UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549

 

FORM 10-Q

 

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2007

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 1-9743

EOG RESOURCES, INC.
(Exact name of registrant as specified in its charter)

Delaware

 

47-0684736

(State or other jurisdiction
of incorporation or organization)

 

(I.R.S. Employer Identification No.)

1111 Bagby, Sky Lobby 2, Houston, Texas 77002
(Address of principal executive offices, including zip code)

713-651-7000
(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):     Large Accelerated Filer x    Accelerated Filer o    Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of July 25, 2007.

Title of each class

 

Number of shares

Common Stock, par value $0.01 per share

 

244,813,916


EOG RESOURCES, INC.

TABLE OF CONTENTS

 

 

PART I.

FINANCIAL INFORMATION

Page No.

       
 

ITEM 1.

Financial Statements (Unaudited)

 
       
   

Consolidated Statements of Income - Three Months Ended June 30, 2007 and 2006 and Six Months Ended June 30, 2007 and 2006

3

       
   

Consolidated Balance Sheets - June 30, 2007 and December 31, 2006

4

       
   

Consolidated Statements of Cash Flows - Six Months Ended June 30, 2007 and 2006

5

       
   

Notes to Consolidated Financial Statements

6

       
 

ITEM 2.

Management's Discussion and Analysis of Financial Condition and Results of Operations

16

       
 

ITEM 3.

Quantitative and Qualitative Disclosures About Market Risk

29

       
 

ITEM 4.

Controls and Procedures

29

       

PART II.

OTHER INFORMATION

 
       
 

ITEM 1.

Legal Proceedings

30

       
 

ITEM 1A.

Risk Factors

30

       
 

ITEM 2.

Unregistered Sales of Equity Securities and Use of Proceeds

30

       
 

ITEM 4.

Submission of Matters to a Vote of Security Holders

31

       
 

ITEM 6.

Exhibits

31

       

SIGNATURES

 

32

       

EXHIBIT INDEX

 

33

-2-

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, Except Per Share Data)
(Unaudited)

   

Three Months Ended

 

Six Months Ended

   

June 30,

 

June 30,

   

2007

 

2006

 

2007

 

2006

                 
                 

Net Operating Revenues

               
 

Wellhead Natural Gas

$

790,456

$

642,969

$

1,526,098

$

1,432,030

 

Wellhead Crude Oil, Condensate and Natural

               
 

   Gas Liquids

 

218,696

 

185,036

 

393,560

 

369,754

 

Gains on Mark-to-Market Commodity

               
 

   Derivative Contracts

 

44,103

 

91,022

 

4,302

 

198,046

 

Other, Net

 

1,988

 

61

 

6,496

 

3,794

   

Total

 

1,055,243

 

919,088

 

1,930,456

 

2,003,624

                   

Operating Expenses

               
 

Lease and Well

 

123,188

 

87,287

 

227,513

 

174,771

 

Transportation Costs

 

41,591

 

25,913

 

79,339

 

54,009

 

Exploration Costs

 

41,216

 

35,313

 

67,600

 

74,705

 

Dry Hole Costs

 

11,816

 

14,668

 

28,626

 

25,394

 

Impairments

 

20,804

 

22,680

 

44,846

 

45,453

 

Depreciation, Depletion and Amortization

 

259,780

 

192,928

 

504,122

 

370,580

 

General and Administrative

 

47,183

 

38,607

 

91,062

 

74,898

 

Taxes Other Than Income

 

62,047

 

46,858

 

102,695

 

100,552

   

Total

 

607,625

 

464,254

 

1,145,803

 

920,362

                   

Operating Income

 

447,618

 

454,834

 

784,653

 

1,083,262

Other Income, Net

 

29,069

 

21,844

 

34,993

 

36,400

Income Before Interest Expense and Income Taxes

 

476,687

 

476,678

 

819,646

 

1,119,662

Interest Expense, Net

 

10,818

 

12,384

 

18,456

 

25,537

Income Before Income Taxes

 

465,869

 

464,294

 

801,190

 

1,094,125

Income Tax Provision

 

158,816

 

132,877

 

276,470

 

336,001

Net Income

 

307,053

 

331,417

 

524,720

 

758,124

Preferred Stock Dividends

 

990

 

1,858

 

1,865

 

3,716

Net Income Available to Common

$

306,063

$

329,559

$

522,855

$

754,408

                 

Net Income Per Share Available to Common

               
 

Basic

$

1.26

$

1.36

$

2.15

$

3.13

 

Diluted

$

1.24

$

1.34

$

2.12

$

3.07

                   

Average Number of Common Shares

               
 

Basic

 

243,227

 

241,613

 

242,976

 

241,370

 

Diluted

 

247,261

 

245,887

 

247,009

 

245,827

The accompanying notes are an integral part of these consolidated financial statements.

-3-

EOG RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Data)
(Unaudited)

   

June 30,

 

December 31,

   

2007

 

2006

ASSETS

Current Assets

       
 

Cash and Cash Equivalents

$

58,534 

$

218,255 

 

Accounts Receivable, Net

 

741,907 

 

754,134 

 

Inventories

 

116,300 

 

113,591 

 

Assets from Price Risk Management Activities

 

60,850 

 

130,612 

 

Income Taxes Receivable

 

39,671 

 

94,311 

 

Other

 

46,506 

 

39,177 

   

Total

 

1,063,768 

 

1,350,080 

             

Oil and Gas Properties (Successful Efforts Method)

 

15,890,787 

 

13,893,851 

 

Less: Accumulated Depreciation, Depletion and Amortization

 

(6,550,931)

 

(5,949,804)

   

Net Oil and Gas Properties

 

9,339,856 

 

7,944,047 

Other Assets

 

120,640 

 

108,033 

Total Assets

$

10,524,264 

$

9,402,160 

             
             

LIABILITIES AND SHAREHOLDERS' EQUITY

Current Liabilities

       
 

Accounts Payable

$

925,829 

$

896,572 

 

Accrued Taxes Payable

 

101,372 

 

130,984 

 

Dividends Payable

 

22,052 

 

14,718 

 

Deferred Income Taxes

 

54,895 

 

144,615 

 

Other

 

54,384 

 

68,123 

   

Total

 

1,158,532 

 

1,255,012 

             

Long-Term Debt

 

883,842 

 

733,442 

Other Liabilities

 

328,121 

 

300,907 

Deferred Income Taxes

 

1,861,180 

 

1,513,128 

             

Shareholders' Equity

       

Preferred Stock, $0.01 Par, 10,000,000 Shares Authorized:

       
 

Series B, Cumulative, $1,000 Liquidation Preference per Share,

       
 

   53,260 Shares Outstanding at June 30, 2007 and December 31,

       
 

     2006

 

52,951 

 

52,887 

Common Stock, $0.01 Par, 640,000,000 Shares Authorized and

       

   249,460,000 Shares Issued

 

202,495 

 

202,495 

Additional Paid in Capital

 

162,594 

 

129,986 

Accumulated Other Comprehensive Income

 

328,918 

 

176,704 

Retained Earnings

 

5,640,660 

 

5,151,034 

Common Stock Held in Treasury, 4,655,082 Shares at

       

   June 30, 2007 and 5,724,959 Shares at December 31, 2006

 

(95,029)

 

(113,435)

   

Total Shareholders' Equity

 

6,292,589 

 

5,599,671 

Total Liabilities and Shareholders' Equity

$

10,524,264 

$

9,402,160 

                 The accompanying notes are an integral part of these consolidated financial statements.

