10-Q 1 eog3qtr10-q.htm EOG FORM 10-Q


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 September 30, 2009

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) (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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
                                                      Large accelerated filer x   Accelerated filer o   Non-accelerated filer o   Smaller reporting company 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 registrant's classes of common stock, as of the latest practicable date.

Title of each class

 

Number of shares

Common Stock, par value $0.01 per share

 

252,355,378 (as of November 2, 2009)


EOG RESOURCES, INC.

TABLE OF CONTENTS

 

 

PART I.

FINANCIAL INFORMATION

Page No.

       
 

ITEM 1.

Financial Statements (Unaudited)

 
       
   

Consolidated Statements of Income - Three Months Ended September 30, 2009 and 2008 and Nine Months Ended September 30, 2009 and 2008


3

       
   

Consolidated Balance Sheets - September 30, 2009 and December 31, 2008

4

       
   

Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2009 and 2008


5

       
   

Notes to Consolidated Financial Statements

6

       
 

ITEM 2.

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


22

       
 

ITEM 3.

Quantitative and Qualitative Disclosures About Market Risk

39

       
 

ITEM 4.

Controls and Procedures

39

       

PART II.

OTHER INFORMATION

 

 

ITEM 1.

Legal Proceedings

40

       
 

ITEM 2.

Unregistered Sales of Equity Securities and Use of Proceeds

40

       
 

ITEM 6.

Exhibits

41

       

SIGNATURES

 

42

       

EXHIBIT INDEX

 

43

 

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

 

Nine Months Ended

   

September 30,

 

September 30,

   

2009

 

2008

 

2009

 

2008

                 
                 

Net Operating Revenues

               
 

Natural Gas

$

450,304 

$

1,259,130 

$

1,477,926

$

3,637,325

 

Crude Oil, Condensate and Natural Gas Liquids

 

398,806 

 

574,402 

 

886,268

 

1,494,043

 

Gains on Mark-to-Market Commodity

               
 

   Derivative Contracts

 

20,877 

 

1,381,733 

 

405,830

 

69,067

 

Gathering, Processing and Marketing

 

134,553 

 

51,145 

 

249,679

 

150,907

 

Other, Net

 

2,309 

 

(2,524)

 

6,394

 

142,074

   

Total

 

1,006,849 

 

3,263,886 

 

3,026,097

 

5,493,416

                   

Operating Expenses

               
 

Lease and Well

 

142,183 

 

142,238 

 

422,288

 

396,294

 

Transportation Costs

 

70,971 

 

78,136 

 

205,844

 

203,205

 

Gathering and Processing Costs

 

13,318 

 

9,104 

 

44,552

 

26,385

 

Exploration Costs

 

44,910 

 

37,943 

 

128,840

 

145,397

 

Dry Hole Costs

 

3,016 

 

12,849 

 

39,653

 

28,062

 

Impairments

 

69,404 

 

32,142 

 

181,921

 

113,591

 

Marketing Costs

 

131,816 

 

44,380 

 

237,819

 

140,411

 

Depreciation, Depletion and Amortization

 

385,330 

 

346,247 

 

1,150,251

 

958,740

 

General and Administrative

 

62,775 

 

70,893 

 

179,481

 

185,459

 

Taxes Other Than Income

 

47,823 

 

97,771 

 

118,715

 

279,866

   

Total

 

971,546 

 

871,703 

 

2,709,364

 

2,477,410

                   

Operating Income

 

35,303 

 

2,392,183 

 

316,733

 

3,016,006

Other Income (Expense), Net

 

(339)

 

13,864 

 

2,637

 

28,756

Income Before Interest Expense and Income Taxes

 

34,964 

 

2,406,047 

 

319,370

 

3,044,762

Interest Expense, Net

 

30,407 

 

12,095 

 

73,594

 

33,315

Income Before Income Taxes

 

4,557 

 

2,393,952 

 

245,776

 

3,011,447

Income Tax Provision

 

361 

 

837,667 

 

99,576

 

1,036,000

Net Income

 

4,196 

 

1,556,285 

 

146,200

 

1,975,447

Preferred Stock Dividends

 

 

 

-

 

443

Net Income Available to Common Stockholders

$

4,196 

$

1,556,285 

$

146,200

$

1,975,004

                 

Net Income Per Share Available to Common
   Stockholders

               
 

Basic

$

0.02

$

6.30 

$

0.59

$

8.02

 

Diluted

$

0.02

$

6.20 

$

0.58

$

7.88

                   

Dividends Declared per Common Share

$

0.145 

$

0.135 

$

0.435

$

0.375

                 

Average Number of Common Shares

               
 

Basic

 

249,535 

 

247,155 

 

248,647

 

246,343

 

Diluted

 

252,422 

 

250,930 

 

251,288

 

250,765

                   

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)

   

September 30,

 

December 31,

   

2009

 

2008

ASSETS

Current Assets

       
 

Cash and Cash Equivalents

$

608,511 

$

331,311 

 

Accounts Receivable, Net

 

604,260 

 

722,695 

 

Inventories

 

240,230 

 

187,970 

 

Assets from Price Risk Management Activities

 

290,536 

 

779,483 

 

Income Taxes Receivable

 

27,134 

 

27,053 

 

Other

 

61,018 

 

59,939 

   

Total

 

1,831,689 

 

2,108,451 

             

Property, Plant and Equipment

       
 

Oil and Gas Properties (Successful Efforts Method)

 

23,515,362 

 

20,803,629 

 

Other Property, Plant and Equipment

 

1,261,505 

 

1,057,888 

   

Total Property, Plant and Equipment

 

24,776,867 

 

21,861,517 

 

Less: Accumulated Depreciation, Depletion and Amortization

 

(9,524,312)

 

(8,204,215)

   

Total Property, Plant and Equipment, Net

 

15,252,555 

 

13,657,302 

Other Assets

 

137,049 

 

185,473 

Total Assets

$

17,221,293 

$

15,951,226 

             
             

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities

       
 

Accounts Payable

$

783,764 

$

1,122,209 

 

Accrued Taxes Payable

 

86,334 

 

86,265 

 

Dividends Payable

 

36,255 

 

33,461 

 

Liabilities from Price Risk Management Activities

 

16,370 

 

4,429 

 

Deferred Income Taxes

 

114,304 

 

368,231 

 

Current Portion of Long-Term Debt

 

37,000 

 

37,000 

 

Other

 

127,124 

 

113,321 

   

Total

 

1,201,151 

 

1,764,916 

             

Long-Term Debt

 

2,760,000 

 

1,860,000 

Other Liabilities

 

609,150 

 

498,291 

Deferred Income Taxes

 

3,133,252 

 

2,813,522 

Commitments and Contingencies (Note 9)

       
             

Stockholders' Equity

       

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

       
 

252,421,628 Shares Issued at September 30, 2009 and 249,758,577

       
 

Shares Issued at December 31, 2008

 

202,524 

 

202,498 

Additional Paid in Capital

 

528,544 

 

323,805 

Accumulated Other Comprehensive Income

 

291,627 

 

27,787 

Retained Earnings

 

8,502,940 

 

8,466,143 

Common Stock Held in Treasury, 128,898 Shares at September 30, 2009

       

   and 126,911 Shares at December 31, 2008

 

(7,895)

 

(5,736)

   

Total Stockholders' Equity

 

9,517,740 

 

9,014,497 

Total Liabilities and Stockholders' Equity

$

17,221,293 

$

15,951,226 

         

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

-4-

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

   

Nine Months Ended

   

September 30,

   

2009

 

2008

Cash Flows From Operating Activities

       

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

       
 

Net Income

$

146,200 

$

1,975,447 

 

Items Not Requiring (Providing) Cash

       
   

Depreciation, Depletion and Amortization

 

1,150,251 

 

958,740 

   

Impairments

 

181,921 

 

113,591 

   

Stock-Based Compensation Expenses

 

74,532 

 

76,344 

   

Deferred Income Taxes

 

39,793 

 

790,699 

   

Other, Net

 

2,738 

 

(135,325)

 

Dry Hole Costs

 

39,653 

 

28,062 

 

Mark-to-Market Commodity Derivative Contracts

       
   

Total Gains

 

(405,830)

 

(69,067)

   

Realized Gains (Losses)

 

986,980 

 

(237,326)

 

Other, Net

 

9,385 

 

14,390 

 

Changes in Components of Working Capital and Other Assets and Liabilities

       
   

Accounts Receivable

 

119,099 

 

(219,947)

   

Inventories

 

(23,592)

 

(45,354)

   

Accounts Payable

 

(361,698)

 

221,449 

   

Accrued Taxes Payable

 

(17,955)

 

135,747 

   

Other Assets

 

(4,255)

 

(18,756)

   

Other Liabilities

 

9,357 

 

(3,397)

 

Changes in Components of Working Capital Associated with

       
   

Investing and Financing Activities

 

147,097 

 

14,389 

Net Cash Provided by Operating Activities

 

2,093,676 

 

3,599,686 

Investing Cash Flows

       
 

Additions to Oil and Gas Properties

 

(2,267,884)

 

(3,532,343)

 

Additions to Other Property, Plant and Equipment

 

(240,614)

 

(320,699)

 

Proceeds from Sales of Assets

 

2,515 

 

369,669 

 

Changes in Components of Working Capital Associated with

       
   

Investing Activities

 

(146,783)

 

(14,501)

 

Other, Net

 

1,405 

 

(1,316)

Net Cash Used in Investing Activities

 

(2,651,361)

 

(3,499,190)

Financing Cash Flows

       
 

Long-Term Debt Borrowings

 

900,000 

 

750,000 

 

Long-Term Debt Repayments

 

 

(38,000)

 

Dividends Paid

 

(105,989)

 

(81,453)

 

Redemptions of Preferred Stock

 

 

(5,395)

 

Excess Tax Benefits from Stock-Based Compensation

 

34,052 

 

69,824 

 

Treasury Stock Purchased

 

(9,888)

 

(11,266)

 

Proceeds from Stock Options Exercised and Employee Stock Purchase Plan

 

13,691 

 

67,414 

 

Debt Issuance Costs

 

(8,887)

 

(6,704)

 

Other, Net

 

(314)

 

112 

Net Cash Provided by Financing Activities

 

822,665 

 

744,532 

Effect of Exchange Rate Changes on Cash

 

12,220 

 

(13,282)

Increase in Cash and Cash Equivalents

 

277,200 

 

831,746 

Cash and Cash Equivalents at Beginning of Period

 

331,311 

 

54,231 

Cash and Cash Equivalents at End of Period

$

608,511 

$

885,977 

         

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., together with its subsidiaries (collectively, EOG), included herein have been prepared by management without audit pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC). 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 presented. Certain information and notes normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such rules and regulations. However, management believes that the disclosures included either on the face of the financial statements or in these notes are sufficient to make the interim 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, 2008, filed on February 25, 2009 (EOG's 2008 Annual Report).

The preparation of financial statements in conformity with GAAP 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 nine months ended September 30, 2009 are not necessarily indicative of the results to be expected for the full year.

