2013

                       

Net Operating Revenues

$

4,645.5

 

$

3,749.0

 

$

18,035.3

 

$

14,487.1

Net Income 

$

444.6

 

$

580.2

 

$

2,915.5

 

$

2,197.1

Net Income Per Share 

                     
 

Basic

$

0.82

 

$

1.07

 

$

5.36

 

$

4.07

 

Diluted

$

0.81

 

$

1.06

 

$

5.32

 

$

4.02

Average Number of Common Shares

                     
 

Basic

 

544.6

   

541.9

   

543.4

   

540.3

 

Diluted

 

549.2

   

548.0

   

548.5

   

546.2

 
 

SUMMARY INCOME STATEMENTS
(Unaudited; in thousands, except per share data)

 
 

Three Months Ended

 

Twelve Months Ended

 

December 31,

 

December 31,

 

2014

 

2013

 

2014

 

2013

Net Operating Revenues

             
 

Crude Oil and Condensate

$

2,054,901

 

$

2,168,073

 

$

9,742,480

 

$

8,300,647

 

Natural Gas Liquids

 

180,916

   

217,794

   

934,051

   

773,970

 

Natural Gas

 

407,494

   

411,425

   

1,916,386

   

1,681,029

 

Gains (Losses) on Mark-to-Market Commodity Derivative Contracts

 

 

750,154

   

 

40,504

   

 

834,273

   

 

(166,349)

 

Gathering, Processing and Marketing

 

806,177

   

888,680

   

4,046,316

   

3,643,749

 

Gains on Asset Dispositions, Net

 

431,890

   

11,996

   

507,590

   

197,565

 

Other, Net

 

13,965

   

10,551

   

54,244

   

56,507

   

Total

 

4,645,497

   

3,749,023

   

18,035,340

   

14,487,118

Operating Expenses

                     
 

Lease and Well

 

380,781

   

288,921

   

1,416,413

   

1,105,978

 

Transportation Costs

 

242,293

   

224,506

   

972,176

   

853,044

 

Gathering and Processing Costs

 

37,785

   

26,349

   

145,800

   

107,871

 

Exploration Costs

 

45,167

   

30,378

   

184,388

   

161,346

 

Dry Hole Costs

 

18,225

   

15,395

   

48,490

   

74,655

 

Impairments 

 

535,637

   

109,509

   

743,575

   

286,941

 

Marketing Costs

 

862,589

   

901,940

   

4,126,060

   

3,648,840

 

Depreciation, Depletion and Amortization

 

1,013,930

   

915,257

   

3,997,041

   

3,600,976

 

General and Administrative

 

131,285

   

91,066

   

402,010

   

348,312

 

Taxes Other Than Income

 

151,153

   

165,378

   

757,564

   

623,944

   

Total

 

3,418,845

   

2,768,699

   

12,793,517

   

10,811,907

 

Operating Income 

 

1,226,652

   

980,324

   

5,241,823

   

3,675,211

 

Other Expense, Net

 

(28,324)

   

(8,732)

   

(45,050)

   

(2,865)

 

Income Before Interest Expense and Income Taxes

 

1,198,328

   

971,592

   

5,196,773

   

3,672,346

 

Interest Expense, Net

 

49,735

   

52,510

   

201,458

   

235,460

 

Income Before Income Taxes

 

1,148,593

   

919,082

   

4,995,315

   

3,436,886

 

Income Tax Provision

 

704,005

   

338,888

   

2,079,828

   

1,239,777

 

Net Income 

$

444,588

 

$

580,194

 

$

2,915,487

 

$

2,197,109

 

Dividends Declared per Common Share

$

0.1675

 

$

0.0938

 

$

0.5850

 

$

0.3750

                           
                           

Note: All share and per-share amounts shown have been restated to reflect the 2-for-1 stock split effective March 31, 2014.

   
                           

EOG RESOURCES, INC.

OPERATING HIGHLIGHTS

(Unaudited)

 
 

Three Months Ended

 

Twelve Months Ended

 

December 31,

 

December 31,

 

2014

 

2013

 

2014

 

2013

Wellhead Volumes and Prices

     

Crude Oil and Condensate Volumes (MBbld) (A)

     
 

United States

 

301.5

   

235.4

   

282.0

   

212.1

 

Canada

 

5.2

   

7.7

   

5.8

   

7.0

 

Trinidad

 

0.9

   

1.1

   

1.0

   

1.2

 

Other International (B)

 

0.1

   

0.1

   

0.1

   

0.1

   

Total

 

307.7

   

244.3

   

288.9

   

220.4

 

Average Crude Oil and Condensate Prices ($/Bbl) ©

                     
 

United States

$

72.76

 

$

97.23

 

$

92.73

 

$

103.81

 

Canada

 

72.72

   

78.02

   

86.71

   

87.05

 

Trinidad

 

63.65

   

84.91

   

84.63

   

90.30

 

Other International (B)

 

87.90

   

89.97

   

90.03

   

89.11

   

Composite

 

72.74

   

96.57

   

92.58

   

103.20

 

Natural Gas Liquids Volumes (MBbld) (A)

                     
 

United States

 

83.1

   

66.6

   

79.7

   

64.3

 

Canada

 

0.5

   

0.8

   

0.6

   

0.9

   

Total

 

83.6

   

67.4

   

80.3

   

65.2

 

Average Natural Gas Liquids Prices ($/Bbl) ©

                     
 

United States

$

23.48

 

$

35.01

 

$

31.84

 

$

32.46

 

Canada

 

31.42

   

45.17

   

40.73

   

39.45

   

Composite

 

23.53

   

35.13

   

31.91

   

32.55

 

Natural Gas Volumes (MMcfd) (A)

                     
 

United States

 

921

   

873

   

920

   

908

 

Canada

 

51

   

69

   

61

   

76

 

Trinidad

 

329

   

372

   

363

   

355

 

Other International (B)

 

9

   

7

   

9

   

8

   

Total

 

1,310

   

1,321

   

1,353

   

1,347

 

Average Natural Gas Prices ($/Mcf) ©

                     
 

United States

$

3.21

 

$

3.28

 