-4-

EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)

   

Six Months Ended

   

June 30,

   

2007

 

2006

Cash Flows From Operating Activities

       

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

       
 

Net Income

$

524,720 

$

758,124 

 

Items Not Requiring Cash

       
   

Depreciation, Depletion and Amortization

 

504,122 

 

370,580 

   

Impairments

 

44,846 

 

45,453 

   

Stock-Based Compensation Expenses

 

29,542 

 

19,618 

   

Deferred Income Taxes

 

223,591 

 

153,552 

   

Other, Net

 

(4,912)

 

(7,485)

 

Dry Hole Costs

 

28,626 

 

25,394 

 

Mark-to-Market Commodity Derivative Contracts

       
   

Total Gains

 

(4,302)

 

(198,046)

   

Realized Gains

 

65,880 

 

93,913 

 

Other, Net

 

(3,951)

 

4,710 

 

Changes in Components of Working Capital and Other Assets and Liabilities

       
   

Accounts Receivable

 

20,734 

 

169,350 

   

Inventories

 

(2,476)

 

(35,066)

   

Accounts Payable

 

14,651 

 

(5,225)

   

Accrued Taxes Payable

 

26,191 

 

(11,470)

   

Other Assets

 

(4,683)

 

28,160 

   

Other Liabilities

 

(20,420)

 

(25,422)

 

Changes in Components of Working Capital Associated with

       
   

Investing and Financing Activities

 

(20,471)

 

(9,708)

Net Cash Provided by Operating Activities

 

1,421,688 

 

1,376,432 

Investing Cash Flows

       
 

Additions to Oil and Gas Properties

 

(1,748,483)

 

(1,189,927)

 

Proceeds from Sales of Assets

 

37,988 

 

14,553 

 

Changes in Components of Working Capital Associated with

       
   

Investing Activities

 

20,412 

 

9,742 

 

Other, Net

 

(32,114)

 

(14,256)

Net Cash Used in Investing Activities

 

(1,722,197)

 

(1,179,888)

Financing Cash Flows

       
 

Net Commercial Paper and Revolving Credit Facility Borrowings

 

180,400 

 

10,000 

 

Long-Term Debt Repayments

 

(30,000)

 

(102,550)

 

Dividends Paid

 

(38,370)

 

(27,712)

 

Excess Tax Benefits from Stock-Based Compensation Expenses

 

11,122 

 

20,841 

 

Proceeds from Stock Options Exercised and Employee Stock Purchase Plan

 

14,089 

 

11,143 

 

Other, Net

 

(194)

 

(214)

Net Cash Provided by (Used in) Financing Activities

 

137,047 

 

(88,492)

Effect of Exchange Rate Changes on Cash

 

3,741 

 

7,245 

(Decrease) Increase in Cash and Cash Equivalents

 

(159,721)

 

115,297 

Cash and Cash Equivalents at Beginning of Period

 

218,255 

 

643,811 

Cash and Cash Equivalents at End of Period

$

58,534 

$

759,108 

                                       The accompanying notes are an integral part of these consolidated financial statements.

-5-

EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

 

1. Summary of Significant Accounting Policies

General. The consolidated financial statements of EOG Resources, Inc. and subsidiaries (EOG) included herein have been prepared by management without audit pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, they reflect all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the financial results for the interim periods. Certain information and notes normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations. However, management believes that the disclosures are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in EOG's Annual Report on Form 10-K for the year ended December 31, 2006 (EOG's 2006 Annual Report).

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The operating results for the three and six months ended June 30, 2007 are not necessarily indicative of the results to be expected for the full year.

On January 31, 2007, the Board of Directors of EOG (Board) increased the quarterly cash dividend on the common stock from the previous $0.06 per share to $0.09 per share effective with the dividend paid on April 30, 2007 to record holders as of April 16, 2007.

Certain reclassifications have been made to prior period financial statements to conform with the current presentation.

Derivative Instruments. As more fully discussed in Note 11 to Consolidated Financial Statements included in EOG's 2006 Annual Report, EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for natural gas and crude oil. EOG utilizes financial commodity derivative instruments, primarily collar and price swap contracts, as the means to manage this price risk. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. In addition to financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.

Recently Issued Accounting Standards and Developments. During February 2007, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - including an amendment of FASB Statement No. 115." The new standard permits an entity to make an irrevocable election to measure most financial assets and financial liabilities at fair value. The fair value option may be elected on an instrument-by-instrument basis, with a few exceptions, as long as it is applied to the instrument in its entirety. Changes in fair value would be recorded in income. SFAS No. 159 established presentation and disclosure requirements intended to help financial statement users understand the effect of the entity's election on earnings. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007. Early adoption is permitted. EOG is currently analyzing SFAS No. 159.

In September 2006, the FASB issued SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Post Retirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R)." SFAS No. 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its balance sheet. The funded status is defined as the difference between the fair

-6-

value of plan assets and the projected benefit obligation (for pension plans) or the accumulated postretirement benefit obligation (for other postretirement benefit plans). SFAS No. 158 also requires that actuarial gains and losses and changes in prior service costs not included in net periodic pension costs be included, net of tax, as a component of other comprehensive income. The statement does not affect the determination of net periodic benefit costs included in the income statement. SFAS No. 158 also requires that an employer measure defined benefit plan assets and benefit obligations as of the date of the employer's fiscal year-end statement of financial position. As of the year ended December 31, 2006, EOG adopted the recognition and disclosure requirements of SFAS No. 158. The impact of the adoption was immaterial. The requirement to measure plan assets and benefit obligations as of the date of the employer's fiscal year-end is effective for fiscal years ending after December 15, 2008, and will not have an impact on EOG's financial statements since plan assets and benefit obligations are currently measured as of the date of EOG's fiscal year-end.

In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements." SFAS No. 157 provides a definition of fair value and provides a framework for measuring fair value. The standard also requires additional disclosures on the use of fair value in measuring assets and liabilities. SFAS No. 157 establishes a fair value hierarchy and requires disclosure of fair value measurements within that hierarchy. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within those years. EOG is assessing the impact, if any, that the adoption of SFAS No. 157 will have on its financial statements.

During July 2006, the FASB issued FASB Interpretation (FIN) No. 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109." FIN No. 48 addresses the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with SFAS No. 109, "Accounting for Income Taxes." FIN No. 48 prescribes specific criteria for the financial statement recognition and measurement of the tax effects of a position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition of previously recognized tax benefits, classification of tax liabilities on the balance sheet, recording interest and penalties on tax underpayments, accounting in interim periods, and disclosure requirements. FIN No. 48 is effective for fiscal periods beginning after December 15, 2006.

EOG adopted FIN No. 48 as of January 1, 2007. The cumulative effect of applying the provisions of FIN No. 48 has been reported as an increase to the opening balance of retained earnings for 2007 in the amount of $10.8 million, representing a reduction in the liability for unrecognized tax benefits. After adoption of FIN No. 48, the balance of unrecognized tax benefits was zero. EOG does not expect a significant increase in unrecognized tax benefits to occur during 2007. EOG or its subsidiaries file income tax returns in the United States federal jurisdiction and various state, local and foreign jurisdictions. EOG is generally no longer subject to income tax examinations by tax authorities in the United States (Federal), Canada and Trinidad before 2002, 2001 and 1999, respectively. EOG records interest and penalties related to unrecognized tax benefits to the income tax provision. EOG has no such accrued interest and penalties as of the date of adoption of FIN No. 48.

-7-

2. Stock-Based Compensation

At June 30, 2007, EOG maintained various stock-based compensation plans as discussed below. Stock-based compensation expense is included in the Consolidated Statements of Income based upon job functions of the employees receiving the grants as follows (in millions):

   

Three Months Ended

 

Six Months Ended

   

June 30,

 

June 30,

   

2007

 

2006

 

2007

 

2006

                 

Lease and Well

$

2.8

$

2.0

$

5.8

$

3.6

Exploration Costs

 

3.0

 

2.3

 

6.0

 

4.0

General and Administrative

 

9.5

 

6.3

 

17.7

 

12.0

   Total

$

15.3

$

10.6

$

29.5

$

19.6

EOG has various stock plans (Plans) under which employees and non-employee members of the Board have been or may be granted certain equity compensation. At June 30, 2007, approximately 2.6 million common shares remained available for grant under the Plans. EOG's policy is to issue shares related to the Plans from treasury stock. At June 30, 2007, EOG held approximately 4.7 million shares of treasury stock.

Stock Options and Stock Appreciation Rights. Under the Plans, participants have been or may be granted options to purchase shares of common stock of EOG at a price not less than the market price of the stock at the date of grant. In addition, participants have been or may be granted Stock-Settled Stock Appreciation Rights (SARs), representing the right to receive shares of EOG common stock based on the appreciation in the stock price from the date of the grant on the number of shares granted. Stock options and SARs granted under the Plans vest on a graded vesting schedule up to four years from the date of grant based on the nature of the grants and as defined in individual grant agreements. Terms for stock options and SARs granted under the Plans have not exceeded a maximum term of 10 years. For all grants made prior to August 2004 and all employee stock purchase plan (ESPP) grants, the fair value of each grant is estimated using the Black-Scholes-Merton model. Certain of EOG's stock options granted in 2005 and 2004 contain a feature that limits the potential gain that can be realized by requiring vested options to be exercised if the market price reaches 200% of the grant price for five consecutive trading days (Capped Option). EOG may or may not issue Capped Options in the future. The fair value of each Capped Option grant was estimated using a Monte Carlo simulation. Effective May 2005, the fair value of stock option grants not containing the Capped Option feature and SARs is estimated using the Hull-White II binomial option pricing model. Stock-based compensation expense related to stock options, SARs and ESPP grants totaled $8.7 million and $6.9 million during the three months ended June 30, 2007 and 2006, respectively. Such expense totaled $17.1 million and $13.5 million during the six months ended June 30, 2007 and 2006, respectively.

