10-Q 1 eog3q10q.txt 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, 2004 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 (I.R.S. Employer jurisdiction of Identification No.) incorporation or organization) 333 Clay Street, Suite 4200, Houston, Texas 77002-7361 (Address of principal executive offices) (zip code) Registrant's telephone number, including area code: 713-651-7000 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 . 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 October 19, 2004. Title of each class Number of shares Common Stock, $.01 118,575,129 par value EOG RESOURCES, INC. TABLE OF CONTENTS PART I. FINANCIAL INFORMATION Page No. ITEM 1. Financial Statements Consolidated Statements of Income - Three Months Ended September 30, 2004 and 2003 And Nine Months Ended September 30, 2004 and 2003 3 Consolidated Balance Sheets - September 30, 2004 and December 31, 2003 4 Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2004 and 2003 5 Notes to Consolidated Financial Statements 6 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 12 ITEM 3. Quantitative and Qualitative Disclosures About Market Risk 23 ITEM 4. Controls and Procedures 23 PART II. OTHER INFORMATION ITEM 1. Legal Proceedings 24 ITEM 2. Changes in Securities and Use of Proceeds 24 ITEM 6. Exhibits 24 SIGNATURES 25 EXHIBIT INDEX 26 -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 Nine Months Ended September 30, September 30, 2004 2003 2004 2003 Net Operating Revenues Natural Gas $448,131 $365,064 $1,296,052 $1,176,798 Crude Oil, Condensate and Natural Gas Liquids 123,379 67,664 316,238 204,643 Gains (Losses) on Mark-to-Market Commodity Derivative Contracts 22,743 23,628 (36,275) (37,346) Other, Net (23) 2,368 1,556 4,052 Total 594,230 458,724 1,577,571 1,348,147 Operating Expenses Lease and Well 69,027 54,431 198,976 156,390 Exploration Costs 21,874 17,812 67,466 57,409 Dry Hole Costs 21,114 8,876 50,205 18,932 Impairments 17,930 26,117 51,289 63,548 Depreciation, Depletion and Amortization 130,257 110,438 360,278 320,578 General and Administrative 29,576 26,379 80,861 71,734 Taxes Other Than Income 29,952 21,359 95,824 63,247 Total 319,730 265,412 904,899 751,838 Operating Income 274,500 193,312 672,672 596,309 Other Income, Net 3,953 1,924 2,649 4,756 Income Before Interest Expense and Income Taxes 278,453 195,236 675,321 601,065 Interest Expense, Net 16,110 15,632 48,209 44,757 Income Before Income Taxes 262,343 179,604 627,112 556,308 Income Tax Provision 90,033 62,185 209,012 193,542 Net Income Before Cumulative Effect of Change in Accounting Principle 172,310 117,419 418,100 362,766 Cumulative Effect of Change in Accounting Principle, Net of Income Tax - - - (7,131) Net Income 172,310 117,419 418,100 355,635 Preferred Stock Dividends 2,758 2,758 8,274 8,274 Net Income Available to Common $169,552 $114,661 $ 409,826 $ 347,361 Net Income Per Share Available to Common Basic Net Income Available to Common Before Cumulative Effect of Change in Accounting Principle $ 1.44 $ 1.00 $ 3.52 $ 3.09 Cumulative Effect of Change in Accounting Principle, Net of Income Tax - - - (0.06) Net Income Available to Common $ 1.44 $ 1.00 $ 3.52 $ 3.03 Diluted Net Income Available to Common Before Cumulative Effect of Change in Accounting Principle $ 1.42 $ 0.99 $ 3.45 $ 3.05 Cumulative Effect of Change in Accounting Principle, Net of Income Tax - - - (0.06) Net Income Available to Common $ 1.42 $ 0.99 $ 3.45 $ 2.99 Average Number of Common Shares Basic 117,411 114,616 116,485 114,489 Diluted 119,677 116,370 118,710 116,284 The accompanying notes are an integral part of these consolidated financial statements.
-3- PART I. FINANCIAL INFORMATION - (Continued) ITEM 1. FINANCIAL STATEMENTS - (Continued) EOG RESOURCES, INC. CONSOLIDATED BALANCE SHEETS (In Thousands, Except Share Data)
September 30, December 31, 2004 2003 (Unaudited) ASSETS Current Assets Cash and Cash Equivalents $ 81,908 $ 4,443 Accounts Receivable, Net 350,170 295,118 Inventories 30,739 21,922 Deferred Income Taxes 22,560 31,548 Other 72,302 42,983 Total 557,679 396,014 Oil and Gas Properties (Successful Efforts Method) 9,069,633 8,189,062 Less: Accumulated Depreciation, Depletion and Amortization (4,311,597) (3,940,145) Net Oil and Gas Properties 4,758,036 4,248,917 Other Assets 108,882 104,084 Total Assets $5,424,597 $4,749,015 LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities Accounts Payable $ 339,303 $ 282,379 Accrued Taxes Payable 59,168 33,276 Dividends Payable 7,497 6,175 Liabilities from Price Risk Management Activities 4,736 37,779 Deferred Income Taxes 66,746 73,611 Other 46,978 43,299 Total 524,428 476,519 Long-Term Debt 1,062,972 1,108,872 Other Liabilities 195,482 171,115 Deferred Income Taxes 915,803 769,128 Shareholders' Equity Preferred Stock, $.01 Par, 10,000,000 Shares Authorized: Series B, 100,000 Shares Issued, Cumulative, $100,000 Liquidation Preference 98,767 98,589 Series D, 500 Shares Issued, Cumulative, $50,000 Liquidation Preference 49,962 49,827 Common Stock, $.01 Par, 320,000,000 Shares Authorized and 124,730,000 Shares Issued 201,247 201,247 Additional Paid in Capital 15,586 1,625 Unearned Compensation (32,555) (23,473) Accumulated Other Comprehensive Income 100,194 73,934 Retained Earnings 2,509,851 2,121,214 Common Stock Held in Treasury, 6,363,820 shares at September 30, 2004 and 8,819,600 shares at December 31, 2003 (217,140) (299,582) Total Shareholders' Equity 2,725,912 2,223,381 Total Liabilities and Shareholders' Equity $5,424,597 $4,749,015 The accompanying notes are an integral part of these consolidated financial statements.
