UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2005
[ ] 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 Number) |
333 Clay Street, Suite 4200
Houston, Texas 77002-7361
(Address of principal executive offices, including zip code)
713-651-7000
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file reports), and (2) has been subject to such filing requirements for the past 90 days. YES x NO ¨
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). YES x NO ¨
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of July 20, 2005.
Title of each class | | Number of shares |
Common Stock, par value $0.01 per share | | 240,101,587 |
EOG RESOURCES, INC.
TABLE OF CONTENTS
| | Page No. |
| PART I. FINANCIAL INFORMATION | |
| | |
| ITEM 1. Financial Statements | |
| | |
| Consolidated Statements of Income - Three Months Ended June 30, 2005 and 2004 and Six Months Ended June 30, 2005 and 2004 | 3 |
| | |
| Consolidated Balance Sheets - June 30, 2005 and December 31, 2004 | 4 |
| | |
| Consolidated Statements of Cash Flows - Six Months Ended June 30, 2005 and 2004 | 5 |
| | |
| Notes to Consolidated Financial Statements | 6 |
| | |
| ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations | 13 |
| | |
| ITEM 3. Quantitative and Qualitative Disclosures About Market Risk | 25 |
| | |
| ITEM 4. Controls and Procedures | 25 |
| | |
| PART II. OTHER INFORMATION | |
| | |
| ITEM 1. Legal Proceedings | 26 |
| | |
| ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds | 26 |
| | |
| ITEM 4. Submission of Matters to a Vote of Security Holders | 26 |
| | |
| ITEM 6. Exhibits | 27 |
| | |
| SIGNATURES | 29 |
| | |
| EXHIBIT INDEX | 30 |
2
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, Except Per Share Amounts)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ ------------------------
2005 2004 2005 2004
----------- ----------- ----------- -----------
Net Operating Revenues
Wellhead Natural Gas $ 625,564 $ 430,134 $ 1,168,670 $ 847,005
Wellhead Crude Oil, Condensate and Natural Gas Liquids 157,307 102,401 301,843 192,859
Losses on Mark-to-Market Commodity Derivative Contracts - (14,563) (940) (59,018)
Other, Net 1,053 1,049 2,507 2,495
----------- ----------- ----------- -----------
Total 783,924 519,021 1,472,080 983,341
----------- ----------- ----------- -----------
Operating Expenses
Lease and Well, including Transportation 86,851 65,532 169,726 129,949
Exploration Costs 27,994 19,596 62,810 45,592
Dry Hole Costs 22,537 19,064 37,119 29,091
Impairments 24,231 15,711 36,403 33,359
Depreciation, Depletion and Amortization 159,896 116,224 312,912 230,021
General and Administrative 30,113 26,370 58,800 51,285
Taxes Other Than Income 37,613 29,788 79,526 65,872
----------- ----------- ----------- -----------
Total 389,235 292,285 757,296 585,169
----------- ----------- ----------- -----------
Operating Income 394,689 226,736 714,784 398,172
Other Income (Expense), Net 6,874 1,425 12,339 (1,304)
----------- ----------- ----------- -----------
Income Before Interest Expense and Income Taxes 401,563 228,161 727,123 396,868
Interest Expense, Net 14,687 15,416 28,644 32,099
----------- ----------- ----------- -----------
Income Before Income Taxes 386,876 212,745 698,479 364,769
Income Tax Provision 137,420 67,808 246,320 118,979
----------- ----------- ----------- -----------
Net Income 249,456 144,937 452,159 245,790
Preferred Stock Dividends 1,858 2,758 3,716 5,516
----------- ----------- ----------- -----------
Net Income Available to Common $ 247,598 $ 142,179 $ 448,443 $ 240,274
=========== =========== =========== ===========
Net Income Per Share Available to Common
Basic $ 1.04 $ 0.61 $ 1.89 $ 1.04
=========== =========== =========== ===========
Diluted $ 1.02 $ 0.60 $ 1.85 $ 1.02
=========== =========== =========== ===========
Average Number of Common Shares
Basic 238,252 232,776 237,752 232,103
=========== =========== =========== ===========
Diluted 243,414 237,417 242,771 236,455
=========== =========== =========== ===========
The accompanying notes are an integral part of these consolidated financial statements.
3
EOG RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Data)
(Unaudited)
June 30, December 31,
2005 2004
------------- -------------
ASSETS
Current Assets
Cash and Cash Equivalents $ 282,701 $ 20,980
Accounts Receivable, Net 450,606 447,742
Inventories 52,188 40,037
Assets from Price Risk Management Activities - 10,747
Deferred Income Taxes 26,644 22,227
Other 54,366 45,070
------------- -------------
Total 866,505 586,803
Oil and Gas Properties (Successful Efforts Method) 10,193,805 9,599,276
Less: Accumulated Depreciation, Depletion and Amortization (4,738,768) (4,497,673)
------------- -------------
Net Oil and Gas Properties 5,455,037 5,101,603
Other Assets 106,115 110,517
------------- -------------
Total Assets $ 6,427,657 $ 5,798,923
============= =============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts Payable $ 439,532 $ 424,581
Accrued Taxes Payable 65,059 51,116
Dividends Payable 9,831 7,394
Deferred Income Taxes 52,350 103,933
Other 38,000 45,180
------------- -------------
Total 604,772 632,204
Long-Term Debt 1,117,097 1,077,622
Other Liabilities 248,137 241,319
Deferred Income Taxes 1,058,229 902,354
Shareholders' Equity
Preferred Stock, $0.01 Par, 10,000,000 Shares Authorized:
Series B, 100,000 Shares Issued, Cumulative,
$100,000,000 Liquidation Preference 98,944 98,826
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and
249,460,000 Shares Issued 202,495 201,247
Additional Paid in Capital 38,391 21,047
Unearned Compensation (34,263) (29,861)
Accumulated Other Comprehensive Income 124,685 148,015
Retained Earnings 3,136,135 2,706,845
Common Stock Held in Treasury, 9,552,169 Shares at
June 30, 2005 and 11,605,112 Shares at December 31, 2004 (166,965) (200,695)
------------- -------------
Total Shareholders' Equity 3,399,422 2,945,424
------------- -------------
Total Liabilities and Shareholders' Equity $ 6,427,657 $ 5,798,923
============= =============
The accompanying notes are an integral part of these consolidated financial statements.
4
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
Six Months Ended
June 30,
----------------------
2005 2004
---------- ----------
Cash Flows From Operating Activities
Reconciliation of Net Income to Net Operating Cash Provided by Operating Activities:
Net Income $ 452,159 $ 245,790
Items Not Requiring Cash
Depreciation, Depletion and Amortization 312,912 230,021
Impairments 36,403 33,359
Deferred Income Taxes 109,278 84,216
Other, Net 5,333 11,277
Dry Hole Costs 37,119 29,091
Mark-to-Market Commodity Derivative Contracts
Total Losses 940 59,018
Realized Gains (Losses) 9,806 (38,211)
Tax Benefits from Stock Options Exercised 18,309 13,792
Other, Net (5,323) (1,273)
Changes in Components of Working Capital and Other Liabilities
Accounts Receivable (5,081) (62,082)
Inventories (12,185) (8,368)
Accounts Payable 16,934 41,515
Accrued Taxes Payable 5,200 1,329
Other Liabilities (5,324) 921
Other, Net (10,917) (10,339)
Changes in Components of Working Capital Associated with Investing
and Financing Activities 19,842 14,403
---------- ----------
Net Cash Provided by Operating Activities 985,405 644,458
Investing Cash Flows
Additions to Oil and Gas Properties (762,347) (563,631)
Proceeds from Sales of Assets 31,578 9,762
Changes in Components of Working Capital Associated with Investing Activities (19,950) (15,150)
Other, Net (16,111) (12,920)
---------- ----------
Net Cash Used in Investing Activities (766,830) (581,939)
Financing Cash Flows
Net Commercial Paper and Line of Credit Borrowings (Repayments) 39,475 (98,050)
Long-Term Debt Borrowings - 150,000
Long-Term Debt Repayments - (75,000)
Dividends Paid (20,220) (18,957)
Proceeds from Stock Options Exercised 24,372 42,294
Other, Net 108 (784)
---------- ----------
Net Cash Provided by (Used in) Financing Activities 43,735 (497)
Effect of Exchange Rate Changes on Cash (589) 1,374
---------- ----------
Increase in Cash and Cash Equivalents 261,721 63,396
Cash and Cash Equivalents at Beginning of Period 20,980 4,443
---------- ----------
Cash and Cash Equivalents at End of Period $ 282,701 $ 67,839
========== ==========
The accompanying notes are an integral part of these consolidated financial statements.