$

3.93

 

$

3.32

 

Canada

 

3.64

   

3.34

   

4.32

   

3.08

 

Trinidad

 

3.77

   

3.60

   

3.65

   

3.68

 

Other International (B)

 

5.04

   

6.01

   

5.03

   

6.45

   

Composite

 

3.38

   

3.39

   

3.88

   

3.42

 

Crude Oil Equivalent Volumes (MBoed) (D)

                     
 

United States 

 

538.3

   

447.6

   

515.0

   

427.9

 

Canada

 

14.1

   

19.9

   

16.7

   

20.5

 

Trinidad

 

55.7

   

63.0

   

61.5

   

60.4

 

Other International (B)

 

1.5

   

1.3

   

1.5

   

1.3

   

Total

 

609.6

   

531.8

   

594.7

   

510.1

 

Total MMBoe (D)

 

56.1

   

48.9

   

217.1

   

186.2

 

 

(A)

Thousand barrels per day or million cubic feet per day, as applicable.

(B)

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

© 

Dollars per barrel or per thousand cubic feet, as applicable.  Excludes the impact of financial commodity derivative instruments.

(D)

Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids (NGL) and natural gas.  Crude 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.  MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

 

 

EOG RESOURCES, INC.

SUMMARY BALANCE SHEETS

(Unaudited; in thousands, except share data)

 
 

December 31,

 

December 31,

 

2014

 

2013

ASSETS

Current Assets

         
 

Cash and Cash Equivalents

$

2,087,213

 

$

1,318,209

 

Accounts Receivable, Net

 

1,779,311

   

1,658,853

 

Inventories

 

706,597

   

563,268

 

Assets from Price Risk Management Activities

 

465,128

   

8,260

 

Income Taxes Receivable

 

71,621

   

4,797

 

Deferred Income Taxes

 

19,618

   

244,606

 

Other

 

286,533

   

274,022

     

Total

 

5,416,021

   

4,072,015

 

Property, Plant and Equipment

         
 

Oil and Gas Properties (Successful Efforts Method)

 

46,503,532

   

42,821,803

 

Other Property, Plant and Equipment

 

3,750,958

   

2,967,085

     

Total Property, Plant and Equipment

 

50,254,490

   

45,788,888

 

Less:  Accumulated Depreciation, Depletion and Amortization

 

(21,081,846)

   

(19,640,052)

     

Total Property, Plant and Equipment, Net

 

29,172,644

   

26,148,836

Other Assets

 

174,022

   

353,387

Total Assets

$

34,762,687

 

$

30,574,238

 

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities

         
 

Accounts Payable

$

2,860,548

 

$

2,254,418

 

Accrued Taxes Payable

 

140,098

   

159,365

 

Dividends Payable

 

91,594

   

50,795

 

Liabilities from Price Risk Management Activities

 

-

   

127,542

 

Deferred Income Taxes

 

110,743

   

-

 

Current Portion of Long-Term Debt

 

6,579

   

6,579

 

Other

 

174,746

   

263,017

     

Total

 

3,384,308

   

2,861,716

 
 

Long-Term Debt

 

5,903,354

   

5,906,642

Other Liabilities

 

939,497

   

865,067

Deferred Income Taxes

 

6,822,946

   

5,522,354

Commitments and Contingencies

         
                 

Stockholders' Equity

         
 

Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 549,028,374 Shares and 546,378,440 Shares Issued at December 31, 2014 and 2013, respectively

         
   

205,492

   

202,732

 

Additional Paid in Capital

 

2,837,150

   

2,646,879

 

Accumulated Other Comprehensive Income (Loss)

 

(23,056)

   

415,834

 

Retained Earnings

 

14,763,098

   

12,168,277

 

Common Stock Held in Treasury, 733,517 Shares and 206,830 Shares at December 31, 2014 and 2013, respectively

         
   

(70,102)

   

(15,263)

     

Total Stockholders' Equity

 

17,712,582

   

15,418,459

Total Liabilities and Stockholders' Equity

$

34,762,687

 

$

30,574,238

                 

Note: All share amounts shown have been restated to reflect the 2-for-1 stock split effective March 31, 2014.

 

EOG RESOURCES, INC.

SUMMARY STATEMENTS OF CASH FLOWS

(Unaudited; in thousands)

                 
 

Twelve Months Ended

 

December 31,

 

2014

 

2013

Cash Flows from Operating Activities

         

Reconciliation of Net Income to Net Cash Provided by Operating Activities:

         
 

Net Income 

$

2,915,487

 

$

2,197,109

 

Items Not Requiring (Providing) Cash

         
     

Depreciation, Depletion and Amortization

 

3,997,041

   

3,600,976

     

Impairments 

 

743,575

   

286,941

     

Stock-Based Compensation Expenses

 

145,086

   

134,055

     

Deferred Income Taxes

 

1,704,946

   

874,765

     

Gains on Asset Dispositions, Net

 

(507,590)

   

(197,565)

     

Other, Net

 

48,138

   

11,072

 

Dry Hole Costs

 

48,490

   

74,655

 

Mark-to-Market Commodity Derivative Contracts

         
     

Total (Gains) Losses

 

(834,273)

   

166,349

     

Net Cash Received from Settlements of Commodity Derivative Contracts 

 

34,007

   

116,361

 

Excess Tax Benefits from Stock-Based Compensation

 

(99,459)

   

(55,831)

 

Other, Net

 

13,009

   

18,205

 

Changes in Components of Working Capital and Other Assets and Liabilities

         
     

Accounts Receivable

 

84,982

   

(23,613)

     

Inventories

 

(161,958)

   

53,402

     

Accounts Payable

 

543,630

   

178,701

     

Accrued Taxes Payable

 

16,486

   

75,142

     

Other Assets

 

(14,448)

   

(109,567)

     

Other Liabilities

 

75,420

   

(20,382)

 

Changes in Components of Working Capital Associated with Investing and Financing Activities

         
   

(103,414)

   

(51,361)

Net Cash Provided by Operating Activities

 

8,649,155

   

7,329,414

           

Investing Cash Flows

         
 

Additions to Oil and Gas Properties

 

