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 March 31, 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.
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333 Clay Street, Suite 4200
Houston, Texas 77002-7361
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 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 121b-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 April 18, 2005.
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Title of each class |
Number of shares |
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Common Stock, par value $0.01 per share |
239,249,355 |
EOG RESOURCES, INC.
FORM 10-Q
TABLE OF CONTENTS
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Page No. |
| PART I. FINANCIAL INFORMATION | |
| Item 1. Financial Statements |
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| Consolidated Statements of Income - Three Months Ended March 31, 2005 and 2004 |
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| Consolidated Balance Sheets - March 31, 2005 and December 31, 2004 |
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| Consolidated Statements of Cash Flows - Three Months Ended March 31, 2005 and 2004 |
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| Notes to Consolidated Financial Statements |
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| Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations |
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| Item 3. Quantitative and Qualitative Disclosures About Market Risk |
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| Item 4. Controls and Procedures |
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| PART II. OTHER INFORMATION |
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| Item 1. Legal Proceedings |
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| Item 2. Unregistered Sales of Equity Securities and Use of Proceeds |
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| Item 6. Exhibits |
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| SIGNATURES |
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| EXHIBIT INDEX |
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2
PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS
EOG RESOURCES, INC.
The accompanying notes are an integral part of these consolidated financial statements.
3
EOG RESOURCES, INC.
The accompanying notes are an integral part of these consolidated financial statements.
4
EOG RESOURCES, INC.
The accompanying notes are an integral part of these consolidated financial statements.
5
EOG RESOURCES, INC. 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. Certain reclassifications have been made to prior period financial statements
to conform with the current presentation. 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. Currently, EOG is not a party to any financial commodity collar or price swap
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. 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. The deduction is subject to a number of
limitations and, currently, uncertainty remains as to how to interpret some provisions in the Act.
In addition, a comprehensive analysis of foreign legal and tax ramifications 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 September 30, 2005. In December 2004, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards (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 Accounting Principles Board (APB) Opinion No. 25. 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 - "Accounting for Stock Issued to Employees." 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 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). 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. 7
EOG's pro forma Net Income and Net Income Per Share Available to Common for
the three-month periods ended March 31, 2005 and 2004, had compensation costs been recorded in
accordance with SFAS No. 123, are presented below (in millions, except per share data): * 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. 2. The following table sets forth the computation of Net Income Per Share
Available to Common for the three-month periods ended March 31 (in thousands, except per share
amounts): * Restated for two-for-one stock split effective March
1, 2005 (see Note 1). 8
3. The following table presents the components of EOG's comprehensive income
for the three-month periods ended March 31 (in thousands): 4. Selected financial information by reportable segment is presented below for
the three-month periods ended March 31 (in thousands): 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. 9
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 period ended March
31, 2005 (in thousands): 7.
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, Except Per Share Amounts)
(Unaudited)
Three Months Ended
March 31,
------------------------
2005 2004
----------- -----------
Net Operating Revenues
Natural Gas $ 543,591 $ 417,389
