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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 September 30, 2003
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 October 21, 2003.
Title of each class Number of shares
Common Stock, $.01 par value 115,086,149
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, 2003 and 2002 And Nine Months Ended
September 30, 2003 and 2002 3
Consolidated Balance Sheets - September 30, 2003 and
December 31, 2002 4
Consolidated Statements of Cash Flows - Nine Months
Ended September 30, 2003 and 2002 5
Notes to Consolidated Financial Statements 6
ITEM 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 12
ITEM 4. Controls and Procedures 22
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings 23
ITEM 6. Exhibits and Current Reports on Form 8-K 23
SIGNATURES 24
EXHIBIT INDEX 25
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,
2003 2002 2003 2002
NET OPERATING REVENUES
Natural Gas $365,064 $224,018 $1,176,798 $631,874
Crude Oil, Condensate and Natural Gas Liquids 67,664 62,121 204,643 165,531
Gains (Losses) on Mark-to-market Commodity
Derivative Contracts 23,628 (7,849) (37,346) (41,451)
Other, Net 2,368 1,589 4,052 651
TOTAL 458,724 279,879 1,348,147 756,605
OPERATING EXPENSES
Lease and Well 54,431 45,727 156,390 129,956
Exploration Costs 17,812 12,824 57,409 41,514
Dry Hole Costs 8,876 9,094 18,932 32,336
Impairments 26,117 11,802 63,548 34,548
Depreciation, Depletion and Amortization 110,438 100,208 320,578 292,624
General and Administrative 26,379 21,582 71,734 64,283
Taxes Other Than Income 21,359 16,932 63,247 50,980
TOTAL 265,412 218,169 751,838 646,241
OPERATING INCOME 193,312 61,710 596,309 110,364
OTHER INCOME (EXPENSE), NET 1,924 (74) 4,756 (2,800)
INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES 195,236 61,636 601,065 107,564
INTEREST EXPENSE, NET 15,632 18,770 44,757 45,003
INCOME BEFORE INCOME TAXES 179,604 42,866 556,308 62,561
INCOME TAX PROVISION 62,185 13,979 193,542 19,807
NET INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE 117,419 28,887 362,766 42,754
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF TAX - - (7,131) -
NET INCOME 117,419 28,887 355,635 42,754
PREFERRED STOCK DIVIDENDS 2,758 2,758 8,274 8,274
NET INCOME AVAILABLE TO COMMON $114,661 $ 26,129 $ 347,361 $ 34,480
NET INCOME PER SHARE AVAILABLE TO COMMON
Basic
Net Income Available to Common Before Cumulative
Effect of Change in Accounting Principle $ 1.00 $ 0.23 $ 3.09 $ 0.30
Cumulative Effect of Change in Accounting Principle,
net of tax - - (0.06) -
Net Income Available to Common $ 1.00 $ 0.23 $ 3.03 $ 0.30
Diluted
Net Income Available to Common Before Cumulative
Effect of Change in Accounting Principle $ 0.99 $ 0.22 $ 3.05 $ 0.29
Cumulative Effect of Change in Accounting Principle,
net of tax - - (0.06) -
Net Income Available to Common $ 0.99 $ 0.22 $ 2.99 $ 0.29
AVERAGE NUMBER OF COMMON SHARES
Basic 114,616 115,621 114,489 115,555
Diluted 116,370 117,078 116,284 117,267
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)
September 30, December 31,
2003 2002
(Unaudited)
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 184,489 $ 9,848
Accounts Receivable, Net 274,834 259,308
Inventories 20,788 18,928
Assets from Price Risk Management Activities 7,769 -
Other 70,096 106,708
TOTAL 557,976 394,792
OIL AND GAS PROPERTIES (SUCCESSFUL EFFORTS METHOD) 7,495,980 6,750,095
Less: Accumulated Depreciation, Depletion and
Amortization (3,792,187) (3,428,547)
Net Oil and Gas Properties 3,703,793 3,321,548
OTHER ASSETS 164,293 97,666
TOTAL ASSETS $ 4,426,062 $ 3,814,006
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable $ 252,211 $ 201,931
Accrued Taxes Payable 38,720 23,170
Dividends Payable 6,151 5,007
Liabilities from Price Risk Management Activities 2,031 5,939
Other 54,815 40,304
TOTAL 353,928 276,351
LONG-TERM DEBT 1,010,822 1,145,132
OTHER LIABILITIES 163,855 59,180
DEFERRED INCOME TAXES 797,010 660,948
SHAREHOLDERS' EQUITY
Preferred Stock, $.01 Par, 10,000,000 Shares Authorized:
Series B, 100,000 Shares Issued, Cumulative,
$100,000,000 Liquidation Preference 98,530 98,352
Series D, 500 Shares Issued, Cumulative,
$50,000,000 Liquidation Preference 49,782 49,647
Common Stock, $.01 Par, 320,000,000 Shares Authorized
and 124,730,000 Shares Issued 201,247 201,247
Additional Paid In Capital 2,801 -
Unearned Compensation (19,712) (15,033)
Accumulated Other Comprehensive Income (Loss) 40,481 (49,877)
Retained Earnings 2,055,248 1,723,948
Common Stock Held in Treasury, 9,664,122 shares at
September 30, 2003 and 10,009,740 shares at
December 31, 2002 (327,930) (335,889)
TOTAL SHAREHOLDERS' EQUITY 2,100,447 1,672,395
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 4,426,062 $ 3,814,006
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)
Nine Months Ended
September 30,
2003 2002
CASH FLOWS FROM OPERATING ACTIVITIES
Reconciliation of Net Income to Net Operating Cash Inflows:
Net Income $ 355,635 $ 42,754
Items Not Requiring Cash
Depreciation, Depletion and Amortization 320,578 292,624
Impairments 63,548 34,548
Deferred Income Taxes 123,431 38,225
Cumulative Effect of Change in Accounting Principle 7,131 -
Other, Net 6,763 16,102
Exploration Costs 57,409 41,514
Dry Hole Costs 18,932 32,336
Mark-to-market Commodity Derivative Contracts
Total Losses 37,346 41,451
Realized Losses (47,700) (11,741)
Collar Premium (1,365) -
Tax Benefits from Stock Options Exercised 7,025 4,216
Other, Net 2,894 (1,538)
Changes in Components of Working Capital and
Other Liabilities
Accounts Receivable (15,905) 902
Inventories (1,860) 768
Accounts Payable 50,028 (45,292)
Accrued Taxes Payable 46,854 (38,303)
Other Liabilities 1,783 (919)
Other, Net 3,989 (19,662)
Changes in Components of Working Capital Associated