Gathering, processing and marketing revenues represent sales of third-party natural gas, crude oil and natural gas liquids as well as gathering fees associated with gathering third-party natural gas. EOG's gathering, processing and marketing revenues were previously presented net of related purchase and transportation costs in Net Operating Revenues - Other, Net. In addition, certain other expenses previously included in Lease and Well have been reclassified to Gathering and Processing Costs. The effect of these reclassifications on the three and nine months ended September 30, 2008 presentation in the Consolidated Statements of Income was to increase total net operating revenues and total operating expenses by $44 million and $140 million, respectively. These changes did not impact previously reported operating income, net income or cash flows.

Recently Issued Accounting Standards and Developments. In June 2009, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 168, "The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162" (SFAS No. 168), which establishes the FASB Accounting Standards Codification (ASC) as the source of authoritative accounting principles recognized by the FASB to be applied in the preparation of financial statements in conformity with GAAP. SFAS No. 168 explicitly recognizes rules and interpretive releases of the SEC under federal securities laws as authoritative GAAP for SEC registrants. The ASC became effective for interim and annual periods ending after September 15, 2009. EOG has modified its disclosures to appropriately update references to GAAP included in this Quarterly Report on Form 10-Q.

Effective June 30, 2009, EOG adopted the interim disclosure provisions of the Financial Instruments Topic of the ASC. The new interim disclosure provisions were issued by the FASB in April 2009 and require disclosures about fair value of financial instruments for interim reporting periods as well as in annual financial statements. The new interim disclosure provisions became effective for interim periods ending after June 15, 2009. See Note 11.

-6-

Effective April 1, 2009, EOG adopted the provisions of the Subsequent Events Topic of the ASC (ASC Topic 855). ASC Topic 855 clarifies that management must evaluate, as of each reporting period, events or transactions that occur after the balance sheet date and through the date that the financial statements are issued or available to be issued, both for interim and annual reporting periods. The provisions of ASC Topic 855 became effective prospectively for interim and annual reporting periods ending after June 15, 2009. Based on an analysis of subsequent events through November 5, 2009, EOG has determined that there are no subsequent events which require recognition or disclosure in these consolidated financial statements.

Effective January 1, 2009, EOG adopted the provisions of the Business Combinations Topic of the ASC (ASC Topic 805). ASC Topic 805 establishes principles and requirements for how the acquirer recognizes and measures in the financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquired, as well as determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. In April 2009, the FASB amended the provisions of ASC Topic 805 related to recognition, measurement and disclosure of assets and liabilities assumed in a business combination that arise from contingencies. The amended provisions of ASC Topic 805 became effective January 1, 2009.

Effective January 1, 2009, EOG adopted the expanded disclosure provisions of the Derivatives and Hedging Topic of the ASC (ASC Topic 815). The new provisions, which were issued by the FASB in March 2008, do not expand the scope of ASC Topic 815, but require expanded disclosures about an entity's derivative instruments and hedging activities. The expanded disclosure provisions became effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. See Note 13.

The Fair Value Measurements and Disclosures Topic of the ASC (ASC Topic 820) was issued by the FASB in September 2006 and provides a definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC Topic 820 also establishes a fair value hierarchy and requires disclosure of fair value measurements within that hierarchy. In February 2008, the FASB amended ASC Topic 820 to delay the effective date of the measurement and disclosure provisions for all nonrecurring fair value measurements of nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008. EOG partially adopted ASC Topic 820 effective January 1, 2008 and adopted the provisions related to nonfinancial assets and liabilities effective January 1, 2009. See Note 12.

In December 2008, the SEC released a final rule, "Modernization of Oil and Gas Reporting," which amends the oil and gas reporting requirements. The key revisions to the reporting requirements include: using a 12-month average price to determine reserves; including nontraditional resources in reserves if they are intended to be upgraded to synthetic oil and gas; ability to use new technologies to determine and estimate reserves; and permitting the disclosure of probable and possible reserves. In addition, the final rule includes the requirements to report the independence and qualifications of the reserve preparer or auditor; to file a report as an exhibit when a third party is relied upon to prepare reserve estimates or conduct reserve audits; and to disclose the development of any proved undeveloped reserves (PUDs), including the total quantity of PUDs at year-end, material changes to PUDs during the year, investments and progress toward the development of PUDs and an explanation of the reasons why material concentrations of PUDs have remained undeveloped for five years or more after disclosure as PUDs. The accounting changes resulting from changes in definitions and pricing assumptions should be treated as a change in accounting principle that is inseparable from a change in accounting estimate, which is to be applied prospectively. The final rule is effective for annual reports for fiscal years ending on or after December 31, 2009. Early adoption is not permitted. EOG is assessing the impact that this final rule will have on its consolidated financial statements.

-7-

2. Stock-Based Compensation

As more fully discussed in Note 6 to the Consolidated Financial Statements included in EOG's 2008 Annual Report, EOG maintains various stock-based compensation plans. 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

 

Nine Months Ended

   

September 30,

 

September 30,

   

2009

 

2008

 

2009

 

2008

                 

Lease and Well

$

6.3

$

5.7

$

17.7

$

14.2

Exploration Costs

 

5.1

 

5.1

 

15.2

 

13.5

General and Administrative

 

14.6

 

20.9

 

41.6

 

48.6

   Total

$

26.0

$

31.7

$

74.5

$

76.3

                 

The EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) provides for grants of stock options, stock-settled stock appreciation rights (SARs), restricted stock, restricted stock units and other stock-based awards, up to an aggregate maximum of 6.0 million shares of common stock, plus shares underlying forfeited or cancelled grants under the prior stock plans. At September 30, 2009, approximately 2.2 million common shares remained available for grant under the 2008 Plan. Effective with the adoption of the 2008 Plan, EOG's policy is to issue shares related to the 2008 Plan from previously authorized unissued shares.

Stock Options and Stock Appreciation Rights and Employee Stock Purchase Plan. The fair value of all Employee Stock Purchase Plan (ESPP) grants is estimated using the Black-Scholes-Merton model. Certain of EOG's stock options granted in 2005 contain a feature that limits the potential gain that can be realized by requiring vested options to be exercised if the market price of EOG's common stock 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. The fair value of stock option grants not containing the Capped Option feature and SAR grants was estimated using the Hull-White II binomial option pricing model. Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $10.3 million and $11.1 million during the three months ended September 30, 2009 and 2008, respectively, and $29.4 million and $28.9 million during the nine months ended September 30, 2009 and 2008, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants during the nine-month periods ended September 30, 2009 and 2008 are as follows:

     

Stock Options/SARs

   

ESPP

     

Nine Months Ended

   

Nine Months Ended

     

September 30,

   

September 30,

     

2009

   

2008

   

2009

   

2008

                         

Weighted Average Fair Value of Grants

 

$

30.11   

 

$

32.17   

 

$

25.78   

 

$

27.81   

Expected Volatility

   

41.92%

   

38.40%

   

78.89%

   

36.17%

Risk-Free Interest Rate

   

1.42%

   

2.55%

   

0.25%

   

2.79%

Dividend Yield

   

0.7%

   

0.6%

   

1.0%

   

0.5%

Expected Life

   

5.5 yrs

   

5.3 yrs

   

0.5 yrs

   

0.5 yrs

                         

-8-

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, SAR and ESPP grants.

EOG suspended the ESPP, effective for the July 1, 2009 - December 31, 2009 offering period, due to an insufficient number of shares remaining available under the ESPP. Subject to stockholder approval of an amendment to the ESPP to increase the shares available under the ESPP at the 2010 Annual Meeting of Stockholders, EOG expects to resume the ESPP for the January 1, 2010 - June 30, 2010 offering period. The ESPP was originally approved by EOG's stockholders in 2001.

The following table sets forth the stock option and SAR transactions for the nine-month periods ended September 30, 2009 and 2008 (stock options and SARs in thousands):

 

Nine Months Ended

   

Nine Months Ended

 

September 30, 2009

   

September 30, 2008

       

Weighted

       

Weighted

 

Number of

   

Average

   

Number of

 

Average

 

Stock Options/SARs

   

Grant Price

   

Stock Options/SARs

 

Grant Price

                   

Outstanding at January 1

7,802 

 

$

52.56

   

9,373 

$

41.04

Granted

1,251 

   

80.87

   

1,211 

 

90.70

Exercised (1)

(387)

   

41.67

   

(2,544)

 

27.99

Forfeited

(87)

   

73.85

   

(116)

 

65.67

Outstanding at September 30 (2)

8,579 

   

56.96

   

7,924 

 

52.46

                   

Vested or Expected to Vest (3)

8,336 

   

56.28

   

7,685 

 

51.70

                   

Exercisable at September 30 (4)

5,603 

44.69

4,759 

36.99

(1) The total intrinsic value of stock options/SARs exercised for the nine months ended September 30, 2009 and 2008 was $12 million and $214 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 stock options/SARs.
(2) The total intrinsic value of stock options/SARs outstanding at September 30, 2009 and 2008 was $236 million and $295 million, respectively. At September 30, 2009
      and 2008, the weighted average remaining contractual life was 4.3 years and 4.8 years, respectively.
(3) The total intrinsic value of stock options/SARs vested or expected to vest at September 30, 2009 and 2008 was $235 million and $292 million, respectively. At
      September 30, 2009 and 2008, the weighted average remaining contractual life was 4.3 years and 4.7 years, respectively.
(4) The total intrinsic value of stock options/SARs exercisable at September 30, 2009 and 2008 was $220 million and $250 million, respectively. At September 30, 2009
      and 2008, the weighted average remaining contractual life was 3.5 years and 4.1 years, respectively.

At September 30, 2009, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $85.8 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.9 years.

-9-

Restricted Stock and Restricted Stock Units. Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them. Stock-based compensation expense related to restricted stock and restricted stock units totaled $15.7 million and $20.6 million for the three months ended September 30, 2009 and 2008, respectively, and $45.1 million and $47.4 million for the nine months ended September 30, 2009 and 2008, respectively.

The following table sets forth the restricted stock and restricted stock unit transactions for the nine-month periods ended September 30, 2009 and 2008 (shares and units in thousands):

 

Nine Months Ended

 

Nine Months Ended

 

September 30, 2009

 

September 30, 2008

     

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

3,048 

$

70.24

 

3,000 

$

50.61

Granted

1,184 

 

62.88

 

788 

 

106.88

Released (1)

(500)

 

28.16

 

(330)

 

20.97

Forfeited

(47)

 

78.06

 

(71)

 

69.04

Outstanding at September 30 (2)

3,685 

 

73.49

 

3,387 

 

66.19

               

(1) The total intrinsic value of restricted stock and restricted stock units released for the nine months ended September 30, 2009 and 2008
      was $32 million and $33 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date
      restricted stock and restricted stock units are released.
(2) The total intrinsic value of restricted stock and restricted stock units outstanding at September 30, 2009 and 2008 was $308 million and
      $303 million, respectively.