5
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. The consolidated financial statements of EOG Resources, Inc. and subsidiaries (EOG) included herein have been prepared by management without audit pursuant to the rules and regulations of the Securities and Exchange Commission (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. Certain information and notes normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations. However, management believes that the disclosures are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in EOG's Annual Report on Form 10-K for the year ended December 31, 2004 (EOG's 2004 Annual Report).
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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.
On February 2, 2005, EOG announced that the Board of Directors had approved a two-for-one stock split in the form of a stock dividend, payable to record holders as of February 15, 2005 and issued on March 1, 2005. All share and per share amounts in the financial statements and accompanying footnotes for all periods have been restated to reflect the two- for-one stock split paid to common shareholders.
On February 24, 2005, the Board of Directors approved an amendment to EOG's Restated Certificate of Incorporation to increase the number of EOG's authorized shares of common stock to 640 million. The shareholders approved the increase at the Annual Meeting of Shareholders on May 3, 2005, and the amendment was filed with the Delaware Secretary of State on May 9, 2005.
Certain reclassifications have been made to prior period financial statements to conform with the current presentation.
Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. As of December 31, 2004, EOG had exploratory drilling costs of $4.3 million, related to an outside operated, deepwater offshore Gulf of Mexico discovery. The amount remained unchanged as of June 30, 2005. Also, as of June 30, 2005, EOG had exploratory drilling costs of $8.5 million related to a Northwest Territories discovery in Northern Canada. These amounts have been deferred for more than one year and will require significant future capital expenditures before production can commence.
As more fully discussed in Note 11 to the consolidated financial statements included in EOG's 2004 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 collars and price swaps, as the means to manage this price risk. During the second quarter of 2005, EOG was not a party to any financial commodity derivative contracts. In 2004 and the first quarter of 2005, EOG accounted for the financial commodity derivative contracts using the mark-to-market accounting method. 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 these various physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.
6
On October 22, 2004, the American Jobs Creation Act of 2004 (the Act) was enacted. Among other things, the Act creates a temporary incentive for United States corporations to repatriate accumulated income earned abroad by providing an 85% dividends received deduction for certain dividends from controlled foreign corporations. A comprehensive analysis of United States and foreign legal and tax ramifications, as well as EOG's future foreign capital requirements, must be completed before such dividends are declared. As such, EOG is not yet in a position to decide to what extent, if any, it might repatriate foreign earnings that have not yet been remitted to the United States. EOG expects to be in a position to complete the assessment by October 31, 2005.
In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 153, "Exchanges of Nonmonetary Assets, an Amendment of Accounting Principles Board (APB) Opinion No. 29," which provides that all nonmonetary asset exchanges that have commercial substance must be measured based on the fair value of the assets exchanged and any resulting gain or loss be recorded. An exchange is defined as having commercial substance if it results in a significant change in expected future cash flows. Exchanges of operating interest by oil and gas producing companies to form a joint venture continue to be exempted. APB Opinion No. 29 previously exempted all exchanges of similar productive assets from fair value accounting, therefore resulting in no gain or loss recorded for such exchanges. SFAS No. 153 will be effective for fiscal periods beginning on or after June 15, 2005. EOG does not expect SFAS No. 153 to have a material impact on its financial statements.
In December 2004, the FASB issued SFAS No. 123(R), "Share-Based Payment," which supersedes SFAS No. 148. SFAS No. 123(R) requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. This eliminates the exception to account for such awards using the intrinsic method previously allowable under APB Opinion No. 25 "Accounting for Stock Issued to Employees." In March 2005, the SEC issued Staff Accounting Bulletin (SAB) 107. Among other things, SAB 107 provides interpretive guidance related to the interaction between SFAS No. 123(R) and certain SEC rules and regulations, as well as provides the SEC staff's views regarding the valuation of share-based payment arrangements for public companies. On April 14, 2005, the SEC issued press release 2005-57 which amends the compliance date of SFAS No. 123(R). As a result, SFAS No. 123(R) will be effective for annual reporting periods beginning on or after June 15, 2005. EOG currently expects to adopt SFAS No. 123(R) effective January 1, 2006 using the modified prospective method.
Until the adoption of SFAS No. 123(R), EOG continues to account for its stock option plans and Employee Stock Purchase Plan under the provisions and related interpretations of APB Opinion No. 25. No compensation expense is recognized for such options. As allowed by SFAS No. 123, "Accounting for Stock-Based Compensation," issued in 1995, EOG has continued to apply APB Opinion No. 25 for purposes of determining net income and to present the pro forma disclosures required by SFAS No. 123.
For stock option grants made prior to August 2004, the fair value of each option grant is estimated using the Black-Scholes Option Pricing Model. Beginning in August 2004, EOG's employee stock options contain a feature that limits the potential gain that can be realized by requiring vested options to be exercised if the market price reaches 200% of the grant price for five consecutive trading days (Capped Option). EOG may or may not continue this capped feature in the future. The fair value of each Capped Option grant is estimated using a Monte Carlo simulation. The fair value of grants under its Employee Stock Purchase Plan is estimated using the Black-Scholes option pricing model. Effective May 2005, the fair value of stock options granted to EOG's Board of Directors is estimated using the Hull-White II Model, a lattice option pricing model.
7
EOG's pro forma Net Income and Net Income Per Share Available to Common for the three-month and six-month periods ended June 30, 2005 and 2004, had compensation costs been recorded in accordance with SFAS No. 123, are presented below (in millions, except per share data):
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- --------------------
2005 2004 2005 2004
--------- --------- --------- ---------
Net Income Available to Common - As Reported $ 247.6 $ 142.2 $ 448.4 $ 240.3
Deduct: Total Stock-Based Employee Compensation
Expense, Net of Income Tax (3.0) (2.9) (6.2) (5.4)
--------- --------- --------- ---------
Net Income Available to Common - Pro Forma $ 244.6 $ 139.3 $ 442.2 $ 234.9
========= ========= ========= =========
Net Income Per Share Available to Common
Basic - As Reported $ 1.04 $ 0.61 * $ 1.89 $ 1.04 *
========= ========= ========= =========
Basic - Pro Forma $ 1.03 $ 0.60 * $ 1.86 $ 1.01 *
========= ========= ========= =========
Diluted - As Reported $ 1.02 $ 0.60 * $ 1.85 $ 1.02 *
========= ========= ========= =========
Diluted - Pro Forma $ 1.00 $ 0.59 * $ 1.82 $ 0.99 *
========= ========= ========= =========
* Restated for two-for-one stock split effective March 1, 2005 (see above).
The effects of applying SFAS No. 123, as amended, in this pro forma disclosure should not be interpreted as being indicative of future effects, including the extent and timing of additional future awards.
In March 2005, the FASB issued FASB Interpretation (FIN) No. 47, "Accounting for Conditional Asset Retirement Obligations." The interpretation clarifies the requirement to record abandonment liabilities stemming from legal obligations when the retirement depends on a conditional future event. FIN No. 47 requires that the uncertainty about the timing or method of settlement of a conditional retirement obligation be factored into the measurement of the liability when sufficient information exists. FIN No. 47 is effective for fiscal years ending after December 15, 2005. EOG does not expect FIN No. 47 will have a material impact on its financial statements.
