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EOG Resources Announces Outstanding Second Quarter 2014 Results; Increases Common Stock Dividend 34 Percent and Adds Delaware Basin Crude Oil Play

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FOR IMMEDIATE RELEASE: August 5, 2014

HOUSTON, Aug. 5, 2014 /PRNewswire/ --

  • Reports 17 Percent Increase in Total Production, Plus 33 Percent Increase in US Crude Oil and Condensate Production Year-Over-Year
  • Raises Common Stock Dividend 34 Percent, Second Increase in 2014
  • Adds Second Bone Spring Sand Crude Oil Play to Portfolio of High Return Assets
  • Realizes Positive Leonard Shale Downspacing Tests
  • Builds on Stellar Eagle Ford and Bakken Success

EOG Resources, Inc. (NYSE: EOG) (EOG) today reported second quarter 2014 net income of $706.4 million, or $1.29 per share. This compares to second quarter 2013 net income of $659.7 million, or $1.21 per share.

Adjusted non-GAAP net income for the second quarter 2014 was $796.0 million, or $1.45 per share, and adjusted non-GAAP net income for the same prior year period was $573.8 million, or $1.05 per share.

Consistent with some analysts' practice of matching realizations to settlement months and making certain other adjustments in order to exclude one-time items, adjusted non-GAAP net income for the second quarter 2014 excluded a previously disclosed non-cash net loss of $229.3 million ($147.0 million after-tax, or $0.27 per share) on the mark-to-market of financial commodity derivative contracts and net gains on asset dispositions of $3.9 million ($1.7 million net of tax, or $0.01 per share). During the second quarter 2014, the net cash outflow related to settlements of financial commodity derivative contracts was $86.9 million ($55.7 million after-tax, or $0.10 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

For the first half 2014, EOG posted strong financial metrics driven by reinvestment of capital into high rate-of-return drilling opportunities. Discretionary cash flow increased 22 percent and adjusted EBITDAX advanced 24 percent. In addition, adjusted non-GAAP earnings per share increased 46 percent, compared to the first half 2013. (Please refer to the attached tables for the reconciliation of non-GAAP discretionary cash flow to net cash provided by operating activities (GAAP), adjusted non-GAAP EBITDAX to income before interest expense and income taxes (GAAP) and adjusted non-GAAP net income to GAAP net income.)

Dividend Increase

The board of directors increased the cash dividend on the common stock by 34 percent. Effective with the dividend payable October 31, 2014, to holders of record as of October 17, 2014, the board declared a quarterly dividend of $0.1675 per share on the common stock. The indicated annual rate of $0.67 per share represents the 16th increase in 15 years.

"EOG's bottom line is a reflection of our top quality drilling operations and return focused capital investments," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "Because EOG has demonstrated its ability to sustain crude oil growth and reinvest cash flows in high return assets, we've increased the common stock dividend for the second time this year, enhancing long-term value for our stockholders."

Operational Highlights

In the U.S., crude oil and condensate production increased 33 percent in the second quarter 2014, compared to the same prior year period. Production gains from the South Texas Eagle Ford and North Dakota Bakken led EOG's U.S. crude oil production growth. Driven by the South Texas Eagle Ford and the Permian Basin, natural gas liquids (NGLs) production increased 22 percent, compared to the second quarter 2013. Natural gas production slightly increased due to EOG's Trinidad operations and strong associated gas production in the U.S. Overall, total company production increased 17 percent. 

Delaware Basin

EOG expanded its inventory of crude oil plays with successful drilling results in the Second Bone Spring Sand, which underlies its extensive Leonard Shale acreage position in Lea and Eddy counties, New Mexico. Through the application of advanced completion techniques, EOG realized robust results from two recent wells. The Mars 3 State #1H, in which EOG has 67 percent working interest, came online at 1,270 barrels of oil per day (Bopd) with 150 barrels per day (Bpd) of NGLs and 1.1 million cubic feet per day (MMcfd) of natural gas. EOG has 100 percent working interest in the Jolly Roger 16 State #1H, which had an initial production rate of 1,450 Bopd with 210 Bpd of NGLs and 1.5 MMcfd of natural gas. While EOG estimates the play may be prospective over the majority of its 73,000 net Leonard acres, evaluation and confirmation is ongoing. Across the Second Bone Spring Sand, EOG's production mix is estimated to be approximately 70 percent crude oil with average estimated gross reserves per well of 500 thousand barrels of oil equivalent. Plans are to drill several more wells in the Second Bone Spring Sand in 2014 and increase activity in 2015.

In the West Texas and southeast New Mexico Leonard Shale play, EOG continues to enhance completions and test well spacing both within and across zones to maximize recovery of the hydrocarbons in place.

