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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
Form 10-Q
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 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 Identification No.)
of 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 July 23, 2004.
Title of each class Number of shares
Common Stock, $.01 117,850,517
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 June 30,
2004 and 2003 and Six Months Ended June 30, 2004 and 2003 3
Consolidated Balance Sheets - June 30, 2004 and December 31, 2003 4
Consolidated Statements of Cash Flows - Six Months Ended June 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 13
ITEM 3. Quantitative and Qualitative Disclosures About
Market Risk 24
ITEM 4. Controls and Procedures 24
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings 25
ITEM 2. Changes in Securities and Use of Proceeds 25
ITEM 4. Submission of Matters to a Vote of Security Holders 25
ITEM 5. Other Information 26
ITEM 6. Exhibits and Current Reports on Form 8-K 26
SIGNATURES 27
EXHIBIT INDEX 28
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, Except Per Share Amounts)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2004 2003 2004 2003
Net Operating Revenues
Natural Gas $430,532 $377,643 $847,921 $811,734
Crude Oil, Condensate and Natural Gas Liquids 102,401 61,471 192,859 136,979
Losses on Mark-to-Market Commodity
Derivative Contracts (14,563) (15,753) (59,018) (60,974)
Other, Net 651 1,393 1,579 1,684
Total 519,021 424,754 983,341 889,423
Operating Expenses
Lease and Well 65,532 53,620 129,949 101,959
Exploration Costs 19,596 22,139 45,592 39,597
Dry Hole Costs 19,064 3,436 29,091 10,056
Impairments 15,711 25,475 33,359 37,431
Depreciation, Depletion and Amortization 116,224 106,587 230,021 210,140
General and Administrative 26,370 24,934 51,285 45,355
Taxes Other Than Income 29,788 11,695 65,872 41,888
Total 292,285 247,886 585,169 486,426
Operating Income 226,736 176,868 398,172 402,997
Other Income (Expense), Net 1,425 2,680 (1,304) 2,832
Income Before Interest Expense and Income Taxes 228,161 179,548 396,868 405,829
Interest Expense, Net 15,416 13,807 32,099 29,125
Income Before Income Taxes 212,745 165,741 364,769 376,704
Income Tax Provision 67,808 56,950 118,979 131,357
Net Income Before Cumulative Effect of Change
in Accounting Principle 144,937 108,791 245,790 245,347
Cumulative Effect of Change in Accounting
Principle, Net of Income Tax - - - (7,131)
Net Income 144,937 108,791 245,790 238,216
Preferred Stock Dividends 2,758 2,758 5,516 5,516
Net Income Available to Common $142,179 $106,033 $240,274 $232,700
Net Income Per Share Available to Common
Basic
Net Income Available to Common Before Cumulative
Effect of Change in Accounting Principle $ 1.22 $ 0.93 $ 2.07 $ 2.09
Cumulative Effect of Change in Accounting
Principle, Net of Income Tax - - - (0.06)
Net Income Available to Common $ 1.22 $ 0.93 $ 2.07 $ 2.03
Diluted
Net Income Available to Common Before Cumulative
Effect of Change in Accounting Principle $ 1.20 $ 0.91 $ 2.03 $ 2.06
Cumulative Effect of Change in Accounting
Principle, Net of Income Tax - - - (0.06)
Net Income Available to Common $ 1.20 $ 0.91 $ 2.03 $ 2.00
Average Number of Common Shares
Basic 116,388 114,382 116,052 114,430
Diluted 118,709 116,131 118,227 116,212
The accompanying notes are an integral part of these consolidated financial statements.
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 1. FINANCIAL STATEMENTS - (Continued)
EOG RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Data)
June 30, December 31,
2004 2003
(Unaudited)
ASSETS
Current Assets
Cash and Cash Equivalents $ 67,839 $ 4,443
Accounts Receivable, Net 355,662 295,118
Inventories 30,253 21,922
Deferred Income Taxes 39,564 31,548
Other 57,106 42,983
Total 550,424 396,014
Oil and Gas Properties (Successful Efforts Method) 8,616,115 8,189,062
Less: Accumulated Depreciation, Depletion
and Amortization (4,149,096) (3,940,145)
Net Oil and Gas Properties 4,467,019 4,248,917
Other Assets 109,523 104,084
Total Assets $5,126,966 $4,749,015
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts Payable $ 319,535 $ 282,379
Accrued Taxes Payable 50,165 33,276
Dividends Payable 7,425 6,175
Liabilities from Price Risk Management Activities 58,601 37,779
Deferred Income Taxes 36,260 73,611
Other 34,078 43,299
Total 506,064 476,519
Long-Term Debt 1,085,822 1,108,872
Other Liabilities 180,743 171,115
Deferred Income Taxes 876,406 769,128
Shareholders' Equity
Preferred Stock, $.01 Par, 10,000,000 Shares Authorized:
Series B, 100,000 Shares Issued, Cumulative,
$100,000 Liquidation Preference 98,707 98,589
Series D, 500 Shares Issued, Cumulative,
$50,000 Liquidation Preference 49,918 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 7,478 1,625
Unearned Compensation (27,978) (23,473)
Accumulated Other Comprehensive Income 41,473 73,934
Retained Earnings 2,347,446 2,121,214
Common Stock Held in Treasury, 7,044,550 shares at
June 30, 2004 and 8,819,600 shares at December 31,
2003 (240,360) (299,582)
Total Shareholders' Equity 2,477,931 2,223,381
Total Liabilities and Shareholders' Equity $5,126,966 $4,749,015
The accompanying notes are an integral part of these consolidated financial statements.