-4- PART I. FINANCIAL INFORMATION - (Continued) ITEM 1. FINANCIAL STATEMENTS - (Continued) EOG RESOURCES, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (In Thousands) (Unaudited)
Nine Months Ended September 30, 2004 2003 Cash Flows From Operating Activities Reconciliation of Net Income to Net Cash Provided by Operating Activities: Net Income $ 418,100 $ 355,635 Items Not Requiring Cash Depreciation, Depletion and Amortization 360,278 320,578 Impairments 51,289 63,548 Deferred Income Taxes 158,216 123,431 Cumulative Effect of Change in Accounting Principle, Net of Income Tax - 7,131 Other, Net 13,546 6,763 Exploration Costs 67,466 57,409 Dry Hole Costs 50,205 18,932 Mark-to-Market Commodity Derivative Contracts Total Losses 36,275 37,346 Realized Losses (70,507) (47,700) Collar Premium - (1,365) Tax Benefits from Stock Options Exercised 20,730 7,025 Other, Net (208) 2,894 Changes in Components of Working Capital and Other Liabilities Accounts Receivable (55,352) (15,905) Inventories (8,817) (1,860) Accounts Payable 58,113 50,028 Accrued Taxes Payable 619 32,769 Other Liabilities 3,566 1,783 Other, Net (531) 18,074 Changes in Components of Working Capital Associated with Investing and Financing Activities (17,940) (22,064) Net Cash Provided by Operating Activities 1,085,048 1,014,452 Investing Cash Flows Additions to Oil and Gas Properties (891,465) (564,825) Exploration Costs (67,466) (57,409) Dry Hole Costs (50,205) (18,932) Proceeds from Sales of Assets 12,771 12,361 Changes in Components of Working Capital Associated with Investing Activities 17,366 22,223 Other, Net (14,322) (70,366) Net Cash Used in Investing Activities (993,321) (676,948) Financing Cash Flows Net Commercial Paper and Line of Credit Repayments (20,900) (134,310) Long-Term Debt Borrowings 150,000 - Long-Term Debt Repayments (175,000) - Dividends Paid (27,828) (22,878) Treasury Stock Purchased - (21,295) Proceeds from Stock Options Exercised 60,479 17,717 Other, Net (1,013) (2,097) Net Cash Used in Financing Activities (14,262) (162,863) Increase in Cash and Cash Equivalents 77,465 174,641 Cash and Cash Equivalents at Beginning of Period 4,443 9,848 Cash and Cash Equivalents at End of Period $ 81,908 $ 184,489 The accompanying notes are an integral part of these consolidated financial statements.
-5- PART I. FINANCIAL INFORMATION (Continued) ITEM 1. FINANCIAL STATEMENTS (Continued) 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, 2003 (EOG's 2003 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. Certain reclassifications have been made to prior period financial statements to conform with the current presentation. As more fully discussed in Note 12 to the consolidated financial statements included in EOG's 2003 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 commodity derivative financial instruments, primarily price swaps and collars, as the means to manage this price risk. In addition to these financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. The financial impact of these various physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices. During the first nine months of 2004 and 2003, EOG elected not to designate any of its commodity derivative financial contracts as accounting hedges, and accordingly, accounted for these commodity derivative financial contracts using the mark-to-market accounting method. EOG is exposed to foreign currency exchange rate risk inherent in its operations in foreign countries, including Canada, Trinidad and the United Kingdom. From time to time, EOG engages in exchange rate risk management activities to manage its exposure to exchange rates. Effective March 9, 2004, EOG entered into a foreign currency swap transaction with multiple banks to eliminate any exchange rate impacts that may result from the notes offered by one of the Canadian subsidiaries on the same date (see Note 8). EOG accounts for the foreign currency swap transaction using the hedge accounting method, pursuant to the provisions of Statement of Financial Accounting Standards (SFAS) No. 133 - "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137, 138 and 149. Under those provisions, as of September 30, 2004, EOG recorded the fair value of the swap of $9.1 million in Other Liabilities in the Liabilities section of the Consolidated Balance Sheets. Changes in the fair value of the foreign currency swap resulted in no net impact to the Consolidated Statements of Income. The after-tax net impact from the foreign currency swap transaction resulted in positive changes of $1.8 million and $0.1 million for the three- month and nine-month periods ended September 30, 2004, respectively. These amounts are included in Accumulated Other Comprehensive Income in the Shareholders' Equity section of the Consolidated Balance Sheets. -6- On January 1, 2003, EOG adopted SFAS No. 143 - "Accounting for Asset Retirement Obligations" which essentially requires entities to record the fair value of a liability for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The impact of adopting the statement was an after-tax charge of $7.1 million, which was reported in the first quarter of 2003 as cumulative effect of change in accounting principle. In December 2002, the Financial Accounting Standards Board (FASB) issued SFAS No. 148 - "Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of FASB Statement No. 123." This statement provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation, along with the requirement of disclosure in both annual and interim financial statements about the method used and effect on reported results (see Note 7). Subsequently, in March 2004, the FASB issued a proposed SFAS - "Share-Based Payment, an amendment of SFAS Nos. 123 and 95." The proposed standard would require share-based payments to employees, including stock options, to be expensed. The final ruling is expected to be issued by June 2005. EOG continues to monitor the developments in this area as details of the implementation of the final ruling emerge. 2. The following table sets forth the computation of net income per share available to common for the three-month and nine-month periods ended September 30, 2004 and 2003 (in thousands, except per share amounts):
Three Months Ended Nine Months Ended September 30, September 30, 2004 2003 2004 2003 Numerator for Basic and Diluted Earnings Per Share - Net Income Available to Common $169,552 $114,661 $409,826 $347,361 Denominator for Basic Earnings Per Share - Weighted Average Shares 117,411 114,616 116,485 114,489 Potential Dilutive Common Shares - Stock Options 1,745 1,476 1,733 1,512 Restricted Stock and Units 521 278 492 283 Denominator for Diluted Earnings Per Share - Adjusted Weighted Average Shares 119,677 116,370 118,710 116,284 Net Income Per Share of Common Stock Basic $ 1.44 $ 1.00 $ 3.52 $ 3.03 Diluted $ 1.42 $ 0.99 $ 3.45 $ 2.99
-7- 3. The following table presents the components of EOG's comprehensive income for the three-month and nine-month periods ended September 30, 2004 and 2003 (in thousands):
Three Months Ended Nine Months Ended September 30, September 30, 2004 2003 2004 2003 Comprehensive Income Net Income $172,310 $117,419 $418,100 $355,635 Other Comprehensive Income Foreign Currency Translation Adjustment 56,919 2,935 26,173 90,358 Foreign Currency Swap Transaction 2,649 - 132 - Income Tax Related to Foreign Currency Swap Transaction (847) - (45) - Total $231,031 $120,354 $444,360 $445,993