Over the last 12 months, EOG has systematically tightened spacing from 660 to 300 feet between wells to test production interference between Leonard 'A' wells. In Lea County, EOG completed a 500-foot spacing test by drilling the Dragon 36 State #05H, #06H, #07H and #08H. The wells were turned to production at initial rates of 1,100, 1,500, 1,270 and 1,360 Bopd, respectively. EOG has 100 percent working interest in these Leonard 'A' zone wells that had associated NGL production of 200, 195, 235 and 235 Bpd and 1.1, 1.1, 1.3 and 1.3 MMcfd of natural gas, respectively.

The most recent successful pilot in Loving County is a three-well pattern, also in the Leonard 'A' zone. The Gemini #1H, #2H and #3H were drilled 300 feet apart and turned to production at initial rates of 1,120, 1,530 and 1,290 Bopd, respectively. These Leonard 'A' zone wells, in which EOG has 48 percent, 100 percent and 48 percent working interest, respectively, had associated NGL production of 185, 220 and 200 Bpd and 1.0, 1.2 and 1.1 MMcfd of natural gas, respectively.

In addition, EOG has completed two strong Leonard 'B' zone wells, one drilled as part of a two-well pattern offsetting an 'A' zone well. In Lea County, the Falcon 25 Fed #2H began sales from the 'B' zone at 920 Bopd with 120 Bpd of NGLs and 660 thousand cubic feet per day (Mcfd) of natural gas. In Loving County, the Mercury State #2H also was completed in the 'B' zone, flowing 1,630 Bopd with 230 Bpd of NGLs and 1.3 MMcfd of natural gas. Offsetting the Mercury State #2H by 250 feet, the Mercury State #1H was completed in the 'A' zone at 1,700 Bopd with 360 Bpd of NGLs and 2.0 MMcfd of natural gas. EOG has 100 percent working interest in these three wells. Positive initial results from the Falcon 25 Fed #2H and the Mercury State #2H wells support additional downspacing tests of the Leonard 'B' zone.

Using early production results from the tightly spaced Gemini 'A' zone wells and the Mercury State wells drilled across zones 'A' and 'B', EOG is evaluating various downspacing options that could significantly increase the number of drilling locations across its Leonard acreage.

"The Second Bone Spring Sand is yet another example of how EOG organically increases its high return crude oil inventory. Its potential, combined with downspacing results from the Leonard Shale play, positions EOG for steady long-term exploration and development activity in the Delaware Basin. We have the momentum to unlock additional high rate-of-return growth from EOG's oil-rich acreage for years to come," Thomas said.

In Reeves County, Texas, EOG reported a number of successful wells from its 134,000 net acre position in the Delaware Basin Wolfcamp play. The State Apache 57 #1103H, #1104H, #1105H and #1107H were completed at initial rates ranging from 590 to 1,600 Bopd with 200 to 460 Bpd of NGLs and 1.3 to 3.0 MMcfd of natural gas. Also in Reeves County, the State Harrison Ranch 56 #302H and #303H began sales at 660 and 665 Bopd with 275 and 450 Bpd of NGLs and 1.8 and 2.9 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these six wells. EOG continues to test various well spacing patterns and zones on its Delaware Basin Wolfcamp acreage.

Eagle Ford

EOG's South Texas Eagle Ford crude oil play again contributed significantly to total company second quarter crude oil production growth. Associated NGL and natural gas production also contributed to total company growth. Maintaining a robust drilling and completion program across its Eagle Ford acreage, EOG is further improving individual well results by modifying completion techniques and reducing drilling days.

In Karnes County, the McCoy Unit #1H and #2H began production at 5,290 and 5,415 Bopd with 475 and 415 Bpd of NGLs and 2.7 and 2.4 MMcfd of natural gas, respectively. EOG has 90 percent working interest in these wells. The Wolf Unit #6H, #7H, #8H and #9H, in which EOG has 100 percent working interest, began sales at rates ranging from 3,160 to 3,600 Bopd with 310 to 390 Bpd of NGLs and 1.8 to 2.3 MMcfd of natural gas.

Northeast of Karnes in DeWitt County, the Justiss Unit #11H, #12H and #13H had initial production rates of 4,000, 3,900 and 4,130 Bopd with 690, 650 and 750 Bpd of NGLs and 4.0, 3.8 and 4.3 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these three wells.

In Gonzales County, EOG recorded a number of wells with robust initial production including the Boothe Unit #11H and #16H, which had rates of 4,570 and 3,245 Bopd with 580 and 500 Bpd of NGLs and 3.4 and 2.9 MMcfd of natural gas, respectively. The Zimmerman Unit #14H began sales at 3,800 Bopd with 350 Bpd of NGLs and 2.0 MMcfd of natural gas. EOG has 100 percent working interest in these three wells.

Southwest of Gonzales in LaSalle County, the Naylor Jones Unit 127 #1H, #2H and #3H had initial production rates ranging from 2,200 to 2,500 Bopd with 220 to 250 Bpd of NGLs and 1.3 to 1.5 MMcfd of natural gas. EOG has 100 percent, 100 percent and 75 percent working interest in these wells, respectively.