In April 2005, the FASB issued Staff Position No. FAS (FSP) 19-1, "Accounting for Suspended Well Costs." FSP 19-1 amended SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies," to provide for the continued capitalization of exploratory well costs beyond one year of the drilling commencement date when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. FSP 19-1 also amends SFAS No. 19 to require additional disclosures of suspended exploratory well costs in the notes to the financial statements for annual and interim periods when there has been a significant change from the previous reporting period. The guidance of FSP 19- 1 is effective for the first reporting period beginning after April 5, 2005 and is to be applied prospectively. EOG does not expect FSP 19-1 will have a material impact on its financial statements.
8
2. The following table sets forth the computation of Net Income Per Share Available to Common for the three-month and six-month periods ended June 30 (in thousands, except per share amounts):
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ ------------------------
2005 2004 2005 2004
----------- ----------- ----------- -----------
Numerator for Basic and Diluted Earnings Per Share -
Net Income Available to Common $ 247,598 $ 142,179 $ 448,443 $ 240,274
=========== =========== =========== ===========
Denominator for Basic Earnings Per Share -
Weighted Average Shares 238,252 232,776 * 237,752 232,103 *
Potential Dilutive Common Shares -
Stock Options 4,038 3,734 * 3,914 3,469 *
Restricted Stock and Units 1,124 907 * 1,105 883 *
----------- ----------- ----------- -----------
Denominator for Diluted Earnings Per Share -
Adjusted Weighted Average Shares 243,414 237,417 * 242,771 236,455 *
=========== =========== =========== ===========
Net Income Per Share Available to Common
Basic $ 1.04 $ 0.61 * $ 1.89 $ 1.04 *
=========== =========== =========== ===========
Diluted $ 1.02 $ 0.60 * $ 1.85 $ 1.02 *
=========== =========== =========== ===========
* Restated for two-for-one stock split effective March 1, 2005 (see Note 1).
3. The following table presents the components of EOG's comprehensive income for the three-month and six-month periods ended June 30 (in thousands):
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ ------------------------
2005 2004 2005 2004
----------- ----------- ----------- -----------
Comprehensive Income
Net Income $ 249,456 $ 144,937 $ 452,159 $ 245,790
Other Comprehensive Income
Foreign Currency Translation Adjustment (15,289) (18,573) (20,215) (30,746)
Foreign Currency Swap Transaction (1,139) (2,517) (4,730) (2,517)
Income Tax Benefit Related to Foreign Currency Swap Transaction 372 802 1,615 802
----------- ----------- ----------- -----------
Total $ 233,400 $ 124,649 $ 428,829 $ 213,329
=========== =========== =========== ===========
9
4. Selected financial information by reportable segment is presented below for the three-month and six-month periods ended June 30 (in thousands):
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ ------------------------
2005 2004 2005 2004
----------- ----------- ----------- -----------
Net Operating Revenues
United States $ 551,131 $ 388,258 $ 1,034,821 $ 723,026
Canada 138,212 99,965 272,199 200,767
Trinidad 76,836 * 30,798 125,827 * 59,548
United Kingdom 17,745 - 39,233 -
----------- ----------- ----------- -----------
Total $ 783,924 $ 519,021 $ 1,472,080 $ 983,341
=========== =========== =========== ===========
Operating Income (Loss)
United States $ 256,349 $ 152,113 $ 465,150 $ 253,118
Canada 78,352 54,769 143,658 109,018
Trinidad 63,156 21,401 93,412 41,278
United Kingdom (3,168) (1,547) 12,564 (5,242)
----------- ----------- ----------- -----------
Total 394,689 226,736 714,784 398,172
Reconciling Items
Other Income (Expense), Net 6,874 1,425 12,339 (1,304)
Interest Expense, Net 14,687 15,416 28,644 32,099
----------- ----------- ----------- -----------
Income Before Income Taxes $ 386,876 $ 212,745 $ 698,479 $ 364,769
=========== =========== =========== ===========
* Includes $19.3 million recorded in the second quarter of 2005 related to an amended Trinidad take-or-pay contract.
5. There are various suits and claims against EOG that have arisen in the ordinary course of business. Management believes that the chance that these suits and claims will individually, or in the aggregate, have a material adverse effect on the financial condition or results of operations of EOG is remote. When necessary, EOG has made accruals in accordance with SFAS No. 5, "Accounting for Contingencies," in order to provide for these matters.
10
6. The following table presents the reconciliation of the beginning and ending aggregate carrying amount of short-term and long-term legal obligations associated with the retirement of oil and gas properties pursuant to SFAS No. 143, "Accounting for Asset Retirement Obligations," for the three-month periods ended March 31 and June 30, 2005 (in thousands):
Asset Retirement Obligations
-------------------------------------
Short-Term Long-Term Total
----------- ----------- -----------
Balance at December 31, 2004 $ 6,970 $ 131,789 $ 138,759
Liabilities Incurred 45 661 706
Liabilities Settled (579) (406) (985)
Accretion 46 1,520 1,566
Revision (1) 1,604 1,603
Reclassification 761 (761) -
Foreign Currency Translation (6) (135) (141)
----------- ----------- -----------
Balance at March 31, 2005 7,236 134,272 141,508
Liabilities Incurred 1,243 989 2,232
Liabilities Settled (511) (619) (1,130)
Accretion 8 2,054 2,062
Revision (1,437) (196) (1,633)
Reclassification (16) 16 -
Foreign Currency Translation 85 526 611
----------- ----------- -----------
Balance at June 30, 2005 $ 6,608 $ 137,042 $ 143,650
=========== =========== ===========
7.Restricted Stock and Units. Under EOG's various stock plans, employees may be granted restricted stock and/or units without cost to them. Related compensation expense for the three-month periods ended June 30, 2005 and 2004 was $3.0 million and $2.4 million, respectively. Related compensation expense for the six-month periods ended June 30, 2005 and 2004 was $5.7 million and $4.4 million, respectively.
Pension Plans. EOG has non-contributory defined contribution pension plans and matched defined contribution savings plans in place for most of its employees. For the three-month periods ended June 30, 2005 and 2004, EOG's total contributions to these pension plans were $2.7 million and $3.0 million, respectively. For the six-month periods ended June 30, 2005 and 2004, EOG's total contributions to these pension plans were $6.2 million and $6.1 million, respectively.
11
Postretirement Plan. The following table summarizes the benefit expense for EOG's contributory defined dollar benefit postretirement medical plan for the three-month and six-month periods ended June 30 (in thousands):
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- --------------------
2005 2004 2005 2004
--------- --------- --------- ---------
Service Cost $ 40 $ 36 $ 82 $ 106
Interest Cost 31 29 62 79
Expected Return on Plan Assets - - - -
Amortization of Prior Service Cost 33 32 65 65
Amortization of Net Actuarial (Gain) Loss (20) (18) (35) (18)
--------- --------- --------- ---------
Net Periodic Benefit Cost $ 84 $ 79 $ 174 $ 232
========= ========= ========= =========
EOG previously disclosed in its financial statements for the year ended December 31, 2004, that it expected to contribute $84,000 to its postretirement plan in 2005. As of June 30, 2005, $32,000 of contributions have been made. EOG presently anticipates contributing an additional $52,000 to fund its postretirement plan in 2005.