(7,519,667)

   

(6,697,091)

 

Additions to Other Property, Plant and Equipment

 

(727,138)

   

(363,536)

 

Proceeds from Sales of Assets

 

569,332

   

760,557

 

Changes in Restricted Cash

 

60,385

   

(65,814)

 

Changes in Components of Working Capital Associated with Investing Activities

 

103,523

   

51,106

Net Cash Used in Investing Activities

 

(7,513,565)

   

(6,314,778)

           

Financing Cash Flows

         
 

Long-Term Debt Borrowings

 

496,220

   

-

 

Long-Term Debt Repayments

 

(500,000)

   

(400,000)

 

Settlement of Foreign Currency Swap

 

(31,573)

   

-

 

Dividends Paid

 

(279,695)

   

(199,178)

 

Excess Tax Benefits from Stock-Based Compensation

 

99,459

   

55,831

 

Treasury Stock Purchased

 

(127,424)

   

(63,784)

 

Proceeds from Stock Options Exercised and Employee Stock Purchase Plan

 

22,249

   

38,730

 

Debt Issuance Costs

 

(895)

   

-

 

Repayment of Capital Lease Obligation

 

(5,966)

   

(5,780)

 

Other, Net

 

(109)

   

255

Net Cash Used in Financing Activities

 

(327,734)

   

(573,926)

           

Effect of Exchange Rate Changes on Cash

 

(38,852)

   

1,064

           

Increase in Cash and Cash Equivalents

 

769,004

   

441,774

Cash and Cash Equivalents at Beginning of Period

 

1,318,209

   

876,435

Cash and Cash Equivalents at End of Period

$

2,087,213

 

$

1,318,209

 

 

EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME (NON-GAAP) 

TO NET INCOME (GAAP)

(Unaudited; in thousands, except per share data)

 

The following chart adjusts the three-month and twelve-month periods ended December 31, 2014 and 2013 reported Net Income (GAAP) to reflect actual net cash received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net gains on asset dispositions in North America in 2014 and 2013, to add back impairment charges related to certain of EOG's assets in 2014 and 2013 and the tax expense related to the anticipated repatriation of accumulated foreign earnings in future years.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items.  EOG management uses this information for comparative purposes within the industry.

 

Three Months Ended 

 

Twelve Months Ended

 

December 31,

 

December 31,

 

2014

 

2013

 

2014

 

2013

                       

Reported Net Income (GAAP)

$

444,588

 

$

580,194

 

$

2,915,487

 

$

2,197,109

                       

Commodity Derivative Contracts Impact

                     
 

(Gains) Losses on Mark-to-Market Commodity Derivative Contracts

 

(750,154)

   

(40,504)

   

(834,273)

   

166,349

                         
 

 

Net Cash Received from Settlements of Commodity Derivative Contracts

 

222,944

   

1,038

   

34,007

   

116,361

   

Subtotal

 

(527,210)

   

(39,466)

   

(800,266)

   

282,710

                       
 

After-Tax Impact

 

(339,792)

   

(24,901)

   

(514,971)

   

181,372

                       

Less: Net Gains on Asset Dispositions, Net of Tax

 

(439,834)

   

(7,232)

   

(487,260)

   

(136,848)

Add: Impairments of Certain Assets, Net of Tax

 

517,041

   

-

   

553,099

   

4,425

                       

 

Add: Tax Expense Related to the Repatriation of Accumulated Foreign Earnings in Future Years

 

249,861

   

-

   

249,861

   

-

                       

Adjusted Net Income (Non-GAAP)

$

431,864

 

$

548,061

 

$

2,716,216

 

$

2,246,058

                       

Net Income Per Share (GAAP)

                     
 

Basic

 

$

0.82

 

$

1.07

 

$

5.36

 

$

4.07

 

Diluted

$

0.81

 

$

1.06

 

$

5.32

 

$

4.02

                       

Adjusted Net Income Per Share (Non-GAAP)

                     
 

Basic

 

$

0.79

 

$

1.01

 

$

5.00

 

$

4.16

 

Diluted

$

0.79

 

$

1.00

 

$

4.95

 

$

4.11

                           

Adjusted Net Income Per Diluted Share (Non-GAAP) - Percentage Increase

 

-21

%

       

20

%

   
                       

Average Number of Common Shares (GAAP)

                     
 

Basic

   

544,579

   

541,857

   

543,443

   

540,341

 

Diluted

 

549,153

   

547,966

   

548,539

   

546,227

                       
                           

Reconciliation of Net Gains on Asset Dispositions and Impairments of Certain Assets

                     
       

Three Months Ended

                 
       

December 31, 2014

                 

Net Gains on Asset Dispositions

$

431,890

                 

   Less: Exit Costs in General and Administrative Expense

 

(21,465)

                 

   Less: Income Tax Benefit (Expense)

 

29,409

                 

       After-Tax Impact

$

439,834

                 
                           
                           

Impairments of Certain Assets

$

444,867

                 

   Less: Income Tax (Benefit) Expense

 

(251,068)

                 

   Add: Deferred Tax Valuation Allowance

 

323,242

                 

       After-Tax Impact

$

517,041

                 
                           
                           

Note: All share and per-share amounts shown have been restated to reflect the 2-for-1 stock split effective March 31, 2014.

 

 

EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF DISCRETIONARY CASH FLOW (NON-GAAP)

TO NET CASH PROVIDED BY OPERATING ACTIVITIES (GAAP)

(Unaudited; in thousands)

 

The following chart reconciles the three-month and twelve-month periods ended December 31, 2014 and 2013 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP).  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities.  EOG management uses this information for comparative purposes within the industry.