North Dakota Bakken

In the North Dakota Bakken, EOG is concentrating activity on its Core acreage in Mountrail County. Well productivity is improving markedly due to continued refinements in completion designs. Three Core wells, the Wayzetta 43-0311H, 44-0311H and 45-0311H, were completed during the second quarter at 1,505, 2,410 and 2,690 Bopd, respectively. EOG has 75 percent working interest in these wells. EOG continues to drill and evaluate production data from various spacing patterns in order to maximize the value of this asset. In addition, EOG plans to drill several Three Forks wells to test various benches of this play on both its Core and Antelope Extension acreage during the remainder of 2014.

Wyoming

In the Wyoming DJ Basin, EOG is simultaneously developing the stacked Codell and Niobrara formations from multi-well pad locations in Laramie County, Wyoming. During the second quarter, the Jubilee 586-1705H, the second well completed from a multi-well pad, began production from the Codell at an initial rate of 1,145 Bopd with 445 Mcfd of rich natural gas. EOG has 75 percent working interest in the well. A number of wells are targeted to begin production in August through year-end. EOG plans to test well spacing patterns and various completion techniques in both the Codell and Niobrara formations. EOG has increased its acreage position in the Codell by 13,000 net acres to 85,000 net acres.

In the Wyoming Powder River Basin, EOG is maintaining a steady drilling program with denser pad drilling operations. In the Parkman play, the Mary's Draw 404-21H and 468-34H, which were drilled from the same pad, had initial production rates of 1,045 and 980 Bopd with 305 and 330 Mcfd of rich natural gas, respectively. EOG has 99 percent and 100 percent working interest in the wells, respectively.

"To summarize our position, EOG is extending its lead as the largest crude oil producer in the onshore U.S. Lower 48. We continue to grow the size and quality of our drilling inventory by generating excellent new plays internally and increasing the drilling potential of our existing plays," Thomas said. "EOG is leading its peers in terms of barrels per day of crude oil growth, while our forecast ROE and ROCE metrics exceed the average of all upstream energy sectors, including the majors."

Crude Oil and Natural Gas Hedging Activity

For the period August 1 through December 31, 2014, EOG has crude oil financial price swap contracts in place for 194,000 Bopd at a weighted average price of $96.19 per barrel. For the calendar year 2015, EOG has no crude oil financial derivative contracts in place, excluding unexercised options.

For the period September 1 through December 31, 2014, EOG has natural gas financial price swap contracts in place for 330,000 million British thermal units per day (MMBtud) at a weighted average price of $4.55 per million British thermal units (MMBtu), excluding unexercised options.

For the period January 1 through December 31, 2015, EOG has natural gas financial price swap contracts in place for 175,000 MMBtud at a weighted average price of $4.51 per MMBtu, excluding unexercised options. (For a comprehensive summary of crude oil and natural gas derivative contracts, please refer to the attached tables.)     

Cash Flow and Capital Structure

At June 30, 2014, EOG's total debt outstanding was $5,910 million for a debt-to-total capitalization ratio of 26 percent. Taking into account cash on the balance sheet of $1.2 billion at June 30, EOG's net debt was $4,680 million for a net debt-to-total capitalization ratio of 22 percent. (Please refer to the attached tables for the reconciliation of net debt (non-GAAP) to current and long-term debt (GAAP) and the reconciliation of net debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization ratio (GAAP).)

EOG is targeting 29 percent total company crude oil production growth in 2014. Total company production is expected to rise 14 percent, an increase from the previous 12 percent estimate. Capital expenditures are anticipated to range from $8.1 billion to $8.3 billion for 2014, unchanged from prior estimates.

Conference Call August 6, 2014

EOG's second quarter 2014 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Wednesday, August 6, 2014. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through August 20, 2014.

EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Canada, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG."  

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 and extent 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 17 through 26 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2013 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).  As noted above, 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, 2013, 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.

For Further Information Contact: 

Investors

 

Maire A. Baldwin

 

(713) 651-6364

 

Kimberly A. Matthews

 

(713) 571-4676

 

David J. Streit

 

(713) 571-4902

   
 

Media

 

K Leonard

 

(713) 571-3870 

 

 

EOG RESOURCES, INC.

FINANCIAL REPORT

(Unaudited; in millions, except per share data)

 
 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2014

 

2013

 

2014

 

2013

                       

Net Operating Revenues

$

4,187.6

 

$

3,840.2

 

$

8,271.2

 

$

7,196.7

Net Income 

$

706.4

 

$

659.7

 

$

1,367.3

 

$

1,154.4

Net Income Per Share 

                     
 

Basic

 

$

1.30

 

$

1.22

 

$

2.52

 

$

2.14

 

Diluted

 

$

1.29

 

$

1.21

 

$

2.49

 

$

2.12

Average Number of Common Shares

                     
 

Basic

   

543.1

   

540.0

   

542.7

   

539.3

 

Diluted

   

548.7

   

545.5

   

548.0

   

544.9

 
 

SUMMARY INCOME STATEMENTS

(Unaudited; in thousands, except per share data)