4. Selected financial information about operating segments is reported below for the three-month and nine-month periods ended September 30, 2004 and 2003 (in thousands):
Three Months Ended Nine Months Ended September 30, September 30, 2004 2003 2004 2003 Net Operating Revenues United States $438,007 $363,791 $1,161,033 $1,050,833 Canada 109,066 69,665 309,833 223,278 Trinidad 43,427 25,268 102,975 74,036 United Kingdom(1) 3,730 - 3,730 - Total $594,230 $458,724 $1,577,571 $1,348,147 Operating Income (Loss) United States $198,978 $139,291 $ 452,096 $ 427,721 Canada 48,121 36,776 157,139 128,297 Trinidad 26,011 17,679 67,289 45,386 United Kingdom(1) 1,390 (434) (3,852) (5,256) Other - - - 161 Total 274,500 193,312 672,672 596,309 Reconciling Items Other Income, Net 3,953 1,924 2,649 4,756 Interest Expense, Net 16,110 15,632 48,209 44,757 Income Before Income Taxes $262,343 $179,604 $ 627,112 $ 556,308 (1) Exploratory activities in the United Kingdom began in June 2002. Production in the United Kingdom commenced in August 2004.
5. EOG has been named as a potentially responsible party in certain Comprehensive Environmental Response Compensation and Liability Act proceedings. However, management does not believe that any potential assessments resulting from such proceedings will individually, or in the aggregate, have a material adverse effect on the financial condition or results of operations of EOG. There are various other lawsuits and claims against EOG that have arisen in the ordinary course of business. However, management does not believe these lawsuits and claims will individually, or in the aggregate, have a material adverse effect on the financial condition or results of operations of EOG. -8- 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 for the three-month periods ended March 31, June 30 and September 30, 2004 (in thousands):
Asset Retirement Obligations Short-Term Long-Term Total Balance at December 31, 2003 $ 5,320 $118,624 $123,944 Liabilities Incurred 321 2,073 2,394 Liabilities Settled (97) (28) (125) Accretion 36 1,331 1,367 Foreign Currency Translation (3) (212) (215) Balance at March 31, 2004 5,577 121,788 127,365 Liabilities Incurred - 2,863 2,863 Liabilities Settled (748) (4,520) (5,268) Accretion 17 1,316 1,333 Foreign Currency Translation (10) (372) (382) Balance at June 30, 2004 4,836 121,075 125,911 Liabilities Incurred 148 1,735 1,883 Liabilities Settled (1,531) (508) (2,039) Accretion 28 1,406 1,434 Revision 679 363 1,042 Reclassification 672 (672) - Foreign Currency Translation 45 997 1,042 Balance at September 30, 2004 $ 4,877 $124,396 $129,273
7. EOG has various stock plans (Plans) under which employees and non- employee members of the Board of Directors of EOG and its subsidiaries have been or may be granted certain equity compensation. Stock Options. EOG has in place compensatory stock option plans whereby participants have been or may be granted rights to purchase shares of common stock of EOG at a price not less than the market price of the stock at the date of grant. Employee Stock Purchase Plan. EOG has in place an employee stock purchase plan, pursuant to Section 423 of the Internal Revenue Code of 1986, as amended, whereby participants are granted rights to purchase shares of common stock of EOG at a price that is 15% less than the market price of the stock on either the first day or the last day of a six-month offering period, whichever is less. -9- Pro Forma Information. EOG's pro forma net income available to common and net income per share available to common for the three- month and nine-month periods ended September 30, 2004 and 2003, if compensation costs of stock options and the employee stock purchase plan had been recorded using the fair value method in accordance with SFAS No. 123 - "Accounting for Stock-Based Compensation," as amended by SFAS No. 148 - "Accounting for Stock- Based Compensation - Transition and Disclosure - an amendment of FASB Statement No. 123," are presented below pursuant to the disclosure requirement of SFAS No. 148 (in thousands, except per share amounts):
Three Months Ended Nine Months Ended September 30, September 30, 2004 2003 2004 2003 Net Income Available to Common - As Reported $169,552 $114,661 $409,826 $347,361 Deduct: Total Stock-Based Employee Compensation Expense, Net of Income Tax (3,210) (5,491) (8,630) (11,138) Net Income Available to Common - Pro Forma $166,342 $109,170 $401,196 $336,223 Net Income Per Share Available to Common Basic - As Reported $ 1.44 $ 1.00 $ 3.52 $ 3.03 Basic - Pro Forma $ 1.42 $ 0.95 $ 3.44 $ 2.94 Diluted - As Reported $ 1.42 $ 0.99 $ 3.45 $ 2.99 Diluted - Pro Forma $ 1.39 $ 0.94 $ 3.38 $ 2.89
The effects of applying SFAS No. 123, as amended, in this pro forma disclosure should not be interpreted as being indicative of future effects. SFAS No. 123 does not apply to awards prior to 1995 and the extent and timing of additional future awards cannot be predicted. Restricted Stock and Units. Under the Plans, employees may be granted restricted stock and/or units without cost to them. Related compensation expense for the three-month periods ended September 30, 2004 and 2003 was $2.5 million and $1.5 million, respectively. Related compensation expense for the nine-month periods ended September 30, 2004 and 2003 was $6.9 million and $4.1 million, respectively. 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. EOG's contributions to these plans are based on various percentages of compensation, and in some instances, are based upon the amount of the employees' contributions to the plan. For the three-month periods ended September 30, 2004 and 2003, the contributions to these plans amounted to $1.9 million and $1.8 million, respectively. For the nine-month periods ended September 30, 2004 and 2003, the contributions to these plans amounted to $7.6 million and $5.7 million, respectively. In addition, EOG's Canadian subsidiary maintains a non- contributory defined contribution pension plan and a matched savings plan. EOG's Trinidadian subsidiary maintains a contributory defined benefit pension plan and a matched savings plan. These plans are available to most employees of the Canadian and Trinidadian subsidiaries, and contributions related to these plans were $184,000 and $160,000 for the three-month periods ended September 30, 2004 and 2003, respectively. Contributions related to these plans were $611,000 and $445,000 for the nine-month periods ended September 30, 2004 and 2003, respectively. -10- Postretirement Plan. During 2000, EOG adopted postretirement medical and dental benefits for eligible employees and their eligible dependents. Benefits are provided under the provisions of a contributory defined dollar benefit plan. EOG accrues these postretirement benefit costs over the service lives of the employees expected to be eligible to receive such benefits. The following table summarizes EOG's postretirement benefit expense for the three-month and nine-month periods ended September 30, 2004 and 2003 (in thousands):