At September 30, 2009, unrecognized compensation expense related to non-vested restricted stock and restricted stock units totaled $149 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 3.2 years.

-10-

3. Earnings Per Share

The following table sets forth the computation of Net Income Per Share Available to Common Stockholders for the three-month and nine-month periods ended September 30, 2009 and 2008 (in thousands, except per share data):

   

Three Months Ended

 

Nine Months Ended

   

September 30,

 

September 30,

   

2009

 

2008

 

2009

 

2008

                 

Numerator for Basic and Diluted Earnings Per Share -

               
 

Net Income

$

4,196

$

1,556,285

$

146,200

$

1,975,447

 

Less: Preferred Stock Dividends

 

-

 

-

 

-

 

443

 

Net Income Available to Common

               
 

   Stockholders

$

4,196

$

1,556,285

$

146,200

$

1,975,004

                 

Denominator for Basic Earnings Per Share -

               
 

Weighted Average Shares

 

249,535

 

247,155

 

248,647

 

246,343

Potential Dilutive Common Shares -

               
 

Stock Options/SARs

 

1,718

 

2,409

 

1,558

 

2,927

 

Restricted Stock and Restricted Stock Units

 

1,169

 

1,366

 

1,083

 

1,495

Denominator for Diluted Earnings Per Share -

               
 

Adjusted Diluted Weighted Average Shares

 

252,422

 

250,930

 

251,288

 

250,765

                 

Net Income Per Share Available to Common

               

   Stockholders

               
 

Basic

$

0.02

$

6.30

$

0.59

$

8.02

 

Diluted

$

0.02

$

6.20

$

0.58

$

7.88

                   

The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive. The excluded stock options and SARs totaled 2.4 million and 40,800 for the three months ended September 30, 2009 and 2008, respectively, and 2.5 million and 21,170 for the nine months ended September 30, 2009 and 2008, respectively.

4. Supplemental Cash Flow Information

Cash paid for interest and income taxes for the nine-month periods ended September 30, 2009 and 2008 was as follows (in thousands):

   

Nine Months Ended

   

September 30,

   

2009

 

2008

         

Interest

$

54,179

$

46,309

Income Taxes, Net of Refunds Received

$

45,823

$

76,412

Non-cash investing and financing activities for the nine months ended September 30, 2009 included the issuance of 1,450,000 shares of EOG common stock valued at $89.6 million at the transaction closing date in connection with EOG's purchase of certain proved developed and undeveloped reserves and unproved acreage (see Note 14).

-11-

5. Comprehensive Income

The following table presents the components of EOG's comprehensive income for the three-month and nine-month periods ended September 30, 2009 and 2008 (in thousands):

   

Three Months Ended

 

Nine Months Ended

   

September 30,

 

September 30,

   

2009

 

2008

 

2009

 

2008

                 

Comprehensive Income

               
 

Net Income

$

4,196 

$

1,556,285 

$

146,200 

$

1,975,447 

 

Other Comprehensive Income (Loss)

               
   

Foreign Currency Translation Adjustments

 

161,044 

 

(87,094)

 

260,007 

 

(148,371)

   

Foreign Currency Swap Transaction

 

504 

 

(1,533)

 

5,470 

 

(4,502)

   

Income Tax Related to Foreign Currency

               
   

   Swap Transaction

 

(446)

 

392 

 

(1,704)

 

1,137 

   

Defined Benefit Pension and

               
   

   Postretirement Plans

 

34 

 

35 

 

104 

 

105 

   

Income Tax Related to Defined Benefit

               
   

   Pension and Postretirement Plans

 

(12)

 

(13)

 

(37)

 

(89)

     

Total

$

165,320 

$

1,468,072 

$

410,040 

$

1,823,727 

                       

6. Segment Information

Selected financial information by reportable segment is presented below for the three-month and nine-month periods ended September 30, 2009 and 2008 (in thousands):

   

Three Months Ended

   

Nine Months Ended

 
   

September 30,

   

September 30,

 
   

2009

 

2008

   

2009

 

2008

 
                     

Net Operating Revenues

                   
 

United States

$

849,338 

$

2,925,237 

 

$

2,571,956 

$

4,527,278 

 
 

Canada

 

92,678 

 

206,237 

   

283,722 

 

591,752 

 
 

Trinidad

 

60,353 

 

118,425 

   

151,765 

 

333,440 

 
 

Other International (1)

 

4,480 

 

13,987 

   

18,654 

 

40,946 

 
   

Total

$

1,006,849 

$

3,263,886 

 

$

3,026,097 

$

5,493,416 

 
                         

Operating Income (Loss)

                   
 

United States

$

26,971 

$

2,196,363 

 

$

282,601 

$

2,491,392 

 
 

Canada

 

(18,883)

 

101,186 

   

(27,281)

 

276,509 

 
 

Trinidad

 

38,370 

 

95,946 

   

89,640 

 

248,507 

 
 

Other International (1)

 

(11,155)

 

(1,312)

   

(28,227)

 

(402)

 
   

Total

 

35,303 

 

2,392,183 

   

316,733 

 

3,016,006 

 
                         

Reconciling Items

                   
 

Other Income (Expense), Net

 

(339)

 

13,864 

   

2,637 

 

28,756 

 
 

Interest Expense, Net

 

30,407 

 

12,095 

   

73,594 

 

33,315 

 
   

Income Before Income Taxes

$

4,557 

$

2,393,952 

 

$

245,776 

$

3,011,447 

 
                         

(1) Other International includes EOG's United Kingdom operations and, effective July 1, 2008, EOG's China operations.

-12-

Total assets by reportable segment are presented below at September 30, 2009 and December 31, 2008 (in thousands):

   

At

   

At

   

September 30,

   

December 31,

   

2009

   

2008

Total Assets

         
 

United States

$

13,376,603

 

$

12,668,763

 

Canada

 

2,803,808

   

2,421,979

 

Trinidad

 

812,648

   

735,387

 

Other International (1)

 

228,234

   

125,097

   

Total

$

17,221,293

 

$

15,951,226

               

(1) Other International includes EOG's United Kingdom operations and, effective July 1, 2008, EOG's China operations.

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 property, plant and equipment for the nine-month periods ended September 30, 2009 and 2008 (in thousands):

Nine Months Ended

September 30,

2009

2008

Carrying Amount at Beginning of Period

$

368,159 

$

211,124 

Liabilities Incurred

38,817 

31,312 

Liabilities Settled

(13,701)

(18,734)

Accretion

16,285 

10,262 

Revisions (1)

13,827 

131,098 

Foreign Currency Translations

10,462 

(4,297)

Carrying Amount at End of Period

$

433,849 

$

360,765 

Current Portion

$

22,923 

$

17,619 

Noncurrent Portion

$

410,926 

$

343,146 

(1) Revisions to asset retirement obligations primarily reflect changes in abandonment cost estimates.

The current and noncurrent portions of EOG's asset retirement obligations are included in Current Liabilities - Other and Other Liabilities, respectively, on the Consolidated Balance Sheets.

-13-

8. Suspended Well Costs

EOG's net changes in suspended well costs for the nine-month period ended September 30, 2009 are presented below (in thousands):

   

Nine Months

 
   

Ended

 
   

September 30,

 
   

2009

 
       

Balance at December 31, 2008

$

85,255 

 
 

Additions Pending the Determination of Proved Reserves

 

85,047 

 
 

Reclassifications to Proved Properties

 

(22,848)

 
 

Charged to Dry Hole Costs

 

(11,503)

 
 

Foreign Currency Translations

 

7,873 

 

Balance at September 30, 2009

$

143,824 

 
       

The following table provides an aging of suspended well costs at September 30, 2009 (in thousands, except well count):

   

At

 
   

September 30,

 
   

2009

 
       

Capitalized exploratory well costs that have been

     
 

capitalized for a period less than one year

$

77,811

 

Capitalized exploratory well costs that have been

     
 

capitalized for a period greater than one year

 

66,013

 (1)

 

   Total

$

143,824

 

Number of exploratory wells that have been

     
 

capitalized for a period greater than one year

 

4

 
         

(1) Consists of costs related to three shale projects in British Columbia, Canada (B.C.) ($44 million)
      and an outside operated, offshore Central North Sea project in the United Kingdom (U.K.) ($22 million).
      In the B.C. shale projects, further reserve evaluations will be made based on drilling and completion
      activities during 2009 and 2010. In addition, EOG is evaluating infrastructure alternatives for the B.C.
      shale projects. In the Central North Sea project, the operator expects to receive approval in late 2010 of
      the field development plan submitted to the U.K. Department of Energy and Climate Change during
      the fourth quarter of 2008. EOG is currently focused on securing an export route for production from the
      Central North Sea project.

9. Commitments and Contingencies

There are currently various suits and claims pending against EOG that have arisen in the ordinary course of EOG's business, including contract disputes, personal injury and property damage claims and title disputes. While the ultimate outcome and impact on EOG cannot be predicted with certainty, management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material adverse effect on EOG's consolidated financial position, results of operations or cash flow. EOG records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

-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 nine months ended September 30, 2009 and 2008, EOG's total costs recognized for these pension plans were $15.2 million and $14.4 million, respectively.

In addition, as more fully discussed in Note 6 to Consolidated Financial Statements in EOG's 2008 Annual Report, EOG's Canadian, Trinidadian and United Kingdom subsidiaries maintain various pension and savings plans for most of their respective employees. For the nine months ended September 30, 2009 and 2008, combined contributions to these pension and savings plans were $1.8 million and $1.9 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 nine months ended September 30, 2009, EOG's total contributions to these plans amounted to $97,000. The net periodic benefit costs recognized for these plans were $0.6 million and $0.5 million for the nine months ended September 30, 2009 and 2008, respectively.

11. Long-Term Debt and Common Stock

Long-Term Debt. EOG utilizes commercial paper and short-term borrowings from uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes. EOG had no outstanding borrowings from commercial paper or uncommitted credit facilities at September 30, 2009. The weighted average interest rates for commercial paper and uncommitted credit facility borrowings for the nine months ended September 30, 2009 were 0.98% and 1.07%, respectively.

On May 21, 2009, EOG completed its public offering of $900 million aggregate principal amount of 5.625% Senior Notes due 2019 (Notes). Interest on the Notes is payable semi-annually in arrears on June 1 and December 1 of each year, beginning December 1, 2009. Net proceeds from the offering of approximately $891 million were used for general corporate purposes, including repayment of outstanding commercial paper borrowings.

EOG currently has a $1.0 billion unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders. The Agreement matures on June 28, 2012. At September 30, 2009, 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 the London InterBank Offering Rate plus an applicable margin (Eurodollar rate) or the base rate of the Agreement's administrative agent. At September 30, 2009, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 0.44% and 3.25%, respectively.

On May 11, 2009, EOG Resources Trinidad Limited, a wholly owned foreign subsidiary of EOG, amended its 3-year, $75 million Revolving Credit Agreement (Credit Agreement) to extend the scheduled maturity date of the remaining outstanding balance of $37 million from May 12, 2009 to May 12, 2010. 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. The applicable Eurodollar rate at September 30, 2009 was 2.75%. The weighted average Eurodollar rate for the amount outstanding during the first nine months of 2009 was 2.80%.