 
 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2014

 

2013

 

2014

 

2013

Net Operating Revenues

             
 

Crude Oil and Condensate

$

2,618,975

 

$

2,012,999

 

$

5,016,077

 

$

3,794,832

 

Natural Gas Liquids

 

247,973

   

178,457

   

494,208

   

347,986

 

Natural Gas

 

509,091

   

462,602

   

1,065,784

   

873,481

 

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

 

(229,270)

   

191,490

   

(385,006)

   

86,534

 

Gathering, Processing and Marketing

 

1,027,795

   

959,413

   

2,043,206

   

1,882,370

 

Gains on Asset Dispositions, Net

 

3,856

   

13,153

   

15,354

   

177,386

 

Other, Net

 

9,136

   

22,071

   

21,604

   

34,110

   

Total

 

4,187,556

   

3,840,185

   

8,271,227

   

7,196,699

Operating Expenses

                     
 

Lease and Well

 

346,458

   

268,888

   

667,292

   

517,888

 

Transportation Costs

 

240,579

   

224,491

   

483,816

   

408,748

 

Gathering and Processing Costs

 

32,470

   

25,897

   

66,394

   

50,401

 

Exploration Costs

 

42,208

   

47,323

   

90,266

   

91,539

 

Dry Hole Costs

 

5,558

   

35,750

   

13,906

   

39,712

 

Impairments 

 

39,035

   

37,967

   

152,396

   

91,515

 

Marketing Costs

 

1,043,515

   

965,490

   

2,049,819

   

1,870,139

 

Depreciation, Depletion and Amortization

 

996,602

   

910,531

   

1,943,093

   

1,756,919

 

General and Administrative

 

90,932

   

80,607

   

173,794

   

158,592

 

Taxes Other Than Income

 

205,469

   

151,197

   

401,442

   

286,128

   

Total

 

3,042,826

   

2,748,141

   

6,042,218

   

5,271,581

 

Operating Income 

 

1,144,730

   

1,092,044

   

2,229,009

   

1,925,118

 

Other Income (Expense), Net

 

7,950

   

4,833

   

4,612

   

(5,301)

 

Income Before Interest Expense and Income Taxes

 

1,152,680

   

1,096,877

   

2,233,621

   

1,919,817

 

Interest Expense, Net

 

51,867

   

61,647

   

102,019

   

123,568

 

Income Before Income Taxes

 

1,100,813

   

1,035,230

   

2,131,602

   

1,796,249

 

Income Tax Provision

 

394,460

   

375,538

   

764,321

   

641,832

 

Net Income 

$

706,353

 

$

659,692

 

$

1,367,281

 

$

1,154,417

 

Dividends Declared per Common Share

$

0.1250

 

$

0.0938

 

$

0.2500

 

$

0.1875

       

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

           

 

 

EOG RESOURCES, INC.

OPERATING HIGHLIGHTS

(Unaudited)

 
 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2014

 

2013

 

2014

 

2013

Wellhead Volumes and Prices

     

Crude Oil and Condensate Volumes (MBbld) (A)

     
 

United States

 

274.6

   

206.5

   

266.4

   

192.4

 

Canada

 

5.6

   

6.4

   

6.4

   

7.1

 

Trinidad

 

1.0

   

1.4

   

1.0

   

1.3

 

Other International (B)

 

0.1

   

0.1

   

0.1

   

0.1

   

Total

 

281.3

   

214.4

   

273.9

   

200.9

 

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

                     
 

United States

$

102.66

 

$

103.73

 

$

101.66

 

$

105.04

 

Canada

 

94.66

   

89.66

   

92.05

   

87.29

 

Trinidad

 

94.25

   

86.96

   

92.09

   

90.36

 

Other International (B)

 

91.27

   

92.28

   

89.10

   

93.56

   

Composite

 

102.47

   

103.19

   

101.40

   

104.31

 

Natural Gas Liquids Volumes (MBbld) (A)

                     
 

United States

 

78.5

   

63.7

   

74.7

   

61.2

 

Canada

 

0.7

   

1.0

   

0.7

   

0.9

   

Total

 

79.2

   

64.7

   

75.4

   

62.1

 

Average Natural Gas Liquids Prices ($/Bbl) ©

                     
 

United States

$

34.35

 

$

30.19

 

$

36.12

 

$

30.87

 

Canada

 

40.90

   

39.49

   

44.15

   

40.62

   

Composite

 

34.41

   

30.33

   

36.20

   

31.02

 

Natural Gas Volumes (MMcfd) (A)

                     
 

United States

 

925

   

928

   

910

   

931

 

Canada

 

67

   

79

   

65

   

79

 

Trinidad

 

380

   

346

   

384

   

349

 

Other International (B)

 

11

   

8

   

9

   

8

   

Total

 

1,383

   

1,361

   

1,368

   

1,367

 

Average Natural Gas Prices ($/Mcf) ©

                     
 

United States

$

4.14

 

$

3.73

 

