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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
Form 10-Q
(Mark One)
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2004
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number: 1-9743
EOG RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Delaware 47-0684736
(State or other (I.R.S. Employer
jurisdiction of Identification No.)
incorporation or
organization)
333 Clay Street, Suite 4200, Houston, Texas 77002-7361
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code: 713-651-7000
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements for
the past 90 days. Yes x No .
Indicate by check mark whether the registrant is an accelerated
filer (as defined in Rule 12b-2 of the Act).
Yes x No .
Indicate the number of shares outstanding of each of the
issuer's classes of common stock, as of October 19, 2004.
Title of each class Number of shares
Common Stock, $.01 118,575,129
par value
EOG RESOURCES, INC.
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION Page No.
ITEM 1. Financial Statements
Consolidated Statements of Income - Three Months Ended
September 30, 2004 and 2003 And Nine Months Ended
September 30, 2004 and 2003 3
Consolidated Balance Sheets - September 30, 2004 and
December 31, 2003 4
Consolidated Statements of Cash Flows - Nine Months Ended
September 30, 2004 and 2003 5
Notes to Consolidated Financial Statements 6
ITEM 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 12
ITEM 3. Quantitative and Qualitative Disclosures About
Market Risk 23
ITEM 4. Controls and Procedures 23
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings 24
ITEM 2. Changes in Securities and Use of Proceeds 24
ITEM 6. Exhibits 24
SIGNATURES 25
EXHIBIT INDEX 26
-2-
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, Except Per Share Amounts)
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2004 2003 2004 2003
Net Operating Revenues
Natural Gas $448,131 $365,064 $1,296,052 $1,176,798
Crude Oil, Condensate and Natural Gas Liquids 123,379 67,664 316,238 204,643
Gains (Losses) on Mark-to-Market Commodity
Derivative Contracts 22,743 23,628 (36,275) (37,346)
Other, Net (23) 2,368 1,556 4,052
Total 594,230 458,724 1,577,571 1,348,147
Operating Expenses
Lease and Well 69,027 54,431 198,976 156,390
Exploration Costs 21,874 17,812 67,466 57,409
Dry Hole Costs 21,114 8,876 50,205 18,932
Impairments 17,930 26,117 51,289 63,548
Depreciation, Depletion and Amortization 130,257 110,438 360,278 320,578
General and Administrative 29,576 26,379 80,861 71,734
Taxes Other Than Income 29,952 21,359 95,824 63,247
Total 319,730 265,412 904,899 751,838
Operating Income 274,500 193,312 672,672 596,309
Other Income, Net 3,953 1,924 2,649 4,756
Income Before Interest Expense and Income Taxes 278,453 195,236 675,321 601,065
Interest Expense, Net 16,110 15,632 48,209 44,757
Income Before Income Taxes 262,343 179,604 627,112 556,308
Income Tax Provision 90,033 62,185 209,012 193,542
Net Income Before Cumulative Effect of Change
in Accounting Principle 172,310 117,419 418,100 362,766
Cumulative Effect of Change in Accounting
Principle, Net of Income Tax - - - (7,131)
Net Income 172,310 117,419 418,100 355,635
Preferred Stock Dividends 2,758 2,758 8,274 8,274
Net Income Available to Common $169,552 $114,661 $ 409,826 $ 347,361
Net Income Per Share Available to Common
Basic
Net Income Available to Common Before Cumulative
Effect of Change in Accounting Principle $ 1.44 $ 1.00 $ 3.52 $ 3.09
Cumulative Effect of Change in Accounting
Principle, Net of Income Tax - - - (0.06)
Net Income Available to Common $ 1.44 $ 1.00 $ 3.52 $ 3.03
Diluted
Net Income Available to Common Before Cumulative
Effect of Change in Accounting Principle $ 1.42 $ 0.99 $ 3.45 $ 3.05
Cumulative Effect of Change in Accounting
Principle, Net of Income Tax - - - (0.06)
Net Income Available to Common $ 1.42 $ 0.99 $ 3.45 $ 2.99
Average Number of Common Shares
Basic 117,411 114,616 116,485 114,489
Diluted 119,677 116,370 118,710 116,284
The accompanying notes are an integral part of these consolidated financial statements.
-3-
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 1. FINANCIAL STATEMENTS - (Continued)
EOG RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Data)
September 30, December 31,
2004 2003
(Unaudited)
ASSETS
Current Assets
Cash and Cash Equivalents $ 81,908 $ 4,443
Accounts Receivable, Net 350,170 295,118
Inventories 30,739 21,922
Deferred Income Taxes 22,560 31,548
Other 72,302 42,983
Total 557,679 396,014
Oil and Gas Properties (Successful Efforts Method) 9,069,633 8,189,062
Less: Accumulated Depreciation, Depletion
and Amortization (4,311,597) (3,940,145)
Net Oil and Gas Properties 4,758,036 4,248,917
Other Assets 108,882 104,084
Total Assets $5,424,597 $4,749,015
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts Payable $ 339,303 $ 282,379
Accrued Taxes Payable 59,168 33,276
Dividends Payable 7,497 6,175
Liabilities from Price Risk Management Activities 4,736 37,779
Deferred Income Taxes 66,746 73,611
Other 46,978 43,299
Total 524,428 476,519
Long-Term Debt 1,062,972 1,108,872
Other Liabilities 195,482 171,115
Deferred Income Taxes 915,803 769,128
Shareholders' Equity
Preferred Stock, $.01 Par, 10,000,000 Shares Authorized:
Series B, 100,000 Shares Issued, Cumulative,
$100,000 Liquidation Preference 98,767 98,589
Series D, 500 Shares Issued, Cumulative,
$50,000 Liquidation Preference 49,962 49,827
Common Stock, $.01 Par, 320,000,000 Shares Authorized
and 124,730,000 Shares Issued 201,247 201,247
Additional Paid in Capital 15,586 1,625
Unearned Compensation (32,555) (23,473)
Accumulated Other Comprehensive Income 100,194 73,934
Retained Earnings 2,509,851 2,121,214
Common Stock Held in Treasury, 6,363,820 shares at
September 30, 2004 and 8,819,600 shares at
December 31, 2003 (217,140) (299,582)
Total Shareholders' Equity 2,725,912 2,223,381
Total Liabilities and Shareholders' Equity $5,424,597 $4,749,015
The accompanying notes are an integral part of these consolidated financial statements.