Three Months Ended Nine Months Ended September 30, September 30, 2004 2003 2004 2003 Service Cost $ 33 $ 44 $139 $132 Interest Cost 28 32 107 96 Expected Return on Plan Assets - - - - Amortization of Prior Service Cost 32 19 97 57 Amortization of Net Actuarial (Gain) Loss (18) - (36) - Net Periodic Benefit Cost $ 75 $ 95 $307 $285
EOG contributed $16,000 and $45,000 to fund its postretirement plan for the three-month and nine-month periods ended September 30, 2004, respectively. EOG presently anticipates contributing an additional $16,000 for a total of $61,000 for the year. EOG previously disclosed in its 2003 Annual Report that it expected to contribute $57,000 to its postretirement plan in 2004. 8. On March 9, 2004, 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, under Rule 144A of the Securities Act of 1933, as amended. The notes are guaranteed by EOG. In conjunction with the offering, EOG entered into a foreign currency swap transaction with multiple banks for the equivalent amount of the notes and related interest, 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. On September 15, 2004, EOG repaid in full upon maturity the $100 million, 6.5% notes. -11- 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 gas companies in the United States and has substantial proved reserves in the United States, Canada, offshore Trinidad and, to a lesser extent, the United Kingdom North Sea. EOG operates under a business strategy that focuses predominantly on three factors: achieving a strong reinvestment rate of return on its capital program, drilling internally generated prospects in order to find and develop low cost reserves, and maintaining a strong balance sheet, with a below industry average debt-to-total capitalization ratio. Operations 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 plans to continue to drill smaller wells in large acreage plays, which, in the aggregate, will contribute substantially to EOG's crude oil and natural gas production. EOG has several larger potential plays under way in Wyoming, Utah and Texas, including the Barnett Shale. To date, EOG has leased approximately 345,000 net acres in the non-core Barnett Shale area (with the core area defined primarily as western Denton and eastern Wise Counties, Texas). While EOG has continued to drill successful wells in the Barnett Shale through the use of 3-D seismic and horizontal drilling techniques, significant production growth or reserve additions are not anticipated from the Barnett Shale until 2005 and beyond. In South Texas, EOG has continued its success in the Roleta and Frio Formations. Through the use of 3-D seismic, EOG has expanded the inventory of drilling locations in the Roleta Formation and also expects to continue an active drilling program in the Frio Formation. International. In Trinidad, EOG drilled two development wells at its Parula Discovery during the second quarter of 2004. Production from these wells are among the sources to supply existing gas contracts, as well as feeding a new methanol plant that is scheduled to commence operations in 2005. EOG completed an additional development well on the U(a) block which will primarily supply natural gas to the Caribbean Nitrogen Company Limited (CNCL) and the Nitrogen (2000) Unlimited (N2000) ammonia plants. The N2000 plant achieved full plant productivity in August 2004. Although EOG continues to focus on United States and Canadian natural gas, EOG sees an increasing linkage between United States and Canadian natural gas demand and Trinidadian natural gas supply. For example, liquefied natural gas (LNG) imports from existing and planned facilities in Trinidad are expected to help meet decreasing United States supply. In addition, ammonia, methanol and chemical production has been relocating from the United States and Canada to Trinidad, driven by attractive natural gas prices in the island nation. EOG anticipates that its existing position with the supply contracts to the two ammonia plants and the new methanol plant will continue to give its portfolio an even broader exposure to United States and Canadian natural gas fundamentals. In EOG's new venue in the Southern Gas Basin of the United Kingdom North Sea, EOG commenced production from its Valkyrie well in August 2004 and is on track to commence production from its Arthur well by the end of 2004. Total production from the two wells is estimated to be approximately 40 MMcfed, net, by year- end 2004. These wells were farm-in opportunities from major oil companies. EOG is reviewing additional farm-in opportunities in this area. Earlier in the year, EOG commenced preparations to become an exploration operator in the United Kingdom and received necessary government approval in August 2004. -12- Capital Structure As noted, one of management's key strategies is to keep a strong balance sheet with a consistently below industry average debt-to- total capitalization ratio. During the first nine months of 2004, EOG reduced debt by $46 million and increased its cash position by $77 million. At September 30, 2004, its debt-to-total capitalization ratio was 28.1%, down from 33.3% at December 31, 2003. On March 9, 2004, EOG Resources Canada Inc., a wholly owned subsidiary of EOG, issued notes with a total principal amount of US$150 million. The proceeds from these notes, along with the cash provided from operating activities, allowed EOG to fund the first nine months of the 2004 capital program of $1 billion, repay in full upon maturity the $100 million, 6.5% notes, and pay down $75 million on its senior unsecured term loan facility and $21 million on outstanding commercial paper borrowings. As management currently assesses price forecast and demand trends for the remainder of 2004, EOG continues to believe that operations and capital expenditure activity can be funded by cash generated from operations and, if needed, available financing alternatives. For 2004, EOG's current estimated capital expenditure budget is approximately $1.45 billion, including acquisitions. 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 believes that EOG has one of the strongest overall drilling inventories in EOG's history. Results of Operations Three Months ended September 30, 2004 vs. Three Months Ended September 30, 2003 The following review of operations for the three-month periods ended September 30, 2004 and 2003 should be read in conjunction with the consolidated financial statements of EOG and notes thereto. Net Operating Revenues. During the third quarter of 2004, net operating revenues increased $136 million to $594 million. Total wellhead revenues of $571 million increased by $139 million, or 32%, as compared to the same period a year ago. Wellhead natural gas volume and price statistics for the three-month periods ended September 30, 2004 and 2003 were as follows:
Three Months Ended September 30, 2004 2003 Natural Gas Volumes (MMcf per day)(1) United States 623 644 Canada 211 152 United States and Canada 834 796 Trinidad 203 155 United Kingdom 8 - Total 1,045 951 Average Natural Gas Prices ($/Mcf)(2) United States $5.57 $4.78 Canada 4.99 4.47 United States and Canada Composite 5.42 4.72 Trinidad 1.50 1.34 United Kingdom 5.30 - Composite 4.66 4.17 (1) Million cubic feet per day. (2) Dollars per thousand cubic feet.