At September 30, 2009 and December 31, 2008, EOG had outstanding $2,797 million and $1,897 million, respectively, of long-term debt, which had estimated fair values of approximately $3,085 million and $1,933 million, respectively. The estimated fair value of long-term debt was based upon quoted market prices and, where such quotes were not available, upon interest rates available to EOG at period-end.

Common Stock. On February 4, 2009, EOG's Board of Directors increased the quarterly cash dividend on EOG's common stock from the previous $0.135 per share to $0.145 per share effective with the dividend paid on April 30, 2009 to record holders as of April 16, 2009.

-15-

On October 7, 2009, EOG entered into an amendment (Amendment) to the Rights Agreement, dated as of February 14, 2000, as amended, by and between EOG and Computershare Trust Company, N.A., as the rights agent (Rights Agreement). The Amendment modifies the definition of "Qualified Institutional Investor" set forth in Section 1 of the Rights Agreement, specifically to delete from clause (A) of the exception to such definition the requirement that a person shall, subsequent to December 31, 2004, continuously beneficially own greater than five percent of the outstanding shares of EOG's common stock prior to the time of determination of such person's "Qualified Institutional Investor" status. Under the Rights Agreement, a person described in Rule 13d-l(b)(1) promulgated under the Securities Exchange Act of 1934 who is eligible to report beneficial ownership of EOG's common stock on Schedule 13G and who beneficially owns 15% or greater of EOG's outstanding common stock will nevertheless be deemed to be a "Qualified Institutional Investor" (and thus not an "Acquiring Person" which would trigger the protections of the Rights Agreement) if such person satisfies the amended exception to the "Qualified Institutional Investor" definition, including the requirement that such person beneficially own less than 30% of EOG's outstanding common stock.

12. Fair Value Measurements

Certain of EOG's financial and nonfinancial assets and liabilities are reported at fair value on the accompanying Consolidated Balance Sheets. Effective January 1, 2008, EOG adopted the provisions of the Fair Value Measurements and Disclosures Topic of the ASC (ASC Topic 820) for its financial assets and liabilities. ASC Topic 820 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. To increase consistency and comparability in fair value measurements and related disclosures, ASC Topic 820 establishes a fair value hierarchy that prioritizes the relative reliability of inputs used in fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy. ASC Topic 820 requires that an entity give consideration to the credit risk of its counterparties, as well as its own credit risk, when measuring financial assets and liabilities at fair value. EOG adopted the provisions of ASC Topic 820 relating to nonfinancial assets and liabilities effective January 1, 2009.

-16-

The following table provides fair value measurement information within the hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at September 30, 2009 and December 31, 2008 (in millions):

     

Fair Value Measurements Using:

     

Quoted

   

Significant

     
     

Prices in

   

Other

   

Significant

     

Active

   

Observable

   

Unobservable

     

Markets

   

Inputs

   

Inputs

     

(Level 1)

   

(Level 2)

   

(Level 3)

At September 30, 2009

                 

Financial Assets:

                 
 

Natural gas collars, price swaps

                 
 

   and basis swaps

 

$

-

 

$

290

 

$

-

                     

Financial Liabilities:

                 
 

Natural gas collars, price swaps

                 
 

   and basis swaps

 

$

-

 

$

41

 

$

-

 

Foreign currency rate swap

 

$

-

 

$

46

 

$

-

                   

At December 31, 2008

                 

Financial Assets:

                 
 

Natural gas collars, price swaps

                 
 

   and basis swaps

 

$

-

 

$

836

 

$

-

                     

Financial Liabilities:

                 
 

Natural gas collars, price swaps

                 
 

   and basis swaps

 

$

-

 

$

12

 

$

-

 

Foreign currency rate swap

 

$

-

 

$

26

 

$

-

                     

The estimated fair value of natural gas collar, price swap and basis swap contracts was based upon forward commodity price curves based on quoted market prices. The estimated fair value of the foreign currency rate swap was based upon forward currency rates.

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of EOG's asset retirement obligations is presented in Note 7.

Proved oil and gas properties with a carrying amount of $50 million were written down to their fair value of $11 million, resulting in a pretax impairment charge of $39 million for the nine months ended September 30, 2009. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include EOG's estimate of future natural gas and crude oil prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data.

-17-

13. Risk Management Activities

Effective January 1, 2009, EOG adopted the expanded disclosure provisions of the Derivatives and Hedging Topic of the ASC. The new provisions require expanded disclosure about an entity's use of derivative instruments and hedging activities and the impact of those instruments on the consolidated financial statements. Information concerning EOG's derivative instruments and hedging activities is presented below.

Commodity Price Risk. As more fully discussed in Note 11 to the Consolidated Financial Statements included in EOG's 2008 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, price swap and basis swap contracts, as a means to manage this price risk. EOG has not designated any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income. The related cash flow impact is reflected as Cash Flows from Operating Activities. In addition to financial transactions, from time to time, 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.

Foreign Currency Exchange Rate Risk. As more fully described in Note 2 to the Consolidated Financial Statements included in EOG's 2008 Annual Report, EOG is party to a foreign currency swap transaction with multiple banks to eliminate any exchange rate impacts that may result from the $150 million principal amount of notes issued by one of EOG's Canadian subsidiaries. EOG accounts for the foreign currency swap transaction using the hedge accounting method, pursuant to the provisions of the Derivatives and Hedging Topic of the ASC. Changes in the fair value of the foreign currency swap do not impact Net Income Available to Common Stockholders. The after-tax net impact of the foreign currency swap transaction was an increase in Other Comprehensive Income of $58,000 and a reduction in Other Comprehensive Income of $1.1 million for the three months ended September 30, 2009 and 2008, respectively, and a $3.8 million increase in Other Comprehensive Income and a $3.4 million reduction in Other Comprehensive Income for the nine months ended September 30, 2009 and 2008, respectively (see Note 5).

-18-

The following table sets forth the amount, on a gross basis, and classification of EOG's outstanding derivative financial instruments at September 30, 2009 and December 31, 2008. Certain amounts may be presented on a net basis in the consolidated financial statements in accordance with master netting arrangements between EOG and the counter-parties to the transactions (in millions):

         

Fair Value at

         

September 30,

   

December 31,

Description

 

Location on Balance Sheet

   

2009

   

2008

                 

Asset Derivatives

               
 

Natural gas collars and price swaps -

               
   

Current portion

 

Assets from Price Risk

           
       

  Management Activities

 

$

324

 

$

786

   

Noncurrent portion

 

Other Assets

 

$

-

 

$

63

                     

Liability Derivatives

               
 

Natural gas basis swaps -

               
   

Current portion

 

Liabilities from Price Risk

           
       

   Management Activities

 

$

50

 

$

11

   

Noncurrent portion

 

Other Liabilities

 

$

25

 

$

14

                     
 

Foreign currency rate swaps -

               
   

Noncurrent portion

 

Other Liabilities

 

$

46

 

$

26

                     

EOG recognized a net gain on the mark-to-market of financial commodity derivative contracts of $406 million and $69 million for the nine months ended September 30, 2009 and 2008, respectively.

Financial Collar Contracts. Presented below is a comprehensive summary of EOG's natural gas financial collar contracts at September 30, 2009. The notional volumes are expressed in million British thermal units per day (MMBtud) and prices are expressed in dollars per million British thermal units ($/MMBtu). The average floor price of EOG's outstanding natural gas financial collar contracts for 2010 was $10.33 per million British thermal units (MMBtu) and the average ceiling price was $12.63 per MMBtu.

Natural Gas Financial Collar Contracts

   

Floor Price

 

Ceiling Price

     

Weighted

   

Weighted

 

Volume

Floor Range

Average Price

 

Ceiling Range

Average Price

 

(MMBtud)

($/MMBtu)

($/MMBtu)

 

($/MMBtu)

($/MMBtu)

2010

           

January

40,000

$11.44 - 11.47

$11.45

 

$13.79 - 13.90

$13.85

February

40,000

11.38 - 11.41

11.40

 

13.75 - 13.85

13.80

March

40,000

11.13 - 11.15

11.14

 

13.50 - 13.60

13.55

April

40,000

9.40 -   9.45

9.42

 

11.55 - 11.65

11.60

May

40,000

9.24 -   9.29

9.26

 

11.41 - 11.55

11.48

June

40,000

9.31 -   9.36

9.34

 

11.49 - 11.60

11.55

             

 

On April 29, 2009, EOG settled its natural gas financial collar contracts with notional volumes of 40,000 MMBtud for the July 1, 2010 - December 31, 2010 period and received proceeds of $26.5 million.

-19-

Financial Price Swap Contracts. Presented below is a comprehensive summary of EOG's natural gas financial price swap contracts at September 30, 2009. The notional volumes are expressed in MMBtud and prices are expressed in $/MMBtu. The average price of EOG's outstanding natural gas financial price swap contracts for 2009 was $9.83 per MMBtu and for 2010 was $10.14 per MMBtu.

Natural Gas Financial Price Swap Contracts

   

Weighted

 

Volume

Average Price

 

(MMBtud)

($/MMBtu)

2009

   

January (closed)

585,000

$10.76

February (closed)

585,000

10.73

March (closed)

585,000

10.50

April (closed)

610,000

9.24

May (closed)

610,000

9.16

June (closed)

710,000

8.53

July (closed)

710,000

8.62

August (closed)

710,000

8.67

September (closed)

710,000

8.69

October (closed)

710,000

8.76

November

610,000

9.66

December

610,000

9.99

     

2010

   

January

20,000

$11.20

February

20,000

11.15

March

20,000

10.89

April

20,000

9.29

May

20,000

9.13

June

20,000

9.21

     

 

On April 24, 2009, EOG settled its natural gas financial price swap contracts with notional volumes of 20,000 MMBtud for the July 1, 2010 - December 31, 2010 period and received proceeds of $12.1 million.

-20-

Financial Basis Swap Contracts. Prices received by EOG for its natural gas production generally vary from New York Mercantile Exchange (NYMEX) prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas financial basis swap contracts in order to fix the differential between prices in the Rocky Mountain area and NYMEX Henry Hub prices. Presented below is a comprehensive summary of EOG's natural gas financial basis swap contracts at September 30, 2009. The weighted average price differential represents the amount of reduction to NYMEX gas prices per MMBtu for the notional volumes covered by the basis swap. Notional volumes are expressed in MMBtud and price differentials are expressed in $/MMBtu.

Natural Gas Financial Basis Swap Contracts

   

Weighted

   

Average Price

 

Volume

Differential

 

(MMBtud)

($/MMBtu)

2009

   

Second Quarter (closed)

65,000

$(2.54)

Third Quarter (closed)

65,000

(2.60)

Fourth Quarter (1)

65,000

(3.03)

     

2010

   

First Quarter

65,000

$(1.72)

Second Quarter

65,000

(2.56)

Third Quarter

65,000

(3.17)

Fourth Quarter

65,000

(3.73)

     

2011

   

First Quarter

65,000

$(1.89)

     

                                                                                                                    (1) Includes closed contracts for October 2009.