-4-
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 1. FINANCIAL STATEMENTS - (Continued)
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
Nine Months Ended
September 30,
2004 2003
Cash Flows From Operating Activities
Reconciliation of Net Income to Net Cash Provided
by Operating Activities:
Net Income $ 418,100 $ 355,635
Items Not Requiring Cash
Depreciation, Depletion and Amortization 360,278 320,578
Impairments 51,289 63,548
Deferred Income Taxes 158,216 123,431
Cumulative Effect of Change in Accounting
Principle, Net of Income Tax - 7,131
Other, Net 13,546 6,763
Exploration Costs 67,466 57,409
Dry Hole Costs 50,205 18,932
Mark-to-Market Commodity Derivative Contracts
Total Losses 36,275 37,346
Realized Losses (70,507) (47,700)
Collar Premium - (1,365)
Tax Benefits from Stock Options Exercised 20,730 7,025
Other, Net (208) 2,894
Changes in Components of Working Capital and
Other Liabilities
Accounts Receivable (55,352) (15,905)
Inventories (8,817) (1,860)
Accounts Payable 58,113 50,028
Accrued Taxes Payable 619 32,769
Other Liabilities 3,566 1,783
Other, Net (531) 18,074
Changes in Components of Working Capital Associated
with Investing and Financing Activities (17,940) (22,064)
Net Cash Provided by Operating Activities 1,085,048 1,014,452
Investing Cash Flows
Additions to Oil and Gas Properties (891,465) (564,825)
Exploration Costs (67,466) (57,409)
Dry Hole Costs (50,205) (18,932)
Proceeds from Sales of Assets 12,771 12,361
Changes in Components of Working Capital Associated
with Investing Activities 17,366 22,223
Other, Net (14,322) (70,366)
Net Cash Used in Investing Activities (993,321) (676,948)
Financing Cash Flows
Net Commercial Paper and Line of Credit Repayments (20,900) (134,310)
Long-Term Debt Borrowings 150,000 -
Long-Term Debt Repayments (175,000) -
Dividends Paid (27,828) (22,878)
Treasury Stock Purchased - (21,295)
Proceeds from Stock Options Exercised 60,479 17,717
Other, Net (1,013) (2,097)
Net Cash Used in Financing Activities (14,262) (162,863)
Increase in Cash and Cash Equivalents 77,465 174,641
Cash and Cash Equivalents at Beginning of Period 4,443 9,848
Cash and Cash Equivalents at End of Period $ 81,908 $ 184,489
The accompanying notes are an integral part of these consolidated financial statements.
-5-
PART I. FINANCIAL INFORMATION (Continued)
ITEM 1. FINANCIAL STATEMENTS (Continued)
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. The consolidated financial statements of EOG Resources, Inc.
and subsidiaries (EOG) included herein have been prepared by
management without audit pursuant to the rules and regulations of
the Securities and Exchange Commission (SEC). Accordingly, they
reflect all normal recurring adjustments which are, in the opinion
of management, necessary for a fair presentation of the financial
results for the interim periods. Certain information and notes
normally included in financial statements prepared in accordance
with accounting principles generally accepted in the United States
of America have been condensed or omitted pursuant to such rules and
regulations. However, management believes that the disclosures are
adequate to make the information presented not misleading. These
consolidated financial statements should be read in conjunction with
the consolidated financial statements and the notes thereto included
in EOG's Annual Report on Form 10-K for the year ended December 31,
2003 (EOG's 2003 Annual Report).
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could
differ from those estimates.
Certain reclassifications have been made to prior period
financial statements to conform with the current presentation.
As more fully discussed in Note 12 to the consolidated financial
statements included in EOG's 2003 Annual Report, EOG engages in
price risk management activities from time to time. These
activities are intended to manage EOG's exposure to fluctuations
in commodity prices for natural gas and crude oil. EOG utilizes
commodity derivative financial instruments, primarily price swaps
and collars, as the means to manage this price risk. In addition
to these financial transactions, EOG is a party to various
physical commodity contracts for the sale of hydrocarbons that
cover varying periods of time and have varying pricing
provisions. The financial impact of these various physical
commodity contracts is included in revenues at the time of
settlement, which in turn affects average realized hydrocarbon
prices. During the first nine months of 2004 and 2003, EOG
elected not to designate any of its commodity derivative
financial contracts as accounting hedges, and accordingly,
accounted for these commodity derivative financial contracts
using the mark-to-market accounting method.
EOG is exposed to foreign currency exchange rate risk inherent in
its operations in foreign countries, including Canada, Trinidad
and the United Kingdom. From time to time, EOG engages in
exchange rate risk management activities to manage its exposure
to exchange rates. Effective March 9, 2004, EOG entered into a
foreign currency swap transaction with multiple banks to
eliminate any exchange rate impacts that may result from the
notes offered by one of the Canadian subsidiaries on the same
date (see Note 8). EOG accounts for the foreign currency swap
transaction using the hedge accounting method, pursuant to the
provisions of Statement of Financial Accounting Standards (SFAS)
No. 133 - "Accounting for Derivative Instruments and Hedging
Activities," as amended by SFAS Nos. 137, 138 and 149. Under
those provisions, as of September 30, 2004, EOG recorded the fair
value of the swap of $9.1 million in Other Liabilities in the
Liabilities section of the Consolidated Balance Sheets. Changes
in the fair value of the foreign currency swap resulted in no net
impact to the Consolidated Statements of Income. The after-tax
net impact from the foreign currency swap transaction resulted in
positive changes of $1.8 million and $0.1 million for the three-
month and nine-month periods ended September 30, 2004,
respectively. These amounts are included in Accumulated Other
Comprehensive Income in the Shareholders' Equity section of the
Consolidated Balance Sheets.
-6-
On January 1, 2003, EOG adopted SFAS No. 143 - "Accounting for
Asset Retirement Obligations" which essentially requires entities
to record the fair value of a liability for legal obligations
associated with the retirement of tangible long-lived assets and
the associated asset retirement costs. The impact of adopting
the statement was an after-tax charge of $7.1 million, which was
reported in the first quarter of 2003 as cumulative effect of
change in accounting principle.
In December 2002, the Financial Accounting Standards Board (FASB)
issued SFAS No. 148 - "Accounting for Stock-Based Compensation -
Transition and Disclosure - an amendment of FASB Statement No.
123." This statement provides alternative methods of transition
for a voluntary change to the fair value based method of
accounting for stock-based employee compensation, along with the
requirement of disclosure in both annual and interim financial
statements about the method used and effect on reported results
(see Note 7). Subsequently, in March 2004, the FASB issued a
proposed SFAS - "Share-Based Payment, an amendment of SFAS Nos.
123 and 95." The proposed standard would require share-based
payments to employees, including stock options, to be expensed.
The final ruling is expected to be issued by June 2005. EOG
continues to monitor the developments in this area as details of
the implementation of the final ruling emerge.