-8-

Weighted average fair values and valuation assumptions used to value stock options, SARs and ESPP grants during the six-month periods ended June 30, 2007 and 2006 are as follows:

     

Stock Options/SARs

   

ESPP

     

Six Months Ended

   

Six Months Ended

     

June 30,

   

June 30,

     

2007

   

2006

   

2007

   

2006

                         

Weighted Average Fair Value of Grants

 

$

21.96   

 

$

25.29   

 

$

15.07   

 

$

21.14   

Expected Volatility

   

29.35%

   

35.20%

   

32.47%

   

39.66%

Risk-Free Interest Rate

   

4.83%

   

4.97%

   

5.07%

   

4.47%

Dividend Yield

   

0.3%

   

0.3%

   

0.3%

   

0.3%

Expected Life

   

4.8 yrs

   

3.9 yrs

   

0.5 yrs

   

0.5 yrs

Expected volatility is based on an equal weighting of historical volatility and implied volatility from traded options in EOG's stock. The risk-free interest rate is based upon United States Treasury yields in effect at the time of grant. The expected life is based upon historical experience and contractual terms of stock options, SARs and ESPP grants.

The following table sets forth the stock option and SAR transactions for the six-month periods ended June 30, 2007 and 2006 (stock options/SARs and dollars in thousands, except per share data):

 

Six Months Ended

   

Six Months Ended

 

June 30, 2007

   

June 30, 2006

       

Weighted

         

Weighted

       

Average

         

Average

 

Number of Stock

   

Grant

   

Number of

   

Grant

 

Options/SARs

   

Price

   

Stock Options

   

Price

                     

Outstanding at January 1

10,150 

 

$

35.29

   

9,698 

 

$

28.26

Granted

216 

   

71.61

   

154 

   

73.59

Exercised (1)

(534)

   

21.86

   

(480)

   

16.25

Forfeited

(85)

   

52.59

   

(67)

   

45.10

Outstanding at June 30 (2)

9,747 

 

$

36.67

   

9,305 

 

$

29.36

                     

Vested or Expected to Vest (3)

9,469 

 

$

36.19

   

8,816 

 

$

29.31

                     

Exercisable at June 30 (4)

4,998 

 

$

22.08

   

4,231 

 

$

17.27

(1) The total intrinsic value of stock options exercised for the six months ended June 30, 2007 and 2006 was $27 million and $30 million, respectively. The intrinsic value
      is based upon the difference between the market price of EOG's common stock on the date of exercise and the grant price of the options.
(2) The total intrinsic value of stock options/SARs outstanding at June 30, 2007 and 2006 was $355 million and $372 million, respectively. At June 30, 2007 and 2006,
      the weighted average remaining contractual life was 5.3 years and 6.2 years, respectively.
(3) The total intrinsic value of stock options/SARs vested or expected to vest at June 30, 2007 and 2006 was $350 million and $353 million, respectively. At June 30,
      2007 and 2006, the weighted average remaining contractual life was 5.3 years and 6.2 years, respectively.
(4) The total intrinsic value of stock options/SARs exercisable at June 30, 2007 and 2006 was $255 million and $220 million, respectively. At June 30, 2007 and 2006,
      the weighted average remaining contractual life was 4.5 years and 5.2 years, respectively.

-9-

At June 30, 2007, unrecognized compensation expense related to non-vested stock options, SARs and ESPP grants totaled $66.3 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.8 years.

Restricted Stock and Units. Under the Plans, employees may be granted restricted (non-vested) stock and/or units without cost to them. The restricted stock and units generally vest five years after the date of grant, except for certain bonus grants, and as defined in individual grant agreements. Upon vesting, restricted stock is released to the employee and restricted units are converted into common stock and released to the employee. Stock-based compensation expense related to restricted stock and units totaled $6.6 million and $3.7 million for the three months ended June 30, 2007 and 2006, respectively, and $12.4 million and $6.1 million for the six months ended June 30, 2007 and 2006, respectively.

The following table sets forth the restricted stock and units transactions for the six-month periods ended June 30, 2007 and 2006 (shares and units and dollars in thousands, except per share data):

Six Months Ended

Six Months Ended

 

June 30, 2007

 

June 30, 2006

     

Weighted

     

Weighted

 

Number of

 

Average

 

Number of

 

Average

 

Shares and

 

Grant Date

 

Shares and

 

Grant Date

 

Units

 

Fair Value

 

Units

 

Fair Value

               

Outstanding at January 1

2,301 

$

36.13

 

2,544 

$

26.04

Granted

520 

 

67.99

 

267 

 

67.07

Released (1)

(245)

 

18.37

 

(649)

 

20.68

Forfeited

(47)

 

53.13

 

(11)

 

51.31

Outstanding at June 30 (2)

2,529 

$

44.08

 

2,151 

$

32.62

(1) The total intrinsic value of restricted stock and units released for the six months ended June 30, 2007 and 2006 was $16 million and $47 million, respectively. The
      intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and units are released.
(2) The aggregate intrinsic value of restricted stock and units outstanding at June 30, 2007 and 2006 was approximately $185 million and $149 million, respectively.

At June 30, 2007, unrecognized compensation expense related to restricted stock and units totaled $77 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 2.7 years.

-10-

3. Earnings Per Share

The following table sets forth the computation of Net Income Per Share Available to Common for the three-month and six-month periods ended June 30 (in thousands, except per share data):

   

Three Months Ended

 

Six Months Ended

   

June 30,

 

June 30,

   

2007

 

2006

 

2007

 

2006

                 

Numerator for Basic and Diluted Earnings Per Share -

               
 

Net Income

$

307,053

$

331,417

$

524,720

$

758,124

 

Less: Preferred Stock Dividends

 

990

 

1,858

 

1,865

 

3,716

 

Net Income Available to Common

$

306,063

$

329,559

$

522,855

$

754,408

                 

Denominator for Basic Earnings Per Share -

               
 

Weighted Average Shares

 

243,227

 

241,613

 

242,976

 

241,370

Potential Dilutive Common Shares -

               
 

Stock Options/SARs

 

3,077

 

3,356

 

2,996

 

3,453

 

Restricted Stock and Units

 

957

 

918

 

1,037

 

1,004

Denominator for Diluted Earnings Per Share -

               
 

Adjusted Diluted Weighted Average Shares

 

247,261

 

245,887

 

247,009

 

245,827

                 

Net Income Per Share Available to Common

               
 

Basic

$

1.26

$

1.36

$

2.15

$

3.13

 

Diluted

$

1.24

 

1.34

$

2.12

$

3.07

The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive. The excluded stock options and SARs totaled 1.9 million and 1.6 million for the three months ended June 30, 2007 and 2006, respectively, and 3.3 million and 1.6 million for the six months ended June 30, 2007 and 2006, respectively.

4. Supplemental Cash Flow Information

Cash paid for interest and income taxes (net of receipts) for the six-month periods ended June 30 was as follows (in thousands):

   

Six Months Ended

   

June 30,

   

2007

 

2006

         

Interest

$

17,226

$

22,074

Income Taxes

$

27,426

$

132,580

-11-

5. Comprehensive Income

The following table presents the components of EOG's comprehensive income for the three-month and six-month periods ended June 30 (in thousands):

   

Three Months Ended

 

Six Months Ended

   

June 30,

 

June 30,

   

2007

 

2006

 

2007

 

2006

Comprehensive Income

               
 

Net Income

$

307,053 

$

331,417 

$

524,720 

$

758,124 

 

Other Comprehensive Income

               
   

Foreign Currency Translation Adjustments

 

132,137 

 

66,633 

 

148,489 

 

64,876 

   

Foreign Currency Swap Transaction

 

3,203 

 

1,610 

 

5,353 

 

2,156 

   

Income Tax Provision Related

               
   

   to Foreign Currency Swap Transaction

 

(1,090)

 

(1,159)

 

(1,705)

 

(1,342)

   

Deferred Postretirement Benefit Costs

 

40 

 

 

77 

 

-

     

Total

$

441,343 

$

398,501 

$

676,934 

$

823,814 

6. Segment Information

Selected financial information by reportable segment is presented below for the three-month and six-month periods ended June 30 (in thousands):