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 1. FINANCIAL STATEMENTS - (Continued)
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
Six Months Ended
June 30,
2004 2003
Cash Flows From Operating Activities
Reconciliation of Net Income to Net Cash Provided
by Operating Activities:
Net Income $ 245,790 $ 238,216
Items Not Requiring Cash
Depreciation, Depletion and Amortization 230,021 210,140
Impairments 33,359 37,431
Deferred Income Taxes 84,216 79,975
Cumulative Effect of Change in Accounting
Principle, Net of Income Tax - 7,131
Other, Net 13,289 3,965
Exploration Costs 45,592 39,597
Dry Hole Costs 29,091 10,056
Mark-to-Market Commodity Derivative Contracts
Total Losses 59,018 60,974
Realized Losses (38,211) (39,089)
Tax Benefits from Stock Options Exercised 13,792 4,802
Other, Net (1,273) 3,499
Changes in Components of Working Capital and
Other Liabilities
Accounts Receivable (60,458) (44,420)
Inventories (8,331) (44)
Accounts Payable 37,171 24,353
Accrued Taxes Payable (4,450) 16,809
Other Liabilities 257 (1,151)
Other, Net (3,465) 7,899
Changes in Components of Working Capital Associated
with Investing and Financing Activities 16,736 (6,931)
Net Cash Provided by Operating Activities 692,144 653,212
Investing Cash Flows
Additions to Oil and Gas Properties (534,540) (325,046)
Exploration Costs (45,592) (39,597)
Dry Hole Costs (29,091) (10,056)
Proceeds from Sales of Assets 9,762 9,750
Changes in Components of Working Capital Associated
with Investing Activities (15,988) 6,879
Other, Net (13,139) 1,279
Net Cash Used in Investing Activities (628,588) (356,791)
Financing Cash Flows
Long-Term Debt Borrowing 150,000 -
Long-Term Debt Repayments (173,050) (134,310)
Dividends Paid (18,099) (14,480)
Treasury Stock Purchased - (21,295)
Proceeds from Stock Options Exercised 43,190 14,730
Other, Net (2,201) 53
Net Cash Used in Financing Activities (160) (155,302)
Increase in Cash and Cash Equivalents 63,396 141,119
Cash and Cash Equivalents at Beginning of Period 4,443 9,848
Cash and Cash Equivalents at End of Period $ 67,839 $ 150,967
The accompanying notes are an integral part of these consolidated financial statements.
PART I. FINANCIAL INFORMATION (Continued)
ITEM 1. FINANCIAL STATEMENTS (Continued)
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. The consolidated financial statements of EOG Resources, Inc.
(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 six
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
June 30, 2004, EOG recorded the fair value of the swap of $2.7
million in Other Liabilities in the Liabilities section of the
Consolidated Balance Sheets. Changes in the fair value of the
foreign currency swap result in no net impact to the
Consolidated Statements of Income and an after-tax loss of
$1.7 million in Accumulated Other Comprehensive Income in the
Shareholders' Equity section of the Consolidated Balance
Sheets.
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). On March 31, 2004, the FASB issued a proposed
statement to amend SFAS No. 123 to require all companies to
expense the value of employee stock options. This proposed
statement set a comment deadline of June 30, 2004, and would be
effective prospectively beginning first quarter of 2005 for EOG.
EOG is currently evaluating the effect of the proposed statement
on its financial statements and continues to monitor further
developments relating to the proposed statement.
During the third quarter of 2003, the SEC made comments to other
registrants that oil and gas mineral rights acquired should be
classified as an intangible asset pursuant to SFAS No. 141 -
"Business Combinations," and SFAS No. 142 - "Goodwill and Other
Intangible Assets." However, the SEC is not currently requiring
all oil and gas producing companies to apply this classification
or the disclosure requirements of intangible assets. Currently,
EOG classifies the cost of oil and gas mineral rights as oil and
gas properties and believes that this is consistent with oil and
gas accounting and industry practice. The FASB has been asked to
address this issue. If the FASB determines that the
reclassification is required, EOG would reclassify these costs
from oil and gas properties to intangible assets on the balance
sheet. There would be no effect on the Consolidated Statements
of Income or Consolidated Statements of Cash Flows. In March
2004, the FASB reached a consensus that for the mining industry
all mineral rights are tangible assets and that SFAS Nos. 141 and
142 should be amended accordingly. In July 2004, the FASB set a
comment deadline of August 17, 2004 to gather input as to whether
the cost of oil and gas mineral rights is covered by the scope
exception in SFAS No. 142 and, therefore, the current oil and gas
accounting and industry practice is proper. EOG will continue to
monitor the developments in this area until the final decision by
the FASB emerges.