 
 

Three Months Ended

 

Twelve Months Ended

 

December 31,

 

December 31,

 

2014

 

2013

 

2014

 

2013

 

Net Cash Provided by Operating Activities (GAAP)

$

2,110,438

 

$

2,001,230

 

$

8,649,155

 

$

7,329,414

                       

Adjustments:

 

Exploration Costs (excluding Stock-Based Compensation Expenses) 

 

 

38,450

   

 

24,201

   

 

157,453

   

 

134,531

                         
 

Excess Tax Benefits from Stock-Based Compensation

 

11,632

   

5,601

   

99,459

   

55,831

 

Changes in Components of Working Capital and Other Assets and Liabilities

                     
                       
     

Accounts Receivable

 

(426,025)

   

(190,133)

   

(84,982)

   

23,613

     

Inventories

 

42,792

   

7,745

   

161,958

   

(53,402)

     

Accounts Payable

 

23,123

   

(33,502)

   

(543,630)

   

(178,701)

     

Accrued Taxes Payable

 

159,926

   

(1,945)

   

(16,486)

   

(75,142)

     

Other Assets

 

(47,518)

   

30,768

   

14,448

   

109,567

     

Other Liabilities

 

(8,802)

   

31,271

   

(75,420)

   

20,382

 

Changes in Components of Working Capital Associated with Investing and Financing Activities

 

 

 

(5,154)

                 
       

 

(21,584)

   

 

103,414

   

51,361

 

Discretionary Cash Flow (Non-GAAP)

$

1,898,862

 

$

1,853,652

 

$

8,465,369

 

$

7,417,454

                             

Discretionary Cash Flow (Non-GAAP) - Percentage Increase

 

2

%

       

14

%

   

 

 

EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF ADJUSTED EARNINGS BEFORE INTEREST EXPENSE, 

INCOME TAXES, DEPRECIATION, DEPLETION AND AMORTIZATION, EXPLORATION COSTS, 

DRY HOLE COSTS, IMPAIRMENTS AND ADDITIONAL ITEMS (ADJUSTED EBITDAX)

 (NON-GAAP) TO INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES (GAAP)

(Unaudited; in thousands)

                           

The following chart adjusts the three-month and twelve-month periods ended December 31, 2014 and 2013 reported Income Before Interest Expense and Income Taxes (GAAP) to Earnings Before Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net gains on asset dispositions in North America in 2014 and 2013.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Income Before Interest Expense and Income Taxes (GAAP) to add back Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items.  EOG management uses this information for comparative purposes within the industry.

 
     

Three Months Ended

 

Twelve Months Ended

     

December 31,

 

December 31,

     

2014

 

2013

 

2014

 

2013

                           

Income Before Interest Expense and Income Taxes (GAAP)

$

1,198,328

 

$

971,592

 

$

5,196,773

 

$

3,672,346

                           

Adjustments:

                     
 

Depreciation, Depletion and Amortization

 

1,013,930

   

915,257

   

3,997,041

   

3,600,976

 

Exploration Costs

 

45,167

   

30,378

   

184,388

   

161,346

 

Dry Hole Costs

 

18,225

   

15,395

   

48,490

   

74,655

 

Impairments 

 

535,637

   

109,509

   

743,575

   

286,941

   

EBITDAX (Non-GAAP)

 

2,811,287

   

2,042,131

   

10,170,267

   

7,796,264

 

Total (Gains) Losses on MTM Commodity Derivative Contracts 

 

 

(750,154)

   

 

(40,504)

   

 

(834,273)

   

 

166,349

 

Net Cash Received from Settlements of Commodity Derivative Contracts

 

 

222,944

   

 

1,038

   

 

34,007

   

 

116,361

 

Gains on Asset Dispositions, Net

 

(431,890)

   

(11,996)

   

(507,590)

   

(197,565)

                           

Adjusted EBITDAX (Non-GAAP)

$

1,852,187

 

$

1,990,669

 

$

8,862,411

 

$

7,881,409

                           

Adjusted EBITDAX (Non-GAAP) - Percentage Increase

 

-7

%

       

12

%

   
                           

 

 

EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF NET DEBT (NON-GAAP) AND TOTAL 

CAPITALIZATION (NON-GAAP) AS USED IN THE CALCULATION OF 

THE NET DEBT-TO-TOTAL CAPITALIZATION RATIO (NON-GAAP) TO

CURRENT AND LONG-TERM DEBT (GAAP) AND TOTAL CAPITALIZATION (GAAP)

(Unaudited; in millions, except ratio data)

     

The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation.  A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation.  EOG management uses this information for comparative purposes within the industry.

     
   

At

 

At

 
 

December 31,

 

December 31,

 
 

2014

 

2013

 
       

Total Stockholders' Equity - (a)

$

17,713

 

$

15,418

 
               

Current and Long-Term Debt (GAAP) - (b)

 

5,910

   

5,913

 

Less: Cash 

 

(2,087)

   

(1,318)

 

Net Debt (Non-GAAP) - (c)

 

3,823

   

4,595

 
               

Total Capitalization (GAAP) - (a) + (b)

$

23,623

 

$

21,331

 
               

Total Capitalization (Non-GAAP) - (a) + (c)

$

21,536

 

$

20,013

 
               

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]

 

25

%

 

28

%

               

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]

 

18

%

 

23

%

 

 

EOG RESOURCES, INC.

 

RESERVES SUPPLEMENTAL DATA

 

(Unaudited)

 
   

2014 NET PROVED RESERVES RECONCILIATION SUMMARY  

 
 

 United 

     

 North 

     

 Other 

 

 Total 

     
 

 States 

 

 Canada 

 

 America 

 

 Trinidad 

 

 Int'l 

 

 Int'l 

 

 Total 

 

CRUDE OIL & CONDENSATE (MMBbls)

                         

Beginning Reserves

880.0

 

10.1

 

890.1

 

1.6

 

8.8

 

10.4

 

900.5

 

Revisions 

28.3

 

(0.3)

 

28.0

 

0.1

 

(0.1)

 

-

 

28.0

 

Purchases in place

9.7

 

-

 

9.7

 

-

 

-

 

-

 

9.7

 

Extensions, discoveries and other additions

319.6

 

-

 

319.6

 

-

 

-

 

-

 

319.6

 

Sales in place

(4.9)

 

(7.7)

 

(12.6)

 

-

 

-

 

-

 

(12.6)

 

Production 

(102.9)

 

(2.1)

 

(105.0)

 

(0.4)

 

-

 

(0.4)

 

(105.4)

 

Ending Reserves

1,129.8

 