2. The following table sets forth the computation of net income
per share available to common for the three-month and nine-month
periods ended September 30, 2004 and 2003 (in thousands, except per
share amounts):
Three Months Ended Nine Months Ended
September 30, September 30,
2004 2003 2004 2003
Numerator for Basic and Diluted Earnings Per Share -
Net Income Available to Common $169,552 $114,661 $409,826 $347,361
Denominator for Basic Earnings Per Share -
Weighted Average Shares 117,411 114,616 116,485 114,489
Potential Dilutive Common Shares -
Stock Options 1,745 1,476 1,733 1,512
Restricted Stock and Units 521 278 492 283
Denominator for Diluted Earnings Per Share -
Adjusted Weighted Average Shares 119,677 116,370 118,710 116,284
Net Income Per Share of Common Stock
Basic $ 1.44 $ 1.00 $ 3.52 $ 3.03
Diluted $ 1.42 $ 0.99 $ 3.45 $ 2.99
-7-
3. The following table presents the components of EOG's
comprehensive income for the three-month and nine-month periods
ended September 30, 2004 and 2003 (in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
2004 2003 2004 2003
Comprehensive Income
Net Income $172,310 $117,419 $418,100 $355,635
Other Comprehensive Income
Foreign Currency Translation Adjustment 56,919 2,935 26,173 90,358
Foreign Currency Swap Transaction 2,649 - 132 -
Income Tax Related to Foreign Currency
Swap Transaction (847) - (45) -
Total $231,031 $120,354 $444,360 $445,993
4. Selected financial information about operating segments is reported
below for the three-month and nine-month periods ended
September 30, 2004 and 2003 (in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
2004 2003 2004 2003
Net Operating Revenues
United States $438,007 $363,791 $1,161,033 $1,050,833
Canada 109,066 69,665 309,833 223,278
Trinidad 43,427 25,268 102,975 74,036
United Kingdom(1) 3,730 - 3,730 -
Total $594,230 $458,724 $1,577,571 $1,348,147
Operating Income (Loss)
United States $198,978 $139,291 $ 452,096 $ 427,721
Canada 48,121 36,776 157,139 128,297
Trinidad 26,011 17,679 67,289 45,386
United Kingdom(1) 1,390 (434) (3,852) (5,256)
Other - - - 161
Total 274,500 193,312 672,672 596,309
Reconciling Items
Other Income, Net 3,953 1,924 2,649 4,756
Interest Expense, Net 16,110 15,632 48,209 44,757
Income Before Income Taxes $262,343 $179,604 $ 627,112 $ 556,308
(1) Exploratory activities in the United Kingdom began in
June 2002. Production in the United Kingdom commenced in
August 2004.
5. EOG has been named as a potentially responsible party in
certain Comprehensive Environmental Response Compensation and
Liability Act proceedings. However, management does not believe
that any potential assessments resulting from such proceedings will
individually, or in the aggregate, have a material adverse effect on
the financial condition or results of operations of EOG.
There are various other lawsuits and claims against EOG that have
arisen in the ordinary course of business. However, management
does not believe these lawsuits and claims will individually, or
in the aggregate, have a material adverse effect on the financial
condition or results of operations of EOG.
-8-
6. The following table presents the reconciliation of the beginning
and ending aggregate carrying amount of short-term and long-term
legal obligations associated with the retirement of oil and gas
properties pursuant to SFAS No. 143 for the three-month periods
ended March 31, June 30 and September 30, 2004 (in thousands):
Asset Retirement Obligations
Short-Term Long-Term Total
Balance at December 31, 2003 $ 5,320 $118,624 $123,944
Liabilities Incurred 321 2,073 2,394
Liabilities Settled (97) (28) (125)
Accretion 36 1,331 1,367
Foreign Currency Translation (3) (212) (215)
Balance at March 31, 2004 5,577 121,788 127,365
Liabilities Incurred - 2,863 2,863
Liabilities Settled (748) (4,520) (5,268)
Accretion 17 1,316 1,333
Foreign Currency Translation (10) (372) (382)
Balance at June 30, 2004 4,836 121,075 125,911
Liabilities Incurred 148 1,735 1,883
Liabilities Settled (1,531) (508) (2,039)
Accretion 28 1,406 1,434
Revision 679 363 1,042
Reclassification 672 (672) -
Foreign Currency Translation 45 997 1,042
Balance at September 30, 2004 $ 4,877 $124,396 $129,273
7. EOG has various stock plans (Plans) under which employees and non-
employee members of the Board of Directors of EOG and its
subsidiaries have been or may be granted certain equity
compensation.
Stock Options. EOG has in place compensatory stock option plans
whereby participants have been or may be granted rights to
purchase shares of common stock of EOG at a price not less than
the market price of the stock at the date of grant.
Employee Stock Purchase Plan. EOG has in place an employee stock
purchase plan, pursuant to Section 423 of the Internal Revenue
Code of 1986, as amended, whereby participants are granted rights
to purchase shares of common stock of EOG at a price that is 15%
less than the market price of the stock on either the first day
or the last day of a six-month offering period, whichever is
less.
-9-
Pro Forma Information. EOG's pro forma net income available to
common and net income per share available to common for the three-
month and nine-month periods ended September 30, 2004 and 2003,
if compensation costs of stock options and the employee stock
purchase plan had been recorded using the fair value method in
accordance with SFAS No. 123 - "Accounting for Stock-Based
Compensation," as amended by SFAS No. 148 - "Accounting for Stock-
Based Compensation - Transition and Disclosure - an amendment of
FASB Statement No. 123," are presented below pursuant to the
disclosure requirement of SFAS No. 148 (in thousands, except per
share amounts):
Three Months Ended Nine Months Ended
September 30, September 30,
2004 2003 2004 2003
Net Income Available to Common - As Reported $169,552 $114,661 $409,826 $347,361
Deduct: Total Stock-Based Employee Compensation
Expense, Net of Income Tax (3,210) (5,491) (8,630) (11,138)
Net Income Available to Common - Pro Forma $166,342 $109,170 $401,196 $336,223
Net Income Per Share Available to Common
Basic - As Reported $ 1.44 $ 1.00 $ 3.52 $ 3.03
Basic - Pro Forma $ 1.42 $ 0.95 $ 3.44 $ 2.94
Diluted - As Reported $ 1.42 $ 0.99 $ 3.45 $ 2.99
Diluted - Pro Forma $ 1.39 $ 0.94 $ 3.38 $ 2.89
The effects of applying SFAS No. 123, as amended, in this pro
forma disclosure should not be interpreted as being indicative of
future effects. SFAS No. 123 does not apply to awards prior to
1995 and the extent and timing of additional future awards cannot
be predicted.
Restricted Stock and Units. Under the Plans, employees may be
granted restricted stock and/or units without cost to them.
Related compensation expense for the three-month periods ended
September 30, 2004 and 2003 was $2.5 million and $1.5 million,
respectively. Related compensation expense for the nine-month
periods ended September 30, 2004 and 2003 was $6.9 million and
$4.1 million, respectively.
Pension Plans. EOG has a non-contributory defined contribution
pension plan and a matched defined contribution savings plan in
place for most of its employees in the United States. EOG's
contributions to these plans are based on various percentages of
compensation, and in some instances, are based upon the amount of
the employees' contributions to the plan. For the three-month
periods ended September 30, 2004 and 2003, the contributions to
these plans amounted to $1.9 million and $1.8 million,
respectively. For the nine-month periods ended September 30,
2004 and 2003, the contributions to these plans amounted to $7.6
million and $5.7 million, respectively.
In addition, EOG's Canadian subsidiary maintains a non-
contributory defined contribution pension plan and a matched
savings plan. EOG's Trinidadian subsidiary maintains a
contributory defined benefit pension plan and a matched savings
plan. These plans are available to most employees of the
Canadian and Trinidadian subsidiaries, and contributions related
to these plans were $184,000 and $160,000 for the three-month
periods ended September 30, 2004 and 2003, respectively.
Contributions related to these plans were $611,000 and $445,000
for the nine-month periods ended September 30, 2004 and 2003,
respectively.