On April 1, 2004, EOG adopted FASB Staff Position No. 106-2 -
"Accounting and Disclosure Requirements related to the Medicare
Prescription Drug, Improvement and Modernization Act of 2003"
(FSP 106-2), which provides guidance on accounting for the
effects of the Medicare Prescription Drug Improvement Act of 2003
for employers that sponsor postretirement health care plans that
provide prescription drug benefits. The adoption of FSP 106-2
did not have a material impact on EOG's financial statements (see
Note 7 - Postretirement Plan).
2. The following table sets forth the computation of net income per
share available to common for the three-month and six-month
periods ended June 30, 2004 and 2003 (in thousands, except per
share amounts):
Three Months Ended Six Months Ended
June 30, June 30,
2004 2003 2004 2003
Numerator for Basic and Diluted Earnings Per Share -
Net Income Available to Common $142,179 $106,033 $240,274 $232,700
Denominator for Basic Earnings Per Share -
Weighted Average Shares 116,388 114,382 116,052 114,430
Potential Dilutive Common Shares -
Stock Options 1,867 1,509 1,734 1,531
Restricted Stock and Units 454 240 441 251
Denominator for Diluted Earnings Per Share -
Adjusted Weighted Average Shares 118,709 116,131 118,227 116,212
Net Income Per Share of Common Stock
Basic $ 1.22 $ 0.93 $ 2.07 $ 2.03
Diluted $ 1.20 $ 0.91 $ 2.03 $ 2.00
3. The following table presents the components of EOG's
comprehensive income for the three-month and six-month periods ended
June 30, 2004 and 2003 (in thousands):
Three Months Ended Six Months Ended
June 30, June 30,
2004 2003 2004 2003
Comprehensive Income
Net Income $144,937 $108,791 $245,790 $238,216
Other Comprehensive Income
Foreign Currency Translation Adjustment (18,573) 48,167 (30,746) 87,423
Foreign Currency Swap Transaction,
Net of Income Tax of $802 (1,715) - (1,715) -
Total $124,649 $156,958 $213,329 $325,639
4. Selected financial information about operating segments is reported
below for the three-month and six-month periods ended June 30,
2004 and 2003 (in thousands):
Three Months Ended Six Months Ended
June 30, June 30,
2004 2003 2004 2003
Net Operating Revenues
United States $388,258 $328,528 $723,026 $687,042
Canada 99,965 72,922 200,767 153,613
Trinidad 30,798 23,304 59,548 48,768
Total $519,021 $424,754 $983,341 $889,423
Operating Income (Loss)
United States $152,113 $126,308 $253,118 $288,430
Canada 54,769 40,130 109,018 91,521
Trinidad 21,401 10,736 41,278 27,707
United Kingdom (1,547) (242) (5,242) (4,822)
Other - (64) - 161
Total 226,736 176,868 398,172 402,997
Reconciling Items
Other Income (Expense), Net 1,425 2,680 (1,304) 2,832
Interest Expense, Net 15,416 13,807 32,099 29,125
Income Before Income Taxes $212,745 $165,741 $364,769 $376,704
5. EOG and numerous other companies in the natural gas industry
were named as defendants in various lawsuits alleging violations of
the Civil False Claims Act in connection with the payment of
royalties on natural gas and natural gas liquids produced on federal
and Indian lands. EOG was involved in two of these lawsuits. The
plaintiffs in one of the lawsuits dismissed EOG from that case
without prejudice. EOG recently settled the second of these
lawsuits for a nominal amount.
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.
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 retirements of oil and gas
properties pursuant to SFAS No. 143 for the three-month periods
ended March 31 and June 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
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.
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 six-month periods ended June 30, 2004 and 2003, had
compensation costs of stock options and the employee stock
purchase plan 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 millions, except per
share amounts):
Three Months Ended Six Months Ended
June 30, June 30,
2004 2003 2004 2003
Net Income Available to Common - As Reported $142.2 $106.0 $240.3 $232.7
Deduct: Total Stock-Based Employee Compensation
Expense, Net of Income Tax (2.9) (2.3) (5.4) (5.6)
Net Income Available to Common - Pro Forma $139.3 $103.7 $234.9 $227.1
Net Income per Share Available to Common
Basic - As Reported $ 1.22 $ 0.93 $ 2.07 $ 2.03
Basic - Pro Forma $ 1.20 $ 0.91 $ 2.02 $ 1.98
Diluted - As Reported $ 1.20 $ 0.91 $ 2.03 $ 2.00
Diluted - Pro Forma $ 1.17 $ 0.89 $ 1.99 $ 1.95
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
June 30, 2004 and 2003 was $2.4 million and $1.3 million,
respectively. Related compensation expense for the six-month
periods ended June 30, 2004 and 2003 was $4.4 million and $2.6
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 June 30, 2004 and 2003, the contributions to these
plans amounted to approximately $2.7 million and $2.0 million,
respectively. For the six-month periods ended June 30, 2004 and
2003, the contributions to these plans amounted to approximately
$5.7 million and $3.9 million, respectively.
In addition, EOG's Canadian subsidiary maintains a non-
contributory defined contribution pension plan and a matched
savings plan and 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 $222,000 and $149,000 for the three-month
periods ended June 30, 2004 and 2003, respectively.