$

4.54

 

$

3.41

 

Canada

 

4.72

   

3.17

   

4.71

   

3.21

 

Trinidad

 

3.69

   

3.82

   

3.66

   

3.86

 

Other International (B)

 

4.39

   

6.81

   

5.04

   

6.78

   

Composite

 

4.04

   

3.73

   

4.31

   

3.53

 

Crude Oil Equivalent Volumes (MBoed) (D)

                     
 

United States 

 

507.2

   

424.8

   

492.7

   

408.8

 

Canada

 

17.4

   

20.6

   

18.1

   

21.2

 

Trinidad

 

64.5

   

59.0

   

65.0

   

59.4

 

Other International (B)

 

1.9

   

1.5

   

1.5

   

1.4

   

Total

 

591.0

   

505.9

   

577.3

   

490.8

 

Total MMBoe (D)

 

53.8

   

46.0

   

104.5

   

88.8

 
   

(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 and natural gas.  Crude oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or natural gas liquids 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)

 
 

June 30,

 

December 31,

 

2014

 

2013

ASSETS

Current Assets

         
 

Cash and Cash Equivalents

$

1,230,140

 

$

1,318,209

 

Accounts Receivable, Net

 

1,902,248

   

1,658,853

 

Inventories

 

667,108

   

563,268

 

Assets from Price Risk Management Activities

 

-

   

8,260

 

Income Taxes Receivable

 

24,527

   

4,797

 

Deferred Income Taxes

 

485,507

   

244,606

 

Other

 

415,215

   

274,022

     

Total

 

4,724,745

   

4,072,015

 

Property, Plant and Equipment

         
 

Oil and Gas Properties (Successful Efforts Method)

 

46,270,734

   

42,821,803

 

Other Property, Plant and Equipment

 

3,374,278

   

2,967,085

     

Total Property, Plant and Equipment

 

49,645,012

   

45,788,888

 

Less:  Accumulated Depreciation, Depletion and Amortization

 

(21,449,581)

   

(19,640,052)

     

Total Property, Plant and Equipment, Net

 

28,195,431

   

26,148,836

Other Assets

 

382,258

   

353,387

Total Assets

$

33,302,434

 

$

30,574,238

 

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities

         
 

Accounts Payable

$

2,661,473

 

$

2,254,418

 

Accrued Taxes Payable

 

228,569

   

159,365

 

Dividends Payable

 

67,865

   

50,795

 

Liabilities from Price Risk Management Activities

 

338,318

   

127,542

 

Current Portion of Long-Term Debt

 

6,579

   

6,579

 

Other

 

234,683

   

263,017

     

Total

 

3,537,487

   

2,861,716

 
 

Long-Term Debt

 

5,903,099

   

5,906,642

Other Liabilities

 

991,450

   

865,067

Deferred Income Taxes

 

6,162,010

   

5,522,354

Commitments and Contingencies

         
                 

Stockholders' Equity

         
 

Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 547,951,875

         
   

Shares Issued at June 30, 2014 and 546,378,440 Shares Issued at December 31, 2013 

 

205,482

   

202,732

 

Additional Paid in Capital

 

2,728,482

   

2,646,879

 

Accumulated Other Comprehensive Income 

 

426,588

   

415,834

 

Retained Earnings

 

13,398,901

   

12,168,277

 

Common Stock Held in Treasury, 515,079 Shares at June 30, 2014 and 

         
   

206,830 Shares at December 31, 2013 

 

(51,065)

   

(15,263)

     

Total Stockholders' Equity

 

16,708,388

   

15,418,459

Total Liabilities and Stockholders' Equity

$

33,302,434

 

$

30,574,238

 

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

 

 

EOG RESOURCES, INC.

SUMMARY STATEMENTS OF CASH FLOWS

(Unaudited; in thousands)

                 
 

Six Months Ended

 

June 30,

 

2014

 

2013

Cash Flows from Operating Activities

         

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

         
 

Net Income 

$

1,367,281

 

$

1,154,417

 

Items Not Requiring (Providing) Cash

         
     

Depreciation, Depletion and Amortization

 

1,943,093

   

1,756,919

     

Impairments 

 

152,396

   

91,515

     

Stock-Based Compensation Expenses

 

65,144

   

57,724

     

Deferred Income Taxes

 

479,109

   

488,632

     

Gains on Asset Dispositions, Net

 

(15,354)

   

(177,386)

     

Other, Net

 

984

   

8,747

 

Dry Hole Costs

 

13,906

   

39,712

 

Mark-to-Market Commodity Derivative Contracts

         
     

Total Losses (Gains)

 

385,006

   

(86,534)

     

Net Cash (Payments for) Received from Settlements of Commodity Derivative Contracts 

 

(120,900)

   

135,959

 

Excess Tax Benefits from Stock-Based Compensation

 

(63,759)

   

(21,869)

 

Other, Net

 

7,223

   

7,759

 

Changes in Components of Working Capital and Other Assets and Liabilities

         
     