Credit Risk. Notional contract amounts are used to express the magnitude of commodity price and foreign currency swap agreements. The amounts potentially subject to credit risk, in the event of nonperformance by EOG's counterparties, are equal to the fair value of such contracts. EOG evaluates its exposure to significant counterparties on an ongoing basis, including those arising from physical and financial transactions. In some instances, EOG requires collateral, parent guarantees or letters of credit to minimize credit risk.

All of EOG's outstanding derivative instruments are covered by International Swap Dealers Association (ISDA) Master Agreements with counterparties. The ISDAs may contain provisions that require EOG, if it is the party in a net liability position, to post collateral when the amount of the net liability exceeds the threshold level specified for EOG's then-current credit ratings. In addition, the ISDA may also provide that as a result of certain circumstances, including certain events that cause EOG's credit ratings to become materially weaker than its then-current ratings, the counterparty may require all outstanding derivatives under the ISDA to be settled immediately. See Note 12 for the aggregate fair value of all derivative instruments with credit-risk related contingent features that are in a net liability position at September 30, 2009 and December 31, 2008. EOG had zero collateral posted at both September 30, 2009 and December 31, 2008.

14. Acquisitions

During the third quarter of 2009, EOG completed three transactions to acquire certain crude oil and natural gas properties and related assets located in Montague and Cooke Counties, Texas (Barnett Shale Combo Assets). The Barnett Shale Combo Assets consist of proved developed and undeveloped reserves and unproved acreage. The aggregate purchase price of the transactions, which is subject to customary post-closing adjustments, totaled $196.7 million, consisting of cash consideration of $107.1 million and 1,450,000 shares of EOG common stock valued at $89.6 million at the closing date of the applicable transaction.

-21-

 

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., together with its subsidiaries (collectively, 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, Trinidad, the United Kingdom and China. 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.

United States and Canada. 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 continues to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's natural gas and crude oil production. Production in the United States and Canada accounted for approximately 86% of total company production in the first nine months of both 2009 and 2008. One of EOG's exploration strategies is to apply its horizontal drilling expertise gained in natural gas resource plays to unconventional oil reservoirs. During the first nine months of 2009, the Fort Worth Basin Barnett Shale and North Dakota Bakken areas produced an increasing amount of crude oil and natural gas liquids as compared to the comparable period in 2008. For the first nine months of 2009, crude oil and natural gas liquids production accounted for approximately 22% of total company production as compared to approximately 18% for the comparable period in 2008. Based on current trends, EOG expects its 2009 crude oil and natural gas liquids production to continue to increase as compared to 2008. EOG's major producing areas are in Louisiana, New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.

During the third quarter of 2009, EOG completed three transactions to acquire certain crude oil and natural gas properties and related assets located in Montague and Cooke Counties, Texas (Barnett Shale Combo Assets). The Barnett Shale Combo Assets consist of proved developed and undeveloped reserves and approximately 33,000 net unproved acres. Production from these assets averaged approximately 2,300 barrels equivalent per day, net, at the time of acquisition. The aggregate purchase price of the transactions, which is subject to customary post-closing adjustments, totaled $196.7 million, consisting of cash consideration of $107.1 million and 1,450,000 shares of EOG common stock valued at $89.6 million at the closing date of the applicable transaction.

International. In the United Kingdom, EOG completed a farm-in agreement with owners of the Central North Sea Block 15/30a Area AB during the third quarter of 2009. An exploratory well, which EOG will operate with a 65% working interest, is planned for the fourth quarter of 2009. Subsequent to its June 2009 oil discovery in the East Irish Sea Block 110/12, EOG plans to drill two additional exploratory wells during the fourth quarter of 2009 and first quarter of 2010. EOG has a 100% working interest in this Block. In the Sichuan Basin, Sichuan Province, The People's Republic of China, EOG drilled a horizontal well in the third quarter of 2009 and plans to complete and test this well during the fourth quarter of 2009 and first quarter of 2010. In addition, to evaluate a different zone, EOG began drilling a second monitoring well during the third quarter of 2009 and plans to begin a second horizontal well in the fourth quarter of 2009.

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.

                                                                                                                             -22-

Capital Structure. One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. At September 30, 2009, EOG's debt-to-total capitalization ratio was 23% as compared to 17% at December 31, 2008. On May 21, 2009, EOG completed its public offering of $900 million aggregate principal amount of 5.625% Senior Notes due 2019 (Notes). Interest on the Notes is payable semi-annually in arrears on June 1 and December 1 of each year, beginning December 1, 2009. Net proceeds from the offering of approximately $891 million were used for general corporate purposes, including repayment of outstanding commercial paper borrowings. During the first nine months of 2009, EOG funded $2.7 billion in exploration and development and other property, plant and equipment expenditures (including $206 million of acquisitions) and paid $106 million in dividends to common stockholders, primarily by utilizing cash provided from its operating activities, proceeds from commercial paper and uncommitted credit facility borrowings and proceeds from the offering of the Notes.

For 2009, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $3.7 billion, including acquisitions of approximately $300 million. United States and Canada natural gas and crude oil drilling activity continues to be a key component of these expenditures. 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.

Results of Operations

The following review of operations for the three and nine months ended September 30, 2009 and 2008 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included in this Quarterly Report on Form 10-Q.

Three Months Ended September 30, 2009 vs. Three Months Ended September 30, 2008

Net Operating Revenues. During the third quarter of 2009, net operating revenues decreased $2,257 million, or 69%, to $1,007 million from $3,264 million for the same period of 2008. Total wellhead revenues for the third quarter of 2009, which are revenues generated from sales of natural gas, crude oil and condensate and natural gas liquids, decreased $985 million, or 54%, to $849 million from $1,834 million for the same period of 2008. During the third quarter of 2009, EOG recognized a net gain on mark-to-market commodity derivative contracts of $21 million compared to a net gain of $1,382 million for the same period of 2008. Gathering, processing and marketing revenues, which are revenues generated from sales of third-party natural gas, crude oil and natural gas liquids as well as gathering fees associated with gathering third-party natural gas, for the third quarter of 2009 increased $84 million, or 163%, to $135 million from $51 million for the same period of 2008.

-23-

Wellhead volume and price statistics for the three-month periods ended September 30, 2009 and 2008 were as follows:

       

Three Months Ended

 
       

September 30,

 
       

2009

 

2008

 

Natural Gas Volumes (MMcfd) (1)

         
 

United States

 

1,128

 

1,196

 
 

Canada

 

219

 

224

 
 

Trinidad

 

268

 

240

 
 

Other International (2)

 

13

 

19

 
   

Total

 

1,628

 

1,679

 
               

Average Natural Gas Prices ($/Mcf) (3)

         
 

United States

$

3.27

$

8.99

 
 

Canada

 

3.15

 

8.15

 
 

Trinidad

 

1.77

 

4.04

 
 

Other International (2)

 

3.53

 

7.41

 
   

Composite

 

3.01

 

8.15

 
               

Crude Oil and Condensate Volumes (MBbld) (1)

         
 

United States

 

51.7

 

41.8

 
 

Canada

 

4.7

 

3.0

 
 

Trinidad

 

3.0

 

3.4

 
 

Other International (2)

 

0.1

 

0.1

 
   

Total

 

59.5

 

48.3

 
               

Average Crude Oil and Condensate Prices ($/Bbl) (3)

         
 

United States

$

60.79

$

109.86

 
 

Canada

 

61.43

 

109.71

 
 

Trinidad

 

57.07

 

111.39

 
 

Other International (2)

 

57.93

 

112.77

 
   

Composite

 

60.65

 

109.96

 
               

Natural Gas Liquids Volumes (MBbld) (1)

         
 

United States

 

23.1

 

13.2

 
 

Canada

 

1.0

 

1.1

 
   

Total

 

24.1

 

14.3

 
               

Average Natural Gas Liquids Prices ($/Bbl) (3)

         
 

United States

$

31.15

$

69.79

 
 

Canada

 

30.96

 

64.01

 
   

Composite

 

31.14

 

69.33

 
               

Natural Gas Equivalent Volumes (MMcfed) (4)

         
 

United States

 

1,577

 

1,525

 
 

Canada

 

253

 

249

 
 

Trinidad

 

286

 

261

 
 

Other International (2)

 

13

 

20

 
   

Total

 

2,129

 

2,055

 

Total Bcfe (4)

 

195.9

 

189.1

 
           

(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) Other International includes EOG's United Kingdom operations and, effective July 1, 2008, EOG's China operations.
(3) Dollars per thousand cubic feet or per barrel, as applicable.
(4) 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.

-24-

Wellhead natural gas revenues for the third quarter of 2009 decreased $809 million, or 64%, to $450 million from $1,259 million for the same period of 2008. The decrease was due to a lower composite average wellhead natural gas price ($770 million) and decreased natural gas deliveries ($39 million). EOG's composite average wellhead natural gas price decreased 63% to $3.01 per thousand cubic feet (Mcf) for the third quarter of 2009 from $8.15 per Mcf for the same period of 2008.

Natural gas deliveries for the third quarter of 2009 decreased 51 MMcfd, or 3%, to 1,628 MMcfd from 1,679 MMcfd for the same period of 2008. The decrease was primarily due to lower production in the United States (68 MMcfd), Canada (5 MMcfd) and the United Kingdom (5 MMcfd), partially offset by increased production in Trinidad (28 MMcfd). The decrease in the United States was primarily attributable to decreased production in Texas (50 MMcfd), the Rocky Mountain area (14 MMcfd), New Mexico (8 MMcfd), Kansas (5 MMcfd) and Mississippi (3 MMcfd), partially offset by increased production in Louisiana (14 MMcfd). The decrease in the United Kingdom primarily resulted from reduced production in the Arthur field. The increase in Trinidad was primarily due to increased net contractual deliveries.

Wellhead crude oil and condensate revenues for the third quarter of 2009 decreased $153 million, or 32%, to $330 million from $483 million for the same period of 2008, due to a lower composite average wellhead crude oil and condensate price ($268 million), partially offset by an increase of 11 MBbld, or 23%, in wellhead crude oil and condensate deliveries ($115 million). The increase in deliveries primarily reflects increased production in North Dakota (9 MBbld), Texas (2 MBbld) and Canada (2 MBbld). The composite average wellhead crude oil and condensate price for the third quarter of 2009 decreased 45% to $60.65 per barrel compared to $109.96 per barrel for the same period of 2008.

Natural gas liquids revenues for the third quarter of 2009 decreased $22 million, or 24%, to $69 million from $91 million for the same period of 2008, due to a lower composite average price ($84 million), partially offset by an increase of 10 MBbld, or 69%, in natural gas liquids deliveries ($62 million). The composite average natural gas liquids price for the third quarter of 2009 decreased 55% to $31.14 per barrel compared to $69.33 per barrel for the same period of 2008. The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale area (6 MBbld) and the Mid-Continent area (2 MBbld).