Contributions related to these plans were $427,000 and $285,000
for the six-month periods ended June 30, 2004 and 2003,
respectively.
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 six-month periods ended June 30,
2003 and 2004 (in thousands):
Three Months Ended Six Months Ended
June 30, June 30,
2004 2003 2004 2003
Service Cost $ 36 $ 44 $106 $ 88
Interest Cost 29 32 79 64
Expected Return on Plan Assets - - - -
Amortization of Prior Service Cost 32 19 65 38
Amortization of Net Actuarial (Gain) Loss (18) - (18) -
Net Periodic Benefit Cost $ 79 $ 95 $232 $190
EOG previously disclosed in its financial statements for the year
ended December 31, 2003, that it expected to contribute $57,000
to its postretirement plan in 2004. As of June 30, 2004, $29,000
of contributions have been made. EOG presently anticipates
contributing an additional $28,000 to fund its postretirement
plan in 2004 for a total of $57,000.
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.
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 258,000 net acres in the non-core Barnett Shale
area (with the core area defined primarily as western Denton and
eastern Wise counties). 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. Production from these wells will be
among the sources to supply existing gas contracts, as well as
feeding the new methanol plant that is scheduled to commence
operations in 2005. EOG recently 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 has commenced commissioning operations ahead of schedule
and is expected to achieve 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 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 Canadian natural gas fundamentals.
In EOG's new venue in the Southern Gas Basin of the United
Kingdom North Sea, EOG is on track to commence production of
approximately 40 MMcfd, net, from its two gas discoveries by the
end of 2004. These wells were farm-in opportunities from major
oil companies. EOG is reviewing additional farm-in opportunities
in this area and expects to participate in at least one more
exploration well in 2004. EOG expects to begin operatorship
in the United Kingdom later in 2004.
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 half of
2004, EOG reduced debt by $23 million and increased its cash
position by $63 million. At June 30, 2004, its debt-to-total
capitalization ratio was 30.5%, 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 its entire first half of 2004 capital program of $609
million and pay down $98 million on outstanding commercial paper
borrowings and $75 million on a senior unsecured term loan
facility. 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
increased from approximately $1.1 billion to approximately $1.3
billion, excluding acquisitions. EOG plans to spend about 5% of
this estimated capital expenditure budget to drill new,
internally generated, bigger target ideas. United States and
Canadian 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 believes
that EOG has one of the strongest overall drilling inventories
in EOG's history.
Results of Operations
The following review of operations for the three-month periods
ended June 30, 2004 and 2003 should be read in conjunction with
the consolidated financial statements of EOG and notes thereto.
Net Operating Revenues
During the second quarter of 2004, net operating revenues
increased $94 million to $519 million. Total wellhead revenues
of $533 million increased $94 million, or 21%, as compared to a
year ago. Wellhead volume and price statistics for the three-
month periods ended June 30, 2004 and 2003 were as follows:
Three Months Ended
June 30,
2004 2003
Natural Gas Volumes (MMcf per day)(1)
United States 619 636
Canada 197 153
United States and Canada 816 789
Trinidad 162 148
Total 978 937
Average Natural Gas Prices ($/Mcf)(2)
United States $5.67 $5.06
Canada 5.04 4.77
United States and Canada Composite 5.52 5.00
Trinidad 1.36 1.32
Composite 4.83 4.42
Crude Oil and Condensate Volumes (MBbl per day)(1)
United States 21.0 17.3
Canada 2.6 2.3
United States and Canada 23.6 19.6
Trinidad 3.1 2.3
Total 26.7 21.9
Average Crude Oil and Condensate Prices ($/Bbl)(2)
United States $37.39 $28.18
Canada 35.59 27.00
United States and Canada Composite 37.19 28.04
Trinidad 37.69 26.31
Composite 37.25 27.86
Natural Gas Liquids Volumes (MBbl per day)(1)
United States 5.0 3.0
Canada 0.6 0.4
Total 5.6 3.4
Average Natural Gas Liquids Prices ($/Bbl)(2)
United States $23.78 $19.63
Canada 20.35 14.15
Composite 23.40 19.00
Natural Gas Equivalent Volumes (MMcfe per day)(3)
United States 775 757
Canada 216 170
United States and Canada 991 927
Trinidad 181 162
Total 1,172 1,089
Total Bcfe(3) Deliveries 106.6 99.1
(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.
Wellhead natural gas revenues for the second quarter of 2004
increased $53 million, or 14%, due to the increase in the composite
average wellhead natural gas price ($37 million) and the increase in
natural gas deliveries ($16 million). The composite average
wellhead price for natural gas increased 9% to $4.83 per Mcf for the
second quarter of 2004 from $4.42 per Mcf for the same period of
2003.
Natural gas deliveries increased 41 MMcf per day, or 4%, to 978
MMcf per day for the second quarter of 2004 from 937 MMcf per day
for the comparable period in 2003, primarily due to a 44 MMcf per
day, or 29%, increase in Canada and a 14 MMcf per day, or 9%,
increase in Trinidad, partially offset by a 17 MMcf per day, or 3%,
decline in the United States. The increase in Canada was
attributable to the property acquisitions in the fourth quarter of
2003 (32 MMcf per day) and additional production from drilling
activities (17 MMcf per day), partially offset by a temporary plant
shutdown (5 MMcf per day). The increase in Trinidad was
attributable to the Parula wells on the SECC block beginning
production in February 2004 (17 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 (5 MMcf per day).