Accounts Receivable

 

(249,336)

   

(164,809)

     

Inventories

 

(109,756)

   

22,085

     

Accounts Payable

 

347,539

   

141,369

     

Accrued Taxes Payable

 

115,668

   

24,816

     

Other Assets

 

(141,453)

   

(92,305)

     

Other Liabilities

 

57,101

   

(51,400)

 

Changes in Components of Working Capital Associated with Investing and

         
   

Financing Activities

 

(31,644)

   

(19,639)

Net Cash Provided by Operating Activities

 

4,202,248

   

3,315,712

           

Investing Cash Flows

         
 

Additions to Oil and Gas Properties

 

(3,724,486)

   

(3,250,091)

 

Additions to Other Property, Plant and Equipment

 

(402,972)

   

(183,516)

 

Proceeds from Sales of Assets

 

74,512

   

579,941

 

Changes in Restricted Cash

 

(91,238)

   

(52,322)

 

Changes in Components of Working Capital Associated with Investing Activities

 

31,620

   

19,358

Net Cash Used in Investing Activities

 

(4,112,564)

   

(2,886,630)

           

Financing Cash Flows

         
 

Long-Term Debt Borrowings

 

496,220

   

-

 

Long-Term Debt Repayments

 

(500,000)

   

-

 

Settlement of Foreign Currency Swap

 

(31,573)

   

-

 

Dividends Paid

 

(119,684)

   

(97,006)

 

Excess Tax Benefits from Stock-Based Compensation

 

63,759

   

21,869

 

Treasury Stock Purchased

 

(89,524)

   

(21,094)

 

Proceeds from Stock Options Exercised and Employee Stock Purchase Plan

 

10,433

   

20,773

 

Debt Issuance Costs

 

(895)

   

-

 

Repayment of Capital Lease Obligation

 

(2,958)

   

(2,866)

 

Other, Net

 

24

   

281

Net Cash Used in Financing Activities

 

(174,198)

   

(78,043)

           

Effect of Exchange Rate Changes on Cash

 

(3,555)

   

542

           

(Decrease) Increase in Cash and Cash Equivalents

 

(88,069)

   

351,581

Cash and Cash Equivalents at Beginning of Period

 

1,318,209

   

876,435

Cash and Cash Equivalents at End of Period

$

1,230,140

 

$

1,228,016

                 
                 

 

 

 

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 six-month periods ended June 30, 2014 and 2013 reported Net Income (GAAP) to reflect actual net cash (payments for) received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market losses (gains) from these transactions, to eliminate the net gains on asset dispositions in North America in 2014 and 2013 and to add back impairment charges related to certain of EOG's non-core North American assets in 2014 and 2013.  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 

 

Six Months Ended

 

June 30,

 

June 30,

 

2014

 

2013

 

2014

 

2013

 

Reported Net Income (GAAP)

$

706,353

 

$

659,692

 

$

1,367,281

 

$

1,154,417

 

Mark-to-Market (MTM) Commodity Derivative Contracts Impact

                     
 

Total Losses (Gains)

 

229,270

   

(191,490)

   

385,006

   

(86,534)

 

Net Cash (Payments for) Received from Settlements of Commodity Derivative Contracts

 

 

(86,867)

   

 

68,909

   

 

(120,900)

   

135,959

   

Subtotal

 

142,403

   

(122,581)

   

264,106

   

49,425

 
 

After-Tax MTM Impact

 

91,359

   

(78,482)

   

169,437

   

31,645

 

Less: Net Gains on Asset Dispositions, Net of Tax

 

(1,663)

   

(9,382)

   

(9,040)

   

(124,375)

Add: Impairments of Certain North American Assets, Net of Tax

 

-

   

2,003

   

36,058

   

2,003

 

Adjusted Net Income (Non-GAAP)

$

796,049

 

$

573,831

 

$

1,563,736

 

$

1,063,690

 

Net Income Per Share (GAAP)

 

Basic

 

$

1.30

 

$

1.22

 

$

2.52

 

$

2.14

 

Diluted

$

1.29

 

$

1.21

 

$

2.49

 

$

2.12

 

Adjusted Net Income Per Share (Non-GAAP)

 

Basic

 

$

1.47

 

$

1.06

 

$

2.88

 

$

1.97

 

Diluted

$

1.45

 

$

1.05

 

$

2.85

 

$

1.95

                           

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

 

38%

         

46%

     
 

Average Number of Common Shares (GAAP)

 

Basic

   

543,099

   

540,033

   

542,675

   

539,330

 

Diluted

 

548,676

   

545,477

   

548,046

   

544,946

 

Note: All share and per-share amounts shown have been restated to reflect the announced 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 six-month periods ended June 30, 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

 

Six Months Ended

 

June 30,

 

June 30,

 

2014

 

2013

 

2014

 

2013

 

Net Cash Provided by Operating Activities (GAAP)

$

1,934,575

 

$

1,890,777

 

$

4,202,248

 

$

3,315,712

                       