During the third quarter of 2009, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $21 million compared to a net gain of $1,382 million for the same period of 2008. During the third quarter of 2009, the net cash inflow related to settled natural gas financial collar, price swap and basis swap contracts was $331 million compared to the net cash outflow related to settled natural gas and crude oil financial price swap contracts of $122 million for the same period of 2008.

Gathering, processing and marketing revenues represent sales of third-party natural gas, crude oil and natural gas liquids as well as gathering fees associated with gathering third-party natural gas. During the three months ended September 30, 2009 and 2008, substantially all of such revenues were related to sales of third-party natural gas and crude oil. Marketing costs represent the costs of purchasing third-party natural gas and crude oil and the associated transportation costs.

Gathering, processing and marketing revenues less marketing costs for the third quarter of 2009 decreased $4 million to $3 million compared to $7 million for the same period of 2008, reflecting lower margins associated with natural gas marketing activities.

-25-

Operating and Other Expenses. For the third quarter of 2009, operating expenses of $972 million were $100 million higher than the $872 million incurred in the third quarter of 2008. The following table presents the costs per thousand cubic feet equivalent (Mcfe) for the three-month periods ended September 30, 2009 and 2008:

   

Three Months Ended

   

September 30,

   

2009

   

2008

           

Lease and Well

$

0.73

 

$

0.75

Transportation Costs

 

0.36

   

0.41

Depreciation, Depletion and Amortization (DD&A) -

         
 

Oil and Gas Properties

 

1.84

   

1.73

 

Other Property, Plant and Equipment

 

0.13

   

0.10

General and Administrative (G&A)

 

0.32

   

0.38

Interest Expense, Net

 

0.16

   

0.06

 

Total (1)

$

3.54

 

$

3.43

             

                                                                                             (1) Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments,
                                                                                                   marketing costs and taxes other than income.

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and interest expense, net for the three months ended September 30, 2009 compared to the same period of 2008 are set forth below.

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 natural gas and crude oil 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 were $142 million for the third quarter of both 2009 and 2008. During 2009, increased operating and maintenance expenses in Canada ($5 million) and China ($1 million) and increased lease and well administrative expenses in Canada ($1 million) were offset by decreased lease and well administrative expenses in the United States ($3 million), decreased operating and maintenance expenses in the United States ($2 million) and changes in the Canadian exchange rate ($2 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 downstream 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 $71 million for the third quarter of 2009 decreased $7 million from $78 million for the same prior year period primarily due to decreased costs associated with marketing arrangements to transport production from the Fort Worth Basin Barnett Shale area ($10 million) to downstream markets, partially offset by increased costs associated with marketing arrangements to transport production from the Rocky Mountain area ($5 million) to downstream markets.

-26-

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 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 year to year. DD&A of the cost of other property, plant and equipment is calculated using the straight-line depreciation method over the useful lives of the assets. Other property, plant and equipment consist of natural gas gathering and processing facilities, compressors, vehicles, buildings and leasehold improvements, furniture and fixtures, and computer hardware and software.

DD&A expenses for the third quarter of 2009 increased $39 million to $385 million from $346 million for the same prior year period. DD&A expenses associated with oil and gas properties for the third quarter of 2009 were $32 million higher than the same prior year period primarily due to higher unit rates in the United States ($18 million), Trinidad ($3 million) and Canada ($3 million) and as a result of increased production in the United States ($9 million), partially offset by changes in the Canadian exchange rate ($3 million).

DD&A expenses associated with other property, plant and equipment for the third quarter of 2009 were $7 million higher than the same prior year period primarily due to increased expenditures associated with natural gas gathering systems and processing plants in the Fort Worth Basin Barnett Shale area ($3 million) and Rocky Mountain area ($3 million).

G&A expenses of $63 million for the third quarter of 2009 decreased $8 million from the same prior year period primarily due to lower employee-related costs.

Interest expense, net of $30 million for the third quarter of 2009 increased $18 million compared to the same prior year period primarily due to a higher average debt balance ($20 million), partially offset by higher capitalized interest ($2 million).

Gathering and processing costs represent operating and maintenance expenses and administrative expenses associated with operating EOG's natural gas gathering and processing assets.

Gathering and processing costs for the third quarter of 2009 increased $4 million to $13 million as compared to the same prior year period primarily due to increased activities in the Rocky Mountain area.

Exploration costs of $45 million for the third quarter of 2009 increased $7 million from the same prior year period primarily due to increased geological and geophysical expenditures in the United States ($4 million) and the United Kingdom ($2 million).

Impairments include amortization and impairments of unproved oil and gas properties, as well as impairments of proved oil and gas properties. Unproved properties with individually significant acquisition costs are assessed on a property-by-property basis, and any impairment in value is recognized. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the average holding period. When circumstances indicate that a proved property may be impaired, EOG compares expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.

Impairments of $69 million for the third quarter of 2009 increased $37 million from $32 million for the same prior year period primarily due to increased amortization and impairments of unproved properties in the United States ($28 million) and increased impairments of proved properties in the United States ($8 million). EOG recorded impairments of proved properties of $15 million and $7 million for the third quarter of 2009 and 2008, respectively.

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 revenues and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.

-27-

Taxes other than income for the third quarter of 2009 decreased $50 million to $48 million (5.6% of wellhead revenues) from $98 million (5.3% of wellhead revenues) for the same prior year period. The decrease in taxes other than income was primarily due to a decrease in severance/production taxes as a result of decreased wellhead revenues in the United States ($33 million) and Trinidad ($4 million) and an increase in credits taken in 2009 for Texas high cost gas severance tax rate reductions ($12 million).

Other income (expense), net for the third quarter of 2009 decreased $14 million from the same prior year period. The decrease was primarily due to lower equity income from ammonia plants in Trinidad ($7 million) and lower interest income ($3 million).

EOG recognized an income tax provision of less than $1 million for the third quarter of 2009 compared to $838 million for the same prior year period. The change was primarily due to decreased pretax income. The net effective tax rate for the third quarter of 2009 decreased to 8% from 35% for the same prior year period due primarily to lower pretax income and lower Canadian taxes.

Nine Months Ended September 30, 2009 vs. Nine Months Ended September 30, 2008

Net Operating Revenues. During the first nine months of 2009, net operating revenues decreased $2,467 million, or 45%, to $3,026 million from $5,493 million for the same period of 2008. Total wellhead revenues for the first nine months of 2009 decreased $2,767 million, or 54%, to $2,364 million from $5,131 million for the same period of 2008. During the first nine months of 2009, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $406 million compared to a net gain of $69 million for the same period of 2008. Gathering, processing and marketing revenues for the first nine months of 2009 increased $99 million, or 66%, to $250 million from $151 million for the same period of 2008. Other, net operating revenues in 2008 primarily consist of a gain of $128 million on the sale of EOG's Appalachian assets in February 2008.

-28-

Wellhead volume and price statistics for the nine-month periods ended September 30, 2009 and 2008 were as follows:

       

Nine Months Ended

 
       

September 30,

 
       

2009

 

2008

 

Natural Gas Volumes (MMcfd)

         
 

United States

 

1,153

 

1,141

 
 

Canada

 

224

 

218

 
 

Trinidad

 

266

 

229

 
 

Other International

 

15

 

16

 
   

Total

 

1,658

 

1,604

 
               

Average Natural Gas Prices ($/Mcf)

         
 

United States

$

3.57

$

9.15

 
 

Canada

 

3.67

 

8.33

 
 

Trinidad

 

1.54

 

3.86

 
 

Other International

 

4.45

 

8.90

 
   

Composite

 

3.27

 

8.28

 
               

Crude Oil and Condensate Volumes (MBbld)

         
 

United States

 

46.5

 

35.9

 
 

Canada

 

3.6

 

2.7

 
 

Trinidad

 

3.0

 

3.4

 
 

Other International

 

0.1

 

0.1

 
   

Total

 

53.2

 

42.1

 
               

Average Crude Oil and Condensate Prices ($/Bbl)

         
 

United States

$

49.54

$

107.36

 
 

Canada

 

51.91

 

104.57

 
 

Trinidad

 

46.13

 

103.80

 
 

Other International

 

50.11

 

104.66

 
   

Composite

 

49.51

 

106.89

 
               

Natural Gas Liquids Volumes (MBbld)

         
 

United States

 

22.2

 

14.7

 
 

Canada

 

1.1

 

1.0

 
   

Total

 

23.3

 

15.7

 
               

Average Natural Gas Liquids Prices ($/Bbl)

         
 

United States

$

26.42

$

63.08

 
 

Canada

 

27.29

 

62.45

 
   

Composite

 

26.46

 

63.04

 
               

Natural Gas Equivalent Volumes (MMcfed)

         
 

United States

 

1,566

 

1,445

 
 

Canada

 

252

 

240

 
 

Trinidad

 

284

 

250

 
 

Other International

 

15

 

16

 
   

Total

 

2,117

 

1,951

 

Total Bcfe

 

578.1

 

534.5

 
           

-29-

Wellhead natural gas revenues for the first nine months of 2009 decreased $2,159 million, or 59%, to $1,478 million from $3,637 million for the same period of 2008. The decrease was due to a lower composite average wellhead natural gas price ($2,268 million), partially offset by increased natural gas deliveries ($109 million). EOG's composite average wellhead natural gas price decreased 61% to $3.27 per Mcf for the first nine months of 2009 from $8.28 per Mcf for the same period of 2008.

Natural gas deliveries for the first nine months of 2009 increased 54 MMcfd, or 3%, to 1,658 MMcfd from 1,604 MMcfd for the same period of 2008. The increase was due to higher production in Trinidad (37 MMcfd), the United States (12 MMcfd) and Canada (6 MMcfd). The increase in Trinidad was primarily due to increased net contractual deliveries and reduced plant shutdowns for maintenance during 2009. The increase in the United States was primarily attributable to increased production in the Rocky Mountain area (15 MMcfd), Texas (12 MMcfd) and Louisiana (6 MMcfd), partially offset by decreased production in Mississippi (7 MMcfd), New Mexico (5 MMcfd), Oklahoma (3 MMcfd), Kansas (3 MMcfd) and as a result of the February 2008 sale of EOG's Appalachian assets (3 MMcfd). The increase in Canada was primarily attributable to British Columbia Horn River Basin production.

Wellhead crude oil and condensate revenues for the first nine months of 2009 decreased $505 million, or 41%, to $718 million from $1,223 million for the same period of 2008, due to a lower composite average wellhead crude oil and condensate price ($832 million), partially offset by an increase of 11 MBbld, or 26%, in wellhead crude oil and condensate deliveries ($327 million). The increase in deliveries primarily reflects increased production in North Dakota (9 MBbld) and Texas (2 MBbld). The composite average wellhead crude oil and condensate price for the first nine months of 2009 decreased 54% to $49.51 per barrel compared to $106.89 per barrel for the same period of 2008.