Wellhead crude oil and condensate revenues increased $35 million,
or 63%, due to increases in both the composite average wellhead
crude oil and condensate price ($23 million) and the wellhead crude
oil and condensate deliveries ($12 million). The composite average
wellhead crude oil and condensate price for the second quarter of
2004 was $37.25 per barrel compared to $27.86 per barrel for the
same period of 2003.
Wellhead crude oil and condensate deliveries increased 4.8 MBbl
per day, or 22%, to 26.7 MBbl per day for the second quarter of
2004. The increase was mainly from the production from new wells in
the United States (3.7 MBbl per day) and from higher production from
the Parula wells in Trinidad (0.9 MBbl per day).
Natural gas liquids revenues were $6 million higher than a year
ago primarily due to increases in deliveries ($4 million) and the
composite average price ($2 million).
During the second quarter of 2004, EOG recognized a loss on mark-
to-market financial commodity derivative contracts of $15 million
compared to a loss of $16 million for the same period in 2003.
During the second quarter of 2004, net cash outflow related to
settled natural gas financial collar contracts and settled natural
gas and crude oil financial price swap contracts was $36 million
compared to a net cash outflow of $11 million for the same period in
2003.
Operating and Other Expenses
For the second quarter of 2004, operating expenses of $292 million
were $44 million higher than the $248 million incurred in the second
quarter of 2003. The following table presents the costs per Mcfe
for the three-month periods ended June 30, 2004 and 2003:
Three Months Ended
June 30,
2004 2003
Lease and Well $0.61 $0.54
DD&A 1.09 1.08
General and Administrative (G&A) 0.25 0.25
Taxes Other than Income 0.28 0.12
Interest Expense, Net 0.15 0.14
Total Per-Unit Costs(1) $2.38 $2.13
(1) Total per-unit costs do not include exploration costs, dry hole
costs and impairments.
The higher per-unit costs of lease and well, depreciation,
depletion and amortization (DD&A), taxes other than income and net
interest expense for the three-month period ended June 30, 2004
compared to the same period in 2003 were due primarily to the
reasons set forth below.
Lease and well expenses of $66 million were $12 million higher
than the prior year period due primarily to a general increase in
service costs related to operating activities in the United States
($4 million), increased transportation expense in the United States
($3 million), increased production in Canada ($3 million) and in the
United States ($1 million), and changes in the Canadian exchange
rate ($1 million).
DD&A expenses of $116 million increased $10 million from the prior
year period due primarily to increased production in Canada ($4
million) and in the United States ($2 million), increased United
States DD&A rates ($2 million) and increased Canadian DD&A rates ($1
million).
Taxes other than income of $30 million were $18 million higher
than the prior year period due primarily to $17 million in
retroactive credits against severance taxes resulting from the
qualification of additional wells for a Texas high cost gas
severance tax exemption recorded in the second quarter of 2003
versus $1 million recorded in the second quarter of 2004.
Net interest expense of $15 million increased $2 million compared
to the second quarter of 2003 primarily due to a slightly higher
average debt balance.
Exploration costs of $20 million were $3 million lower than a year
ago due primarily to a major seismic acquisition program in Trinidad
($4 million) which began in the second quarter of 2003, partially
offset by increased geological and geoscience expenditures in the
United States ($1 million).
Impairments of $16 million decreased $10 million compared to the
prior year period 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 as a result of downward revisions
in the future cash flow analysis for certain properties in the
United States ($6 million). Total impairments under Statement of
Financial Accounting Standards No. 144 - "Accounting for the
Impairment or Disposal of Long-Lived Assets" for the second quarter
of 2004 and 2003 were $2 million and $8 million, respectively.
For the second quarter of 2004, the income tax provision of $68
million increased $11 million compared to the second quarter of
2003, primarily due to higher income before income taxes ($17
million) and higher effective foreign income tax rates ($3 million),
partially offset by lower deferred income taxes associated with a
reduction in the Alberta (Canada) corporate tax rate ($5 million)
and decreases in other adjustments ($4 million). The net effective
tax rate for the second quarter of 2004 decreased to 32% from 34%
for the same period of 2003.
Results of Operations
Net Operating Revenues
During the first half of 2004, net operating revenues increased
$94 million to $983 million. Total wellhead revenues of $1,040
million increased $92 million, or 10%, as compared to a year ago.