Adjustments:

 

Exploration Costs (excluding Stock-Based Compensation Expenses) 

 

36,659

   

40,930

   

76,783

   

77,575

 

Excess Tax Benefits from Stock-Based Compensation

 

36,337

   

10,196

   

63,759

   

21,869

 

Changes in Components of Working Capital and Other Assets and Liabilities

                     
     

Accounts Receivable

 

105,019

   

(71,948)

   

249,336

   

164,809

     

Inventories

 

40,808

   

(37,143)

   

109,756

   

(22,085)

     

Accounts Payable

 

14,271

   

44,696

   

(347,539)

   

(141,369)

     

Accrued Taxes Payable

 

24,133

   

(15,812)

   

(115,668)

   

(24,816)

     

Other Assets

 

128,917

   

45,112

   

141,453

   

92,305

     

Other Liabilities

 

(86,270)

   

(1,533)

   

(57,101)

   

51,400

 

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

 

 

(36,639)

   

 

(37,782)

   

 

31,644

   

19,639

 

Discretionary Cash Flow (Non-GAAP)

$

2,197,810

 

$

1,867,493

 

$

4,354,671

 

$

3,555,039

                             

Discretionary Cash Flow (Non-GAAP) - Percentage Increase

 

18%

         

22%

     
                             
                             

 

 

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 six-month periods ended June 30, 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 (payments for) received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) losses (gains) 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

 

Six Months Ended

     

June 30,

 

June 30,

     

2014

 

2013

 

2014

 

2013

                           

Income Before Interest Expense and Income Taxes (GAAP)

$

1,152,680

 

$

1,096,877

 

$

2,233,621

 

$

1,919,817

                           

Adjustments:

                     
 

Depreciation, Depletion and Amortization

 

996,602

   

910,531

   

1,943,093

   

1,756,919

 

Exploration Costs

 

42,208

   

47,323

   

90,266

   

91,539

 

Dry Hole Costs

 

5,558

   

35,750

   

13,906

   

39,712

 

Impairments 

 

39,035

   

37,967

   

152,396

   

91,515

   

EBITDAX (Non-GAAP)

 

2,236,083

   

2,128,448

   

4,433,282

   

3,899,502

 

Total Losses (Gains) on MTM Commodity Derivative Contracts 

229,270

   

(191,490)

   

385,006

   

(86,534)

 

Net Cash (Payments for) Received from Settlements of Commodity Derivative Contracts

 

 

(86,867)

   

 

68,909

   

 

(120,900)

   

135,959

 

Net Gains on Asset Dispositions

 

(3,856)

   

(13,153)

   

(15,354)

   

(177,386)

                           

Adjusted EBITDAX (Non-GAAP)

$

2,374,630

 

$

1,992,714

 

$

4,682,034

 

$

3,771,541

                           

Adjusted EBITDAX (Non-GAAP) - Percentage Increase

 

19%

         

24%

     
                           
                           

 

 

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

 

June 30,

 

December 31,

 

2014

 

2013

     

Total Stockholders' Equity - (a)

$

16,708

 

$

15,418

             

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

 

5,910

   

5,913

Less: Cash 

 

(1,230)

   

(1,318)

Net Debt (Non-GAAP) - (c)

 

4,680

   

4,595

             

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

$

22,618

 

$

21,331

             

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

$

21,388

 

$

20,013

             

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

 

26%

   

28%

             

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

 

22%

   

23%

             

 

 

 

 

 

 

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 August 5, 2014, 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) 

2014

               

January 2014 (closed)

     

156,000

 

$            96.30

February 2014 (closed)

     

171,000

 

96.35

March 1, 2014 through June 30, 2014 (closed)

 

181,000

 

96.55

July 2014 (closed)

     

202,000

 

96.34

August 2014

     

202,000

 

96.34

September 1, 2014 through December 31, 2014

 

192,000

 

96.15

                   

2015 (1)

         

-

 

$                 -

 

(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 69,000 Bbld are exercisable on or about December 31, 2014.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 69,000 Bbld at an average price of $95.20 per barrel for each month during the period January 1, 2015 through June 30, 2015.

   
 

NATURAL GAS DERIVATIVE CONTRACTS

 

Weighted

 

Volume

 

Average Price

 

(MMBtud) 

 

($/MMBtu) 

2014 (2)

               

January 2014 (closed)

     

230,000

 

$             4.51

February 2014 (closed)

     

710,000

 

4.57

March 2014 (closed)

     

810,000

 

4.60

April 2014 (closed)

     

465,000

 

4.52

May 2014 (closed)

     

685,000

 

4.55

June 2014 (closed)

     

515,000

 

4.52

July 2014 (closed)

     

340,000

 

4.55

August 2014 (closed)

     

330,000

 

4.55

September 1, 2014 through December 31, 2014

 

330,000

 

4.55

 

2015 (3)

               

January 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 480,000 MMBtud at an average price of $4.63 per MMBtu for each month during the period September 1, 2014 through December 31, 2014.