   

Three Months Ended

   

Six Months Ended

 
   

June 30,

   

June 30,

 
   

2007

 

2006

   

2007

 

2006

 
                     

Net Operating Revenues

                   
 

United States

$

813,231 

$

676,637 

 

$

1,442,390 

$

1,455,039 

 
 

Canada

 

158,826 

 

145,288 

   

302,293 

 

322,267 

 
 

Trinidad

 

73,830 

 

81,840 

   

160,938 

 

174,429 

 
 

United Kingdom

 

9,356 

 

15,323 

   

24,835 

 

51,889 

 
   

Total

$

1,055,243 

$

919,088 

 

$

1,930,456 

$

2,003,624 

 
                         

Operating Income (Loss)

                   
 

United States

$

324,246 

$

325,203 

 

$

535,990 

$

758,959 

 
 

Canada

 

70,138 

 

69,707 

   

128,935 

 

166,481 

 
 

Trinidad

 

52,810 

 

53,119 

   

116,400 

 

123,568 

 
 

United Kingdom

 

434 

 

6,837 

   

3,400 

 

34,286 

 
 

Other

 

(10)

 

(32)

   

(72)

 

(32)

 
   

Total

 

447,618 

 

454,834 

   

784,653 

 

1,083,262 

 
                         

Reconciling Items

                   
 

Other Income, Net

 

29,069 

 

21,844 

   

34,993 

 

36,400 

 
 

Interest Expense, Net

 

10,818 

 

12,384 

   

18,456 

 

25,537 

 
   

Income Before Income Taxes

$

465,869 

$

464,294 

 

$

801,190 

$

1,094,125 

 

-12-

7. Asset Retirement Obligations

The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of oil and gas properties pursuant to SFAS No. 143, "Accounting for Asset Retirement Obligations," for the six-month periods ended June 30 (in thousands):

   

Six Months Ended

   

June 30,

   

2007

   

2006

           

Carrying Amount at Beginning of Period

$

182,407 

 

$

161,488 

 

Liabilities Incurred

 

10,123 

   

4,633 

 

Liabilities Settled

 

(5,339)

   

(2,937)

 

Accretion

 

5,062 

   

4,623 

 

Revisions

 

(126)

   

(52)

 

Foreign Currency Translations

 

799 

   

1,904 

Carrying Amount at End of Period

$

192,926 

 

$

169,659 

           

Current Portion

$

8,614 

 

$

5,424 

Noncurrent Portion

$

184,312 

 

$

164,235 

8. Suspended Well Costs

EOG's net changes in suspended well costs for the six-month period ended June 30, 2007 in accordance with FASB Staff Position No. 19-1, "Accounting for Suspended Well Costs," are presented below (in thousands):

   

Six Months

   

Ended

   

June 30,

   

2007

     

Balance at December 31, 2006

$

77,365 

 

Additions Pending the Determination of Proved Reserves

 

78,784 

 

Reclassifications to Proved Properties

 

(18,450)

 

Charged to Dry Hole Costs

 

(4,250)

 

Foreign Currency Translations

 

5,463 

Balance at June 30, 2007

$

138,912 

-13-

The following table provides an aging of suspended well costs as of June 30, 2007 (in thousands, except well count):

   

As of

 
   

June 30,

 
   

2007

 
       

Capitalized exploratory well costs that have been

     
 

capitalized for a period less than one year

$

114,193

 

Capitalized exploratory well costs that have been

     
 

capitalized for a period greater than one year

 

24,719

 (1)

 

       Total

$

138,912

 

Number of projects that have exploratory well costs that have been

     
 

capitalized for a period greater than one year

 

1

 

(1) Amount represents an outside operated, winter access only, Northwest Territories discovery. During the first six months of 2007, the Canadian government indicated
      they were prepared to grant a significant discovery license for the D-57 area. The size of the license is being negotiated by the operator prior to the formal acceptance
      of the license. The operator plans to submit a second significant discovery application in the second half of 2007 for the B-44 area after the size of the D-57 license
      has been determined. A significant discovery license holds the lease indefinitely for the licensee.

9. Commitments and Contingencies

There are various suits and claims against EOG that have arisen in the ordinary course of business. Management believes that the chance that these suits and claims will individually, or in the aggregate, have a material adverse effect on the financial condition or results of operations of EOG is remote. When necessary, EOG has made accruals in accordance with SFAS No. 5, "Accounting for Contingencies," in order to provide for these matters.

-14-

10. Pension and Postretirement Benefits

Pension Plans. EOG has a non-contributory defined contribution pension plan and a matched defined contribution savings plan in place for most of its employees in the United States. For the six months ended June 30, 2007 and 2006, EOG's total costs recognized for these pension plans were $8.0 million and $6.9 million, respectively.

In addition, as more fully discussed in Note 6 to Consolidated Financial Statements in EOG's 2006 Annual Report, EOG's Canadian, Trinidadian and United Kingdom subsidiaries maintain various pension and savings plans for most of their employees. For the six months ended June 30, 2007 and 2006, combined contributions to these pension plans were $1.0 million and $1.4 million, respectively.

Postretirement Plan. EOG has postretirement medical and dental benefits in place for eligible United States and Trinidad employees and their eligible dependents. For the six months ended June 30, 2007, EOG's total contributions to these plans amounted to approximately $55,000. The net periodic pension costs recognized for the postretirement medical and dental plans were approximately $357,000 and $334,000, respectively, for the six months ended June 30, 2007 and 2006.

11. Long-Term Debt

At June 30, 2007, the $98 million principal amount of the 6.50% Notes due 2007 and $170 million principal amount of commercial paper were classified as long-term debt based upon EOG's intent and ability to ultimately replace such amounts with long-term debt.

The weighted average interest rate for commercial paper borrowings was 5.55% at June 30, 2007. The weighted average interest rate for commercial paper borrowings for the six months ended June 30, 2007 was 5.36%.

On May 18, 2007, EOG amended its 5-year, $600 million unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders and JP Morgan Chase Bank N.A., as Administrative Agent, to increase the facility from $600 million to $1.0 billion and to provide EOG the option to request letters of credit to be issued in an aggregate amount of up to $1.0 billion, replacing the previous limitation of up to $200 million. Concurrent with the effectiveness of the amendment, the maturity date of the Agreement was extended from June 28, 2011 to June 28, 2012. At June 30, 2007 there were no borrowings or letters of credit outstanding under the Agreement. Advances under the Agreement accrue interest based, at EOG's option, on either London InterBank Offering Rate plus an applicable margin (Eurodollar rate) or the base rate of the Agreement's administrative agent. At June 30, 2007, the Eurodollar rate and applicable base rate, had there been an amount borrowed under the Agreement, would have been 5.51% and 8.25%, respectively.

In the first six months of 2007, EOGI International Company, a wholly owned foreign subsidiary of EOG, repaid $30 million of the $60 million year-end 2006 outstanding balance of its $600 million, 3-year unsecured Senior Term Loan Agreement (Term Loan Agreement). Borrowings under the Term Loan Agreement accrue interest based, at EOG's option, on either the Eurodollar rate or the base rate of the Term Loan Agreement's administrative agent. The applicable Eurodollar rate for the $30 million outstanding at June 30, 2007 was 5.72%. The weighted average Eurodollar rate for the amounts outstanding for the six months ended June 30, 2007 was 5.72%.

On May 12, 2006, EOG Resources Trinidad Limited, a wholly-owned foreign subsidiary of EOG, entered into a 3-year $75 million Revolving Credit Agreement (Credit Agreement). Borrowings under the Credit Agreement accrue interest based, at EOG's option, on either the Eurodollar rate or the base rate of the Credit Agreement's administrative agent. At June 30, 2007, EOG had $75 million outstanding under the Credit Agreement. The applicable Eurodollar rate at June 30, 2007 was 5.72%. The weighted average Eurodollar rate for the amounts outstanding during the first six months of 2007 was 5.75%.

-15-

 

PART I. FINANCIAL INFORMATION

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EOG RESOURCES, INC.

Overview

EOG Resources, Inc. and its subsidiaries (EOG) is one of the largest independent (non-integrated) oil and natural gas companies in the United States with proved reserves in the United States, Canada, offshore Trinidad and the United Kingdom North Sea. EOG operates under a consistent business and operational strategy that focuses predominantly on achieving a strong reinvestment rate of return, drilling internally generated prospects, delivering long-term production growth and maintaining a strong balance sheet.