-

 

1,129.8

 

1.3

 

8.7

 

10.0

 

1,139.8

 
   

NATURAL GAS LIQUIDS (MMBbls)

                           

Beginning Reserves

376.0

 

1.2

 

377.2

 

-

 

-

 

-

 

377.2

 

Revisions 

27.5

 

-

 

27.5

 

-

 

-

 

-

 

27.5

 

Purchases in place

1.8

 

-

 

1.8

 

-

 

-

 

-

 

1.8

 

Extensions, discoveries and other additions

91.7

 

-

 

91.7

 

-

 

-

 

-

 

91.7

 

Sales in place

(1.0)

 

(0.8)

 

(1.8)

 

-

 

-

 

-

 

(1.8)

 

Production 

(29.0)

 

(0.3)

 

(29.3)

 

-

 

-

 

-

 

(29.3)

 

Ending Reserves

467.0

 

0.1

 

467.1

 

-

 

-

 

-

 

467.1

 
   

NATURAL GAS (Bcf) 

                           

Beginning Reserves 

4,398.7

 

102.1

 

4,500.8

 

520.7

 

23.3

 

544.0

 

5,044.8

 

Revisions 

252.2

 

9.8

 

262.0

 

12.9

 

(4.3)

 

8.6

 

270.6

 

Purchases in place

17.1

 

-

 

17.1

 

-

 

-

 

-

 

17.1

 

Extensions, discoveries and other additions

638.3

 

-

 

638.3

 

4.5

 

4.7

 

9.2

 

647.5

 

Sales in place

(52.4)

 

(78.7)

 

(131.1)

 

-

 

-

 

-

 

(131.1)

 

Production 

(348.4)

 

(22.3)

 

(370.7)

 

(132.5)

 

(3.1)

 

(135.6)

 

(506.3)

 

Ending Reserves

4,905.5

 

10.9

 

4,916.4

 

405.6

 

20.6

 

426.2

 

5,342.6

 
   

OIL EQUIVALENTS (MMBoe) 

                           

Beginning Reserves 

1,989.2

 

28.3

 

2,017.5

 

88.4

 

12.6

 

101.0

 

2,118.5

 

Revisions 

97.8

 

1.3

 

99.1

 

2.2

 

(0.7)

 

1.5

 

100.6

 

Purchases in place

14.4

 

-

 

14.4

 

-

 

-

 

-

 

14.4

 

Extensions, discoveries and other additions

517.6

 

-

 

517.6

 

0.8

 

0.8

 

1.6

 

519.2

 

Sales in place

(14.7)

 

(21.6)

 

(36.3)

 

-

 

-

 

-

 

(36.3)

 

Production 

(190.1)

 

(6.0)

 

(196.1)

 

(22.4)

 

(0.6)

 

(23.0)

 

(219.1)

 

Ending Reserves

2,414.2

 

2.0

 

2,416.2

 

69.0

 

12.1

 

81.1

 

2,497.3

 
   

 Net Proved Developed Reserves (MMBoe)  

                           

      At December 31, 2013 

1,015.4

 

24.8

 

1,040.2

 

83.9

 

3.4

 

87.3

 

1,127.5

 

      At December 31, 2014 

1,275.4

 

2.0

 

1,277.4

 

67.5

 

3.0

 

70.5

 

1,347.9

 
   

2014 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions) 

 
 

 United 

     

 North 

     

 Other 

 

 Total 

     
 

 States 

 

 Canada 

 

 America 

 

 Trinidad 

 

 Int'l 

 

 Int'l 

 

 Total 

 
   

Acquisition Cost of Unproved Properties

$   365.9

 

$      4.5

 

$    370.4

 

$           -

 

$         -

 

$         -

 

$   370.4

 

Exploration Costs

332.7

 

13.0

 

345.7

 

2.8

 

47.5

 

50.3

 

396.0

 

Development Costs

6,489.3

 

70.7

 

6,560.0

 

75.5

 

168.2

 

243.7

 

6,803.7

 

Total Drilling

7,187.9

 

88.2

 

7,276.1

 

78.3

 

215.7

 

294.0

 

7,570.1

 

Acquisition Cost of Proved Properties

138.8

 

0.3

 

139.1

 

-

 

-

 

-

 

139.1

 

Total Exploration & Development Expenditures 

7,326.7

 

88.5

 

7,415.2

 

78.3

 

215.7

 

294.0

 

7,709.2

 

Gathering, Processing and Other

725.0

 

1.4

 

726.4

 

0.2

 

0.5

 

0.7

 

727.1

 

Asset Retirement Costs 

148.9

 

31.0

 

179.9

 

14.0

 

1.7

 

15.7

 

195.6

 

Total Expenditures

8,200.6

 

120.9

 

8,321.5

 

92.5

 

217.9

 

310.4

 

8,631.9

 

Proceeds from Sales in Place

(175.5)

 

(393.8)

 

(569.3)

 

-

 

-

 

-

 

(569.3)

 

Net Expenditures

$8,025.1

 

$  (272.9)

 

$ 7,752.2

 

$     92.5

 

$  217.9

 

$  310.4

 

$8,062.6

 
   

RESERVE REPLACEMENT COSTS ($ / Boe) * 

                           

Total Drilling, Before Revisions 

$   13.89

 

 NA 

 

$    14.06

 

$    97.88

 

$269.63

 

$183.75

 

$   14.58

 

All-in Total, Net of Revisions 

$   11.63

 

$   68.08

 

$    11.75

 

$    26.10

 

 NA 

 

$  94.84

 

$   12.16

 

All-in Total, Excluding Revisions Due to Price

$   12.68

 

$   88.50

 

$    12.81

 

$    26.10

 

 NA 

 

$  94.84

 

$   13.25

 
   

RESERVE REPLACEMENT *

                           

Drilling Only

272

%

0

%

264

%

4

%

133

%

7

%

237

%

All-in Total, Net of Revisions & Dispositions  

324

%

-338

%

303

%

13

%

17

%

13

%

273

%

All-in Total, Excluding Revisions Due to Price

296

%

-343

%

277

%

13

%

17

%

13

%

249

%

All-in Total, Liquids

358

%

-367

%

345

%

25

%

 NA 

 

0

%

344

%

   

*   See attached reconciliation schedule for calculation methodology

 

 

 

EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF TOTAL EXPLORATION AND DEVELOPMENT EXPENDITURES

FOR DRILLING ONLY (NON-GAAP) AND TOTAL EXPLORATION AND DEVELOPMENT EXPENDITURES (NON-GAAP)

AS USED IN THE CALCULATION OF RESERVE REPLACEMENT COSTS ($ / BOE)

TO TOTAL COSTS INCURRED IN EXPLORATION AND DEVELOPMENT ACTIVITIES (GAAP)

(Unaudited; in millions, except ratio information)

 

The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe.  There are numerous ways that industry participants present Reserve Replacement Costs, including "Drilling Only" and "All-In", which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources.  Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program.  Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry.  Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures.  Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs.  EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures.