Wellhead volume and price statistics for the six-month periods ended
June 30, 2004 and 2003 were as follows:
Six Months Ended
June 30,
2004 2003
Natural Gas Volumes (MMcf per day)
United States 618 639
Canada 201 155
United States and Canada 819 794
Trinidad 158 152
Total 977 946
Average Natural Gas Prices ($/Mcf)
United States $5.54 $5.49
Canada 5.01 4.97
United States and Canada Composite 5.41 5.39
Trinidad 1.42 1.32
Composite 4.77 4.74
Crude Oil and Condensate Volumes (MBbl per day)
United States 20.5 17.8
Canada 2.6 2.2
United States and Canada 23.1 20.0
Trinidad 2.8 2.4
Total 25.9 22.4
Average Crude Oil and Condensate Prices ($/Bbl)
United States $36.11 $30.63
Canada 33.63 29.26
United States and Canada Composite 35.83 30.48
Trinidad 35.52 29.82
Composite 35.80 30.41
Natural Gas Liquids Volumes (MBbl per day)
United States 4.9 3.1
Canada 0.6 0.5
Total 5.5 3.6
Average Natural Gas Liquids Prices ($/Bbl)
United States $24.24 $21.46
Canada 20.25 19.22
Composite 23.80 21.13
Natural Gas Equivalent Volumes (MMcfe per day)
United States 771 764
Canada 219 172
United States and Canada 990 936
Trinidad 175 166
Total 1,165 1,102
Total Bcfe Deliveries 212.1 199.4
During the first half of 2004, wellhead natural gas revenues
increased 4% to $847 million from $811 million for the same period
of 2003. The increase was due to the increase in natural gas
deliveries ($31 million) and the increase in the composite average
wellhead natural gas price ($5 million). The composite average
wellhead price for natural gas increased to $4.77 per Mcf from $4.74
per Mcf for the comparable period a year ago.
Natural gas deliveries increased 31 MMcf per day, or 3%, to 977
MMcf per day for the first half of 2004 from 946 MMcf per day a year
ago, primarily due to a 46 MMcf per day, or 30%, increase in Canada
and a 6 MMcf per day, or 4%, increase in Trinidad, partially offset
by a 21 MMcf per day, or 3%, decline in the United States. The
increase in Canada was attributable to the property acquisitions in
the fourth quarter of 2003 (32 MMcf per day) and additional
production from drilling activities (17 MMcf per day), offset by a
temporary plant shutdown (3 MMcf per day). The increase in Trinidad
was attributable to the Parula wells on the SECC block beginning
production in February 2004 (9 MMcf per day).
Wellhead crude oil and condensate revenues for the first half of
2004 increased $46 million, or 37%, as compared to the prior year
same period, due to the increases in both the average wellhead crude
oil and condensate prices ($26 million) and crude oil and condensate
deliveries ($20 million). The composite average wellhead price for
crude oil and condensate increased 18% to $35.80 per barrel from
$30.41 per barrel for the comparable period a year ago.
Wellhead crude oil and condensate deliveries increased 3.5 MBbl
per day, or 16%, to 25.9 MBbl per day for the first half of 2004
from 22.4 MBbl per day a year ago. The increase was mainly due to
the production from new wells in the United States (2.7 MBbl per
day) and production from the Parula wells on the SECC block
commencing in February 2004 in Trinidad (0.5 MBbl per day).
Natural gas liquids revenues were $10 million higher than a year
ago primarily due to increases in deliveries ($7 million) and the
composite average price ($3 million).
During the first six months of 2004, EOG recognized a loss on mark-
to-market financial commodity derivative contracts of $59 million
compared to a loss of $61 million for the same period in 2003.
During the first six months of 2004, net cash outflow related to
settled natural gas financial collar contracts and settled natural
gas and crude oil financial price swap contracts was $38 million
compared to a net cash outflow of $39 million for the same period in
2003.
Operating and Other Expenses
For the first six months of 2004, operating expenses of $585
million were $99 million higher than the $486 million incurred in
the first six months of 2003. The following table presents the
costs per Mcfe for the six-month periods ended June 30, 2004 and
2003:
Six Months Ended
June 30,
2004 2003
Lease and Well $0.61 $0.51
DD&A 1.09 1.05
G&A 0.24 0.23
Taxes Other than Income 0.31 0.21
Interest Expense, Net 0.15 0.15
Total Per-Unit Costs(1) $2.40 $2.15
(1) Total per-unit costs do not include exploration costs, dry hole
costs and impairments.
The higher per-unit costs of lease and well, DD&A, G&A, taxes
other than income and net interest expense for the six-month period
ended June 30, 2004 compared to the same period in 2003 were due
primarily to the reasons set forth below.
Lease and well expenses of $130 million were $28 million higher
than the prior year period due primarily to a general increase in
service costs related to operating activities in the United States
($9 million) and Canada ($1 million), increased transportation
expense in the United States ($7 million) and in Canada ($1
million), increased production in Canada ($6 million) and changes in
the Canadian exchange rate ($3 million).
DD&A expenses of $230 million increased $20 million from the prior
year period due primarily to increased production in Canada ($8
million), changes in the Canadian exchange rate ($3 million),
increased Canadian DD&A rates ($3 million) from acquiring and
developing reserves and increased United States DD&A rates ($3
million) due to a gradual proportional increase in production from
higher cost properties.
G&A expenses of $51 million were $6 million higher than the
comparable prior year period due primarily to expanded operations.
Taxes other than income of $66 million were $24 million higher
than the prior year period due primarily to $18 million in
retroactive credits against severance taxes resulting from the
qualification of additional wells for a Texas high cost gas
severance tax exemption recorded in the first half of 2003 versus $2
million recorded in the first half of 2004 and the results of a
production tax lawsuit expensed in the first quarter of 2004 ($5
million).