Crude Oil, Condensate and Natural Gas Liquids 144,536 90,458
Losses on Mark-to-Market Commodity Derivative Contracts (940) (44,455)
Other, Net 969 928
----------- -----------
Total 688,156 464,320
----------- -----------
Operating Expenses
Lease and Well, including Transportation 82,875 64,417
Exploration Costs 34,816 25,996
Dry Hole Costs 14,582 10,027
Impairments 12,172 17,648
Depreciation, Depletion and Amortization 153,016 113,797
General and Administrative 28,687 24,915
Taxes Other Than Income 41,913 36,084
----------- -----------
Total 368,061 292,884
----------- -----------
Operating Income 320,095 171,436
Other Income (Expense), Net 5,465 (2,729)
----------- -----------
Income Before Interest Expense and Income Taxes 325,560 168,707
Interest Expense, Net 13,957 16,683
----------- -----------
Income Before Income Taxes 311,603 152,024
Income Tax Provision 108,900 51,171
----------- -----------
Net Income 202,703 100,853
Preferred Stock Dividends 1,858 2,758
----------- -----------
Net Income Available to Common $ 200,845 $ 98,095
=========== ===========
Net Income Per Share Available to Common
Basic $ 0.85 $ 0.42
=========== ===========
Diluted $ 0.83 $ 0.42
=========== ===========
Average Number of Common Shares
Basic 237,293 231,289
=========== ===========
Diluted 242,114 235,242
=========== ===========
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Data)
(Unaudited)
March 31, December 31,
2005 2004
------------- -------------
ASSETS
Current Assets
Cash and Cash Equivalents $ 173,385 $ 20,980
Accounts Receivable, Net 441,157 447,742
Inventories 48,741 40,037
Assets from Price Risk Management Activities - 10,747
Deferred Income Taxes 25,788 22,227
Other 42,995 45,070
------------- -------------
Total 732,066 586,803
Oil And Gas Properties (Successful Efforts Method) 9,934,032 9,599,276
Less: Accumulated Depreciation, Depletion and Amortization (4,646,824) (4,497,673)
------------- -------------
Net Oil and Gas Properties 5,287,208 5,101,603
Other Assets 97,754 110,517
------------- -------------
Total Assets $ 6,117,028 $ 5,798,923
============= =============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts Payable $ 400,802 $ 424,581
Accrued Taxes Payable 90,911 51,116
Dividends Payable 9,811 7,394
Deferred Income Taxes 20,293 103,933
Other 40,970 45,180
------------- -------------
Total 562,787 632,204
Long-Term Debt 1,119,797 1,077,622
Other Liabilities 251,997 241,319
Deferred Income Taxes 1,028,805 902,354
Shareholders' Equity
Preferred Stock, $0.01 Par, 10,000,000 Shares Authorized:
Series B, 100,000 Shares Issued, Cumulative,
$100,000,000 Liquidation Preference 98,885 98,826
Common Stock, $0.01 Par, 320,000,000 Shares Authorized and
249,460,000 Shares Issued 202,495 201,247
Additional Paid in Capital 31,480 21,047
Unearned Compensation (37,116) (29,861)
Accumulated Other Comprehensive Income 140,741 148,015
Retained Earnings 2,898,126 2,706,845
Common Stock Held in Treasury, 10,364,740 Shares at
March 31, 2005 and 11,605,112 Shares at December 31, 2004 (180,969) (200,695)
------------- -------------
Total Shareholders' Equity 3,153,642 2,945,424
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Total Liabilities and Shareholders' Equity $ 6,117,028 $ 5,798,923
============= =============
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
Three Months Ended
March 31,
----------------------
2005 2004
---------- ----------
Cash Flows From Operating Activities
Reconciliation of Net Income to Net Operating Cash Provided by Operating Activities:
Net Income $ 202,703 $ 100,853
Items Not Requiring Cash
Depreciation, Depletion and Amortization 153,016 113,797
Impairments 12,172 17,648
Deferred Income Taxes 44,928 32,016
Other, Net 1,257 7,432
Dry Hole Costs 14,582 10,027
Mark-to-Market Commodity Derivative Contracts
Total Losses 940 44,455
Realized Gains (Losses) 9,806 (2,342)
Tax Benefits from Stock Options Exercised 9,348 2,419
Other, Net (2,112) (825)
Changes in Components of Working Capital and Other Liabilities
Accounts Receivable 5,518 (9,160)
Inventories (8,701) (1,849)
Accounts Payable (26,352) 13,579
Accrued Taxes Payable 41,807 22,094
Other Liabilities 3,666 (371)
Other, Net (6,459) 6,097
Changes in Components of Working Capital Associated with Investing
and Financing Activities 25,720 9,576
---------- ----------
Net Cash Provided by Operating Activities 481,839 365,446
Investing Cash Flows
Additions to Oil and Gas Properties (363,760) (240,543)
Proceeds from Sales of Assets 19,752 5,954
Changes in Components of Working Capital Associated with Investing Activities (25,671) (11,162)
Other, Net (7,394) (7,646)
---------- ----------
Net Cash Used in Investing Activities (377,073) (253,397)
Financing Cash Flows
Net Commercial Paper and Line of Credit Borrowings (Repayments) 42,175 (98,050)
Long-Term Debt Borrowings - 150,000
Long-Term Debt Repayments - (75,000)
Dividends Paid (8,880) (8,461)
Proceeds from Stock Options Exercised 14,264 8,775
Other, Net (49) 264