Natural gas liquids revenues for the first nine months of 2009 decreased $103 million, or 38%, to $168 million from $271 million for the same period of 2008, due to a lower composite average price ($233 million), partially offset by an increase of 8 MBbld, or 48%, in natural gas liquids deliveries ($130 million). The composite average natural gas liquids price for the first nine months of 2009 decreased 58% to $26.46 per barrel compared to $63.04 per barrel for the same period of 2008. The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale area.

During the first nine months of 2009, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $406 million compared to a net gain of $69 million for the same period of 2008. During the first nine months of 2009, the net cash inflow related to settled natural gas financial collar, price swap and basis swap contracts was $987 million compared to a net cash outflow related to settled natural gas and crude oil financial price swap contracts of $237 million for the same period of 2008.

Gathering, processing and marketing revenues less marketing costs for the first nine months of 2009 increased $1 million to $12 million compared to the same prior year period of 2008. The increase resulted primarily from increased natural gas marketing operations in the Gulf Coast area.

-30-

Operating and Other Expenses. For the first nine months of 2009, operating expenses of $2,709 million were $232 million higher than the $2,477 million incurred in the same period of 2008. The following table presents the costs per Mcfe for the nine-month periods ended September 30, 2009 and 2008:

   

Nine Months Ended

   

September 30,

   

2009

   

2008

           

Lease and Well

$

0.73

 

$

0.74

Transportation Costs

 

0.36

   

0.38

DD&A -

         
 

Oil and Gas Properties

 

1.87

   

1.71

 

Other Property, Plant and Equipment

 

0.12

   

0.09

G&A

 

0.31

   

0.35

Interest Expense, Net

 

0.13

   

0.06

 

Total (1)

$

3.52

 

$

3.33

             

                                                                                               (1) Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments,
                                                                                                     marketing costs and taxes other than income.

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and interest expense, net for the nine months ended September 30, 2009 compared to the same period of 2008 are set forth below.

Lease and well expenses of $422 million for the first nine months of 2009 increased $26 million from $396 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($25 million), Canada ($11 million) and China ($3 million), partially offset by changes in the Canadian exchange rate ($13 million).

Transportation costs of $206 million for the first nine months of 2009 increased $3 million from $203 million for the same prior year period primarily due to increased transportation costs in the United States ($4 million) and Trinidad ($1 million), partially offset by decreased transportation costs in the United Kingdom ($1 million) and Canada ($1 million). The increased transportation costs in the United States were primarily due to increased transportation costs in the Rocky Mountain area ($11 million), partially offset by decreased transportation costs in the Fort Worth Basin Barnett Shale area ($4 million).

DD&A expenses for the first nine months of 2009 increased $191 million to $1,150 million from $959 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first nine months of 2009 were $166 million higher than the same prior year period primarily due to higher unit rates in the United States ($92 million), Canada ($11 million), Trinidad ($10 million) and China ($3 million) and increased production in the United States ($60 million), Canada ($6 million) and in Trinidad ($2 million), partially offset by changes in the Canadian exchange rate ($21 million).

DD&A expenses associated with other property, plant and equipment for the first nine months of 2009 were $25 million higher than the same prior year period primarily due to increased expenditures associated with natural gas gathering systems and processing plants in the Fort Worth Basin Barnett Shale area ($11 million) and Rocky Mountain area ($7 million).

G&A expenses of $179 million for the first nine months of 2009 decreased $6 million from the same prior year period primarily due to lower employee-related costs.

Interest expense, net of $74 million for the first nine months of 2009 increased $40 million compared to the same prior year period primarily due to a higher average debt balance ($48 million), partially offset by higher capitalized interest ($8 million).

-31-

Gathering and processing costs for the first nine months of 2009 increased $18 million to $45 million as compared to the same prior year period primarily due to increased activities in the Rocky Mountain area ($11 million) and the Fort Worth Basin Barnett Shale area ($6 million).

Exploration costs of $129 million for the first nine months of 2009 decreased $17 million compared to the same prior year period primarily due to decreased geological and geophysical expenditures in the United States.

Impairments of $182 million for the first nine months of 2009 increased $68 million compared to the same prior year period primarily due to increased amortization and impairments of unproved properties in the United States ($69 million) and increased impairments of proved properties in the United States ($20 million), partially offset by an impairment in Trinidad recorded in the second quarter of 2008 as a result of EOG's relinquishment of its rights to Block Lower Reverse "L" (LRL) ($20 million). EOG recorded impairments of proved properties of $39 million and $40 million for the nine months ended September 30, 2009 and 2008, respectively.

Taxes other than income for the first nine months of 2009 decreased $161 million to $119 million (5.0% of wellhead revenues) from $280 million (5.5% of wellhead revenues) for the same prior year period. The decrease in taxes other than income was primarily due to decreased severance/production taxes primarily as a result of decreased wellhead revenues in the United States ($103 million) and Trinidad ($16 million), an increase in credits taken in 2009 for Texas high cost gas severance tax rate reductions ($32 million) and lower ad valorem/property taxes in the United States ($13 million), partially offset by an increase in franchise taxes in the United States ($5 million). The decline in taxes other than income as a percentage of wellhead revenues primarily reflects an increase in credits taken in 2009 for Texas high cost gas severance tax rate reductions combined with a decline in non-revenue based taxes.

Other income (expense), net was $3 million for the first nine months of 2009 compared to $29 million for the same prior year period. The decrease of $26 million was primarily due to lower equity income from ammonia plants in Trinidad ($17 million), lower interest income ($6 million) and settlements received related to the Enron Corp. bankruptcy in the second quarter of 2008 ($2 million), partially offset by increased foreign currency transaction gains ($5 million).

Income tax provision of $100 million for the first nine months of 2009 decreased $936 million compared to $1,036 million for the same prior year period due primarily to decreased pretax income ($968 million), partially offset by higher foreign taxes ($28 million). The net effective tax rate for the first nine months of 2009 increased to 41% from 34% for the same prior year period primarily as a result of higher state and foreign tax rates and the absence of 2008 tax benefits related to the impairment of LRL.

Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the nine months ended September 30, 2009 were funds generated from operations, net commercial paper and uncommitted credit facility borrowings and proceeds from the offering of the Notes. The primary uses of cash were funds used in operations; exploration and development expenditures; other property, plant and equipment expenditures; and dividend payments to stockholders. During the first nine months of 2009, EOG's cash balance increased $278 million to $609 million from $331 million at December 31, 2008.

Net cash provided by operating activities of $2,094 million for the first nine months of 2009 decreased $1,506 million compared to the same period of 2008 primarily reflecting a decrease in wellhead revenues ($2,767 million), unfavorable changes in working capital and other assets and liabilities ($62 million) and an increase in cash paid for interest expense ($8 million), partially offset by a favorable change in net cash flow from the settlement of financial commodity derivative contracts ($1,224 million), a decrease in cash operating expenses ($137 million) and a decrease in net cash paid for income taxes ($31 million).

-32-

Net cash used in investing activities of $2,651 million for the first nine months of 2009 decreased by $848 million compared to the same period of 2008 due primarily to a decrease in additions to oil and gas properties ($1,264 million) and a decrease in additions to other property, plant and equipment ($80 million), partially offset by a decrease in proceeds from sales of assets ($367 million), primarily reflecting net proceeds from the sale of EOG's Appalachian assets in February 2008, and unfavorable changes in working capital associated with investing activities ($132 million).

Net cash provided by financing activities was $823 million for the first nine months of 2009 compared to $745 million for the same period of 2008. Cash provided by financing activities for the first nine months of 2009 included the proceeds from the offering of the Notes ($900 million), excess tax benefits from stock-based compensation ($34 million) and proceeds from stock options exercised and employee stock purchase plan activity ($14 million). Cash used by financing activities for the first nine months of 2009 included cash dividend payments ($106 million), the purchase of treasury stock ($10 million) and debt issuance costs ($9 million).

Total Expenditures. For 2009, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $3.7 billion, including acquisitions of approximately $300 million. The table below sets out components of total expenditures for the nine-month periods ended September 30, 2009 and 2008 (in millions):

       

Nine Months Ended

       

September 30,

       

2009

 

2008

Expenditure Category

       

Capital

       
 

Drilling and Facilities

$

1,780

$

2,988

 

Leasehold Acquisitions

 

293

 

377

 

Property Acquisitions

 

206

 

109

 

Capitalized Interest

 

38

 

30

 

   Subtotal

 

2,317

 

3,504

Exploration Costs

 

129

 

145

Dry Hole Costs

 

40

 

28

 

   Exploration and Development Expenditures

 

2,486

 

3,677

Asset Retirement Costs

 

53

 

164

 

   Total Exploration and Development Expenditures

 

2,539

 

3,841

Other Property, Plant and Equipment

 

241

 

321

 

   Total Expenditures

$

2,780

$

4,162

           

Exploration and development expenditures of $2,486 million for the first nine months of 2009 were $1,191 million lower than the same period of 2008 due primarily to decreased drilling and facilities expenditures in the United States ($1,150 million), Trinidad ($42 million) and Canada ($29 million), decreased leasehold acquisition expenditures in Canada ($105 million), changes in the foreign currency exchange rate in Canada ($27 million) and the United Kingdom ($5 million), decreased geological and geophysical expenditures in the United States ($17 million) and decreased property acquisition expenditures in Trinidad ($15 million) and Canada ($14 million). These decreases were partially offset by increased property acquisition expenditures in the United States ($136 million), increased leasehold acquisition expenditures in the United States ($27 million), increased drilling and facilities expenditures in China ($24 million) and the United Kingdom ($14 million), increased capitalized interest in the United States ($10 million) and increased dry hole costs in the United Kingdom ($9 million) and the United States ($8 million). The exploration and development expenditures for the first nine months of 2009 of $2,486 million included $1,589 million in development, $653 million in exploration, $206 million in property acquisitions and $38 million in capitalized interest. The exploration and development expenditures for the first nine months of 2008 of $3,677 million included $2,722 million in development, $816 million in exploration, $109 million in property acquisitions and $30 million in capitalized interest.

-33-

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, the United Kingdom and China, 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 the Consolidated Financial Statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 25, 2009, 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, price swap and basis swap contracts, as a means to manage this price risk. EOG has not designated any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income. The related cash flow impact is reflected as Cash Flows from Operating Activities. In addition to financial transactions, from time to time, 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.

Financial Collar Contracts. The total fair value of EOG's natural gas financial collar contracts at September 30, 2009 was a positive $32 million, which is reflected in the Consolidated Balance Sheets. Presented below is a comprehensive summary of EOG's natural gas financial collar contracts at November 5, 2009. The notional volumes are expressed in million British thermal units per day (MMBtud) and prices are expressed in dollars per million British thermal units ($/MMBtu). The average floor price of EOG's outstanding natural gas financial collar contracts for 2010 is $10.33 per million British thermal units (MMBtu) and the average ceiling price is $12.63 per MMBtu.