Net interest expense of $32 million increased $3 million compared
to the same period of 2003 primarily due to an interest charge
related to the results of a production tax lawsuit in the first
quarter of 2004 ($2 million) and a slightly higher average debt
balance ($1 million).
Exploration costs of $46 million were $6 million higher than a
year ago due primarily to increased geological and geoscience
expenditures in the United States ($9 million) and Canada ($1
million), partially offset by a decrease in geological and
geoscience expenditures in Trinidad due primarily to a major seismic
acquisition program in Trinidad ($4 million) which began in the
second quarter of 2003.
Impairments decreased $4 million to $33 million compared to the
comparable prior year period due to lower amortization of unproved
leases in the United States ($1 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 ($3 million). Total impairments
under Statement of Financial Accounting Standards No. 144 -
"Accounting for the Impairment or Disposal of Long-Lived Assets" for
the first six months of 2004 and 2003 were $5 million and $8
million, respectively.
For the first six months of 2004, the income tax provision of $119
million decreased $12 million compared to the first six months of
2003, primarily due to lower income before income taxes ($5
million), lower deferred income taxes associated with a reduction in
the Alberta (Canada) corporate tax rate ($5 million) and decreases
in other adjustments ($5 million), partially offset by higher
effective foreign tax rates ($3 million). The net effective tax
rate for the first six months of 2004 decreased to 33% from 35% for
the same period of 2003.
Capital Resources and Liquidity
Cash Flows
At June 30, 2004 and December 31, 2003, EOG had cash and cash
equivalents of $68 million and $4 million, respectively.
The primary sources of cash for EOG during the first half of 2004
included funds generated from operations, proceeds from sales of
assets, proceeds from new borrowings (see discussion on 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 $692 million for the
first six months of 2004 increased $39 million as compared to the
same period in 2003 primarily reflecting higher wellhead revenues
($92 million), partially offset by higher cash operating expenses
($44 million) and unfavorable changes in working capital ($19
million).
Cash used in investing activities of $629 million for the first
six months of 2004 increased by $272 million as compared to the same
period in 2003 due primarily to increased exploration and
development expenditures ($235 million) and unfavorable changes in
working capital related to investing activities ($23 million).
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.
During the first quarter of 2004, EOG completed a sale agreement
whereby a portion of an EOG subsidiary's shareholdings in N2000, a
Trinidadian company, was sold to a third party energy company for $3
million. The sale left EOG with an equity interest of approximately
23% in N2000 and did not result in any gain or loss. The proceeds
were reported as Proceeds from Sales of Assets.
Cash used by financing activities was less than $1 million for the
first six months of 2004 versus cash used of $155 million for the
same period in 2003. Financing activities for 2004 included the net
repayment of long-term debt ($23 million) consisting of repayments
of the outstanding balances of commercial paper borrowings ($98
million) and a senior unsecured term loan facility ($75 million),
offset partially by the notes issuance discussed below ($150
million). Other financing activities included proceeds from the
exercise of employee stock options ($43 million) and payments of
cash dividends ($18 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.
Total Exploration and Development Expenditures
The table below presents total exploration and development
expenditures for the six-month periods ended June 30, 2004 and 2003
(in millions):
Six Months Ended
June 30,
2004 2003
United States $ 446 $ 298
Canada 106 54
United States and Canada 552 352
Trinidad 38 10
United Kingdom 17 11
Other 2 2
Exploration and Development Expenditures 609 375
Asset Retirement Costs 5 3
Deferred Income Tax Benefits on Acquired Properties (17) -
Total Exploration and Development Expenditures $ 597 $ 378
Exploration and development expenditures of $609 million for the
first half of 2004 were $234 million higher than the prior year
period due primarily to increased development and exploratory
activities and higher cost structure in the United States and Canada
($200 million), and increased drilling activities in Trinidad
($28 million) and the United Kingdom ($6 million). The 2004
exploration and development expenditures of $609 million included
$420 million in development,$182 million in exploration,
$4 million in capitalized interest and $3 million in property
acquisitions. The 2003 exploration and development expenditures
of $375 million included $248 million in development, $105 million
in exploration, $18 million in property acquisitions and
$4 million in capitalized interest.
The level of exploration and development expenditures, including
acquisitions, will vary in future periods depending on energy market
conditions and other related economic factors. EOG has significant
flexibility with respect to financing alternatives and the ability
to adjust its exploration and development expenditure budget as
circumstances warrant. There are no material continuing commitments
associated with expenditure plans.
Commodity Derivative Transactions
As more fully discussed in Note 12 to the consolidated financial
statements included in EOG's Annual Report on Form 10-K for the year
ended December 31, 2003, EOG engages in price risk management
activities from time to time. These activities are intended to
manage EOG's exposure to fluctuations in commodity prices for
natural gas and crude oil. EOG utilizes commodity derivative
financial instruments, primarily price swaps and collars, as the
means to manage this price risk. In addition to these financial
transactions, EOG is a party to various physical commodity contracts
for the sale of hydrocarbons that cover varying periods of time and
have varying pricing provisions. The financial impact of these
various physical commodity contracts is included in revenues at the
time of settlement, which in turn affects average realized
hydrocarbon prices. During the first six months of 2004 and 2003,
EOG elected not to designate any of its commodity derivative
financial contracts as accounting hedges, and accordingly, accounted
for these commodity derivative financial contracts using the mark-to-
market accounting method.