---------- ----------
Net Cash Provided by (Used in) Financing Activities 47,510 (22,472)
Effect of Exchange Rate Changes on Cash 129 1,697
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Increase in Cash and Cash Equivalents 152,405 91,274
Cash and Cash Equivalents at Beginning of Period 20,980 4,443
---------- ----------
Cash and Cash Equivalents at End of Period $ 173,385 $ 95,717
========== ==========
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Three Months Ended
March 31,
--------------------
2005 2004
--------- ---------
Net Income Available to Common - As Reported $ 200.8 $ 98.1
Deduct: Total Stock-Based Employee Compensation
Expense, Net of Income Tax (3.2) (2.5)
--------- ---------
Net Income Available to Common - Pro Forma $ 197.6 $ 95.6
========= =========
Net Income Per Share Available to Common
Basic - As Reported $ 0.85 $ 0.42 *
========= =========
Basic - Pro Forma $ 0.83 $ 0.41 *
========= =========
Diluted - As Reported $ 0.83 $ 0.42 *
========= =========
Diluted - Pro Forma $ 0.82 $ 0.41 *
========= =========
Three Months Ended
March 31,
------------------------
2005 2004
----------- -----------
Numerator for Basic and Diluted Earnings Per Share -
Net Income Available to Common $ 200,845 $ 98,095
=========== ===========
Denominator for Basic Earnings Per Share -
Weighted Average Shares 237,293 231,289 *
Potential Dilutive Common Shares -
Stock Options 3,792 3,192 *
Restricted Stock and Units 1,029 761 *
Denominator for Diluted Earnings Per Share -
----------- -----------
Adjusted Weighted Average Shares 242,114 235,242 *
=========== ===========
Net Income Per Share Available to Common
Basic $ 0.85 $ 0.42 *
=========== ===========
Diluted $ 0.83 $ 0.42 *
=========== ===========
Three Months Ended
March 31,
------------------------
2005 2004
----------- -----------
Comprehensive Income
Net Income $ 202,703 $ 100,853
Other Comprehensive Loss
Foreign Currency Translation Adjustment (4,926) (12,173)
Foreign Currency Swap Transaction, Net of Income Tax
Benefit of $1,243 (2,348) -
----------- -----------
Total $ 195,429 $ 88,680
=========== ===========
Three Months Ended
March 31,
------------------------
2005 2004
----------- -----------
Net Operating Revenues
United States $ 483,690 $ 334,768
Canada 133,987 100,802
Trinidad 48,991 28,750
United Kingdom 21,488 -
----------- -----------
Total $ 688,156 $ 464,320
=========== ===========
Operating Income (Loss)
United States $ 208,801 $ 101,005
Canada 65,306 54,249
Trinidad 30,256 19,877
United Kingdom 15,732 (3,695)
----------- -----------
Total 320,095 171,436
Reconciling Items
Other Income (Expense), Net 5,465 (2,729)
Interest Expense, Net 13,957 16,683
----------- -----------
Income Before Income Taxes $ 311,603 $ 152,024
=========== ===========
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
=========== =========== ===========
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 March 31, 2005 and 2004, EOG's total contributions to these pension plans amounted to $3.6 million and $3.2 million, respectively.Postretirement Plan. The following table summarizes the benefit expense for EOG's contributory defined dollar benefit postretirement medical plan for the three-month periods ended March 31 (in thousands):
Three Months Ended
March 31,
--------------------
2005 2004
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Service Cost $ 42 $ 70
Interest Cost 31 50
Expected Return on Plan Assets - -
Amortization of Prior Service Cost 32 33
Amortization of Net Actuarial (Gain) Loss (15) -
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Net Periodic Benefit Cost $ 90 $ 153
========= =========
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 March 31, 2005, $16,000 of contributions have been made. EOG presently anticipates contributing an additional $68,000 to fund its postretirement plan in 2005 for a total of $84,000.
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8. 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.
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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
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, Texas, Oklahoma and western Canada.
International. In mid-2004, EOG began additional natural gas sales to the National Gas Company of Trinidad and Tobago (NGC) under a fifteen-year take-or-pay contract. Under the contract, EOG supplies approximately 60 million cubic feet (MMcf) per day gross of natural gas to NGC. This gas is being resold by NGC to an anhydrous ammonia plant located in Point Lisas, Trinidad. The plant is owned by Nitrogen (2000) Unlimited (N2000). At December 31, 2004, EOG's subsidiary, EOG Resources NITRO2000 Ltd. (EOGNitro2000), owned a 23% equity interest in N2000. In February 2005, a portion of EOGNitro2000's shareholdings was sold to a subsidiary of one of the other shareholders. The sale resulted in a pre-tax gain of approximately $2 million. EOGNitro2000's equity interest in N2000 was 10% as of March 31, 2005.