-10-
Postretirement Plan. During 2000, EOG adopted postretirement
medical and dental benefits for eligible employees and their
eligible dependents. Benefits are provided under the provisions
of a contributory defined dollar benefit plan. EOG accrues these
postretirement benefit costs over the service lives of the
employees expected to be eligible to receive such benefits.
The following table summarizes EOG's postretirement benefit
expense for the three-month and nine-month periods ended
September 30, 2004 and 2003 (in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
2004 2003 2004 2003
Service Cost $ 33 $ 44 $139 $132
Interest Cost 28 32 107 96
Expected Return on Plan Assets - - - -
Amortization of Prior Service Cost 32 19 97 57
Amortization of Net Actuarial (Gain) Loss (18) - (36) -
Net Periodic Benefit Cost $ 75 $ 95 $307 $285
EOG contributed $16,000 and $45,000 to fund its postretirement
plan for the three-month and nine-month periods ended September
30, 2004, respectively. EOG presently anticipates contributing
an additional $16,000 for a total of $61,000 for the year. EOG
previously disclosed in its 2003 Annual Report that it expected
to contribute $57,000 to its postretirement plan in 2004.
8. On March 9, 2004, EOG Resources Canada Inc., a wholly owned
subsidiary of EOG, issued notes with a total principal amount of
US$150 million, an annual interest rate of 4.75% and a maturity
date of March 15, 2014, under Rule 144A of the Securities Act of
1933, as amended. The notes are guaranteed by EOG. In
conjunction with the offering, EOG entered into a foreign
currency swap transaction with multiple banks for the equivalent
amount of the notes and related interest, which has in effect
converted this indebtedness into CAD$201.3 million with a 5.275%
interest rate.
On March 31, 2004, EOG repaid $75 million of its $150 million,
floating rate Senior Unsecured Term Loan Facility with a maturity
date of October 30, 2005.
On September 15, 2004, EOG repaid in full upon maturity the $100
million, 6.5% notes.
-11-
PART I. FINANCIAL INFORMATION (Continued)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EOG RESOURCES, INC.
Overview
EOG Resources, Inc. (EOG) is one of the largest independent
(non-integrated) oil and gas companies in the United States and
has substantial proved reserves in the United States, Canada,
offshore Trinidad and, to a lesser extent, the United Kingdom
North Sea. EOG operates under a business strategy that focuses
predominantly on three factors: achieving a strong reinvestment
rate of return on its capital program, drilling internally
generated prospects in order to find and develop low cost
reserves, and maintaining a strong balance sheet, with a below
industry average debt-to-total capitalization ratio.
Operations
United States and Canada. EOG's effort to identify plays with
larger reserve potential has proven a successful supplement to
its base development and exploitation program in the United
States and Canada. EOG plans to continue to drill smaller wells
in large acreage plays, which, in the aggregate, will contribute
substantially to EOG's crude oil and natural gas production. EOG
has several larger potential plays under way in Wyoming, Utah and
Texas, including the Barnett Shale. To date, EOG has leased
approximately 345,000 net acres in the non-core Barnett Shale
area (with the core area defined primarily as western Denton and
eastern Wise Counties, Texas). While EOG has continued to drill
successful wells in the Barnett Shale through the use of 3-D
seismic and horizontal drilling techniques, significant
production growth or reserve additions are not anticipated from
the Barnett Shale until 2005 and beyond.
In South Texas, EOG has continued its success in the Roleta and
Frio Formations. Through the use of 3-D seismic, EOG has
expanded the inventory of drilling locations in the Roleta
Formation and also expects to continue an active drilling program
in the Frio Formation.
International. In Trinidad, EOG drilled two development wells
at its Parula Discovery during the second quarter of 2004.
Production from these wells are among the sources to supply
existing gas contracts, as well as feeding a new methanol plant
that is scheduled to commence operations in 2005. EOG completed
an additional development well on the U(a) block which will
primarily supply natural gas to the Caribbean Nitrogen Company
Limited (CNCL) and the Nitrogen (2000) Unlimited (N2000) ammonia
plants. The N2000 plant achieved full plant productivity in
August 2004.
Although EOG continues to focus on United States and Canadian
natural gas, EOG sees an increasing linkage between United States
and Canadian natural gas demand and Trinidadian natural gas
supply. For example, liquefied natural gas (LNG) imports from
existing and planned facilities in Trinidad are expected to help
meet decreasing United States supply. In addition, ammonia,
methanol and chemical production has been relocating from the
United States and Canada to Trinidad, driven by attractive
natural gas prices in the island nation. EOG anticipates that
its existing position with the supply contracts to the two
ammonia plants and the new methanol plant will continue to give
its portfolio an even broader exposure to United States and
Canadian natural gas fundamentals.
In EOG's new venue in the Southern Gas Basin of the United
Kingdom North Sea, EOG commenced production from its Valkyrie
well in August 2004 and is on track to commence production from
its Arthur well by the end of 2004. Total production from the
two wells is estimated to be approximately 40 MMcfed, net, by year-
end 2004. These wells were farm-in opportunities from major oil
companies. EOG is reviewing additional farm-in opportunities in
this area. Earlier in the year, EOG commenced preparations to
become an exploration operator in the United Kingdom and received
necessary government approval in August 2004.
-12-
Capital Structure
As noted, one of management's key strategies is to keep a strong
balance sheet with a consistently below industry average debt-to-
total capitalization ratio. During the first nine months of 2004,
EOG reduced debt by $46 million and increased its cash position by
$77 million. At September 30, 2004, its debt-to-total
capitalization ratio was 28.1%, down from 33.3% at December 31,
2003. On March 9, 2004, EOG Resources Canada Inc., a wholly owned
subsidiary of EOG, issued notes with a total principal amount of
US$150 million. The proceeds from these notes, along with the cash
provided from operating activities, allowed EOG to fund the first
nine months of the 2004 capital program of $1 billion, repay in
full upon maturity the $100 million, 6.5% notes, and pay down $75
million on its senior unsecured term loan facility and $21 million
on outstanding commercial paper borrowings. As management currently
assesses price forecast and demand trends for the remainder of 2004,
EOG continues to believe that operations and capital expenditure
activity can be funded by cash generated from operations and, if
needed, available financing alternatives.
For 2004, EOG's current estimated capital expenditure budget is
approximately $1.45 billion, including acquisitions. When it fits
EOG's strategy, EOG will make acquisitions that bolster existing
drilling programs or offer EOG incremental exploration and/or
production opportunities. Management believes that EOG has one of
the strongest overall drilling inventories in EOG's history.
Results of Operations
Three Months ended September 30, 2004 vs. Three Months Ended
September 30, 2003
The following review of operations for the three-month periods
ended September 30, 2004 and 2003 should be read in conjunction with
the consolidated financial statements of EOG and notes thereto.
Net Operating Revenues. During the third quarter of 2004, net
operating revenues increased $136 million to $594 million. Total
wellhead revenues of $571 million increased by $139 million, or 32%,
as compared to the same period a year ago. Wellhead natural gas
volume and price statistics for the three-month periods ended
September 30, 2004 and 2003 were as follows:
Three Months Ended
September 30,
2004 2003
Natural Gas Volumes (MMcf per day)(1)
United States 623 644
Canada 211 152
United States and Canada 834 796
Trinidad 203 155
United Kingdom 8 -
Total 1,045 951
Average Natural Gas Prices ($/Mcf)(2)
United States $5.57 $4.78
Canada 4.99 4.47
United States and Canada Composite 5.42 4.72
Trinidad 1.50 1.34
United Kingdom 5.30 -
Composite 4.66 4.17
(1) Million cubic feet per day.