Presented below is a summary of EOG's remaining 2004 natural gas
financial collar contracts and natural gas and crude oil financial
price swap contracts at June 30, 2004 with prices expressed in
dollars per million British thermal units ($/MMBtu) and in dollars
per barrel ($/Bbl), as applicable, and notional volumes in million
British thermal units per day (MMBtud) and in barrels per day
(Bbld), as applicable. EOG has not entered into any additional
natural gas financial collar contracts or natural gas or crude oil
financial price swap contracts since EOG filed its Current Report on
Form 8-K on August 2, 2004. The total fair value of the natural gas
financial collar contracts and natural gas and crude oil financial
price swap contracts at June 30, 2004 was a negative $59 million.
There are no such contracts for any period after 2004.
Natural Gas Financial Collar Contracts Financial Price Swap Contracts
Floor Price Ceiling Price Natural Gas Crude Oil
Floor Weighted Weighted
Range Weighted Ceiling Weighted Average Average
Volume /Floor Average Range Average Volume Price Volume Price
Month (MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) (MMBtud) ($/MMBtu) (Bbld) ($/Bbl)
Jul 375,000 $4.47 - 4.75 $4.58 $4.93 - 5.19 $5.09 30,000 $4.80 3,000 $27.91
Aug 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 2,000 28.11
Sep 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.78 - -
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 - - - -
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 extent to
which EOG can replicate on its other Barnett Shale acreage the
results of its most recent Barnett Shale wells; 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.
PART 1. FINANCIAL INFORMATION (Concluded)
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 June 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 June 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 June 30, 2004 that have materially affected, or
are reasonably likely to materially affect, EOG's internal control
over financial reporting.
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. 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)
April 1, 2004 - April 30, 2004 1,043 $46.59 - 6,386,200
May 1, 2004 - May 31, 2004 65,219 52.19 - 6,386,200
June 1, 2004 - June 30, 2004 46 53.73 - 6,386,200
Total 66,308 $51.97 -
(1) Includes 52,274 shares that were returned to EOG in
payment of the exercise price of employee stock options and
14,034 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 4. Submission of Matters to a Vote of Security Holders
The Annual Meeting of Shareholders of EOG Resources, Inc.
was held on May 4, 2004, in Houston, Texas, for the purpose of
electing a board of directors, ratifying the appointment of
auditors and approving EOG's Amended and Restated 1992 Stock
Plan. Proxies for the meeting were solicited pursuant to
Section 14(a) of the Securities Exchange Act of 1934, and
there was no solicitation in opposition to management's
solicitations.
(a) Each of the directors nominated by the Board and
listed in the proxy statement was elected with votes as
follows:
Shares Shares
Nominee For Withheld
George A. Alcorn 102,580,412 2,817,641
Charles R. Crisp 102,633,144 2,764,909
Mark G. Papa 103,091,689 2,306,364
Edmund P. Segner, III 102,868,915 2,529,138
Donald F. Textor 101,979,815 3,418,238
Frank G. Wisner 102,592,185 2,805,868
(b) The appointment of Deloitte & Touche LLP, independent public
accountants, as auditors for the year ending December 31, 2004 was
ratified by the following vote: 103,387,415 shares for; 1,359,286
shares against; and 535,373 shares abstaining.
(c) EOG's Amended and Restated 1992 Stock Plan was
approved by the following vote: 85,375,150 shares for;
10,155,324 shares against; and 703,041 shares abstaining.
PART II. OTHER INFORMATION (Concluded)
EOG RESOURCES, INC.
ITEM 5. Other Information
On July 2, 2004, EOG announced that Mr. W. D. (Bill) Stevens
and Mr. H. Leighton Steward had been elected to its Board of
Directors.
ITEM 6. Exhibits and Current Reports on Form 8-K
(a) 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.
(b) Current Reports on Form 8-K
During the second quarter of 2004, EOG furnished the
following Current Reports on Form 8-K:
- On April 5, 2004, to report anticipated financial results of
the price risk management activities for the first quarter of 2004
and provide updated information on the remaining 2004 natural gas
financial collar contracts and natural gas and crude oil financial
price swap contracts in Item 9 - Regulation FD Disclosure.
- On April 30, 2004, to provide estimates for the second quarter
and full year 2004 and to provide updated information on the
remaining 2004 natural gas financial collar contracts and natural
gas and crude oil financial price swap contracts in Item 9 -
Regulation FD Disclosure.
- On May 3, 2004, to furnish the press release issued on May 2,
2004 for the first quarter 2004 financial and operational results in
Item 7 - Financial Statements and Exhibits and Item 12 - Results of
Operations and Financial Condition.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
EOG RESOURCES, INC.
(Registrant)
Date: August 3, 2004 By: /s/ TIMOTHY K. DRIGGERS
Timothy K. Driggers
Vice President and Chief
Accounting Officer
(Principal Accounting Officer)
EXHIBIT INDEX
Exhibit Number 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