(3)

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 January 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.

THIRD QUARTER AND FULL YEAR 2014 FORECAST AND BENCHMARK COMMODITY PRICING

                                   
 

(a)  Third Quarter and Full Year 2014 Forecast

 

The forecast items for the third quarter and full year 2014 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, Canada 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 and Canada 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)

           

3Q 2014

   

Full Year 2014

Daily Production

                     
 

Crude Oil and Condensate Volumes (MBbld)

                     
   

United States

 

278.0

-

 

292.0

   

268.0

-

 

288.0

   

Canada

 

4.5

-

 

5.5

   

5.5

-

 

6.5

   

Trinidad

 

0.6

-

 

0.8

   

0.7

-

 

1.0

   

Other International

 

0.0

-

 

0.0

   

0.0

-

 

0.0

     

Total

 

283.1

-

 

298.3

   

274.2

-

 

295.5

 
 

Natural Gas Liquids Volumes (MBbld)

                     
   

United States

 

75.5

-

 

79.5

   

73.8

-

 

78.3

   

Canada

 

0.4

-

 

0.6

   

0.5

-

 

0.7

     

Total

 

75.9

-

 

80.1

   

74.3

-

 

79.0

                               
 

Natural Gas Volumes (MMcfd)

                     
   

United States

 

877

-

 

901

   

886

-

 

905

   

Canada

 

58

-

 

62

   

61

-

 

64

   

Trinidad

 

327

-

 

345

   

358

-

 

372

   

Other International

 

8

-

 

10

   

8

-

 

10

     

Total

 

1,270

-

 

1,318

   

1,313

-

 

1,351

 
 

Crude Oil Equivalent Volumes (MBoed)  

                     
   

United States

 

499.7

-

 

521.7

   

489.5

-

 

517.1

   

Canada

 

14.6

-

 

16.4

   

16.2

-

 

17.9

   

Trinidad

 

55.1

-

 

58.3

   

60.4

-

 

63.0

   

Other International

 

1.3

-

 

1.7

   

1.3

-

 

1.7

     

Total

 

570.7

-

 

598.1

   

567.4

-

 

599.7

 

Operating Costs

                     
 

Unit Costs ($/Boe)

                     
   

Lease and Well

$

6.40

-

$

6.70

 

$

6.40

-

$

6.60

   

Transportation Costs

$

4.79

-

$

4.98

 

$

4.66

-

$

4.86

   

Depreciation, Depletion and Amortization

$

18.35

-

$

19.05

 

$

18.30

-

$

19.00

 

Expenses ($MM)

                     
 

Exploration, Dry Hole and Impairment

$

130

-

$

150

 

$

500

-

$

550

 

General and Administrative

$

101

-

$

112

 

$

380

-

$

390

 

Gathering and Processing 

$

38

-

$

44

 

$

130

-

$

150

 

Capitalized Interest

$

14

-

$

16

 

$

55

-

$

65

 

Net Interest

$

48

-

$

52

 

$

194

-

$

214

 

Taxes Other Than Income (% of Wellhead Revenue)

 

6.1%

-

 

6.5%

   

6.0%

-

 

6.5%

 

Income Taxes

                     
 

Effective Rate 

 

35%

-

 

40%

   

35%

-

 

40%

 

Current Taxes ($MM)

$

120

-

$

135

 

$

540

-

$

560

                               

Capital Expenditures ($MM) - FY 2014 (Excluding Acquisitions)

                     
 

Exploration and Development, Excluding Facilities

           

$

6,450

-

$

6,550

 

Exploration and Development Facilities

           

$

880

-

$

920

 

Gathering, Processing and Other

           

$

770

-

$

810

 

Pricing - (Refer to Benchmark Commodity Pricing in text)

                     
 

Crude Oil and Condensate ($/Bbl)

                     
   

Differentials

                     
     

United States - (above) below WTI

$

0.70

-

$

1.70

 

$

0.01

-

$

0.51

     

Canada - (above) below WTI

$

10.50

-

$

12.50

 

$

8.00

-

$

12.00

     

Trinidad - (above) below WTI

$

9.00

-

$

11.00

 

$

7.20

-

$

11.40

                               
 

Natural Gas Liquids

                     
   

Realizations as % of WTI

                     
     

United States

 

30%

-

 

37%

   

32%

-

 

37%

     

Canada

 

32%

-

 

38%

   

38%

-

 

43%

                               
 

Natural Gas ($/Mcf)

                     
   

Differentials

                     
     

United States - (above) below NYMEX Henry Hub

$

0.30

-

$

0.70

 

$

0.15

-

$

0.50

     

Canada - (above) below NYMEX Henry Hub

$

0.10

-

$

0.50

 

$

0.00

-

$

0.25

 
   

Realizations

                     
     

Trinidad

$

2.85

-

$

3.35

 

$

3.20

-

$

3.55

     

Other International

$

3.75

-

$

5.75

 

$

3.80

-

$

5.90

 

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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