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 the two ammonia plants and the new methanol plant, will continue to give its portfolio an even broader exposure to United States and Canada natural gas fundamentals.
EOG continues its progress in the Southern Gas Basin of the United Kingdom North Sea. In 2004, a development well was drilled in the Valkyrie field and commenced production in August of the same year. Production commenced in January 2005 from the production facilities installed in the Arthur field, which was discovered in 2003. The Arthur 2 well was drilled during the first quarter of 2005 as an extension to the Arthur 1 discovery. The well tested 58 MMcf per day and first production is expected later in 2005. EOG has a 30 percent working interest. EOG continues to review additional opportunities in this area and expects to participate in several exploration 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 debt-to-total capitalization ratio. At March 31, 2005, EOG's debt-to-total capitalization ratio was 26%, slightly down from 27% at year-end 2004. During the first quarter 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 essentially be funded by cash from operations.
For 2005, EOG's estimated exploration and development expenditure budget is approximately $1.6 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 periods ended March 31, 2005 and 2004 should be read in conjunction with the consolidated financial statements of EOG and notes thereto.
Net Operating Revenues
During the first quarter of 2005, net operating revenues increased $224 million to $688 million from $464 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 36% to $688 million, as compared to $507 million for the same period in 2004. Natural Gas Revenues consists of natural gas wellhead revenues and revenues from marketing activities associated with the sales and purchases of natural gas. Revenues from natural gas marketing activities were $0.5 million for each of the first quarters of 2005 and 2004. Crude oil, condensate and natural gas liquids revenues represent solely wellhead revenues for these products.
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Wellhead volume and price statistics for the three-month periods ended March 31 were as follows:
Three Months Ended
March 31,
--------------------
2005 2004
--------- ---------
Natural Gas Volumes (MMcf per day) (1)
United States 689 618
Canada 234 203
--------- ---------
United States and Canada 923 821
Trinidad 205 154
United Kingdom 35 -
--------- ---------
Total 1,163 975
========= =========
Average Natural Gas Prices ($/Mcf) (2)
United States $ 5.97 $ 5.40
Canada 5.69 4.98
United States and Canada 5.90 5.30
Trinidad 1.74 1.49
United Kingdom 6.65 -
Composite 5.19 4.70
Crude Oil and Condensate Volumes (MBbl per day) (1)
United States 22.5 20.0
Canada 2.5 2.6
--------- ---------
United States and Canada 25.0 22.6
Trinidad 4.1 2.6
United Kingdom 0.2 -
--------- ---------
Total 29.3 25.2
========= =========
Average Crude Oil and Condensate Prices ($/Bbl) (2)
United States $ 48.79 $ 34.76
Canada 44.79 31.72
United States and Canada 48.39 34.41
Trinidad 45.38 32.91
United Kingdom 39.74 -
Composite 47.91 34.25
Natural Gas Liquids Volumes (MBbl per day) (1)
United States 5.5 4.8
Canada 1.5 0.6
--------- ---------
Total 7.0 5.4
========= =========
Average Natural Gas Liquids Prices ($/Bbl) (2)
United States $ 29.28 $ 24.71
Canada 27.47 20.14
Composite 28.89 24.21
Natural Gas Equivalent Volumes (MMcfe per day) (3)
United States 857 767
Canada 258 222
--------- ---------
United States and Canada 1,115 989
Trinidad 230 169
United Kingdom 36 -
--------- ---------
Total 1,381 1,158
========= =========
Total Bcfe (3) Deliveries 124.3 105.4
(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) Dollars per thousand cubic feet or per barrel, as applicable.
(3) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil, condensate and natural gas liquids.
14
Wellhead natural gas revenues for the first quarter of 2005 increased $126 million, or 30%, to $543 million from $417 million for the same period of 2004 due to increases in natural gas deliveries ($75 million) and the composite average wellhead natural gas price ($51 million). The composite average wellhead price for natural gas increased 10% to $5.19 per Mcf for the first quarter of 2005 from $4.70 per Mcf for the first quarter of 2004.