   
   

 United 

     

 North 

     

 Other 

 

 Total 

     
   

 States 

 

 Canada 

 

 America 

 

 Trinidad 

 

 Int'l 

 

 Int'l 

 

 Total 

 
   

Total Costs Incurred in Exploration and Development Activities (GAAP)

$7,475.6

 

$   119.5

 

$ 7,595.1

 

$     92.3

 

$  217.4

 

$  309.7

 

$7,904.8

 

Less:  

Asset Retirement Costs

(148.9)

 

(31.0)

 

(179.9)

 

(14.0)

 

(1.7)

 

(15.7)

 

(195.6)

 
 

Acquisition Cost of Proved Properties

(138.8)

 

(0.3)

 

(139.1)

 

-

 

-

 

-

 

(139.1)

 

Total Exploration & Development Expenditures for Drilling Only

                           

   (Non-GAAP) (a) 

$7,187.9

 

$    88.2

 

$ 7,276.1

 

$     78.3

 

$  215.7

 

$  294.0

 

$7,570.1

 
   

Total Costs Incurred in Exploration and Development Activities (GAAP)

$7,475.6

 

$   119.5

 

$ 7,595.1

 

$     92.3

 

$  217.4

 

$  309.7

 

$7,904.8

 

Less:  Asset Retirement Costs

(148.9)

 

(31.0)

 

(179.9)

 

(14.0)

 

(1.7)

 

(15.7)

 

(195.6)

 
   

Total Exploration & Development Expenditures (Non-GAAP) (b) 

$7,326.7

 

$    88.5

 

$ 7,415.2

 

$     78.3

 

$  215.7

 

$  294.0

 

$7,709.2

 
   

Total Expenditures (GAAP)

$8,200.6

 

$   120.9

 

$ 8,321.5

 

$     92.5

 

$  217.9

 

$  310.4

 

$8,631.9

 

Less:  

Asset Retirement Costs

(148.9)

 

(31.0)

 

(179.9)

 

(14.0)

 

(1.7)

 

(15.7)

 

(195.6)

 
 

Non-Cash Acquisition Costs of Unproved Properties

(5.0)

 

-

 

(5.0)

 

-

 

-

 

-

 

(5.0)

 
   

Total Cash Expenditures (Non-GAAP) 

$8,046.7

 

$    89.9

 

$ 8,136.6

 

$     78.5

 

$  216.2

 

$  294.7

 

$8,431.3

 
   

Net Proved Reserve Additions From All Sources - Oil Equivalents

                           

   (MMBoe) 

                           

Revisions due to price (c)

51.9

 

0.3

 

52.2

 

-

 

-

 

-

 

52.2

 

Revisions other than price

45.9

 

1.0

 

46.9

 

2.2

 

(0.7)

 

1.5

 

48.4

 

Purchases in place

14.4

 

-

 

14.4

 

-

 

-

 

-

 

14.4

 

Extensions, discoveries and other additions (d)

517.6

 

-

 

517.6

 

0.8

 

0.8

 

1.6

 

519.2

 

Total Proved Reserve Additions (e) 

629.8

 

1.3

 

631.1

 

3.0

 

0.1

 

3.1

 

634.2

 

Sales in place

(14.7)

 

(21.6)

 

(36.3)

 

-

 

-

 

-

 

(36.3)

 

Net Proved Reserve Additions From All Sources (f) 

615.1

 

(20.3)

 

594.8

 

3.0

 

0.1

 

3.1

 

597.9

 
   

Production (g) 

190.1

 

6.0

 

196.1

 

22.4

 

0.6

 

23.0

 

219.1

 
   

RESERVE REPLACEMENT COSTS ($ / Boe)

                           

Total Drilling, Before Revisions (a / d) 

$   13.89

 

 NA 

 

$    14.06

 

$    97.88

 

$269.63

 

$183.75

 

$   14.58

 

All-in Total, Net of Revisions (b / e)  

$   11.63

 

$   68.08

 

$    11.75

 

$    26.10

 

 NA 

 

$  94.84

 

$   12.16

 

All-in Total, Excluding Revisions Due to Price (b / (e - c)) 

$   12.68

 

$   88.50

 

$    12.81

 

$    26.10

 

 NA 

 

$  94.84

 

$   13.25

 
   

RESERVE REPLACEMENT

                           

Drilling Only (d / g) 

272

%

0

%

264

%

4

%

133

%

7

%

237

%

All-in Total, Net of Revisions & Dispositions (f / g) 

324

%

-338

%

303

%

13

%

17

%

13

%

273

%

All-in Total, Excluding Revisions Due to Price ((f - c ) / g) 

296

%

-343

%

277

%

13

%

17

%

13

%

249

%

   

Net Proved Reserve Additions From All Sources - Liquids (MMBbls) 

                           

Revisions

55.7

 

(0.3)

 

55.4

 

0.1

 

(0.1)

 

-

 

55.4

 

Purchases in place

11.5

 

-

 

11.5

 

-

 

-

 

-

 

11.5

 

Extensions, discoveries and other additions (h)

411.3

 

-

 

411.3

 

-

 

-

 

-

 

411.3

 

Total Proved Reserve Additions 

478.5

 

(0.3)

 

478.2

 

0.1

 

(0.1)

 

-

 

478.2

 

Sales in place

(6.0)

 

(8.5)

 

(14.5)

 

-

 

-

 

-

 

(14.5)

 

Net Proved Reserve Additions From All Sources (i) 

472.5

 

(8.8)

 

463.7

 

0.1

 

(0.1)

 

-

 

463.7

 
   

Production (j)   

131.9

 

2.4

 

134.3

 

0.4

 

-

 

0.4

 

134.7

 
   

RESERVE REPLACEMENT - LIQUIDS

                           

Drilling Only (h / j) 

312

%

0

%

306

%

0

%

 NA 

 

0

%

305

%

All-in Total, Net of Revisions & Dispositions (i / j) 

358

%

-367

%

345

%

25

%

 NA 

 

0

%

344

%

 

EOG RESOURCES, INC.