8. On June 28, 2005, EOG entered into a new five-year $600 million unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders and JPMorgan Chase Bank, N.A., as Administrative Agent, and concurrently terminated the existing $600 million three-year credit facility scheduled to expire in July 2006. Under the Agreement, EOG has the option to extend the term for successive one-year periods with the consent of the majority banks and to request increases in the aggregate commitments to an amount not to exceed $1 billion. The Agreement also provides for the allocation, at the option of EOG, of up to $75 million of the $600 million each to EOG's current United Kingdom subsidiary and one of its Canadian subsidiaries. Interest accrues on advances at LIBOR plus an applicable margin (Eurodollar rate) or at the Adminstrative Agent's base rate, as selected by EOG. Advances to the Canadian or the United Kingdom subsidiaries, should they occur, would be guaranteed by EOG and would bear interest at a rate calculated in accordance with the Agreement. In addition, the Agreement provides EOG the option to request letters of credit to be issued in an aggregate amount of up to $200 million. EOG has not borrowed under this Agreement. The applicable base rate and Eurodollar rate, had there been an amount borrowed under the Agreement, would have been 6.25% and 3.58% at June 30, 2005, respectively.
On March 9, 2004, under Rule 144A of the Securities Act of 1933, as amended, EOG Resources Canada Inc., a wholly owned subsidiary of EOG, issued notes with a total principal amount of US$150 million, an annual interest rate of 4.75% and a maturity date of March 15, 2014. The notes are guaranteed by EOG. In conjunction with the offering, EOG entered into a cross currency swap transaction with multiple banks for the equivalent amount of the notes, which has in effect converted this indebtedness into CAD$201.3 million with a 5.275% interest rate.
On March 31, 2004, EOG repaid $75 million of its $150 million floating rate Senior Unsecured Term Loan Facility with a maturity date of October 30, 2005.
12
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EOG RESOURCES, INC.
Overview
EOG Resources, Inc. (EOG) is one of the largest independent (non-integrated) oil and natural gas companies in the United States with proved reserves in the United States, Canada, offshore Trinidad and the United Kingdom North Sea. EOG operates under a consistent business and operational strategy which focuses predominantly on achieving a strong reinvestment rate of return, drilling internally generated prospects, delivering long-term production growth and maintaining a strong balance sheet.
Operations. EOG's effort to identify plays with larger reserve potential has proven a successful supplement to its base development and exploitation program in the United States and Canada. EOG plans to continue to drill smaller wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's crude oil and natural gas production. EOG has several larger potential plays under way in Wyoming, Utah, Texas, Oklahoma and western Canada.
Although EOG continues to focus on United States and Canada natural gas, EOG sees an increasing linkage between United States and Canada natural gas demand and Trinidad natural gas supply. For example, liquefied natural gas (LNG) imports from existing and planned facilities in Trinidad are serious contenders to meet increasing United States demand. In addition, ammonia, methanol and chemical production has been relocating from the United States and Canada to Trinidad, driven by attractive natural gas feedstock prices in the island nation. EOG anticipates that its existing position with the supply contracts to two ammonia plants and a new methanol plant will continue to give its portfolio an even broader exposure to United States and Canada natural gas fundamentals. The methanol plant is expected to commence operations in August 2005.
In July 2005, EOG, through its subsidiary, EOG Resources Trinidad Block 4(a) Unlimited, signed a production sharing contract with the Government of Trinidad and Tobago for Block 4(a) which is located off Trinidad's East Coast. EOG holds a 90% working interest in Block 4(a).
EOG continues its progress in the Southern Gas Basin of the United Kingdom North Sea. In addition to EOG's current production from the Valkyrie and Arthur fields, production from the Arthur 2 well, in which EOG has a 30 percent working interest, commenced in July 2005. The Arthur 2 well was drilled during the first quarter of 2005 as an extension to the Arthur 1 discovery. EOG continues to review additional opportunities in the United Kingdom North Sea and expects to participate in additional exploratory wells in 2005.
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Capital Structure. As noted, one of management's key strategies is to keep a strong balance sheet with a consistently below average year-end debt-to-total capitalization ratio as compared to those in EOG's peer group. At June 30, 2005, EOG's debt-to-total capitalization ratio was 25%, down slightly from 26% at March 31, 2005. In addition, EOG's cash balance increased to $283 million. During the first six months of 2005, EOG funded its capital programs by utilizing cash provided from its operating activities. On February 2, 2005, EOG increased the quarterly cash dividend on common stock by 33%, beginning with dividends payable on April 29, 2005. As management continues to assess price forecast and demand trends for 2005, EOG believes that operations and capital expenditure activity can be funded by cash from operations.
On June 28, 2005, EOG entered into a new five-year $600 million unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders and concurrently terminated the existing $600 million three-year credit facility scheduled to expire in July 2006. Under the Agreement, EOG has the option to extend the term for successive one-year periods with the consent of the majority banks and to request increases in the aggregate commitments to an amount not to exceed $1 billion. The Agreement also provides for the allocation, at the option of EOG, of up to $75 million of the $600 million each to EOG's current United Kingdom subsidiary and one of its Canadian subsidiaries. EOG has not borrowed under the Agreement.
For 2005, EOG's estimated exploration and development expenditure budget is approximately $1.7 billion, excluding acquisitions. United States and Canada natural gas continues to be a key component of this effort. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer EOG incremental exploration and/or production opportunities. Management continues to believe EOG has one of the strongest prospect inventories in EOG's history.
Results of Operations
The following review of operations for the three-month and six-month periods ended June 30, 2005 and 2004 should be read in conjunction with the consolidated financial statements of EOG and notes thereto.
Three Months Ended June 30, 2005 vs. Three Months Ended June 30, 2004
Net Operating Revenues. During the second quarter of 2005, net operating revenues increased $265 million to $784 million from $519 million for the same period in 2004. Total wellhead revenues, which are revenues generated from sales of natural gas, crude oil, condensate and natural gas liquids from producing wells, increased $250 million, or 47%, to $783 million, as compared to $533 million for the same period in 2004.
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Wellhead volume and price statistics for the three-month periods ended June 30 were as follows:
Three Months Ended
June 30,
--------------------
2005 2004
--------- ---------
Natural Gas Volumes (MMcf per day) (1)
United States 706 619
Canada 228 197
--------- ---------
United States and Canada 934 816
Trinidad 214 162
United Kingdom 34 -
--------- ---------
Total 1,182 978
========= =========
Average Natural Gas Prices ($/Mcf) (2)
United States $ 6.64 $ 5.67
Canada 6.02 5.04
United States and Canada 6.49 5.52
Trinidad (3) 2.92 1.36
United Kingdom 5.54 -
Composite 5.82 4.83
Crude Oil and Condensate Volumes (MBbl per day) (1)
United States 21.7 21.0
Canada 2.5 2.6
--------- ---------
United States and Canada 24.2 23.6
Trinidad 4.2 3.1
United Kingdom 0.1 -
--------- ---------
Total 28.5 26.7
========= =========
Average Crude Oil and Condensate Prices ($/Bbl) (2)
United States $ 51.03 $ 37.39
Canada 46.58 35.59
United States and Canada 50.58 37.19
Trinidad 53.05 37.69
United Kingdom 49.10 -
Composite 50.93 37.25
Natural Gas Liquids Volumes (MBbl per day) (1)
United States 7.9 5.0
Canada 1.2 0.6
--------- ---------
Total 9.1 5.6
========= =========
Average Natural Gas Liquids Prices ($/Bbl) (2)
United States $ 30.51 $ 23.78
Canada 30.52 20.35
Composite 30.51 23.40
Natural Gas Equivalent Volumes (MMcfe per day) (4)
United States 885 775
Canada 249 216
--------- ---------
United States and Canada 1,134 991
Trinidad 238 181
United Kingdom 35 -
--------- ---------
Total 1,407 1,172
========= =========
Total Bcfe (4) Deliveries 128.1 106.6
(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) Dollars per thousand cubic feet or per barrel, as applicable.
(3) Includes $0.99 per Mcf as a result of a revenue adjustment in the second quarter of 2005 related to an amended Trinidad take-or-pay contract.
(4) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil, condensate and natural gas liquids.