Operations. EOG's effort to identify plays with larger reserve potential has proven a successful supplement to its base development and exploitation program in the United States and Canada. EOG plans to continue to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's crude oil and natural gas production. Production in the United States and Canada accounted for approximately 82% of total company production in the first six months of 2007. Based on current trends, EOG expects its United States production to increase at a greater rate than its other operating areas in the second half of 2007. EOG's major United States producing areas are Louisiana, New Mexico, Oklahoma, Texas, Utah and Wyoming.

Although EOG continues to focus on United States and Canada natural gas, EOG sees an increasing linkage between United States and Canada natural gas demand and Trinidad natural gas supply. For example, liquefied natural gas (LNG) imports from existing and planned facilities in Trinidad are contenders to meet increasing United States natural gas demand. In addition, ammonia, methanol and chemical production has been relocating from the United States and Canada to Trinidad, driven by attractive natural gas feedstock prices in the island nation. EOG believes that its existing position with the supply contracts to two ammonia plants, a methanol plant and the Atlantic LNG Train 4 (ALNG) plant will continue to give its portfolio an even broader exposure to United States and Canada natural gas fundamentals. EOG delivered gas at the contractual rate of 30 MMcfd, gross (13 MMcfd, net) beginning in May 2007 when ALNG reached commercial status.

In July 2007, EOG executed a 15 year natural gas contract with the National Gas Company of Trinidad and Tobago (NGC) for the sale of approximately 110 MMcfd, gross (75 MMcfd, net to EOG, based on current pricing and operating assumptions). EOG expects to begin initial delivery under this contract in early 2010 from its first discovery on Block 4(a) , subject to the completion of a pipeline by NGC.

In addition to EOG's ongoing production from the Valkyrie and Arthur Fields in the United Kingdom North Sea, EOG participated in the drilling and successful testing of the Columbus prospect, a farm-in opportunity, in the Central North Sea Block 23/16f at the end of 2006. A rig has been contracted by the operator to drill an appraisal well on this prospect in the third quarter of 2007. EOG is also participating in an exploratory well that spud in July 2007 on the Eos prospect located in the Southern North Sea Block 48/11c.

EOG continues to evaluate other select natural gas and crude oil opportunities outside the United States and Canada primarily by pursuing exploitation opportunities in countries where indigenous natural gas and crude oil reserves have been identified.

                                                                                                                                                    -16-

Capital Structure. One of management's key strategies is to keep a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 12% at June 30, 2007 and March 31, 2007. During the first six months of 2007, EOG funded its capital programs by utilizing cash provided from its operating activities and net commercial paper and revolving credit facility borrowings.  Management believes that cash provided by operating activities will continue to be the primary funding source for capital expenditures.  Cash from operating activities is sensitive to many factors, including commodity prices, which may cause capital expenditures to exceed cash provided by operating activities.  For the remainder of 2007, management anticipates increasing debt to fund any shortfall between cash provided by operating activities and EOG's 2007 capital program.

On May 18, 2007, EOG amended its 5-year, $600 million unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders and JP Morgan Chase Bank N.A., as Administrative Agent, to increase the facility from $600 million to $1.0 billion and to provide EOG the option to request letters of credit to be issued in an aggregate amount of up to $1.0 billion, replacing the previous limitation of up to $200 million. Concurrent with the effectiveness of the amendment, the maturity date of the Agreement was extended from June 28, 2011 to June 28, 2012.

For 2007, EOG's estimated exploration and development expenditure budget is approximately $3.6 billion, excluding acquisitions. United States and Canada natural gas drilling activity continues to be a key component of this effort. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer EOG incremental exploration and/or production opportunities. Management continues to believe EOG has one of the strongest prospect inventories in EOG's history.

Other. EOG has decided to sell the majority of its producing shallow gas assets and surrounding acreage in the Appalachian Basin in order to reallocate resources to focus on larger potential plays in North America. The Appalachian area includes approximately 2,400 wells which account for approximately 2% of EOG's  United States production and its total year-end 2006 proved reserves. EOG will retain certain of its undeveloped acreage in this area and continue its shale exploration program. EOG intends to solicit bids from interested parties and will agree to a sale only if the terms are acceptable to management.

Results of Operations

The following review of operations for the three and six months ended June 30, 2007 and 2006 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included with this Quarterly Report on Form 10-Q.

Three Months Ended June 30, 2007 vs. Three Months Ended June 30, 2006

Net Operating Revenues. During the second quarter of 2007, net operating revenues increased $136 million, or 15%, to $1,055 million from $919 million for the same period of 2006. Total wellhead revenues, which are revenues generated from sales of natural gas, crude oil, condensate and natural gas liquids, increased $181 million, or 22%, to $1,009 million from $828 million for the same period of 2006.

-17-

Wellhead volume and price statistics for the three-month periods ended June 30 were as follows:

       

Three Months Ended

       

June 30,

       

2007

 

2006

Natural Gas Volumes (MMcfd) (1)

       
 

United States

 

960

 

776

 

Canada

 

232

 

225

   

United States and Canada

 

1,192

 

1,001

 

Trinidad

 

250

 

265

 

United Kingdom

 

22

 

25

   

Total

 

1,464

 

1,291

             

Average Natural Gas Prices ($/Mcf) (2)

       
 

United States

$

6.80

$

6.33

 

Canada

 

6.70

 

6.28

   

United States and Canada Composite

 

6.78

 

6.32

 

Trinidad

 

2.04

 

2.18

 

United Kingdom

 

4.35

 

6.34

   

Composite

 

5.93

 

5.47

             

Crude Oil and Condensate Volumes (MBbld) (1)

       
 

United States

 

23.4

 

19.5

 

Canada

 

2.4

 

2.4

   

United States and Canada

 

25.8

 

21.9

 

Trinidad

 

4.0

 

4.8

 

United Kingdom

 

0.1

 

0.1

   

Total

 

29.9

 

26.8

             

Average Crude Oil and Condensate Prices ($/Bbl) (2)

       
 

United States

$

61.38

$

67.69

 

Canada

 

60.08

 

62.62

   

United States and Canada Composite

 

61.26

 

67.06

 

Trinidad

 

75.16

 

67.47

 

United Kingdom

 

68.82

 

65.80

   

Composite

 

63.15

 

67.13

             

Natural Gas Liquids Volumes (MBbld) (1)

       
 

United States

 

10.4

 

9.0

 

Canada

 

1.1

 

0.6

   

Total

 

11.5

 

9.6

             

Average Natural Gas Liquids Prices ($/Bbl) (2)

       
 

United States

$

45.35

$

41.02

 

Canada

 

42.30

 

46.55

   

Composite

 

45.04

 

41.38

             

Natural Gas Equivalent Volumes (MMcfed) (3)

       
 

United States

 

1,163

 

947

 

Canada

 

253

 

244

   

United States and Canada

 

1,416

 

1,191

 

Trinidad

 

274

 

293

 

United Kingdom

 

23

 

26

   

Total

 

1,713

 

1,510

Total Bcfe (3)

 

155.8

 

137.4

(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) Dollars per thousand cubic feet or per barrel, as applicable.
(3) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil, condensate and natural gas liquids. Natural gas equivalents are
      determined using the ratio of 6.0 thousand cubic feet of natural gas to 1.0 barrel of crude oil, condensate or natural gas liquids.

-18-

Wellhead natural gas revenues for the second quarter of 2007 increased $147 million, or 23%, to $790 million from $643 million for the same period of 2006. The increase was due to increased natural gas deliveries ($86 million) and a higher composite average wellhead natural gas price ($61 million). The composite average wellhead price for natural gas increased 8% to $5.93 per Mcf for the second quarter of 2007 from $5.47 per Mcf for the same period of 2006.

Natural gas deliveries increased 173 MMcfd, or 13%, to 1,464 MMcfd for the second quarter of 2007 from 1,291 MMcfd for the same period of 2006. The increase was primarily due to higher production in the United States (184 MMcfd) and Canada (7 MMcfd), partially offset by decreased production in Trinidad (15 MMcfd). The increase in the United States was primarily attributable to increased production in Texas (127 MMcfd), the Rocky Mountain area (28 MMcfd), Kansas (19 MMcfd) and Mississippi (9 MMcfd). The decrease in Trinidad was primarily due to second quarter 2006 volumes reflecting higher demand and EOG supplying gas for use in ALNG's start-up phase. In 2007, ALNG remained in the start-up phase but did not require any gas from EOG until May when ALNG reached commercial status and EOG began supplying gas under the ALNG take-or-pay contract.