CRUDE OIL AND NATURAL GAS FINANCIAL

COMMODITY DERIVATIVE CONTRACTS

 

Presented below is a comprehensive summary of EOG's crude oil and natural gas derivative contracts at February 16, 2015, with notional volumes expressed in Bbld and MMBtud and prices expressed in $/Bbl and $/MMBtu.  EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method.

 

CRUDE OIL DERIVATIVE CONTRACTS

 

Weighted

 

Volume 

 

Average Price

 

(Bbld) 

 

($/Bbl) 

2015(1)

       

January 2015 (closed)

47,000

 

$           91.22

February 1, 2015 through June 30, 2015

47,000

 

91.22

July 1, 2015 through December 31, 2015

10,000

 

89.98

           
   

(1)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month periods. Options covering a notional volume of 37,000 Bbld are exercisable on June 30, 2015. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 37,000 Bbld at an average price of $91.56 per barrel for each month during the period July 1, 2015 through December 31, 2015.

   

NATURAL GAS DERIVATIVE CONTRACTS

 

Weighted

 

Volume

 

Average Price

 

(MMBtud) 

 

($/MMBtu) 

2015(2)

       

January 1, 2015 through February 28, 2015 (closed)

235,000

 

$             4.47

March 2015

 

225,000

 

4.48

April 2015

 

195,000

 

4.49

May 1, 2015 through December 31, 2015

175,000

 

4.51

           

(2)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates.  All such options are exercisable monthly up until the settlement date of each monthly contract.  If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 175,000 MMBtud at an average price of $4.51 per MMBtu for each month during the period March 1, 2015 through December 31, 2015.

 

$/Bbl

Dollars per barrel

     

$/MMBtu

Dollars per million British thermal units

     

Bbld

Barrels per day

     

MMBtu

Million British thermal units

     

MMBtud

Million British thermal units per day

     
           

 

EOG RESOURCES, INC.

DIRECT AFTER-TAX RATE OF RETURN (ATROR)

 

The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated proved reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated present value of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be).  As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. 

 
 
 

Direct ATROR

Based on Cash Flow and Time Value of Money

  - Estimated future commodity prices and operating costs

  - Costs incurred to drill and complete a well, including facilities

Excludes Indirect Capital

  - Gathering and Processing and other Midstream

  - Land, Seismic, Geological and Geophysical

 

Payback ~12 Months on 100% Direct ATROR Wells

First Five Years ~1/2 EUR Produced but ~3/4 of NPV Captured

ATROR of Drilling Program Has Been Rising

 
 

Return on Equity / Return on Capital Employed

Based on GAAP Accrual Accounting

Includes All Indirect Capital and Growth Capital for Infrastructure

  - Eagle Ford, Bakken, Permian Facilities

  - Gathering and Processing

Includes Legacy Gas Capital and Capital from Mature Wells

Has Been Increasing Due to Increasing Direct ATROR of Drilling Program

 

 

 

EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF AFTER-TAX INTEREST EXPENSE, NET (NON-GAAP), ADJUSTED NET INCOME

(NON-GAAP), NET DEBT (NON-GAAP) AND TOTAL CAPITALIZATION (NON-GAAP) AS USED IN THE CALCULATIONS OF RETURN ON CAPITAL EMPLOYED (NON-GAAP) AND RETURN ON EQUITY (NON-GAAP) TO INTEREST EXPENSE, NET (GAAP), NET INCOME (GAAP), CURRENT AND LONG-TERM DEBT (GAAP) AND TOTAL CAPITALIZATION (GAAP), RESPECTIVELY

(Unaudited; in millions, except ratio data)

                   

The following chart reconciles Interest Expense, Net (GAAP), Net Income (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Interest Expense, Net (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Interest Expense, Net, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations.  EOG management uses this information for comparative purposes within the industry.

                   
     

2014

   

2013

   

2012

Return on Capital Employed (ROCE) (Non-GAAP)

                 
                   

Interest Expense, Net (GAAP)

 

$

201

 

$

235

     

Tax Benefit Imputed (based on 35%) 

   

(70)

   

(82)

     

After-Tax Interest Expense, Net (Non-GAAP) - (a) 

 

$

131

 

$

153

     
                   

Net Income (GAAP) - (b)                                                   

 

$

2,915

 

$

2,197

     
                   

Add: After-Tax Mark-to-Market Commodity Derivative Contracts Impact

   

(515)

   

182

     

Add: Impairments of Certain Assets, Net of Tax

   

553

   

4

     

Add: Tax Expense Related to the Repatriation of Accumulated Foreign Earnings in Future Years

                 
   

250

   

-

     

Less: Net Gains on Asset Dispositions, Net of Tax

   

(487)

   

(137)

     
                   

Adjusted Net Income (Non-GAAP) - (c)   

 

$

2,716

 

$

2,246

     
                   

Total Stockholders' Equity - (d)   

 

$

17,713

 

$

15,418

 

$

13,285

                   

Average Total Stockholders' Equity * - (e)   

 

$

16,566

 

$

14,352

     
                   

Current and Long-Term Debt (GAAP) - (f) 

 

$

5,910

 

$

5,913

 

$

6,312

Less: Cash                                                       

   

(2,087)

   

(1,318)

   

(876)

Net Debt (Non-GAAP) - (g) 

 