-13- Wellhead crude oil and condensate and natural gas liquids volume and price and natural gas equivalent volume statistics for the three- month periods ended September 30, 2004 and 2003 were as follows:
Three Months Ended September 30, 2004 2003 Crude Oil and Condensate Volumes (MBbl per day)(1) United States 21.0 18.0 Canada 2.7 2.3 United States and Canada 23.7 20.3 Trinidad 4.0 2.5 Total 27.7 22.8 Average Crude Oil and Condensate Prices ($/Bbl)(2) United States $43.30 $29.43 Canada 40.17 28.11 United States and Canada Composite 42.94 29.28 Trinidad 42.06 26.80 Composite 42.81 29.01 Natural Gas Liquids Volumes (MBbl per day)(1) United States 4.4 2.9 Canada 0.9 0.8 Total 5.3 3.7 Average Natural Gas Liquids Prices ($/Bbl) (2) United States $30.07 $20.53 Canada 23.58 18.23 Composite 29.02 20.06 Natural Gas Equivalent Volumes (MMcfe per day)(3) United States 775 770 Canada 233 170 United States and Canada 1,008 940 Trinidad 227 170 United Kingdom 8 - Total 1,243 1,110 Total Bcfe(4) Deliveries 114.4 102.1 (1) Thousand barrels per day. (2) Dollars per barrel. (3) Million cubic feet equivalent per day. (4) Billion cubic feet equivalent.
Wellhead natural gas revenues for the third quarter of 2004 increased $83 million, or 23%, to $448 million from $365 million for the same period of 2003. The increase was due to higher composite average wellhead natural gas price ($47 million) and natural gas deliveries ($36 million). The composite average wellhead price for natural gas increased 12% to $4.66 per Mcf for the third quarter of 2004 from $4.17 per Mcf for the same period of 2003. -14- Natural gas deliveries increased 94 MMcf per day, or 10%, to 1,045 MMcf per day for the third quarter of 2004 from 951 MMcf per day for the same period in 2003, primarily due to a 59 MMcf per day, or 39%, increase in Canada; a 48 MMcf per day, or 31%, increase in Trinidad; and an 8 MMcf per day increase in the United Kingdom due to commencement of production in August 2004. These increases were partially offset by a 21 MMcf per day, or 3%, decline in the United States. The increase in Canada (59 MMcf per day) was attributable approximately equally to both the property acquisitions in the fourth quarter of 2003 and the additional production that resulted primarily from drilling activities. The increase in Trinidad was attributable to the increased production from the U(a) block (40 MMcf per day) which began supplying natural gas in April 2004 to the N2000 ammonia plant and commencement of production from the Parula wells on the SECC block in February 2004 (9 MMcf per day). Wellhead crude oil and condensate revenues increased $48 million, or 79%, to $109 million from $61 million due to increases in both the composite average wellhead crude oil and condensate price ($35 million) and the wellhead crude oil and condensate deliveries ($13 million). The composite average wellhead crude oil and condensate price for the third quarter of 2004 was $42.81 per barrel compared to $29.01 per barrel for the same period of 2003. Wellhead crude oil and condensate deliveries increased 4.9 MBbl per day, or 21%, to 27.7 MBbl per day from 22.8 MBbl per day for the same period in 2003. The increase was mainly due to production from new wells in the United States (3.0 MBbl per day), higher production in Trinidad from the Parula wells (0.8 MBbl per day) and new production from the U(a) block (0.7 MBbl per day). Natural gas liquids revenues were $7 million higher than a year ago primarily due to increases in the composite average price ($4 million) and deliveries ($3 million). During the third quarter of 2004, EOG recognized a gain from the mark-to-market of financial commodity collar and price swap contracts of $23 million compared to a gain of $24 million for the prior year period. During the third quarter of 2004, the net cash outflow related to settled natural gas financial collar contracts and settled natural gas and crude oil financial price swap contracts was $32 million compared to a net cash outflow related to settled natural gas financial collar contracts, premium payments associated with certain natural gas financial collar contracts and settled natural gas and crude oil financial price swap contracts of $10 million for the prior year period. Operating and Other Expenses. For the third quarter of 2004, operating expenses of $320 million were $55 million higher than the $265 million incurred in the third quarter of 2003. The following table presents the costs per Mcfe for the three-month periods ended September 30, 2004 and 2003:
Three Months Ended September 30, 2004 2003 Lease and Well $0.60 $0.53 DD&A 1.14 1.08 G&A 0.26 0.26 Taxes Other than Income 0.26 0.21 Interest Expense, Net 0.14 0.15 Total Per-Unit Costs(1) $2.40 $2.23 (1) Total per-unit costs do not include exploration costs, dry hole costs and impairments.