Wellhead crude oil and condensate revenues for the second quarter of 2007 increased $23 million, or 15%, to $172 million from $149 million for the same period of 2006. The increase was due to increased wellhead crude oil and condensate deliveries ($34 million), partially offset by a lower composite average wellhead crude oil and condensate price ($11 million). The composite average wellhead crude oil and condensate price for the second quarter of 2007 was $63.15 per barrel compared to $67.13 per barrel for the same period of 2006.

Natural gas liquids revenues for the second quarter of 2007 increased $11 million, or 30%, to $47 million from $36 million for the same period of 2006. The increase was due to increased deliveries ($7 million) and a higher composite average price ($4 million).

During the second quarter of 2007, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $44 million compared to a gain of $91 million for the same period of 2006. During the second quarter of 2007, the net cash inflow related to settled natural gas and crude oil financial price swap contracts was $19 million compared to the net cash inflow related to settled natural gas financial collar and price swap contracts of $64 million for the same period of 2006.

Operating and Other Expenses. For the second quarter of 2007, operating expenses of $608 million were $144 million higher than the $464 million incurred in the second quarter of 2006. The following table presents the costs per Mcfe for the three-month periods ended June 30:

   

Three Months Ended

   

June 30,

   

2007

   

2006

           

Lease and Well

$

0.79

 

$

0.64

Transportation Costs

 

0.27

   

0.19

Depreciation, Depletion and Amortization (DD&A)

 

1.67

   

1.42

General and Administrative (G&A)

 

0.30

   

0.28

Interest Expense, Net

 

0.07

   

0.09

 

Total Per-Unit Costs(1)

$

3.10

 

$

2.62

(1) Total per-unit costs do not include taxes other than income, exploration costs, dry hole costs and impairments.

The changes in per-unit rates of lease and well, transportation costs, DD&A, G&A and interest expense, net for the three months ended June 30, 2007 compared to the same period of 2006 were due primarily to the reasons set forth below.

-19-

Lease and well expenses include expenses for EOG operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property. Lease and well expenses can be divided into the following categories: costs to operate and maintain EOG's oil and natural gas wells, the cost of workovers, and lease and well administrative expenses. Operating and maintenance expenses include, among other things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep, and fuel and power. Workovers are costs of operations to restore or maintain production from existing wells.

Each of these categories of costs individually fluctuate from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.

Lease and well expenses of $123 million for the second quarter of 2007 increased $36 million from $87 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($18 million) and Canada ($7 million); higher workover expenditures in the United States ($6 million); and higher lease and well administrative expenses ($5 million).

Transportation costs represent costs incurred directly by EOG from third-party carriers associated with the delivery of hydrocarbon products from the lease to a down-stream point of sale. Transportation costs include the cost of compression (the cost of compressing natural gas to meet pipeline pressure requirements), dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees, fuel costs and transportation fees.

Transportation costs of $42 million for the second quarter of 2007 increased $16 million from $26 million for the same prior year period primarily due to increased production in the Fort Worth Basin Barnett Shale Play.

DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as the field production profiles; drilling or acquisition of new wells; disposition of existing wells; reserve revisions (upward or downward) primarily related to well performance; and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from quarter to quarter.

DD&A expenses of $260 million for the second quarter of 2007 increased $67 million from the same prior year period primarily due to increased production ($36 million) and DD&A rates ($29 million) in the United States.

G&A expenses of $47 million for the second quarter of 2007 were $9 million higher than the same prior year period primarily due to higher employee-related costs ($6 million) and higher office rent ($1 million).

Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are determined based on wellhead sales and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.

Taxes other than income for the second quarter of 2007 increased $15 million to $62 million (6.1% of wellhead revenues) from $47 million (5.7% of wellhead revenues) for the same prior year period. The increase was due to an increase in severance/production taxes as a result of increased wellhead revenues in the United States ($10 million) and lower 2007 credits taken for Texas high cost gas severance tax rate reductions ($2 million).

Exploration costs of $41 million for the second quarter of 2007 increased $6 million from $35 million for the same prior year period primarily due to increased geological and geophysical expenditures in the United States ($4 million) and Canada ($1 million).

-20-

Impairments include amortization of unproved leases, as well as impairments under SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which requires an entity to compute impairments to the carrying value of long-lived assets based on future cash flow analysis. Impairments of $21 million for the second quarter of 2007 decreased by $2 million compared to $23 million in the same prior year period primarily due to decreased SFAS No. 144 related impairments ($4 million), partially offset by increased amortization of unproved leases in the United States ($2 million). Under SFAS No. 144, EOG recorded impairments of $6 million and $10 million for the second quarters of 2007 and 2006, respectively.

Other income, net was $29 million for the second quarter of 2007 compared to $22 million for the same prior year period. The increase of $7 million was primarily due to higher gains on sales of properties ($11 million) and net foreign currency transaction gains in 2007 ($2 million), partially offset by decreased interest income ($6 million).

Income tax provision of $159 million for the second quarter of 2007 increased $26 million compared to the same prior year period due primarily to an increase in foreign income taxes ($29 million), largely related to the 2006 reductions in the Canadian federal tax rate ($19 million) and the Alberta, Canada provincial tax rate ($13 million), partially offset by lower 2007 United States state income taxes ($6 million). The net effective tax rate for the second quarter of 2007 increased to 34% from 29% for the same prior year period.

Six Months Ended June 30, 2007 vs. Six Months Ended June 30, 2006

Net Operating Revenues. During the first six months of 2007, net operating revenues decreased $74 million, or 4%, to $1,930 million from $2,004 million for the same period of 2006. Total wellhead revenues increased $118 million, or 7%, to $1,920 million from $1,802 million for the same period of 2006.

-21-

Wellhead volume and price statistics for the six-month periods ended June 30 were as follows:

       

Six Months Ended

       

June 30,

       

2007

 

2006

Natural Gas Volumes (MMcfd)

       
 

United States

 

938

 

767

 

Canada

 

227

 

227

   

United States and Canada

 

1,165

 

994

 

Trinidad

 

251

 

274

 

United Kingdom

 

26

 

30

   

Total

 

1,442

 

1,298

             

Average Natural Gas Prices ($/Mcf)

       
 

United States

$

6.61

$

7.04

 

Canada

 

6.57

 

7.08

   

United States and Canada Composite

 

6.60

 

7.04

 

Trinidad

 

2.42

 

2.31

 

United Kingdom

 

5.04

 

9.32

   

Composite

 

5.85

 

6.10

             

Crude Oil and Condensate Volumes (MBbld)

       
 

United States

 

22.6

 

20.2

 

Canada

 

2.5

 

2.5

   

United States and Canada

 

25.1

 

22.7

 

Trinidad

 

4.2

 

5.2

 

United Kingdom

 

0.1

 

0.1

   

Total

 

29.4

 

28.0

             

Average Crude Oil and Condensate Prices ($/Bbl)

       
 

United States

$

57.75

$

63.70

 

Canada

 

55.88

 

57.12

   

United States and Canada Composite

 

57.56

 

62.92

 

Trinidad

 

67.32

 

64.45

 

United Kingdom

 

59.61

 

61.04

   

Composite

 

58.96

 

63.21

             

Natural Gas Liquids Volumes (MBbld)

       
 

United States

 

10.0

 

8.1

 

Canada

 

1.1

 

0.7

   

Total

 

11.1

 

8.8

             

Average Natural Gas Liquids Prices ($/Bbl)

       
 

United States

$

41.40

$

39.32

 

Canada

 

39.39

 

44.56

   

Composite

 

41.20

 

39.72

             

Natural Gas Equivalent Volumes (MMcfed)

       
 

United States

 

1,134

 

937

 

Canada

 

248

 

246

   

United States and Canada

 

1,382

 

1,183

 

Trinidad

 

276

 

305

 

United Kingdom

 

27

 

30

   

Total

 

1,685

 

1,518

Total Bcfe

 

305.0

 

274.8

-22-

Wellhead natural gas revenues for the first six months of 2007 increased $94 million, or 7%, to $1,526 million from $1,432 million for the same period of 2006. The increase was due to increased natural gas deliveries ($160 million), partially offset by a lower composite wellhead natural gas price ($66 million). The composite average wellhead price for natural gas decreased 4% to $5.85 per Mcf for the first six months of 2007 from $6.10 per Mcf for the same period of 2006.