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Wellhead natural gas revenues for the second quarter of 2005 increased $196 million, or 46%, to $626 million from $430 million for the same period of 2004 due to increased natural gas deliveries ($90 million), higher composite average wellhead natural gas price ($87 million) and a revenue adjustment related to an amended Trinidad take-or-pay contract ($19 million). The composite average wellhead price for natural gas increased 20% to $5.82 per Mcf for the second quarter of 2005 from $4.83 per Mcf for the same period in 2004. Excluding the aforementioned adjustment, the composite average wellhead price for natural gas increased 17% to $5.64 per Mcf for the second quarter of 2005 from $4.83 per Mcf for the same period in 2004. This adjustment increased the average Trinidad wellhead natural gas price by $0.99 per Mcf for the second quarter of 2005.
Natural gas deliveries increased 204 MMcf per day, or 21%, to 1,182 MMcf per day for the second quarter of 2005 from 978 MMcf per day for the same period in 2004, due to an 87 MMcf per day, or 14%, increase in the United States; a 52 MMcf per day, or 32%, increase in Trinidad; a 34 MMcf per day increase in the United Kingdom; and a 31 MMcf per day, or 16%, increase in Canada. The increase in the United States was primarily attributable to increased production from Texas (63 MMcf per day), Louisiana (19 MMcf per day), and the Rocky Mountain area (10 MMcf per day). The increase in Trinidad was attributable to the increased production from the U(a) block (55 MMcf per day) which began supplying natural gas late in the second quarter of 2004 to the Nitrogen (2000) Unlimited (N2000) ammonia plant. The increase in the United Kingdom was due to the commencement of production in August 2004. The increase in Canada was attributable to additional production from drilling programs.
Wellhead crude oil and condensate revenues increased $42 million, or 47%, to $132 million from $90 million as compared to the same period in 2004, due to increases in both the composite average wellhead crude oil and condensate price ($36 million) and the wellhead crude oil and condensate deliveries ($6 million). The composite average wellhead crude oil and condensate price for the second quarter of 2005 was $50.93 per barrel compared to $37.25 per barrel for the same period in 2004.
Wellhead crude oil and condensate deliveries increased 1.8 MBbl per day, or 7%, to 28.5 MBbl per day from 26.7 MBbl per day for the same period in 2004. The increase was mainly due to higher production in Trinidad from the U(a) block (1.0 MBbl per day) and higher production in the United States (0.7 MBbl per day).
Natural gas liquids revenues were $13 million higher than a year ago primarily due to increases in deliveries ($7 million) and the increase in the composite average price ($6 million).
Beginning in the second quarter of 2005, EOG has not been a party to any financial commodity derivative contracts. During the second quarter of 2004, EOG recognized a loss on mark-to-market financial commodity derivative contracts of $15 million and the net cash inflow related to settled natural gas financial collar contracts and settled natural gas and crude oil financial price swap contracts was $36 million.
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Operating and Other Expenses. For the second quarter of 2005, operating expenses of $389 million were $97 million higher than the $292 million incurred in the second quarter of 2004. The following table presents the costs per Mcfe for the three-month periods ended June 30:
Three Months Ended
June 30,
--------------------
2005 2004
--------- ---------
Lease and Well, including Transportation $ 0.68 $ 0.61
Depreciation, Depletion and Amortization (DD&A) 1.25 1.09
General and Administrative (G&A) 0.24 0.25
Taxes Other Than Income 0.29 0.28
Interest Expense, Net 0.11 0.15
--------- ---------
Total Per-Unit Costs* $ 2.57 $ 2.38
========= =========
* Total per-unit costs do not include exploration costs, dry hole costs and impairments.
The higher per-unit rates of lease and well, including transportation, DD&A and taxes other than income for the three-month period ended June 30, 2005 compared to the same period in 2004 were due primarily to the reasons set forth below.
Lease and well expense includes EOG's lease and well expenses for EOG operated properties, as well as lease and well expenses billed to EOG from other operators where EOG is not the operator of a property. Lease and well expense can be divided into the following categories: costs to operate and maintain EOG's oil and gas wells, the cost of workovers, transportation costs associated with selling hydrocarbon products and lease and well administrative expenses. Operating and maintenance expenses include, among other service costs, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep, fuel and power. Workovers are costs of operations to restore, maintain or increase production from existing wells.
Each of these categories of costs individually fluctuate from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.
Lease and well expenses of $87 million were $21 million higher than the prior year period primarily due to higher operating and maintenance expenses in the United States ($8 million) and increased transportation related costs in the United States ($6 million) and the United Kingdom ($2 million).In addition, higher lease and well administrative expenses in the United States ($2 million), changes in the Canadian exchange rate ($2 million), and higher workover expenditures in Canada ($1 million) contributed to the increase in lease and well expenses.
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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. The individual field expense is calculated by dividing sales volume by reserves and multiplying the result by the depreciable net book value. There are several factors that can impact an individual field, such as the field production profile; drilling or acquisition of new wells; disposition of existing wells; reserve revisions (upward or downward), primarily related to well performance; and impairments. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are also taken into account. Changes to the individual fields, due to any of these factors, may cause EOG's composite DD&A rate and expense to fluctuate from quarter to quarter.
DD&A expenses of $160 million increased $44 million from the prior year period primarily due to increased DD&A rates in the United States ($16 million) and Canada ($4 million); increased production in the United States ($13 million), Canada ($3 million) and Trinidad ($1 million), as discussed previously in the Net Operating Revenues section; the commencement of production in August 2004 in the United Kingdom ($3 million); and changes in the Canadian exchange rate ($3 million).
G&A expenses of $30 million were $4 million higher than the prior year period primarily due to expanded operations.
Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Taxes other than income of $38 million were $8 million higher than the prior year period primarily due to increased wellhead revenues in the United States ($6 million) and production tax relief in the second quarter of 2004 in Trinidad ($3 million), partially offset by an increase in credits taken against severance taxes resulting from the qualification of additional wells for a Texas high cost gas severance tax exemption ($3 million).
Exploration costs of $28 million were $8 million higher than the prior year period primarily due to increased geological and geophysical expenditures in the United States.
Impairments of $24 million increased by $8 million from $16 million in the prior year period. Under Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long- Lived Assets," which requires an entity to compute impairments to the carrying value of long-lived assets based on future cash flow analysis, EOG recorded impairments of $12 million and $2 million for the second quarters of 2005 and 2004, respectively, for certain properties in the United States.
Other income, net was $7 million for the second quarter of 2005 compared to $1 million for the second quarter of 2004. The increase of $6 million was primarily due to increased equity income from investments in the Caribbean Nitrogen Company Limited (CNCL) and N2000 ammonia plants ($3 million), gain on sale of properties ($1 million) and interest income ($1 million).
Income tax provision of $137 million increased $69 million compared to the second quarter of 2004, due primarily to higher pre-tax income ($65 million) and an Alberta (Canada) corporate tax rate reduction occurring in the second quarter of 2004 ($5 million). The net effective tax rate for the second quarter of 2005 increased to 36% from 32% for the same period of 2004.
Six Months Ended June 30, 2005 vs. Six Months Ended June 30, 2004
Net Operating Revenues. During the first half of 2005, net operating revenues increased $489 million to $1,472 million from $983 million for the same period in 2004. Total wellhead revenues increased $431 million, or 41% to $1,471 million as compared to $1,040 million for the same period in 2004.