Natural gas deliveries increased 188 MMcf per day, or 19%, to 1,163 MMcf per day for the first quarter of 2005 from 975 MMcf per day for the same period in 2004, primarily due to a 51 MMcf per day, or 33%, increase in Trinidad; a 31 MMcf per day, or 15%, increase in Canada; a 71 MMcf per day, or 11%, increase in the United States; and a 35 MMcf per day increase in the United Kingdom due to commencement of production in August 2004. The increase in Trinidad was attributable to the increased production from the U(a) block (45 MMcf per day) which began supplying natural gas in mid-2004 to the N2000 ammonia plant and commencement of production from the Parula wells on the South East Coast Consortium block in February 2004 (7 MMcf per day). The increase in Canada was attributable to additional production from the drilling program including continued development of the properties acquired in late 2003. The increase in the United States was primarily attributable to increased production from Texas (36 MMcf per day), the Rocky Mountain area (17 MMcf per day) and Louisiana (14 MMcf per day).
Wellhead crude oil and condensate revenues increased $48 million, or 62%, to $126 million from $78 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 ($12 million). The composite average wellhead crude oil and condensate price for the first quarter of 2005 was $47.91 per barrel compared to $34.25 per barrel for the same period in 2004.
Wellhead crude oil and condensate deliveries increased 4.1 MBbl per day, or 16%, to 29.3 MBbl per day from 25.2 MBbl per day for the first quarter of 2004. The increase was mainly due to production from new wells in the United States (2.5 MBbl per day), higher production in Trinidad from the Parula wells (0.7 MBbl per day) and new production from the U(a) block (0.7 MBbl per day).
Natural gas liquids revenues were $6 million higher than a year ago primarily due to increases in deliveries ($3 million) and the increase in the composite average price ($3 million).
During the first quarter of 2005, EOG recognized a loss on mark-to-market financial commodity derivative contracts of $1 million compared to a loss of $44 million for the same period in 2004. During the first quarter of 2005, the net cash inflow related to settled natural gas financial collar contracts was $10 million compared to a net cash outflow related to settled natural gas financial collar contracts and settled natural gas and crude oil financial price swap contracts of $2 million for the comparable period in 2004.
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Operating and Other Expenses
For the first quarter of 2005, operating expenses of $368 million were $75 million higher than the $293 million incurred in the first three months of 2004. The following table presents the costs per Mcfe for the three-month periods ended March 31:
Three Months Ended
March 31,
--------------------
2005 2004
--------- ---------
Lease and Well, including Transportation $ 0.67 $ 0.61
DD&A 1.23 1.08
G&A 0.23 0.24
Taxes Other Than Income 0.34 0.34
Interest Expense, Net 0.11 0.16
--------- ---------
Total Per-Unit Costs* $ 2.58 $ 2.43
========= =========
* 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, and DD&A for the three-month period ended March 31, 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 company 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 operations, 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, contract pumping, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep, fuel and power. Workovers are costs of operations to restore efficient operating conditions to maintain and increase production.
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 $83 million were $18 million higher than the prior year period primarily due to higher operating and maintenance expenses in the United States ($5 million), increased transportation related costs in the United States ($4 million) and the United Kingdom ($2 million), increased lease and well administrative expenses in the United States ($2 million), increased workover expenditures in Trinidad ($2 million) and the United States ($1 million), and changes in the Canadian exchange rate ($1 million).
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DD&A expenses of $153 million increased $39 million from the prior year period primarily due to increased United States DD&A rates ($17 million); increased production in the United States ($9 million), Canada ($3 million) and Trinidad ($1 million), as discussed above; the commencement of production in August 2004 in the United Kingdom ($3 million); increased Canadian DD&A rates ($3 million); and changes in the Canadian exchange rate ($2 million).
General and Administrative (G&A) expenses of $29 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 $42 million were $6 million higher than the prior year period primarily due to increased wellhead revenue in the United States ($5 million), production tax relief in the first quarter of 2004 in Trinidad ($3 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 $14 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 $35 million were $9 million higher than the prior year period primarily due to increased geological and geophysical expenditures in the United States ($5 million) and Trinidad ($1 million), and increased exploration administrative expenses in the United States ($2 million) and Trinidad ($1 million).
Impairments of $12 million were $5 million lower than the prior year period primarily due to lower amortization of unproved leases in the United States ($4 million) and lower impairments to the carrying value of certain long-lived assets in the United States ($2 million), partially offset by higher amortization of unproved leases in Canada ($1 million). Total impairments under Statement of Financial Accounting Standards No. 144 - "Accounting for the Impairment or Disposal of Long-Lived Assets" for the first quarters of 2005 and 2004 were $1 million and $3 million, respectively.