(2) Dollars per thousand cubic feet.
-13-
Wellhead crude oil and condensate and natural gas liquids volume
and price and natural gas equivalent volume statistics for the three-
month periods ended September 30, 2004 and 2003 were as follows:
Three Months Ended
September 30,
2004 2003
Crude Oil and Condensate Volumes (MBbl per day)(1)
United States 21.0 18.0
Canada 2.7 2.3
United States and Canada 23.7 20.3
Trinidad 4.0 2.5
Total 27.7 22.8
Average Crude Oil and Condensate Prices ($/Bbl)(2)
United States $43.30 $29.43
Canada 40.17 28.11
United States and Canada Composite 42.94 29.28
Trinidad 42.06 26.80
Composite 42.81 29.01
Natural Gas Liquids Volumes (MBbl per day)(1)
United States 4.4 2.9
Canada 0.9 0.8
Total 5.3 3.7
Average Natural Gas Liquids Prices ($/Bbl) (2)
United States $30.07 $20.53
Canada 23.58 18.23
Composite 29.02 20.06
Natural Gas Equivalent Volumes (MMcfe per day)(3)
United States 775 770
Canada 233 170
United States and Canada 1,008 940
Trinidad 227 170
United Kingdom 8 -
Total 1,243 1,110
Total Bcfe(4) Deliveries 114.4 102.1
(1) Thousand barrels per day.
(2) Dollars per barrel.
(3) Million cubic feet equivalent per day.
(4) Billion cubic feet equivalent.
Wellhead natural gas revenues for the third quarter of 2004
increased $83 million, or 23%, to $448 million from $365 million for
the same period of 2003. The increase was due to higher composite
average wellhead natural gas price ($47 million) and natural gas
deliveries ($36 million). The composite average wellhead price for
natural gas increased 12% to $4.66 per Mcf for the third quarter of
2004 from $4.17 per Mcf for the same period of 2003.
-14-
Natural gas deliveries increased 94 MMcf per day, or 10%, to 1,045
MMcf per day for the third quarter of 2004 from 951 MMcf per day for
the same period in 2003, primarily due to a 59 MMcf per day, or 39%,
increase in Canada; a 48 MMcf per day, or 31%, increase in Trinidad;
and an 8 MMcf per day increase in the United Kingdom due to
commencement of production in August 2004. These increases were
partially offset by a 21 MMcf per day, or 3%, decline in the United
States. The increase in Canada (59 MMcf per day) was attributable
approximately equally to both the property acquisitions in the fourth
quarter of 2003 and the additional production that resulted primarily
from drilling activities. The increase in Trinidad was attributable
to the increased production from the U(a) block (40 MMcf per day) which
began supplying natural gas in April 2004 to the N2000 ammonia plant
and commencement of production from the Parula wells on the SECC
block in February 2004 (9 MMcf per day).
Wellhead crude oil and condensate revenues increased $48 million,
or 79%, to $109 million from $61 million due to increases in both
the composite average wellhead crude oil and condensate price ($35
million) and the wellhead crude oil and condensate deliveries ($13
million). The composite average wellhead crude oil and condensate
price for the third quarter of 2004 was $42.81 per barrel compared
to $29.01 per barrel for the same period of 2003.
Wellhead crude oil and condensate deliveries increased 4.9 MBbl
per day, or 21%, to 27.7 MBbl per day from 22.8 MBbl per day for the
same period in 2003. The increase was mainly due to production from
new wells in the United States (3.0 MBbl per day), higher production
in Trinidad from the Parula wells (0.8 MBbl per day) and new
production from the U(a) block (0.7 MBbl per day).
Natural gas liquids revenues were $7 million higher than a year
ago primarily due to increases in the composite average price ($4
million) and deliveries ($3 million).
During the third quarter of 2004, EOG recognized a gain from the
mark-to-market of financial commodity collar and price swap
contracts of $23 million compared to a gain of $24 million for the
prior year period. During the third quarter of 2004, the net cash
outflow related to settled natural gas financial collar contracts
and settled natural gas and crude oil financial price swap contracts
was $32 million compared to a net cash outflow related to settled
natural gas financial collar contracts, premium payments associated
with certain natural gas financial collar contracts and settled
natural gas and crude oil financial price swap contracts of $10
million for the prior year period.
Operating and Other Expenses. For the third quarter of 2004,
operating expenses of $320 million were $55 million higher than the
$265 million incurred in the third quarter of 2003. The following
table presents the costs per Mcfe for the three-month periods ended
September 30, 2004 and 2003:
Three Months Ended September 30,
2004 2003
Lease and Well $0.60 $0.53
DD&A 1.14 1.08
G&A 0.26 0.26
Taxes Other than Income 0.26 0.21
Interest Expense, Net 0.14 0.15
Total Per-Unit Costs(1) $2.40 $2.23
(1) Total per-unit costs do not include exploration costs, dry hole
costs and impairments.
-15-
The higher per-unit costs of lease and well, depreciation,
depletion and amortization (DD&A) and taxes other than income for
the three-month period ended September 30, 2004 compared to the same
period in 2003 were due primarily to the reasons set forth below.
Lease and well expenses of $69 million were $15 million higher
than the prior year period due primarily to increased production in
Canada ($4 million), increased transportation expense in the United
States ($3 million) and in Canada ($1 million), higher service cost
structures related to operating activities in the United States ($2
million) and in Canada ($2 million), and changes in the Canadian
exchange rate ($1 million).
DD&A expenses of $130 million increased $20 million from the prior
year period due primarily to increased production in Canada ($5
million), increased Canadian DD&A rates mainly from developing
acquired proved reserves ($5 million), increased United States DD&A
rates due to a gradual proportional increase in production from
higher cost properties ($5 million), increased production in the
United States ($1 million) and in Trinidad ($1 million), and changes
in the Canadian exchange rate ($1 million).
General and administrative (G&A) expenses of $30 million were $3
million higher than the prior year period due primarily to expanded
operations.
Taxes other than income of $30 million were $9 million higher than
the prior year period due primarily to increased wellhead revenue in
the United States, as previously discussed ($4 million), higher
property taxes in the United States as a result of higher property
valuation ($2 million) and a decrease in retroactive credits against
severance taxes resulting from the qualification of additional wells
for a Texas high cost gas severance tax exemption ($2 million).
Exploration costs of $22 million were $4 million higher than the
prior year period due primarily to increased geological and
geoscience expenditures in Canada ($2 million) and in Trinidad ($2
million) and increased technical staff costs in the United States
($1 million), partially offset by decreased geological and
geoscience expenditures in the United States ($1 million).