-15- The higher per-unit costs of lease and well, depreciation, depletion and amortization (DD&A) and taxes other than income for the three-month period ended September 30, 2004 compared to the same period in 2003 were due primarily to the reasons set forth below. Lease and well expenses of $69 million were $15 million higher than the prior year period due primarily to increased production in Canada ($4 million), increased transportation expense in the United States ($3 million) and in Canada ($1 million), higher service cost structures related to operating activities in the United States ($2 million) and in Canada ($2 million), and changes in the Canadian exchange rate ($1 million). DD&A expenses of $130 million increased $20 million from the prior year period due primarily to increased production in Canada ($5 million), increased Canadian DD&A rates mainly from developing acquired proved reserves ($5 million), increased United States DD&A rates due to a gradual proportional increase in production from higher cost properties ($5 million), increased production in the United States ($1 million) and in Trinidad ($1 million), and changes in the Canadian exchange rate ($1 million). General and administrative (G&A) expenses of $30 million were $3 million higher than the prior year period due primarily to expanded operations. Taxes other than income of $30 million were $9 million higher than the prior year period due primarily to increased wellhead revenue in the United States, as previously discussed ($4 million), higher property taxes in the United States as a result of higher property valuation ($2 million) and a decrease in retroactive credits against severance taxes resulting from the qualification of additional wells for a Texas high cost gas severance tax exemption ($2 million). Exploration costs of $22 million were $4 million higher than the prior year period due primarily to increased geological and geoscience expenditures in Canada ($2 million) and in Trinidad ($2 million) and increased technical staff costs in the United States ($1 million), partially offset by decreased geological and geoscience expenditures in the United States ($1 million). Impairments of $18 million decreased $8 million compared to the prior year period due to lower amortization of unproved leases in the United States ($5 million) and lower impairments to the carrying value of certain long-lived assets as a result of downward revisions in the future cash flow analysis for certain properties in the United States ($4 million), partially offset by higher amortization of unproved leases in Canada ($1 million). Total impairments under Statement of Financial Accounting Standards (SFAS) No. 144 - "Accounting for the Impairment or Disposal of Long-Lived Assets" for the third quarter of 2004 and 2003 were $4 million and $8 million, respectively. For the third quarter of 2004, the income tax provision of $90 million increased $28 million compared to the third quarter of 2003, primarily due to higher income before income taxes ($29 million). The net effective tax rate for the third quarter of 2004 decreased to 34% from 35% for the same period of 2003. -16- Nine Months Ended September 30, 2004 vs. Nine Months Ended September 30, 2003 Net Operating Revenues. During the first nine months of 2004, net operating revenues increased $229 million to $1,578 million. Total wellhead revenues of $1,611 million increased $231 million, or 17%, as compared to the same period a year ago. Wellhead volume and price statistics for the nine-month periods ended September 30, 2004 and 2003 were as follows:
Nine Months Ended September 30, 2004 2003 Natural Gas Volumes (MMcf per day) United States 620 641 Canada 204 154 United States and Canada 824 795 Trinidad 173 152 United Kingdom 3 - Total 1,000 947 Average Natural Gas Prices ($/Mcf) United States $5.55 $5.25 Canada 5.00 4.80 United States and Canada Composite 5.41 5.16 Trinidad 1.46 1.33 United Kingdom 5.30 - Composite 4.73 4.54 Crude Oil and Condensate Volumes (MBbl per day) United States 20.7 17.9 Canada 2.6 2.2 United States and Canada 23.3 20.1 Trinidad 3.2 2.4 Total 26.5 22.5 Average Crude Oil and Condensate Prices ($/Bbl) United States $38.57 $30.22 Canada 35.89 28.86 United States and Canada Composite 38.26 30.07 Trinidad 38.19 28.75 Composite 38.26 29.93 Natural Gas Liquids Volumes (MBbl per day) United States 4.7 3.0 Canada 0.7 0.6 Total 5.4 3.6 Average Natural Gas Liquids Prices ($/Bbl) United States $26.09 $21.16 Canada 21.65 18.80 Composite 25.52 20.76 Natural Gas Equivalent Volumes (MMcfe per day) United States 772 766 Canada 224 172 United States and Canada 996 938 Trinidad 192 166 United Kingdom 3 - Total 1,191 1,104 Total Bcfe Deliveries 326.5 301.5
-17- During the first nine months of 2004, wellhead natural gas revenues increased $120 million, or 10%, to $1,295 million from $1,175 million for the same period of 2003. The increase was due to higher natural gas deliveries ($69 million) and composite average wellhead natural gas price ($51 million). The composite average wellhead price for natural gas increased to $4.73 per Mcf from $4.54 per Mcf for the same period of 2003. Natural gas deliveries increased 53 MMcf per day, or 6%, to 1,000 MMcf per day for the first nine months of 2004 from 947 MMcf per day a year ago, primarily due to a 50 MMcf per day, or 32%, increase in Canada; a 21 MMcf per day, or 14%, increase in Trinidad; and a 3 MMcf per day increase in the United Kingdom due to commencement of production in August 2004; partially offset by a 21 MMcf per day, or 3%, decline in the United States. The increase in Canada (50 MMcf per day) was attributable approximately equally to both the property acquisitions in the fourth quarter of 2003 and the additional production that resulted primarily from drilling activities. The increase in Trinidad was mainly attributable to the increased production from the U(a) block (13 MMcf per day) which began supplying natural gas in April 2004 to the N2000 ammonia plant and commencement of production from the Parula wells on the SECC block in February 2004 (9 MMcf per day), partially offset by the decreased production from the U(a) block as a result of a temporary ammonia plant shutdown in May 2004 (2 MMcf per day). Wellhead crude oil and condensate revenues for the first nine months of 2004 increased $94 million, or 51%, to $278 million from $184 million as compared to the same period of 2003, due to increases in both the composite average wellhead crude oil and condensate price ($61 million) and crude oil and condensate deliveries ($33 million). The composite average wellhead price for crude oil and condensate increased 28% to $38.26 per barrel from $29.93 per barrel for the same period of 2003. Wellhead crude oil and condensate deliveries increased 4.0 MBbl per day, or 18%, to 26.5 MBbl per day from 22.5 MBbl per day for the same period a year ago. The increase was mainly due to production from new wells in the United States (2.8 MBbl per day) and commencement in February 2004 of production from the Parula wells on the SECC block in Trinidad (0.6 MBbl per day). Natural gas liquids revenues were $18 million higher than a year ago primarily due to increases in deliveries ($11 million) and the composite average price ($7 million). During the first nine months of 2004, EOG recognized a loss from the mark-to-market of financial commodity collar and price swap contracts of $36 million compared to a loss of $37 million for the prior year period. During the same period of 2004, the net cash outflow related to settled natural gas financial collar contracts and settled natural gas and crude oil financial price swap contracts was $71 million compared to a net cash outflow related to settled natural gas financial collar contracts, premium payments associated with certain natural gas financial collar contracts and settled natural gas and crude oil financial price swap contracts of $49 million for the prior year period. Operating and Other Expenses. For the first nine months of 2004, operating expenses of $905 million were $153 million higher than the $752 million incurred in the first nine months of 2003. The following table presents the costs per Mcfe for the nine-month periods ended September 30, 2004 and 2003:
Nine Months Ended September 30, 2004 2003 Lease and Well $0.61 $0.52 DD&A 1.10 1.06 G&A 0.25 0.24 Taxes Other than Income 0.29 0.21 Interest Expense, Net 0.15 0.15 Total Per-Unit Costs(1) $2.40 $2.18 (1) Total per-unit costs do not include exploration costs, dry hole costs and impairments.