$

3,823

 

$

4,595

 

$

5,436

                   

Total Capitalization (GAAP) - (d) + (f)  

 

$

23,623

 

$

21,331

 

$

19,597

                   

Total Capitalization (Non-GAAP) - (d) + (g) 

 

$

21,536

 

$

20,013

 

$

18,721

                   

Average Total Capitalization (Non-GAAP) * - (h)   

 

$

20,775

 

$

19,367

     
                   

ROCE (GAAP Net Income) - [(a) + (b)] / (h)       

   

14.7

%

 

12.1

%

   
                   

ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h)       

   

13.7

%

 

12.4

%

   
                   

Return on Equity (ROE) (Non-GAAP)

                 
                   

ROE (GAAP Net Income) - (b) / (e)

   

17.6

%

 

15.3

%

   
                   

ROE (Non-GAAP Adjusted Net Income) - (c) / (e)

   

16.4

%

 

15.6

%

   
                   

* Average for the current and immediately preceding year

 

 

 

EOG RESOURCES, INC.

 

FIRST QUARTER AND FULL YEAR 2015 FORECAST AND BENCHMARK COMMODITY PRICING

 
   
 

(a)  First Quarter and Full Year 2015 Forecast

 
   

The forecast items for the first quarter and full year 2015 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release.  EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.  This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast.

 
   
 

(b)  Benchmark Commodity Pricing

 
   

EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month.

 
   

EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month.

 
                                 
           

 

 

ESTIMATED RANGES

 
           

 

 

(Unaudited)

 
           

1Q 2015

   

Full Year 2015

 

Daily Production

                       
 

Crude Oil and Condensate Volumes (MBbld)

                       
   

United States

 

287.0

-

 

297.0

   

264.0

-

 

293.0

 
   

Trinidad

 

0.5

-

 

0.9

   

0.7

-

 

0.9

 
   

Other International

 

0.1

-

 

0.3

   

6.0

-

 

11.0

 
     

Total

 

287.6

-

 

298.2

   

270.7

-

 

304.9

 
   
 

Natural Gas Liquids Volumes (MBbld)

                       
     

Total

 

75.0

-

 

83.0

   

68.0

-

 

88.0

 
                                 
 

Natural Gas Volumes (MMcfd)

                       
   

United States

 

880

-

 

910

   

850

-

 

890

 
   

Trinidad

 

330

-

 

360

   

330

-

 

360

 
   

Other International

 

24

-

 

30

   

27

-

 

33

 
     

Total

 

1,234

-

 

1,300

   

1,207

-

 

1,283

 
   
 

Crude Oil Equivalent Volumes (MBoed)  

                       
   

United States

 

508.7

-

 

531.7

   

473.7

-

 

529.3

 
   

Trinidad

 

55.5

-

 

60.9

   

55.7

-

 

60.9

 
   

Other International

 

4.1

-

 

5.3

   

10.5

-

 

16.5

 
     

Total

 

568.3

-

 

597.9

   

539.9

-

 

606.7

 
                                 

Operating Costs

                       
 

Unit Costs ($/Boe)

                       
   

Lease and Well

$

6.35

-

$

6.65

 

$

6.35

-

$

6.85

 
   

Transportation Costs

$

4.60

-

$

4.90

 

$

4.60

-

$

5.00

 
   

Depreciation, Depletion and Amortization

$

17.35

-

$

17.75

 

$

17.70

-

$

18.30

 
   

Expenses ($MM)

                       
 

Exploration, Dry Hole and Impairment

$

130

-

$

150

 

$

525

-

$

575

 
 

General and Administrative

$

90

-

$

100

 

$

375

-

$

400

 
 

Gathering and Processing 

$

40

-

$

46

 

$

155

-

$

185

 
 

Capitalized Interest

$

14

-

$

15

 

$

55

-

$

60

 
 

Net Interest

$

49

-

$

50

 

$

200

-

$

205

 
   

Taxes Other Than Income (% of Wellhead Revenue)

 

6.5

% -

 

7.0

%

 

6.3

% -

 

6.9

%

   

Income Taxes

                       
 

Effective Rate 

 

22

% -

 

27

%

 

23

% -

 

28

%

 

Current Taxes ($MM)

$

30

-

$

45

 

$

140

-

$

160

 
                                 

Capital Expenditures ($MM) - (Excluding Acquisitions)

                       
 

Exploration and Development, Excluding Facilities

           

$

3,950

-

$

4,050

 
 

Exploration and Development Facilities

           

$

580

-

$

620

 
 

Gathering, Processing and Other

           

$

370

-

$

430

 
   

Pricing - (Refer to Benchmark Commodity Pricing in text)

                       
 

Crude Oil and Condensate ($/Bbl)

                       
   

Differentials

                       
     

United States - above (below) WTI

$

(1.60)

-

$

0.00

 

$

(2.00)

-

$

0.00

 
     

Trinidad - above (below) WTI

$

(10.50)

-

$

(9.50)

 

$

(12.00)

-

$

(8.00)

 
                                 
 

Natural Gas Liquids

                       
   

Realizations as % of WTI

 

31

% -

 

35

%

 

30

% -

 

36

%

                                 
 

Natural Gas ($/Mcf)

                       
   

Differentials

                       
     

United States - above (below) NYMEX Henry Hub

$

(0.80)

-

$

(0.35)

 

$

(0.85)

-

$

(0.35)

 
   
   

Realizations

                       
     

Trinidad

$

2.80

-

$

3.60

 

$

2.80

-

$

3.60

 
     

Other International

$

3.15

-

$

3.75

 

$

3.25

-

$

3.85

 
   

Definitions

$/Bbl 

 

U.S. Dollars per barrel

$/Boe

U.S. Dollars per barrel of oil equivalent

$/Mcf 

 

U.S. Dollars per thousand cubic feet

$MM

 

U.S. Dollars in millions

MBbld

Thousand barrels per day

MBoed

Thousand barrels of oil equivalent per day

MMcfd

Million cubic feet per day

NYMEX

New York Mercantile Exchange

WTI

 

West Texas Intermediate

 

SOURCE EOG Resources, Inc.

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