Natural Gas Financial Collar Contracts

   

Floor Price

 

Ceiling Price

     

Weighted

 

Ceiling

Weighted

 

Volume

Floor Range

Average Price

 

Range

Average Price

 

(MMBtud)

($/MMBtu)

($/MMBtu)

 

($/MMBtu)

($/MMBtu)

2010

           

January

40,000

$11.44 - 11.47

$11.45

 

$13.79 - 13.90

$13.85

February

40,000

11.38 - 11.41

11.40

 

13.75 - 13.85

13.80

March

40,000

11.13 - 11.15

11.14

 

13.50 - 13.60

13.55

April

40,000

9.40 -   9.45

9.42

 

11.55 - 11.65

11.60

May

40,000

9.24 -   9.29

9.26

 

11.41 - 11.55

11.48

June

40,000

9.31 -   9.36

9.34

 

11.49 - 11.60

11.55

             

On April 29, 2009, EOG settled its natural gas financial collar contracts with notional volumes of 40,000 MMBtud for the July 1, 2010 - December 31, 2010 period and received proceeds of $26.5 million.

-34-

Financial Price Swap Contracts. The total fair value of EOG's natural gas financial price swap contracts at September 30, 2009 was a positive $292 million, which is reflected in the Consolidated Balance Sheets. Presented below is a comprehensive summary of EOG's natural gas financial price swap contracts at November 5, 2009. The notional volumes are expressed in MMBtud and prices are expressed in $/MMBtu. The average price of EOG's outstanding natural gas financial price swap contracts for 2009 is $9.99 per MMBtu and for 2010 is $10.14 per MMBtu.

Natural Gas Financial Price Swap Contracts

   

Weighted

 

Volume

Average Price

 

(MMBtud)

($/MMBtu)

2009

   

January (closed)

585,000

$10.76

February (closed)

585,000

10.73

March (closed)

585,000

10.50

April (closed)

610,000

9.24

May (closed)

610,000

9.16

June (closed)

710,000

8.53

July (closed)

710,000

8.62

August (closed)

710,000

8.67

September (closed)

710,000

8.69

October (closed)

710,000

8.76

November (closed)

610,000

9.66

December

610,000

9.99

     

2010

   

January

20,000

$11.20

February

20,000

11.15

March

20,000

10.89

April

20,000

9.29

May

20,000

9.13

June

20,000

9.21

     

On April 24, 2009, EOG settled its natural gas financial price swap contracts with notional volumes of 20,000 MMBtud for the July 1, 2010 - December 31, 2010 period and received proceeds of $12.1 million.

-35-

Financial Basis Swap Contracts. Prices received by EOG for its natural gas production generally vary from New York Mercantile Exchange (NYMEX) prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas financial basis swap contracts in order to fix the differential between prices in the Rocky Mountain area and NYMEX Henry Hub prices. The total fair value of EOG's natural gas financial basis swap contracts at September 30, 2009 was a negative $75 million, which is reflected in the Consolidated Balance Sheets. Presented below is a comprehensive summary of EOG's natural gas financial basis swap contracts at November 5, 2009. The weighted average price differential represents the amount of reduction to NYMEX gas prices per MMBtu for the notional volumes covered by the basis swap. The notional volumes are expressed in MMBtud and price differentials expressed in $/MMBtu.

Natural Gas Financial Basis Swap Contracts

   

Weighted

 


Volume

Average Price Differential

 

(MMBtud)

($/MMBtu)

2009

   

Second Quarter (closed)

65,000

$(2.54)

Third Quarter (closed)

65,000

(2.60)

Fourth Quarter (1)

65,000

(3.03)

     

2010

   

First Quarter

65,000

$(1.72)

Second Quarter

65,000

(2.56)

Third Quarter

65,000

(3.17)

Fourth Quarter

65,000

(3.73)

     

2011

   

First Quarter

65,000

$(1.89)

     

                                                                                                        (1) Includes closed contracts for the months of October and November 2009.

-36-

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, 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, budgets, reserve information, levels of production and costs 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" 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 or generate income or cash flows 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 these expectations will be achieved or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known and unknown 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 natural gas, crude oil and related commodities;

  • changes in demand for natural gas, crude oil and related commodities, including ammonia and methanol;

  • the extent to which EOG is successful in its efforts to discover, develop, market and produce reserves and to acquire natural gas and crude oil properties;

  • the extent to which EOG can optimize reserve recovery and economically develop its plays utilizing horizontal and vertical drilling and advanced completion technologies;

  • the extent to which EOG is successful in its efforts to economically develop its acreage in the Barnett Shale, the Bakken Formation, its Horn River Basin and Haynesville plays and its other exploration and development areas;

  • EOG's ability to achieve anticipated production levels from existing and future natural gas and crude oil development projects, given the risks and uncertainties inherent in drilling, completing and operating natural gas and crude oil wells and the potential for interruptions of production, whether involuntary or intentional as a result of market or other conditions;

  • the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation 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;

  • competition in the oil and gas exploration and production industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;

  • EOG's ability to obtain access to surface locations for drilling and production facilities;

  • the extent to which EOG's third-party-operated natural gas and crude oil properties are operated successfully and economically;

  • EOG's ability to effectively integrate acquired natural gas and crude oil 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;

  • weather, including its impact on natural gas and crude oil demand, and weather-related delays in drilling and in the installation and operation of gathering and production 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;

  • the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;

-37-

  • 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;

  • the extent and effect of any hedging activities engaged in by EOG;

  • the timing and impact of liquefied natural gas imports;

  • the use of competing energy sources and the development of alternative energy sources;

  • political developments around the world, including in the areas in which EOG operates;

  • changes in government policies, legislation and regulations, including environmental regulations;

  • the extent to which EOG incurs uninsured losses and liabilities;

  • acts of war and terrorism and responses to these acts; and

  • the other factors described under Item 1A, "Risk Factors," on pages 13 through 19 of EOG's Annual Report on Form 10-K for the year ended December 31, 2008 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and 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 to update or revise its forward-looking statements, whether as a result of new information, future events or otherwise.

-38-

 

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 (i) 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 36 through 42 of EOG's Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 25, 2009 (EOG's 2008 Annual Report); and (ii) Note 11, "Price, Interest Rate and Credit Risk Management Activities," on pages F-26 through F-29, to EOG's Consolidated Financial Statements included in EOG's 2008 Annual Report. There have been no material changes in this information. For additional information regarding EOG's financial commodity derivative contracts and physical commodity contracts, see (i) Note 13 to Consolidated Financial Statements in this Quarterly Report on Form 10-Q; (ii) "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Net Operating Revenues" in this Quarterly Report on Form 10-Q; and (iii) "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Commodity Derivative Transactions" in this Quarterly Report on Form 10-Q.

 

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, EOG's principal executive officer and principal financial officer have concluded that EOG's disclosure controls and procedures were effective as of the Evaluation Date in ensuring 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 (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act) that occurred during the quarterly 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.

-39-

 

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 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth, for the periods indicated, EOG's share repurchase activity:

             

Total Number of

   
   

Total

       

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)

                   

July 1, 2009 - July 31, 2009

 

2,203

 

$

72.97

 

-

 

6,386,200

August 1, 2009 - August 31, 2009

 

44,063

   

76.62

 

-

 

6,386,200

September 1, 2009 - September 30, 2009

 

2,869

   

78.86

 

-

 

6,386,200

Total

 

49,135

   

76.59

 

-

   
                   

(1) Represents 49,135 total shares for the quarter ended September 30, 2009 that consist solely of shares that were withheld by or returned to EOG
      (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or stock-settled stock appreciation rights
      or the vesting of restricted stock or restricted stock unit grants or (ii) in payment of the exercise price of employee stock options. These shares
      do not count against the 10 million aggregate share authorization by EOG's Board of Directors (Board) discussed below.
(2) In September 2001, the Board authorized the repurchase of up to 10 million shares of EOG's common stock. During the third quarter of 2009,
      EOG did not repurchase any shares under the Board-authorized repurchase program.

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ITEM 6. EXHIBITS

Exhibit No.                              Description

         4.1

-

Amendment No. 7 to Rights Agreement, dated as of October 7, 2009, between EOG and Computershare Trust Company, N.A., as rights agent (via succession) (incorporated by reference to Exhibit 4.12 to EOG's Current Report on Form 8-K, filed October 7, 2009).

     

*      31.1

-

Section 302 Certification of Periodic Report of Principal Executive Officer.

     

*      31.2

-

Section 302 Certification of Periodic Report of Principal Financial Officer.

     

*      32.1

-

Section 906 Certification of Periodic Report of Principal Executive Officer.

     

*      32.2

-

Section 906 Certification of Periodic Report of Principal Financial Officer.

     

* **101.INS

-

XBRL Instance Document.

     

* **101.SCH

-

XBRL Schema Document.

     

* **101.CAL

-

XBRL Calculation Linkbase Document.

     

* **101.LAB

-

XBRL Label Linkbase Document.

     

* **101.PRE

-

XBRL Presentation Linkbase Document.

     

* **101.DEF

-

XBRL Definition Linkbase Document.

     

* Exhibits filed herewith

** Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Statements of Income - Three Months Ended September 30, 2009 and 2008 and Nine Months Ended September 30, 2009 and 2008, (ii) the Consolidated Balance Sheets - September 30, 2009 and December 31, 2008, (iii) the Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2009 and 2008 and (iv) Notes to Consolidated Financial Statements. Users of this data are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

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SIGNATURES

 

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

 

   

EOG RESOURCES, INC.

   

(Registrant)

     
     
     

Date: November 5, 2009

By:

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

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EXHIBIT INDEX

Exhibit No.                            Description

         4.1

-

Amendment No. 7 to Rights Agreement, dated as of October 7, 2009, between EOG and Computershare Trust Company, N.A., as rights agent (via succession) (incorporated by reference to Exhibit 4.12 to EOG's Current Report on Form 8-K, filed October 7, 2009).

     

*      31.1

-

Section 302 Certification of Periodic Report of Principal Executive Officer.

     

*      31.2

-

Section 302 Certification of Periodic Report of Principal Financial Officer.

     

*      32.1

-

Section 906 Certification of Periodic Report of Principal Executive Officer.

     

*      32.2

-

Section 906 Certification of Periodic Report of Principal Financial Officer.

     

* **101.INS

-

XBRL Instance Document.

     

* **101.SCH

-

XBRL Schema Document.

     

* **101.CAL

-

XBRL Calculation Linkbase Document.

     

* **101.LAB

-

XBRL Label Linkbase Document.

     

* **101.PRE

-

XBRL Presentation Linkbase Document.

     

* **101.DEF

-

XBRL Definition Linkbase Document.

     

* Exhibits filed herewith

** Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Statements of Income - Three Months Ended September 30, 2009 and 2008 and Nine Months Ended September 30, 2009 and 2008, (ii) the Consolidated Balance Sheets - September 30, 2009 and December 31, 2008, (iii) the Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2009 and 2008 and (iv) Notes to Consolidated Financial Statements. Users of this data are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

-43-