-18- The higher per-unit costs of lease and well, DD&A, G&A and taxes other than income for the nine-month period ended September 30, 2004 compared to the same period in 2003 were due primarily to the reasons set forth below. Lease and well expenses of $199 million were $43 million higher than the prior year period due primarily to higher service cost structures related to operating activities in the United States ($12 million) and in Canada ($3 million), increased production in Canada ($11 million) and in the United States ($1 million), increased transportation expense in the United States ($10 million) and in Canada ($1 million), and changes in the Canadian exchange rate ($4 million). DD&A expenses of $360 million increased $40 million from the prior year period due primarily to increased production in Canada ($13 million), increased Canadian DD&A rates from developing acquired proved reserves ($8 million), increased United States DD&A rates due to a gradual proportional increase in production from higher cost properties ($8 million), changes in the Canadian exchange rate ($5 million) and increased production in the United States ($3 million) and in Trinidad ($1 million). G&A expenses of $81 million were $9 million higher than the prior year period due primarily to expanded operations. Taxes other than income of $96 million were $33 million higher than the prior year period due primarily to a decrease in retroactive credits against severance taxes resulting from the qualification of additional wells for a Texas high cost gas severance tax exemption ($18 million), the results of a production tax lawsuit expensed in the first quarter of 2004 ($5 million), higher property taxes in the United States as a result of higher property valuation ($5 million) and increased wellhead revenue in the United States, as previously discussed ($4 million). Exploration costs of $67 million were $10 million higher than the prior year period due primarily to increased geological and geoscience expenditures in the United States ($7 million) and in Canada ($2 million), and expanded operations in Canada ($1 million) and in Trinidad ($1 million), partially offset by decreased geological and geoscience expenditures in Trinidad ($2 million). Impairments decreased $12 million to $51 million compared to the prior year period due to lower amortization of unproved leases in the United States ($6 million) and lower impairments to the carrying value of certain long-lived assets as a result of downward revisions in the future cash flow analysis for certain properties in the United States ($8 million), partially offset by higher amortization of unproved leases in Canada ($2 million). Total impairments under SFAS No. 144 for the first nine months of 2004 and 2003 were $8 million and $16 million, respectively. For the first nine months of 2004, the income tax provision of $209 million increased $15 million compared to the first nine months of 2003, primarily due to higher income before income taxes ($25 million), partially offset by lower deferred income taxes associated with a reduction in the Alberta, Canada corporate tax rate ($5 million), lower effective foreign income tax rates ($3 million), and lower state income taxes ($1 million). The net effective tax rate for the first nine months of 2004 decreased to 33% from 35% for the same period of 2003. -19- Capital Resources and Liquidity Cash Flows At September 30, 2004 and December 31, 2003, EOG had cash and cash equivalents of $82 million and $4 million, respectively. The primary sources of cash for EOG during the first nine months of 2004 included funds generated from operations, proceeds from sales of assets, proceeds from new borrowings (see discussion of the US$150 million notes issuance below) and proceeds from stock options exercised. Primary cash outflows included funds used in operations, exploration and development expenditures, repayment of debt and payment of dividends to shareholders. Cash provided by operating activities of $1,085 million for the first nine months of 2004 increased $71 million as compared to the same period in 2003 primarily due to higher net income ($62 million). Cash used in investing activities of $993 million for the first nine months of 2004 increased by $316 million as compared to the same period in 2003 due primarily to increased exploration and development expenditures ($368 million), partially offset by a property acquisition deposit made by a Canadian subsidiary of EOG in the third quarter of 2003 ($64 million), which was recorded in Other, Net of the Investing Cash Flows section. Changes in Components of Working Capital Associated with Investing Activities included changes in accounts payable associated with the accrual of exploration and development expenditures and changes in inventories which represent materials and equipment used in drilling and related activities. Cash used in financing activities was $14 million for the first nine months of 2004 versus cash used of $163 million for the same period in 2003. Financing activities for 2004 included the net repayment of debt ($46 million) consisting of repayments of the outstanding balances of commercial paper borrowings ($21 million), a senior unsecured term loan facility ($75 million) and 6.5% notes upon maturity ($100 million), offset partially by the notes issuance discussed below ($150 million). Other financing activities included proceeds from the exercise of employee stock options ($60 million) and payments of cash dividends ($28 million). On March 9, 2004, 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, under Rule 144A of the Securities Act of 1933, as amended. The notes are guaranteed by EOG. In conjunction with the offering, EOG entered into a foreign currency swap transaction for the equivalent amount of the notes and related interest, which has in effect converted this indebtedness into CAD$201.3 million with a 5.275% interest rate. Based upon existing economic and market conditions, management believes net operating cash flow and available financing alternatives will be sufficient to fund net investing and other cash requirements of EOG for the foreseeable future. -20- Total Exploration and Development Expenditures The table below presents total exploration and development expenditures for the nine-month periods ended September 30, 2004 and 2003 (in millions):
Nine Months Ended September 30, 2004 2003 United States $ 726 $ 490 Canada 195 116 United States and Canada 921 606 Trinidad 55 17 United Kingdom 29 14 Other 4 4 Exploration and Development Expenditures 1,009 641 Asset Retirement Costs(1) 7 4 Deferred Income Tax Benefits on Acquired Properties (17) - Total Exploration and Development Expenditures $ 999 $ 645 (1) Asset retirement costs for the first nine months of 2003 do not include the cumulative effect of adoption of SFAS No. 143 - "Accounting for Asset Retirement Obligations" on January 1, 2003.