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Wellhead volume and price statistics for the six-month periods ended June 30 were as follows:
Six Months Ended
June 30,
--------------------
2005 2004
--------- ---------
Natural Gas Volumes (MMcf per day)
United States 698 618
Canada 231 201
--------- ---------
United States and Canada 929 819
Trinidad 209 158
United Kingdom 34 -
--------- ---------
Total 1,172 977
========= =========
Average Natural Gas Prices ($/Mcf)
United States $ 6.31 $ 5.54
Canada 5.85 5.01
United States and Canada 6.20 5.41
Trinidad (1) 2.35 1.42
United Kingdom 6.10 -
Composite 5.51 4.77
Crude Oil and Condensate Volumes (MBbl per day)
United States 22.1 20.5
Canada 2.5 2.6
--------- ---------
United States and Canada 24.6 23.1
Trinidad 4.1 2.8
United Kingdom 0.2 -
--------- ---------
Total 28.9 25.9
========= =========
Average Crude Oil and Condensate Prices ($/Bbl)
United States $ 49.90 $ 36.11
Canada 45.68 33.63
United States and Canada 49.47 35.83
Trinidad 49.22 35.52
United Kingdom 43.93 -
Composite 49.41 35.80
Natural Gas Liquids Volumes (MBbl per day)
United States 6.7 4.9
Canada 1.3 0.6
--------- ---------
Total 8.0 5.5
========= =========
Average Natural Gas Liquids Prices ($/Bbl)
United States $ 30.01 $ 24.24
Canada 28.80 20.25
Composite 29.81 23.80
Natural Gas Equivalent Volumes (MMcfe per day)
United States 870 771
Canada 254 219
--------- ---------
United States and Canada 1,124 990
Trinidad 235 175
United Kingdom 35 -
--------- ---------
Total 1,394 1,165
========= =========
Total Bcfe Deliveries 252.3 212.1
(1) Includes $0.51 per Mcf as a result of a revenue adjustment in the second quarter of 2005 related to an amended Trinidad take-or-pay contract.
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Wellhead natural gas revenues for the first six months of 2005 increased $322 million, or 38%, to $1,169 million from $847 million for the same period of 2004 due to increased natural gas deliveries ($165 million), higher composite average wellhead natural gas price ($138 million) and a revenue adjustment related to an amended Trinidad take-or-pay contract ($19 million). The composite average wellhead price for natural gas increased 16% to $5.51 per Mcf from $4.77 per Mcf for the same period of 2004. Excluding the aforementioned adjustment, the composite average wellhead price for natural gas increased 14% to $5.42 per Mcf from $4.77 per Mcf for the same period in 2004. This adjustment increased the average Trinidad wellhead natural gas price by $0.51 per Mcf for the first six months of 2005.
Natural gas deliveries increased 195 MMcf per day, or 20%, to 1,172 MMcf per day for the first half of 2005 from 977 MMcf per day for the same period in 2004, due to an 80 MMcf per day, or 13%, increase in the United States; a 51 MMcf per day, or 32%, increase in Trinidad; a 34 MMcf per day increase in the United Kingdom; and a 30 MMcf per day, or 15%, increase in Canada. The increase in the United States was primarily attributable to increased production from Texas (49 MMcf per day), Louisiana (17 MMcf per day), and the Rocky Mountain area (13 MMcf per day). The increase in Trinidad was mainly attributable to the increased production from the U(a) block (50 MMcf per day) which began supplying natural gas late in the second quarter of 2004 to the N2000 ammonia plant. The increase in the United Kingdom was due to the commencement of production in August 2004. The increase in Canada was attributable to additional production from drilling programs.
Wellhead crude oil and condensate revenues increased $89 million, or 53%, to $258 million from $169 million as compared to the same period in 2004, due to increases in both the composite average wellhead crude oil and condensate price ($71 million) and the wellhead crude oil and condensate deliveries ($18 million). The composite average wellhead crude oil and condensate price for the first half of 2005 was $49.41 per barrel compared to $35.80 per barrel for the same period in 2004.
Wellhead crude oil and condensate deliveries increased 3.0 MBbl per day, or 12%, to 28.9 MBbl per day from 25.9 MBbl per day for the same period of 2004. The increase was mainly due to higher production in Trinidad from the U(a) block (0.8 MBbl per day) and higher production in the United States (1.6 MBbl per day).
Natural gas liquids revenues were $20 million higher than a year ago primarily due to increases in deliveries ($11 million) and the increase in the composite average price ($9 million).
During the first quarter of 2005, EOG recognized a loss on mark-to-market financial commodity derivative contracts of $1 million and a net cash inflow related to settled natural gas financial collar contracts of $10 million. Beginning in the second quarter of 2005, EOG has not been a party to any financial commodity derivative contracts. During the first six months of 2004, EOG recognized a loss of $59 million and a net cash outflow related to settled natural gas financial collar contracts and settled natural gas and crude oil financial price swap contracts of $38 million.
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Operating and Other Expenses. For the first six months of 2005, operating expenses of $757 million were $172million higher than the $585million incurred in the same period of 2004. The following table presents the costs per Mcfe for the six-month periods ended June 30:
Six Months Ended
June 30,
--------------------
2005 2004
--------- ---------
Lease and Well, including Transportation $ 0.67 $ 0.61
DD&A 1.24 1.09
G&A 0.23 0.24
Taxes Other Than Income 0.32 0.31
Interest Expense, Net 0.11 0.15
--------- ---------
Total Per-Unit Costs* $ 2.57 $ 2.40
========= =========
*Total per-unit costs do not include exploration costs, dry hole costs and impairments.
The higher per-unit rates of lease and well, including transportation, DD&A and taxes other than income for the six-month period ended June 30, 2005 compared to the same period in 2004 were due primarily to the reasons set forth below.
Lease and well expenses of $170 million were $40 million higher than the prior year primarily due to higher operating and maintenance expenses in the United States ($13 million) and the United Kingdom ($1 million), and increased transportation related costs in the United States ($9 million) and the United Kingdom ($4 million). In addition, higher lease and well administrative expenses in the United States ($4 million) and Trinidad ($1 million), changes in the Canadian exchange rate ($3 million), and higher workover expenditures in Trinidad ($2 million) and Canada ($1 million) contributed to the increase in lease and well expenses.
DD&A expenses of $313million increased $83million from the prior year period primarily due to increased DD&A rates in the United States ($34million) and Canada ($8 million); increased production in the United States ($22million), Canada ($6million) and Trinidad ($3million), as discussed previously in the Net Operating Revenues section; the commencement of production in August 2004 in the United Kingdom ($5million); and changes in the Canadian exchange rate ($5million).
G&A expenses of $59million were $8million higher than the prior year period primarily due to expanded operations.
Taxes other than income of $80 million were $14 million higher than the prior year period primarily due to increased wellhead revenues in the United States ($11 million), production tax relief in the first six months of 2004 in Trinidad ($6 million), increased payroll taxes in the United States ($1 million) and higher property taxes as a result of higher property valuation in the United States ($1 million), partially offset by the results of a production tax audit lawsuit in the first quarter of 2004 which increased the amount for the period ($5 million).
Net interest expense of $29 million decreased $3 million primarily due to an interest charge related to the results of a production tax audit lawsuit in the first quarter of 2004.
Exploration costs of $63 million were $17 million higher than the prior year period primarily due to increased geological and geophysical expenditures in the United States ($13 million) and increased exploration administrative expenses in the United States ($3 million).
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Impairments of $36 million increased by $3 million compared to $33 million in the prior year period. SFAS No. 144 requires an entity to compute impairments to the carrying value of long-lived assets based on future cash flow analysis. As a result, EOG recorded impairments of $13 million and $5 million for the first six-month periods of 2005 and 2004, respectively, for certain properties in the United States. The increase in the impairment recorded related to SFAS No. 144 ($8 million) was partially offset by lower amortization of unproved leases in the United States ($7 million).
Other income, net was $12 million for the first six months of 2005 as compared to other expense, net of $1 million for the same period in 2004. The increase of $13 million was primarily due to foreign currency transaction losses during the first quarter of 2004 ($5 million), higher equity income from investments in the CNCL and N2000 ammonia plants in 2005 ($5 million) and a gain on the sale of part of EOG's interest in the N2000 ammonia plant in the first quarter of 2005 ($2 million).