Impairments of $18 million decreased $8 million compared to the
prior year period due to lower amortization of unproved leases in
the United States ($5 million) and lower impairments to the carrying
value of certain long-lived assets as a result of downward revisions
in the future cash flow analysis for certain properties in the
United States ($4 million), partially offset by higher amortization
of unproved leases in Canada ($1 million). Total impairments under
Statement of Financial Accounting Standards (SFAS) No. 144 -
"Accounting for the Impairment or Disposal of Long-Lived Assets" for
the third quarter of 2004 and 2003 were $4 million and $8 million,
respectively.
For the third quarter of 2004, the income tax provision of $90
million increased $28 million compared to the third quarter of 2003,
primarily due to higher income before income taxes ($29 million).
The net effective tax rate for the third quarter of 2004 decreased
to 34% from 35% for the same period of 2003.
-16-
Nine Months Ended September 30, 2004 vs. Nine Months Ended
September 30, 2003
Net Operating Revenues. During the first nine months of 2004, net
operating revenues increased $229 million to $1,578 million. Total
wellhead revenues of $1,611 million increased $231 million, or 17%,
as compared to the same period a year ago. Wellhead volume and
price statistics for the nine-month periods ended September 30, 2004
and 2003 were as follows:
Nine Months Ended
September 30,
2004 2003
Natural Gas Volumes (MMcf per day)
United States 620 641
Canada 204 154
United States and Canada 824 795
Trinidad 173 152
United Kingdom 3 -
Total 1,000 947
Average Natural Gas Prices ($/Mcf)
United States $5.55 $5.25
Canada 5.00 4.80
United States and Canada Composite 5.41 5.16
Trinidad 1.46 1.33
United Kingdom 5.30 -
Composite 4.73 4.54
Crude Oil and Condensate Volumes (MBbl per day)
United States 20.7 17.9
Canada 2.6 2.2
United States and Canada 23.3 20.1
Trinidad 3.2 2.4
Total 26.5 22.5
Average Crude Oil and Condensate Prices ($/Bbl)
United States $38.57 $30.22
Canada 35.89 28.86
United States and Canada Composite 38.26 30.07
Trinidad 38.19 28.75
Composite 38.26 29.93
Natural Gas Liquids Volumes (MBbl per day)
United States 4.7 3.0
Canada 0.7 0.6
Total 5.4 3.6
Average Natural Gas Liquids Prices ($/Bbl)
United States $26.09 $21.16
Canada 21.65 18.80
Composite 25.52 20.76
Natural Gas Equivalent Volumes (MMcfe per day)
United States 772 766
Canada 224 172
United States and Canada 996 938
Trinidad 192 166
United Kingdom 3 -
Total 1,191 1,104
Total Bcfe Deliveries 326.5 301.5
-17-
During the first nine months of 2004, wellhead natural gas
revenues increased $120 million, or 10%, to $1,295 million from
$1,175 million for the same period of 2003. The increase was due to
higher natural gas deliveries ($69 million) and composite average
wellhead natural gas price ($51 million). The composite average
wellhead price for natural gas increased to $4.73 per Mcf from $4.54
per Mcf for the same period of 2003.
Natural gas deliveries increased 53 MMcf per day, or 6%, to 1,000
MMcf per day for the first nine months of 2004 from 947 MMcf per day
a year ago, primarily due to a 50 MMcf per day, or 32%, increase in
Canada; a 21 MMcf per day, or 14%, increase in Trinidad; and a 3
MMcf per day increase in the United Kingdom due to commencement of
production in August 2004; partially offset by a 21 MMcf per day, or
3%, decline in the United States. The increase in Canada (50 MMcf
per day) was attributable approximately equally to both the property
acquisitions in the fourth quarter of 2003 and the additional
production that resulted primarily from drilling activities. The
increase in Trinidad was mainly attributable to the increased
production from the U(a) block (13 MMcf per day) which began
supplying natural gas in April 2004 to the N2000 ammonia plant and
commencement of production from the Parula wells on the SECC block
in February 2004 (9 MMcf per day), partially offset by the decreased
production from the U(a) block as a result of a temporary ammonia
plant shutdown in May 2004 (2 MMcf per day).
Wellhead crude oil and condensate revenues for the first nine
months of 2004 increased $94 million, or 51%, to $278 million from
$184 million as compared to the same period of 2003, due to
increases in both the composite average wellhead crude oil and
condensate price ($61 million) and crude oil and condensate
deliveries ($33 million). The composite average wellhead price for
crude oil and condensate increased 28% to $38.26 per barrel from
$29.93 per barrel for the same period of 2003.
Wellhead crude oil and condensate deliveries increased 4.0 MBbl
per day, or 18%, to 26.5 MBbl per day from 22.5 MBbl per day for the
same period a year ago. The increase was mainly due to production
from new wells in the United States (2.8 MBbl per day) and
commencement in February 2004 of production from the Parula wells on
the SECC block in Trinidad (0.6 MBbl per day).
Natural gas liquids revenues were $18 million higher than a year
ago primarily due to increases in deliveries ($11 million) and the
composite average price ($7 million).
During the first nine months of 2004, EOG recognized a loss from
the mark-to-market of financial commodity collar and price swap
contracts of $36 million compared to a loss of $37 million for the
prior year period. During the same period of 2004, the net cash
outflow related to settled natural gas financial collar contracts
and settled natural gas and crude oil financial price swap contracts
was $71 million compared to a net cash outflow related to settled
natural gas financial collar contracts, premium payments associated
with certain natural gas financial collar contracts and settled
natural gas and crude oil financial price swap contracts of $49
million for the prior year period.
Operating and Other Expenses. For the first nine months of 2004,
operating expenses of $905 million were $153 million higher than the
$752 million incurred in the first nine months of 2003. The
following table presents the costs per Mcfe for the nine-month
periods ended September 30, 2004 and 2003:
Nine Months Ended September 30,
2004 2003
Lease and Well $0.61 $0.52
DD&A 1.10 1.06
G&A 0.25 0.24
Taxes Other than Income 0.29 0.21
Interest Expense, Net 0.15 0.15
Total Per-Unit Costs(1) $2.40 $2.18
(1) Total per-unit costs do not include exploration costs, dry hole
costs and impairments.
-18-
The higher per-unit costs of lease and well, DD&A, G&A and taxes
other than income for the nine-month period ended September 30, 2004
compared to the same period in 2003 were due primarily to the
reasons set forth below.
Lease and well expenses of $199 million were $43 million higher
than the prior year period due primarily to higher service cost
structures related to operating activities in the United States ($12
million) and in Canada ($3 million), increased production in Canada
($11 million) and in the United States ($1 million), increased
transportation expense in the United States ($10 million) and in
Canada ($1 million), and changes in the Canadian exchange rate ($4
million).
DD&A expenses of $360 million increased $40 million from the prior
year period due primarily to increased production in Canada ($13
million), increased Canadian DD&A rates from developing acquired
proved reserves ($8 million), increased United States DD&A rates due
to a gradual proportional increase in production from higher cost
properties ($8 million), changes in the Canadian exchange rate ($5
million) and increased production in the United States ($3 million)
and in Trinidad ($1 million).
G&A expenses of $81 million were $9 million higher than the prior
year period due primarily to expanded operations.