Exploration and development expenditures of $1 billion for the first nine months of 2004 were $368 million higher than the prior year period due primarily to increased drilling expenditures ($304 million) resulting from higher exploration and development activities across EOG and higher cost structures in the United States and Canada; increased lease acquisitions in the United States ($69 million), primarily in the non-core Barnett Shale area and to a lesser extent, in South Texas; and changes in the Canadian exchange rate ($13 million); partially offset by decreased property acquisitions ($14 million). The higher cost structure was primarily due to increases in materials and services across the industry. The 2004 exploration and development expenditures of $1 billion included $702 million in development, $293 million in exploration, $7 million in property acquisitions and $7 million in capitalized interest. The 2003 exploration and development expenditures of $641 million included $445 million in development, $169 million in exploration, $21 million in property acquisitions and $6 million in capitalized interest. The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other related economic factors. EOG has significant flexibility with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. There are no material continuing commitments associated with expenditure plans. Commodity Derivative Transactions As more fully discussed in Note 12 to the consolidated financial statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2003, EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for natural gas and crude oil. EOG utilizes commodity derivative financial instruments, primarily price swaps and collars, as the means to manage this price risk. In addition to these financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. The financial impact of these various physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices. During the first nine months of 2004 and 2003, EOG elected not to designate any of its commodity derivative financial contracts as accounting hedges, and accordingly, accounted for these commodity derivative financial contracts using the mark-to- market accounting method. -21- Presented below is a summary of EOG's remaining 2004 natural gas financial collar and price swap contracts at September 30, 2004 with prices expressed in dollars per million British thermal units ($/MMBtu) and notional volumes in million British thermal units per day (MMBtud). The total fair value of the natural gas financial collar and price swap contracts at September 30, 2004 was a negative $5 million.
Natural Gas Financial Contracts Collar Contracts Price Swap Contracts Floor Price Ceiling Price Weighted Floor Range/ Weighted Ceiling Weighted Average Volume Floor Average Range Average Volume Price (MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) (MMBtud) ($/MMBtu) 2004 Oct 375,000 $ 4.47 - 4.75 $ 4.58 $ 4.93 - 5.19 $ 5.09 30,000 $ 4.80 Nov 100,000 6.35 6.35 7.60 - 7.64 7.61 - -
Subsequent to September 30, 2004, EOG has entered into additional natural gas financial collar and price swap contracts. Presented below is a summary of EOG's natural gas financial collar and price swap contracts as of October 28, 2004:
Natural Gas Financial Contracts Collar Contracts Price Swap Contracts Floor Price Ceiling Price Weighted Floor Range/ Weighted Ceiling Range/ Weighted Average Volume Floor Average Ceiling Average Volume Price (MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) (MMBtud) ($/MMBtu) 2004 Oct 375,000 $ 4.47 - 4.75 $ 4.58 $ 4.93 - 5.19 $ 5.09 30,000 $ 4.80 Nov 100,000 6.35 6.35 7.60 - 7.64 7.61 200,000 6.82 Dec 50,000 7.65 7.65 8.90 8.90 - - 2005 Jan(1) 75,000 $ 7.65 - 8.00 $ 7.77 $ 8.90 - 9.50 $ 9.10 - $ - Feb(2) 75,000 7.65 - 8.00 7.77 9.19 - 9.50 9.32 - - Mar(2) 75,000 7.65 - 8.00 7.77 9.19 - 9.50 9.32 - - (1) Notional volumes of 25,000 MMBtud of the January 2005 collar contracts were purchased at a premium of $0.10 per MMBtu. (2) The collar contracts for February 2005 and March 2005 were purchased at a premium of $0.10 per MMBtu.
-22- 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. 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 of pipeline transportation capacity; the extent to which EOG can replicate on its other Barnett Shale acreage the results of its most recent Barnett Shale wells; the results of wells yet to be drilled that are necessary to test whether substantial Barnett Shale acreage positions in Erath, Somervell, Hood, Jack, Palo Pinto and Hill Counties, Texas, contain suitable drilling prospects; 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. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK EOG RESOURCES, INC. EOG's exposure to interest rate risk, commodity price risk and foreign currency exchange risk is discussed respectively in the Financing and Outlook sections of the "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity," on pages 10 through 14 of the Form 8-K filed on February 24, 2004. ITEM 4. CONTROLS AND PROCEDURES EOG RESOURCES, INC. 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 quarter ended September 30, 2004. 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 end of the quarter ended September 30, 2004 to ensure that information that is required to be disclosed by EOG in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms. There were no changes in EOG's internal control over financial reporting that occurred during the quarter ended September 30, 2004 that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting. -23- PART II. OTHER INFORMATION EOG RESOURCES, INC. ITEM 1. Legal Proceedings See Part 1, Item 1, Note 5 to Consolidated Financial Statements, which is incorporated herein by reference. ITEM 2. Changes in Securities and Use of Proceeds
(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) July 1, 2004 - July 31, 2004 - $ - - 6,386,200 Aug 1, 2004 - Aug 31, 2004 120 57.45 - 6,386,200 Sept 1, 2004 - Sept 30, 2004 133 58.98 - 6,386,200 Total 253 $58.25 - (1) Includes 253 shares 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 6. Exhibits Exhibit 31.1 - Section 302 Certification of Periodic Report of Chief Executive Officer. 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. -24- 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: October 28, 2004 By: /s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Vice President and Chief Accounting Officer (Principal Accounting Officer) -25- EXHIBIT INDEX Exhibit No. Description *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 -26-