Natural gas deliveries increased 144 MMcfd, or 11%, to 1,442 MMcfd for the first six months of 2007 from 1,298 MMcfd for the same period of 2006. The increase was due to higher production in the United States (171 MMcfd), partially offset by decreased production in Trinidad (23 MMcfd). The increase in the United States was primarily attributable to increased production in Texas (125 MMcfd), the Rocky Mountain area (25 MMcfd) and Kansas (17 MMcfd). The decrease in Trinidad was due to volumes in the first six months of 2006 reflecting higher demand and EOG supplying gas for use in ALNG's start-up phase. In 2007, ALNG remained in the start-up phase but did not require any gas from EOG until May when ALNG reached commercial status and EOG began supplying gas under the ALNG take-or-pay contract.

Wellhead crude oil and condensate revenues for the first six months of 2007 increased $5 million, or 2%, to $311 million from $306 million for the same period of 2006. The increase was due to increased wellhead crude oil and condensate deliveries ($27 million), partially offset by a lower composite average wellhead crude oil and condensate price ($22 million). The composite average wellhead crude oil and condensate price for the first six months of 2007 was $58.96 per barrel compared to $63.21 per barrel for the same period of 2006.

Natural gas liquids revenues for the first six months of 2007 increased $19 million, or 30%, to $83 million from $64 million for the same period of 2006. The increase was due to increases in deliveries ($16 million) and composite average price ($3 million).

During the first six months of 2007, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $4 million compared to a gain of $198 million for the same period of 2006. During the first six months of 2007, the net cash inflow related to settled natural gas and crude oil financial price swap contracts was $66 million compared to the net cash inflow related to settled natural gas financial collar and price swap contracts of $94 million for the same period of 2006.

Operating and Other Expenses. For the first six months of 2007, operating expenses of $1,146 million were $226 million higher than the $920 million incurred in the same period of 2006. The following table presents the costs per Mcfe for the six-month periods ended June 30:

   

Six Months Ended

   

June 30,

   

2007

   

2006

           

Lease and Well

$

0.75

 

$

0.64

Transportation Costs

 

0.26

   

0.20

DD&A

 

1.65

   

1.36

G&A

 

0.30

   

0.27

Interest Expense, Net

 

0.06

   

0.09

 

Total Per-Unit Costs(1)

$

3.02

 

$

2.56

(1) Total per-unit costs do not include taxes other than income, exploration costs, dry hole costs and impairments.

The changes in per-unit rates of lease and well, transportation costs, DD&A, G&A and interest expense, net for the six months ended June 30, 2007 compared to the same period of 2006 were due primarily to the reasons set forth below.

-23-

Lease and well expenses of $228 million for the first six months of 2007 were $53 million higher than the same prior year period primarily due to higher operating and maintenance expenses in the United States ($31 million) and Canada ($6 million); higher lease and well administrative expenses ($9 million); and higher workover expenditures in the United States ($8 million).

Transportation costs of $79 million for the first six months of 2007 increased $25 million from $54 million for the same prior year period primarily due to increased production in the Fort Worth Basin Barnett Shale Play.

DD&A expenses of $504 million for the first six months of 2007 increased $134 million from the same prior year period primarily due to increased DD&A rates in the United States ($64 million), Canada ($8 million) and the United Kingdom ($2 million); and increased production in the United States ($59 million).

G&A expenses of $91 million for the first six months of 2007 were $16 million higher than the same prior year period primarily due to higher employee-related expenses ($13 million) and higher office rent ($2 million).

Taxes other than income for the first six months of 2007 increased $2 million to $103 million (5.3% of wellhead revenues) from $101 million (5.6% of wellhead revenues) for the same prior year period. The increase was primarily due to increased ad valorem/property taxes, partially offset by decreased severance/production taxes. Ad valorem/property taxes increased primarily due to higher property valuations in the United States ($3 million). Severance/production taxes in the United States decreased primarily due to higher 2007 credits taken for Texas high cost gas severance tax rate reductions ($15 million), partially offset by an increase in wellhead revenues in the United States ($11 million) and changes to Trinidad tax legislation governing the Supplemental Petroleum Tax which resulted in an adjustment that decreased production tax expense in the first six months of 2006 ($3 million).

Interest expense, net was $18 million for the first six months of 2007, down $7 million compared to the same prior year period primarily due to higher capitalized interest ($4 million) and a slightly lower average debt balance ($2 million).

Exploration costs of $68 million for the first six months of 2007 decreased $7 million from $75 million for the same prior year period primarily due to decreased geological and geophysical expenditures in the United States ($12 million), partially offset by increased geological and geophysical expenditures in Canada ($2 million) and higher employee-related costs ($4 million).

Impairments were $45 million for both six-month periods ended June 30, 2007 and 2006. SFAS No. 144 related impairments decreased ($4 million) and amortization of unproved leases increased in the United States ($3 million) and Canada ($1 million). Under SFAS No. 144, EOG recorded impairments of $16 million and $20 million for the six months ended June 30, 2007 and 2006, respectively.

Income tax provision of $276 million for the first six months of 2007 decreased $60 million compared to the same prior year period due primarily to a lower tax provision resulting from decreased pretax income ($103 million), partially offset by an increase in foreign income taxes ($46 million), largely related to the 2006 reductions in the Canadian federal tax rate ($19 million) and the Alberta, Canada provincial tax rate ($13 million). The net effective tax rate for the first six months of 2007 increased to 35% from 31% for the same prior year period.

-24-

Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the six months ended June 30, 2007 were funds generated from operations and net commercial paper and revolving credit facility borrowings. The primary uses of cash were funds used in operations, exploration and development expenditures, dividend payments to shareholders and repayment of debt. During the first six months of 2007, EOG's cash balance decreased $160 million to $58 million from $218 million at December 31, 2006.

Net cash provided by operating activities of $1,422 million for the first six months of 2007 increased $45 million compared to the same period of 2006 primarily reflecting an increase in wellhead revenues ($118 million) and a decrease in cash paid for interest and income taxes ($110 million), partially offset by unfavorable changes in working capital and other assets and liabilities ($135 million), an increase in cash operating expenses ($54 million) and a decrease in the net cash flows from settlement of financial commodity derivative contracts ($28 million).

Net cash used in investing activities of $1,722 million for the first six months of 2007 increased by $542 million compared to the same period of 2006 due primarily to increased additions to oil and gas properties.

Net cash provided by financing activities was $137 million for the first six months of 2007 compared to net cash used in financing activities of $88 million for the same period of 2006. Cash provided by financing activities for 2007 included net commercial paper and Trinidad revolving credit facility borrowings ($180 million), proceeds from sales of treasury stock attributable to employee stock option exercises and employee stock purchase plan ($14 million), and excess tax benefits from stock-based compensation expenses ($11 million). Cash used by financing activities for 2007 included cash dividend payments ($38 million) and repayments of long-term debt borrowings ($30 million).

Total Exploration and Development Expenditures. The table below presents total exploration and development expenditures for the six-month periods ended June 30 (in millions):

       

Six Months Ended

       

June 30,

       

2007

 

2006

         

United States

$

1,540

$

1,024

Canada

 

182

 

153

 

United States and Canada

 

1,722

 

1,177

Trinidad

 

89

 

70

United Kingdom

 

3

 

15

Other

 

2

 

3

 

Exploration and Development Expenditures

 

1,816

 

1,265

Asset Retirement Costs

 

11

 

4

 

Total Exploration and Development Expenditures

$

1,827

$

1,269

Total exploration and development expenditures of $1,827 million for the first six months of 2007 were $558 million higher than the same period of 2006. The 2007 exploration and development expenditures of $1,816 included $1,441 million in development, $361 million in exploration, $13 million in capitalized interest and $1 million in property acquisitions. The 2006 exploration and development expenditures of $1,265 included $920 million in development, $330 million in exploration, $9 million in capitalized interest and $6 million in property acquisitions.

Higher development expenditures for the first six months of 2007 of $521 million were due primarily to increased development drilling expenditures in the United States ($349 million), Trinidad ($48 million) and Canada ($12 million); and increased expenditures related to infrastructure facilities in the United States ($104 million) and Canada ($7 million).

Higher exploration expenditures for the first six months of 2007 of $31 million were primarily due to increased expenditures for leasehold acquisitions in the United States ($36 million), increased exploratory drilling

-25-

expenditures, including dry hole costs, in the United States ($27 million) and Canada ($8 million), partially offset by decreased exploratory drilling expenditures, including dry hole costs, in Trinidad ($26 million); and decreased geological and geophysical expenditures in the United States ($12 million).

The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other related economic factors. EOG has significant flexibility with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to operations in the United States, Canada, Trinidad and the United Kingdom North Sea, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.