Taxes other than income of $96 million were $33 million higher
than the prior year period due primarily to a decrease in
retroactive credits against severance taxes resulting from the
qualification of additional wells for a Texas high cost gas
severance tax exemption ($18 million), the results of a production
tax lawsuit expensed in the first quarter of 2004 ($5 million),
higher property taxes in the United States as a result of higher
property valuation ($5 million) and increased wellhead revenue in
the United States, as previously discussed ($4 million).
Exploration costs of $67 million were $10 million higher than the
prior year period due primarily to increased geological and
geoscience expenditures in the United States ($7 million) and in
Canada ($2 million), and expanded operations in Canada ($1 million)
and in Trinidad ($1 million), partially offset by decreased
geological and geoscience expenditures in Trinidad ($2 million).
Impairments decreased $12 million to $51 million compared to the
prior year period due to lower amortization of unproved leases in
the United States ($6 million) and lower impairments to the carrying
value of certain long-lived assets as a result of downward revisions
in the future cash flow analysis for certain properties in the
United States ($8 million), partially offset by higher amortization
of unproved leases in Canada ($2 million). Total impairments under
SFAS No. 144 for the first nine months of 2004 and 2003 were $8
million and $16 million, respectively.
For the first nine months of 2004, the income tax provision of
$209 million increased $15 million compared to the first nine months
of 2003, primarily due to higher income before income taxes ($25
million), partially offset by lower deferred income taxes associated
with a reduction in the Alberta, Canada corporate tax rate ($5
million), lower effective foreign income tax rates ($3 million), and
lower state income taxes ($1 million). The net effective tax rate
for the first nine months of 2004 decreased to 33% from 35% for the
same period of 2003.
-19-
Capital Resources and Liquidity
Cash Flows
At September 30, 2004 and December 31, 2003, EOG had cash and cash
equivalents of $82 million and $4 million, respectively.
The primary sources of cash for EOG during the first nine months
of 2004 included funds generated from operations, proceeds from
sales of assets, proceeds from new borrowings (see discussion of the
US$150 million notes issuance below) and proceeds from stock options
exercised. Primary cash outflows included funds used in operations,
exploration and development expenditures, repayment of debt and
payment of dividends to shareholders.
Cash provided by operating activities of $1,085 million for the
first nine months of 2004 increased $71 million as compared to the
same period in 2003 primarily due to higher net income ($62 million).
Cash used in investing activities of $993 million for the first
nine months of 2004 increased by $316 million as compared to the
same period in 2003 due primarily to increased exploration and
development expenditures ($368 million), partially offset by a
property acquisition deposit made by a Canadian subsidiary of EOG in
the third quarter of 2003 ($64 million), which was recorded in
Other, Net of the Investing Cash Flows section. Changes in
Components of Working Capital Associated with Investing Activities
included changes in accounts payable associated with the accrual of
exploration and development expenditures and changes in inventories
which represent materials and equipment used in drilling and related
activities.
Cash used in financing activities was $14 million for the first
nine months of 2004 versus cash used of $163 million for the same
period in 2003. Financing activities for 2004 included the net
repayment of debt ($46 million) consisting of repayments of the
outstanding balances of commercial paper borrowings ($21 million), a
senior unsecured term loan facility ($75 million) and 6.5% notes
upon maturity ($100 million), offset partially by the notes issuance
discussed below ($150 million). Other financing activities included
proceeds from the exercise of employee stock options ($60 million)
and payments of cash dividends ($28 million).
On March 9, 2004, EOG Resources Canada Inc., a wholly owned
subsidiary of EOG, issued notes with a total principal amount of
US$150 million, an annual interest rate of 4.75% and a maturity date
of March 15, 2014, under Rule 144A of the Securities Act of 1933, as
amended. The notes are guaranteed by EOG. In conjunction with the
offering, EOG entered into a foreign currency swap transaction for
the equivalent amount of the notes and related interest, which has
in effect converted this indebtedness into CAD$201.3 million with a
5.275% interest rate.
Based upon existing economic and market conditions, management
believes net operating cash flow and available financing
alternatives will be sufficient to fund net investing and other cash
requirements of EOG for the foreseeable future.
-20-
Total Exploration and Development Expenditures
The table below presents total exploration and development
expenditures for the nine-month periods ended September 30, 2004 and
2003 (in millions):
Nine Months Ended September 30,
2004 2003
United States $ 726 $ 490
Canada 195 116
United States and Canada 921 606
Trinidad 55 17
United Kingdom 29 14
Other 4 4
Exploration and Development Expenditures 1,009 641
Asset Retirement Costs(1) 7 4
Deferred Income Tax Benefits on Acquired
Properties (17) -
Total Exploration and Development Expenditures $ 999 $ 645
(1) Asset retirement costs for the first nine months of 2003 do not
include the cumulative effect of adoption of SFAS No. 143 -
"Accounting for Asset Retirement Obligations" on January 1, 2003.
Exploration and development expenditures of $1 billion for the
first nine months of 2004 were $368 million higher than the prior
year period due primarily to increased drilling expenditures ($304
million) resulting from higher exploration and development
activities across EOG and higher cost structures in the United
States and Canada; increased lease acquisitions in the United States
($69 million), primarily in the non-core Barnett Shale area and to a
lesser extent, in South Texas; and changes in the Canadian exchange
rate ($13 million); partially offset by decreased property
acquisitions ($14 million). The higher cost structure was primarily
due to increases in materials and services across the industry. The
2004 exploration and development expenditures of $1 billion included
$702 million in development, $293 million in exploration, $7 million
in property acquisitions and $7 million in capitalized interest.
The 2003 exploration and development expenditures of $641 million
included $445 million in development, $169 million in exploration,
$21 million in property acquisitions and $6 million in capitalized
interest.
The level of exploration and development expenditures, including
acquisitions, will vary in future periods depending on energy market
conditions and other related economic factors. EOG has significant
flexibility with respect to financing alternatives and the ability
to adjust its exploration and development expenditure budget as
circumstances warrant. There are no material continuing commitments
associated with expenditure plans.
Commodity Derivative Transactions
As more fully discussed in Note 12 to the consolidated financial
statements included in EOG's Annual Report on Form 10-K for the year
ended December 31, 2003, EOG engages in price risk management
activities from time to time. These activities are intended to
manage EOG's exposure to fluctuations in commodity prices for
natural gas and crude oil. EOG utilizes commodity derivative
financial instruments, primarily price swaps and collars, as the
means to manage this price risk. In addition to these financial
transactions, EOG is a party to various physical commodity contracts
for the sale of hydrocarbons that cover varying periods of time and
have varying pricing provisions. The financial impact of these
various physical commodity contracts is included in revenues at the
time of settlement, which in turn affects average realized
hydrocarbon prices. During the first nine months of 2004 and 2003,
EOG elected not to designate any of its commodity derivative
financial contracts as accounting hedges, and accordingly, accounted
for these commodity derivative financial contracts using the mark-to-
market accounting method.
-21-
Presented below is a summary of EOG's remaining 2004 natural gas
financial collar and price swap contracts at September 30, 2004 with
prices expressed in dollars per million British thermal units
($/MMBtu) and notional volumes in million British thermal units per
day (MMBtud). The total fair value of the natural gas financial
collar and price swap contracts at September 30, 2004 was a negative
$5 million.