Income tax provision of $246 million increased $127 million compared to the first half of 2004, due primarily to higher pre-tax income ($123 million) and an Alberta (Canada) corporate tax rate reduction occurring in the second quarter of 2004 ($5 million). The net effective tax rate for the first half of 2005 increased to 35% from 33% for the same period of 2004.
Capital Resources and Liquidity
Cash Flow. The primary sources of cash for EOG during the six months ended June 30, 2005 included funds generated from operations, proceeds from sales of partial interests in certain equity investments in Trinidad, proceeds from the sale of oil and gas properties in the United States, proceeds from new borrowings and proceeds from sales of treasury stock attributable to employee stock option exercises. Primary cash outflows included funds used in operations, exploration and development expenditures, and dividend payments to shareholders. During the first six months of 2005, EOG's cash balance increased $262 million to $283 million from $21 million at December 31, 2004. The cash balance as of June 30, 2005, was primarily maintained in bank accounts associated with EOG's international operations.
Net cash provided by operating activities of $985million for the first six months of 2005 increased $341million compared to the same period in 2004 primarily reflecting an increase in wellhead revenues ($431million), a change in the net cash flows from settlement of financial commodity derivative contracts ($48million), favorable changes in working capital and other liabilities ($31 million), and an increase in tax benefits from stock options exercised ($5million), partially offset by an increase in current tax expense ($102million) and an increase in cash operating expenses ($75million).
Net cash used in investing activities of $767 million for the first six months of 2005 increased by $185 million compared to the same period in 2004 due primarily to increased additions to oil and gas properties ($199 million), partially offset by proceeds from sales of assets ($22 million).
Net cash provided by financing activities was $44 million for the first six months of 2005 versus cash used of less than $1 million for the same period in 2004. Financing activities for 2005 included net commercial paper borrowings ($39 million), proceeds from sales of treasury stock attributable to employee stock option exercises ($24 million) and cash dividend payments ($20 million).
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Total Exploration and Development Expenditures. The table below presents total exploration and development expenditures for the six-month periods ended June 30 (in millions):
Six Months Ended
June 30,
--------------------
2005 2004
--------- ---------
United States $ 660 $ 446
Canada 114 106
--------- ---------
United States and Canada 774 552
Trinidad 23 38
United Kingdom 26 17
Other 2 2
--------- ---------
Exploration and Development Expenditures 825 609
Asset Retirement Costs 3 5
Deferred Income Tax Benefits on Acquired Properties - (17)
--------- ---------
Total Exploration and Development Expenditures $ 828 $ 597
========= =========
Exploration and development expenditures of $825 million for the first six months of 2005 were $216 million higher than the same period in 2004. The 2005 exploration and development expenditures of $825 included $544 million in development, $262 million in exploration, $12 million in property acquisitions, and $7 million in capitalized interest. The 2004 exploration and development expenditures of $609 included $420 million in development, $182 million in exploration, $4 million in capitalized interest and $3 million in property acquisitions.
Higher development expenditures for the first six months of 2005 of $124 million were due primarily to increased development drilling expenditures in the United States ($148 million), partially offset by the decreased drilling activities in Trinidad ($34 million).
Higher exploration expenditures for the first six months of 2005 of $80 million were due primarily to increased exploration drilling expenditures ($42 million), exploration expenses ($17 million), and unproved lease acquisitions in the United States ($16 million) and Canada ($3 million).
The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other related economic factors. EOG has significant flexibility with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. There are no material continuing commitments associated with expenditure plans.
Commodity Derivative Transactions. As more fully discussed in Note 11 to the consolidated financial statements included in EOG's 2004 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 collars and price swaps, as the means to manage this price risk. During 2004 and the first quarter of 2005, EOG accounted for the financial commodity derivative contracts using the mark-to- market accounting method. Beginning in the second quarter of 2005, EOG has not been a party to any financial commodity derivative contracts. 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 these various physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.
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Information Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts, including, among others, statements regarding EOG's future financial position, business strategy, budgets, reserve information, projected levels of production, projected costs and plans and objectives of management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "strategy," "intend," "plan," "target" and "believe" or the negative of those terms or other variations of them or by comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning future operating results, the ability to replace or increase reserves or to increase production, or the ability to generate income or cash flows are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes its expectations reflected in forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will be achieved. Important factors that could cause actual results to differ materially from the expectations reflected in the forward-looking statements include, among others: the timing and extent of changes in commodity prices for crude oil, natural gas and related products, foreign currency exchange rates and interest rates; the timing and impact of liquefied natural gas imports and changes in demand or prices for ammonia or methanol; the extent and effect of any hedging activities engaged in by EOG; the extent of EOG's success in discovering, developing, marketing and producing reserves and in acquiring oil and gas properties; the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise; the availability and cost of drilling rigs, experienced drilling crews and tubular steel; the availability, terms and timing of governmental and other permits and rights of way; the availability of pipeline transportation capacity; the extent to which EOG can replicate on its other Barnett Shale acreage outside of Johnson and Parker Counties, Texas, the results of its most recent Barnett Shale wells; whether EOG is successful in its efforts to more densely develop its acreage in the Barnett Shale and other production areas; political developments around the world; acts of war and terrorism and responses to these acts; and financial market conditions. In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements might not occur. EOG undertakes no obligations to update or revise its forward-looking statements, whether as a result of new information, future events or otherwise.
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PART I. FINANCIAL INFORMATION - (Concluded)
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
EOG RESOURCES, INC.
EOG's exposure to commodity price risk, interest rate risk and foreign currency exchange rate risk is discussed in the Derivative Transactions, Financing, Foreign Currency Exchange Rate Risk and Outlook sections of "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity," on pages 26 through 29 of the Annual Report on Form 10-K for the year ended December 31, 2004, filed on February 25, 2005.
ITEM 4. CONTROLS AND PROCEDURES
EOG RESOURCES, INC.
Disclosure Controls and Procedures. EOG's management, with the participation of EOG's principal executive officer and principal financial officer, evaluated the effectiveness of EOG's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of the end of the period covered by this Quarterly Report on Form 10-Q (Evaluation Date). Based on this evaluation, the principal executive officer and principal financial officer have concluded that EOG's disclosure controls and procedures were effective as of the Evaluation Date to ensure that information that is required to be disclosed by EOG in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms and (ii) accumulated and communicated to EOG's management as appropriate to allow timely decisions regarding required disclosure.
Internal Control Over Financial Reporting.There were no changes in EOG's internal control over financial reporting that occurred during the period covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting.
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PART II. OTHER INFORMATION
EOG RESOURCES, INC.
ITEM 1. Legal Proceedings
See Part I, Item 1, Note 5 to Consolidated Financial Statements, which is incorporated herein by reference.
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
(c)
(a) Total Number of (d)
Total (b) Shares Purchased as Maximum Number
Number of Average Part of Publicly of Shares that May Yet
Shares Price Paid Announced Plans or Be Purchased Under
Period Purchased (1) per Share Programs the Plans or Programs (2)
- ---------------------------------------- ------------- ------------ -------------------- -------------------------
April 1, 2005 - April 30, 2005 8,954 $ 40.68 - 6,386,200
May 1, 2005 - May 31, 2005 - - - 6,386,200
June 1, 2005 - June 30, 2005 1,528 56.78 - 6,386,200
------------- --------------------
Total 10,482 43.03 -
============= ====================
(1) Comprises 10,482shares that were returned to EOG to satisfy tax withholding obligations that arose upon the exercise of employee stock options or the vesting of restricted stock or units.
(2) In September 2001, EOG announced that its Board of Directors authorized the repurchase of up to 10,000,000 shares of EOG's common stock.
ITEM 4. Submission of Matters to a Vote of Security Holders
The Annual Meeting of Shareholders of EOG Resources, Inc. was held on May 3, 2005, in Houston, Texas, for the purpose of electing a board of directors, ratifying the appointment of auditors and approving the amendment to EOG's Restated Certificate of Incorporation. Proxies for the meeting were solicited pursuant to Section 14(a) of the Securities Exchange Act of 1934, and there was no solicitation in opposition to management's solicitations.