Commodity Derivative Transactions. As more fully discussed in Note 11 to Consolidated Financial Statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2006, EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for natural gas and crude oil. EOG utilizes financial commodity derivative instruments, primarily collar and price swap contracts, as the means to manage this price risk. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. In addition to financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.

The total fair value of the natural gas financial price swap contracts at June 30, 2007 was a positive $63 million. Subsequent to June 30, 2007, EOG has entered into additional natural gas financial price swap contracts covering notional volumes of 90,000 million British thermal units per day (MMBtud) for the period January 2008 through December 2008 at an average price of $8.54 per million British thermal units (MMBtu). Presented below is a comprehensive summary of EOG's natural gas financial price swap contracts at August 1, 2007 with notional volumes expressed in MMBtud and prices in dollars per MMBtu ($/MMBtu).

Natural Gas Financial Price Swap Contracts

     

Weighted

 

Volume

 

Average Price

 

(MMBtud)

 

($/MMBtu)

2007

     

   July (closed)

120,000

 

$    8.84

   August (closed)

120,000

 

8.92

   September

120,000

 

9.00

   October

120,000

 

9.14

   November

120,000

 

9.94

   December

120,000

 

10.70

2008

     

   January

160,000

 

$  9.44

   February

160,000

 

9.44

   March

160,000

 

9.25

   April

160,000

 

8.28

   May

160,000

 

8.21

   June

160,000

 

8.29

   July

160,000

 

8.38

   August

160,000

 

8.46

   September

160,000

 

8.51

   October

160,000

 

8.62

   November

160,000

 

9.07

   December

160,000

 

9.53

-26-

The total fair value of the crude oil financial price swap contracts at June 30, 2007 was a positive $5 million. Presented below is a comprehensive summary of EOG's 2007 crude oil financial price swap contracts at August 1, 2007 with notional volumes expressed in barrels per day (Bbld) and prices in dollars per barrel ($/Bbl).

 

Crude Oil Financial Price Swap Contracts

     

Weighted

 

Volume

 

Average Price

 

(Bbld)

 

($/Bbl)

2007

     

July (closed)

4,000

 

$ 78.28

August

4,000

 

78.16

September

4,000

 

78.03

October

4,000

 

77.91

November

4,000

 

77.75

December

4,000

 

77.57

 

Information Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts, including, among others, statements regarding EOG's future financial position, business strategy, budgets, reserve information, projected levels of production, projected costs and plans and objectives of management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "strategy," "intend," "plan," "target" and "believe" or the negative of those terms or other variations of them or by comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning future operating results, the ability to replace or increase reserves or to increase production, or the ability to generate income or cash flows are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes its expectations reflected in forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will be achieved. Important factors that could cause actual results to differ materially from the expectations reflected in the forward-looking statements include, among others:

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements might not occur. Forward-looking statements speak only as of the date made and EOG undertakes no obligation to update or revise its forward-looking statements, whether as a result of new information, future events or otherwise.

-28-

PART I. FINANCIAL INFORMATION

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
EOG RESOURCES, INC.

 

EOG's exposure to commodity price risk, interest rate risk and foreign currency exchange rate risk is discussed in the Derivative Transactions, Financing, Foreign Currency Exchange Rate Risk and Outlook sections of "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity," on pages 29 through 32 of the Annual Report on Form 10-K for the year ended December 31, 2006, filed on February 28, 2007.

 

ITEM 4. CONTROLS AND PROCEDURES
EOG RESOURCES, INC.

 

Disclosure Controls and Procedures. EOG's management, with the participation of EOG's principal executive officer and principal financial officer, evaluated the effectiveness of EOG's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of the end of the period covered by this Quarterly Report on Form 10-Q (Evaluation Date). Based on this evaluation, the principal executive officer and principal financial officer have concluded that EOG's disclosure controls and procedures were effective as of the Evaluation Date to ensure that information that is required to be disclosed by EOG in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms and (ii) accumulated and communicated to EOG's management as appropriate to allow timely decisions regarding required disclosure.

Internal Control Over Financial Reporting. There were no changes in EOG's internal control over financial reporting that occurred during the period covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting.

-29-

 

PART II. OTHER INFORMATION

EOG RESOURCES, INC.

ITEM 1. LEGAL PROCEEDINGS

    See Part I, Item 1, Note 9 to Consolidated Financial Statements, which is incorporated herein by reference.

 

ITEM 1A. RISK FACTORS

    There have been no material changes from the risk factors previously disclosed in Item 1A "Risk Factors" of EOG's Annual Report on Form 10-K for the year ended December 31, 2006.

 

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

             

(c)

   
   

(a)

       

Total Number of

 

(d)

   

Total

   

(b)

 

Shares Purchased as

 

Maximum Number

   

Number of

   

Average

 

Part of Publicly

 

of Shares that May Yet

   

Shares

   

Price Paid

 

Announced Plans or

 

Be Purchased Under

Period

 

Purchased(1)

   

Per Share

 

Programs

 

The Plans or Programs(2)

                   

April 1, 2007 - April 30, 2007

 

182

 

$

73.44

 

-

 

6,386,200

May 1, 2007 - May 31, 2007

 

-

   

-

 

-

 

6,386,200

June 1, 2007 - June 30, 2007

-

-

-

6,386,200

Total

 

182

   

73.44

 

-

   

(1) Represents 182 shares that were withheld by or returned to EOG to satisfy tax withholding obligations that arose upon the exercise of employee stock options or the vesting
      of restricted stock or units.
(2) In September 2001, EOG announced that its Board of Directors authorized the repurchase of up to 10,000,000 shares of EOG's common stock.

-30-

 

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

The Annual Meeting of Shareholders of EOG Resources, Inc. was held on April 24, 2007, in Houston, Texas, for the purpose of electing a board of directors and ratifying the appointment of auditors. Proxies for the meeting were solicited pursuant to Section 14(a) of the Securities Exchange Act of 1934, and there was no solicitation in opposition to management's solicitations.

(a) Each of the directors nominated by the Board and listed in the proxy statement was elected with votes as follows:

   

Shares

 

Shares

Nominee

 

For

 

Withheld

         

George A. Alcorn

 

220,920,462

 

3,443,794

Charles R. Crisp

 

220,962,051

 

3,402,205

Mark G. Papa

 

219,833,565

 

4,530,692

Edmund P. Segner, III (1)

 

211,442,073

 

12,922,183

William D. Stevens

 

220,984,475

 

3,379,782

H. Leighton Steward

 

220,988,035

 

3,376,222

Donald F. Textor

 

209,987,868

 

14,376,389

Frank G. Wisner

 

220,955,315

 

3,408,941

(1) EOG has approved Mr. Segner's request for "Company-approved retirement prior to age 62" effective November 30, 2008.
      Effective June 30, 2007, Mr. Segner remains an officer, but is no longer principal financial officer, an executive officer, or a
      director of EOG.

(b) The ratification of the appointment of Deloitte & Touche LLP, independent registered public accountants, as EOG's independent auditors for the year ending December 31, 2007 was ratified by the following vote: 223,141,463 shares for; 63,492 shares against; and 1,159,301 shares abstaining.

 

ITEM 6. Exhibits

*10.1 -

Second Amendment, dated May 18, 2007, to Revolving Credit Agreement, dated June 28, 2005, among EOG Resources, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto.

   

*31.1 -

Section 302 Certification of Periodic Report of Chief Executive Officer.

   

*31.2 -

Section 302 Certification of Periodic Report of Principal Financial Officer.

   

*32.1 -

Section 906 Certification of Periodic Report of Chief Executive Officer.

   

*32.2 -

Section 906 Certification of Periodic Report of Principal Financial Officer.

   

*Exhibits filed herewith

-31-

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

   

EOG RESOURCES, INC.

   

(Registrant)

     
     
     

Date: August 2, 2007

By:

/s/ TIMOTHY K. DRIGGERS
Timothy K. Driggers
Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)

-32-

 

EXHIBIT INDEX

 

Exhibit No.

Description

   

*10.1 -

Second Amendment, dated May 18, 2007, to Revolving Credit Agreement, dated June 28, 2005, among EOG Resources, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto.

   

*31.1 -

Section 302 Certification of Periodic Report of Chief Executive Officer.

   

*31.2 -

Section 302 Certification of Periodic Report of Principal Financial Officer.

   

*32.1 -

Section 906 Certification of Periodic Report of Chief Executive Officer.

   

*32.2 -

Section 906 Certification of Periodic Report of Principal Financial Officer.

*Exhibits filed herewith

-33-