Natural Gas Financial Contracts
Collar Contracts Price Swap Contracts
Floor Price Ceiling Price Weighted
Floor Range/ Weighted Ceiling Weighted Average
Volume Floor Average Range Average Volume Price
(MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) (MMBtud) ($/MMBtu)
2004
Oct 375,000 $ 4.47 - 4.75 $ 4.58 $ 4.93 - 5.19 $ 5.09 30,000 $ 4.80
Nov 100,000 6.35 6.35 7.60 - 7.64 7.61 - -
Subsequent to September 30, 2004, EOG has entered into additional
natural gas financial collar and price swap contracts. Presented
below is a summary of EOG's natural gas financial collar and price
swap contracts as of October 28, 2004:
Natural Gas Financial Contracts
Collar Contracts Price Swap Contracts
Floor Price Ceiling Price Weighted
Floor Range/ Weighted Ceiling Range/ Weighted Average
Volume Floor Average Ceiling Average Volume Price
(MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) (MMBtud) ($/MMBtu)
2004
Oct 375,000 $ 4.47 - 4.75 $ 4.58 $ 4.93 - 5.19 $ 5.09 30,000 $ 4.80
Nov 100,000 6.35 6.35 7.60 - 7.64 7.61 200,000 6.82
Dec 50,000 7.65 7.65 8.90 8.90 - -
2005
Jan(1) 75,000 $ 7.65 - 8.00 $ 7.77 $ 8.90 - 9.50 $ 9.10 - $ -
Feb(2) 75,000 7.65 - 8.00 7.77 9.19 - 9.50 9.32 - -
Mar(2) 75,000 7.65 - 8.00 7.77 9.19 - 9.50 9.32 - -
(1) Notional volumes of 25,000 MMBtud of the January 2005 collar
contracts were purchased at a premium of $0.10 per MMBtu.
(2) The collar contracts for February 2005 and March 2005 were
purchased at a premium of $0.10 per MMBtu.
-22-
Information Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q includes forward-looking
statements within the meaning of Section 27A of the Securities Act
of 1933 and Section 21E of the Securities Exchange Act of 1934.
Forward-looking statements are not guarantees of performance.
Although EOG believes its expectations reflected in forward-looking
statements are based on reasonable assumptions, no assurance can be
given that these expectations will be achieved. Important factors
that could cause actual results to differ materially from the
expectations reflected in the forward-looking statements include,
among others: the timing and extent of changes in commodity prices
for crude oil, natural gas and related products, foreign currency
exchange rates and interest rates; the timing and impact of
liquefied natural gas imports and changes in demand or prices for
ammonia or methanol; the extent and effect of any hedging activities
engaged in by EOG; the extent of EOG's success in discovering,
developing, marketing and producing reserves and in acquiring oil
and gas properties; the accuracy of reserve estimates, which by
their nature involve the exercise of professional judgment and may
therefore be imprecise; the availability and cost of drilling rigs,
experienced drilling crews and tubular steel; the availability of
pipeline transportation capacity; the extent to which EOG can
replicate on its other Barnett Shale acreage the results of its most
recent Barnett Shale wells; the results of wells yet to be drilled
that are necessary to test whether substantial Barnett Shale acreage
positions in Erath, Somervell, Hood, Jack, Palo Pinto and Hill
Counties, Texas, contain suitable drilling prospects; whether EOG is
successful in its efforts to more densely develop its acreage in the
Barnett Shale and other production areas; political developments
around the world; acts of war and terrorism and responses to these
acts; and financial market conditions. In light of these risks,
uncertainties and assumptions, the events anticipated by EOG's
forward-looking statements might not occur. EOG undertakes no
obligations to update or revise its forward-looking statements,
whether as a result of new information, future events or otherwise.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
EOG RESOURCES, INC.
EOG's exposure to interest rate risk, commodity price risk and
foreign currency exchange risk is discussed respectively in the
Financing and Outlook sections of the "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Capital
Resources and Liquidity," on pages 10 through 14 of the Form 8-K
filed on February 24, 2004.
ITEM 4. CONTROLS AND PROCEDURES
EOG RESOURCES, INC.
EOG's management, with the participation of EOG's principal
executive officer and principal financial officer, evaluated the
effectiveness of EOG's disclosure controls and procedures (as
defined in Rules 13a-15(e) and 15d-15(e) promulgated under the
Securities Exchange Act of 1934, as amended (Exchange Act)) as of
the end of the quarter ended September 30, 2004. Based on this
evaluation, the principal executive officer and principal financial
officer have concluded that EOG's disclosure controls and procedures
were effective as of the end of the quarter ended September 30, 2004
to ensure that information that is required to be disclosed by EOG
in the reports it files or submits under the Exchange Act is
recorded, processed, summarized and reported, within the time
periods specified in the SEC's rules and forms. There were no
changes in EOG's internal control over financial reporting that
occurred during the quarter ended September 30, 2004 that have
materially affected, or are reasonably likely to materially affect,
EOG's internal control over financial reporting.
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PART II. OTHER INFORMATION
EOG RESOURCES, INC.
ITEM 1. Legal Proceedings
See Part 1, Item 1, Note 5 to Consolidated Financial
Statements, which is incorporated herein by reference.
ITEM 2. Changes in Securities and Use of Proceeds
(c)
(a) Total Number of (d)
Total (b) Shares Purchased as Maximum Number
Number of Average Part of Publicly of Shares that May Yet
Shares Price Paid Announced Plans or Be Purchased Under
Period Purchased(1) per Share Programs the Plans or Programs(2)
July 1, 2004 - July 31, 2004 - $ - - 6,386,200
Aug 1, 2004 - Aug 31, 2004 120 57.45 - 6,386,200
Sept 1, 2004 - Sept 30, 2004 133 58.98 - 6,386,200
Total 253 $58.25 -
(1) Includes 253 shares that were returned to EOG to
satisfy tax withholding obligations that arose upon the
exercise of employee stock options or the vesting of
restricted stock or units.
(2) In September 2001, EOG announced that its Board of
Directors authorized the repurchase of up to 10,000,000
shares of EOG's common stock.
ITEM 6. Exhibits
Exhibit 31.1 - Section 302 Certification of Periodic Report
of Chief Executive Officer.
Exhibit 31.2 - Section 302 Certification of Periodic Report
of Principal Financial Officer.
Exhibit 32.1 - Section 906 Certification of Periodic Report
of Chief Executive Officer.
Exhibit 32.2 - Section 906 Certification of Periodic Report
of Principal Financial Officer.
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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: October 28, 2004 By: /s/ TIMOTHY K. DRIGGERS
Timothy K. Driggers
Vice President and Chief Accounting Officer
(Principal Accounting Officer)
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EXHIBIT INDEX
Exhibit No. Description
*31.1 -- Section 302 Certification of Periodic Report of Chief
Executive Officer
*31.2 -- Section 302 Certification of Periodic Report of
Principal Financial Officer
*32.1 -- Section 906 Certification of Periodic Report of Chief
Executive Officer
*32.2 -- Section 906 Certification of Periodic Report of
Principal Financial Officer
*Exhibits filed herewith
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