Net other income was $5 million for the first quarter of 2005 compared to net other expense of $3 million for the first quarter of 2004. The increased other income of $8 million was primarily due to foreign currency transaction losses ($5 million) during the first quarter of 2004 as a result of applying the changes in the Canadian exchange rate to certain intercompany short-term loans that eliminate in consolidation and a gain on the sell down of interest in Nitro2000 Ammonia Plant ($2 million) in the first quarter of 2005.
Income tax provision of $109 million increased $58 million compared to the first quarter of 2004, primarily resulting from higher income before income taxes ($56 million) and higher state income taxes ($1 million). As a result of the above changes, the net effective tax rate for the first quarter of 2005 increased to 35% from 34% for the same period of 2004.
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Capital Resources and Liquidity
Cash Flow
The primary sources of cash for EOG during the three months ended March 31, 2005 included funds generated from operations, proceeds from sales of partial interests in certain equity investments in Trinidad, 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.
Net cash provided by operating activities of $482 million for the first three months of 2005 increased approximately $116 million as compared to the same period in 2004 primarily reflecting an increase in wellhead revenues of $180 million, an increase in realized gains from mark-to-market commodity derivative contracts of $12 million and an increase in tax benefits from stock options exercised of $7 million, partially offset by an increase in current tax expense of $45 million, an increase in cash operating expenses of $34 million and unfavorable changes in working capital and other liabilities of $5 million.
Net cash used in investing activities of $377 million for the first three months of 2005 increased by $124 million as compared to the same period in 2004 due primarily to increased additions to oil and gas properties.
Net cash provided by financing activities was $48 million for the first three months of 2005 versus cash used of $22 million for the same period in 2004. Financing activities for 2005 included net commercial paper borrowings of $42 million, proceeds from sales of treasury stock attributable to employee stock option exercises of $14 million and cash dividend payments of $9 million.
Total Exploration and Development Expenditures
The table below presents total exploration and development expenditures for the three-month periods ended March 31 (in millions):
Three Months Ended
March 31,
--------------------
2005 2004
--------- ---------
United States $ 298 $ 192
Canada 72 49
--------- ---------
United States and Canada 370 241
Trinidad 14 17
United Kingdom 13 8
Other 1 1
--------- ---------
Exploration and Development Expenditures 398 267
Asset Retirement Costs 1 2
--------- ---------
Total Exploration and Development Expenditures $ 399 $ 269
========= =========
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Exploration and development expenditures of $398 million for the first three months of 2005 were $131 million higher than the prior year due primarily to increased drilling expenditures resulting from higher exploration and development activities in the United States ($80 million), Canada ($14 million) and the United Kingdom ($5 million); increased lease acquisitions in the United States ($19 million), primarily in the non-core Barnett Shale area, and Canada ($3 million); and changes in the Canadian exchange rate ($5 million). The 2005 exploration and development expenditures of $398 million included $257 million in development, $137 million in exploration, $3 million in capitalized interest and $1 million in property acquisitions. The 2004 exploration and development expenditures of $267 million included $186 million in development, $78 million in exploration, $2 million in capitalized interest and $1 million in property acquisitions.
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. Currently, EOG is not a party to any financial commodity collar or price swap 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.
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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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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 rate risk is discussed in the "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity," on pages 25 through 30 of the Form 10-K 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 recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms.
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)
- ---------------------------------------- ------------- ------------ -------------------- -------------------------
January 1, 2005 - January 31, 2005 50 * $ 36.34 * - 6,386,200
February 1, 2005 - February 28, 2005 83,719 * 39.02 * - 6,386,200
March 1, 2005 - March 31, 2005 3,844 45.70 - 6,386,200
------------- --------------------
Total 87,613 39.20 -
============= ====================
(1) Comprises 87,613 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
* Adjusted to reflect the two-for-one stock split effective March 1, 2005 (see Note 1 to the Consolidated Financial Statements included in Part I, Item 1).
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.
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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: April 26, 2005 |
By: |
/s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Vice President and Chief Accounting Officer (Principal Accounting Officer) |
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EXHIBIT INDEX
*Exhibits filed herewith
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