(a) Each of the directors nominated by the Board and listed in the proxy statement was elected with votes as follows:
| | | Shares | | Shares |
Nominee | | For | | Withheld |
| | | | | |
George A. Alcorn | | 210,505,773 | | 3,717,526 |
Charles R. Crisp | | 210,569,405 | | 3,653,894 |
Mark G. Papa | | 208,530,429 | | 5,692,870 |
Edmund P. Segner, III | | 206,764,732 | | 7,458,567 |
William D. Stevens | | 210,538,818 | | 3,684,481 |
H. Leighton Steward | | 205,305,417 | | 8,917,882 |
Donald F. Textor | | 205,952,473 | | 8,270,826 |
Frank G. Wisner | | 210,546,013 | | 3,677,286 |
(b) The ratification of the appointment of Deloitte & Touche LLP, independent public accountants, as EOG's independent auditors for the year ending December 31, 2005 was ratified by the following vote: 212,346,737 shares for; 778,803 shares against; and 1,097,758 shares abstaining.
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(c) The amendment to EOG's Restated Certificate of Incorporation was approved by the following vote: 193,331,158 shares for; 19,666,685 shares against; and 1,160,655 shares abstaining.
ITEM 6. Exhibits
Exhibit 3.1(a) - Restated Certificate of Incorporation (Exhibit 3.1 to Form S-1 Registration Statement, Reg. No. 33-30678, filed August 24, 1989).
Exhibit 3.1(b) - Certificate of Amendment of Restated Certificate of Incorporation (Exhibit 4.1(b) to Form S-8 Registration Statement No. 33-52201, filed February 8, 1994).
Exhibit 3.1(c) - Certificate of Amendment of Restated Certificate of Incorporation (Exhibit 4.1(c) to Form S-8 Registration Statement No. 33-58103, filed March 15, 1995).
Exhibit 3.1(d) - Certificate of Amendment of Restated Certificate of Incorporation, dated June 11, 1996 (Exhibit 3(d) to Form S-3 Registration Statement No. 333-09919, filed August 9, 1996).
Exhibit 3.1(e) - Certificate of Amendment of Restated Certificate of Incorporation, dated May 7, 1997 (Exhibit 3(e) to Form S-3 Registration Statement No. 333-44785, filed January 23, 1998).
Exhibit 3.1(f) - Certificate of Ownership and Merger, dated August 26, 1999 (Exhibit 3.1(f) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999).
Exhibit 3.1(g) - Certificate of Designations of Series E Junior Participating Preferred Stock, dated February 14, 2000 (Exhibit 2 to Form 8-A Registration Statement, filed February 18, 2000).
Exhibit 3.1(h) - Certificate of Designation, Preferences and Rights of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, dated July 19, 2000 (Exhibit 3.1(h) to EOG's Registration Statement on Form S-3 Registration Statement No. 333-46858, filed September 28, 2000).
Exhibit 3.1(i) - Certificate of Elimination of the Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series A, dated September 15, 2000 (Exhibit 3.1(j) to EOG's Registration Statement on Form S-3 Registration Statement No. 333-46858, filed September 28, 2000).
Exhibit 3.1(j) - Certificate of Elimination of the Flexible Money Market Cumulative Preferred Stock, Series C, dated September 15, 2000 (Exhibit 3.1(k) to EOG's Registration Statement on Form S-3 Registration Statement No. 333-46858, filed September 28, 2000).
Exhibit 3.1(k) - Certificate of Elimination of the Flexible Money Market Cumulative Preferred Stock, Series D, dated February 24, 2005 (Exhibit 3.1(k) to EOG's Annual Report on Form 10-K for the year ended December 31, 2004, filed February 25, 2005).
*Exhibit 3.1(1) - Certificate of Amendment of Restated Certificate of Incorporation, dated May 3, 2005.
*Exhibit 10.1 - Revolving Credit Agreement, dated June 28, 2005, among EOG Resources, Inc., JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto.
*Exhibit 31.1 - Section 302 Certification of Periodic Report of Chief Executive Officer.
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*Exhibit 31.2 - Section 302 Certification of Periodic Report of Principal Financial Officer.
*Exhibit 32.1 - Section 906 Certification of Periodic Report of Chief Executive Officer.
*Exhibit 32.2 - Section 906 Certification of Periodic Report of Principal Financial Officer.
*Exhibits filed herewith
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| | | EOG RESOURCES, INC. |
| | | (Registrant) |
| | | |
| | | |
| | | |
Date: July 29, 2005 | By: | /s/ TIMOTHY K. DRIGGERS
Timothy K. Driggers
Vice President and Chief Accounting Officer
(Principal Accounting Officer) |
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EXHIBIT INDEX
Exhibit No. | Description |
| | |
3.1(a) - | Restated Certificate of Incorporation (Exhibit 3.1 to Form S-1 Registration Statement, Reg. No. 33-30678, filed August 24, 1989). |
| |
3.1(b) - | Certificate of Amendment of Restated Certificate of Incorporation (Exhibit 4.1(b) to Form S-8 Registration Statement No. 33- 52201, filed February 8, 1994). |
| |
3.1(c) - | Certificate of Amendment of Restated Certificate of Incorporation (Exhibit 4.1(c) to Form S-8 Registration Statement No. 33- 58103, filed March 15, 1995). |
| |
3.1(d) - | Certificate of Amendment of Restated Certificate of Incorporation, dated June 11, 1996 (Exhibit 3(d) to Form S-3 Registration Statement No. 333-09919, filed August 9, 1996). |
| |
3.1(e) - | Certificate of Amendment of Restated Certificate of Incorporation, dated May 7, 1997 (Exhibit 3(e) to Form S-3 Registration Statement No. 333-44785, filed January 23, 1998). |
| |
3.1(f) - | Certificate of Ownership and Merger, dated August 26, 1999 (Exhibit 3.1(f) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999). |
| |
3.1(g) - | Certificate of Designations of Series E Junior Participating Preferred Stock, dated February 14, 2000 (Exhibit 2 to Form 8-A Registration Statement, filed February 18, 2000). |
| |
3.1(h) - | Certificate of Designation, Preferences and Rights of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, dated July 19, 2000 (Exhibit 3.1(h) to EOG's Registration Statement on Form S-3 Registration Statement No. 333-46858, filed September 28, 2000). |
| |
3.1(i) - | Certificate of Elimination of the Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series A, dated September 15, 2000 (Exhibit 3.1(j) to EOG's Registration Statement on Form S-3 Registration Statement No. 333-46858, filed September 28, 2000). |
| |
3.1(j) - | Certificate of Elimination of the Flexible Money Market Cumulative Preferred Stock, Series C, dated September 15, 2000 (Exhibit 3.1(k) to EOG's Registration Statement on Form S-3 Registration Statement No. 333-46858, filed September 28, 2000). |
| |
3.1(k) - | Certificate of Elimination of the Flexible Money Market Cumulative Preferred Stock, Series D, dated February 24, 2005 (Exhibit 3.1(k) to EOG's Annual Report on Form 10-K for the year ended December 31, 2004, filed February 25, 2005). |
| |
*3.1(1) - | Certificate of Amendment of Restated Certificate of Incorporation, dated May 3, 2005. |
| | |
*10.1 - | Revolving Credit Agreement, dated June 28, 2005, among EOG Resources, Inc., JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto. |
| | |
*31.1 - | Section 302 Certification of Periodic Report of Chief Executive Officer. |
| | |
*31.2 - | Section 302 Certification of Periodic Report of Principal Financial Officer. |
| | |
*32.1 - | Section 906 Certification of Periodic Report of Chief Executive Officer. |
| | |
*32.2 - | Section 906 Certification of Periodic Report of Principal Financial Officer. |
*Exhibits filed herewith
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