with Investing and Financing Activities (22,064) 35,046
NET OPERATING CASH INFLOWS 1,014,452 463,031
INVESTING CASH FLOWS
Additions to Oil and Gas Properties (564,825) (541,034)
Exploration Costs (57,409) (41,514)
Dry Hole Costs (18,932) (32,336)
Proceeds from Sales of Assets 12,361 6,334
Changes in Components of Working Capital Associated
with Investing Activities 22,223 (35,590)
Other, Net (70,366) (14,017)
NET INVESTING CASH OUTFLOWS (676,948) (658,157)
FINANCING CASH FLOWS
Long-Term Debt Borrowings (Repayments) (134,310) 234,899
Dividends Paid (22,878) (21,878)
Treasury Stock Purchased (21,295) (24,288)
Proceeds from Stock Options Exercised 17,717 13,831
Other, Net (2,097) (2,168)
NET FINANCING CASH INFLOWS (OUTFLOWS) (162,863) 200,396
INCREASE IN CASH AND CASH EQUIVALENTS 174,641 5,270
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 9,848 2,512
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 184,489 $ 7,782
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
(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,
2002 (EOG's 2002 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 11 to the consolidated financial
statements included in EOG's 2002 Annual Report, EOG engages in
price risk management activities from time to time. Derivative
financial instruments (primarily price swaps and collars) are
utilized selectively to hedge the impact of market fluctuations
on natural gas and crude oil prices. During the first nine
months of 2003 and 2002, EOG elected not to designate any of its
derivative financial transactions as accounting hedges, and
accordingly, accounted for them using the mark-to-market
accounting method. In addition to these financial transactions,
EOG is 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,
which in turn affects average realized hydrocarbon prices.
In June 2001, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standards (SFAS) No.
143 - "Accounting for Asset Retirement Obligations" effective for
fiscal years beginning after June 15, 2002. As more fully
discussed in Note 1 to the consolidated financial statements
included in EOG's 2002 Annual Report, SFAS No. 143 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. EOG
adopted the statement on January 1, 2003. The impact of adopting
the statement resulted in an after-tax charge of $7.1 million
(see Note 6).
In December 2002, the 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 8). Subsequently, at the
April 22, 2003 FASB meeting, the FASB decided to require all
companies to expense the value of employee stock options.
Companies will be required to measure the cost according to the
fair value of the options under a method yet to be determined.
On October 1, 2003, the FASB set a goal of completing its
deliberations and issuing a final statement in the second half of
2004. EOG continues to monitor the developments in this area as
details of the implementation of the decision emerge.
In January 2003, the FASB released its Interpretation No. 46,
"Consolidation of Variable Interest Entities, an Interpretation
of Accounting Research Bulletin No. 51" (FIN 46). FIN 46
requires a company to consolidate a variable interest entity if
the company has a variable interest (or combination of variable
interests) that will absorb a majority of the entity's expected
losses if they occur, receive a majority of the entity's expected
residual returns if they occur, or both. The new interpretation
is effective immediately at the time of its release for variable
interest entities created after January 31, 2003, and is
effective in the first interim or annual period beginning after
December 15, 2003, for variable interest entities in which a
company holds a variable interest that it acquired before
February 1, 2003. While EOG continues to evaluate the impact, if
any, FIN 46 may have on its consolidated financial statements, it
does not believe that it owns any interest in a variable interest
entity.
In April 2003, the FASB issued SFAS No. 149 - "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities."
This statement amends and clarifies SFAS No. 133 as a result of
various implementation issues and does not impact the accounting
treatment of EOG's derivative financial instruments.
In May 2003, the FASB issued SFAS No. 150 - "Accounting for
Certain Financial Instruments with Characteristics of both
Liabilities and Equity." Currently, EOG does not have any
financial instruments in place which fall under the scope of this
statement.
Recently, the SEC has 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 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 SEC prevails on this issue, EOG would
reclassify these costs from oil and gas properties to intangible
assets on the balance sheet. There would be no effect on the
statement of income or cash flows.
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, 2003 and 2002 (in thousands, except per
share amounts):
Three Months Ended Nine Months Ended
September 30, September 30,
2003 2002 2003 2002
Numerator for basic and diluted earnings per share -
Net income available to common $114,661 $ 26,129 $347,361 $ 34,480
Denominator for basic earnings per share -
Weighted average shares 114,616 115,621 114,489 115,555
Potential dilutive common shares -
Stock options 1,476 1,252 1,512 1,474
Restricted stock and units 278 205 283 238
Denominator for diluted earnings per share -
Adjusted weighted average shares 116,370 117,078 116,284 117,267
Net income per share of common stock
Basic $ 1.00 $ 0.23 $ 3.03 $ 0.30
Diluted $ 0.99 $ 0.22 $ 2.99 $ 0.29
3. The following table presents the components of EOG's comprehensive
income for the three-month and nine-month periods ended
September 30, 2003 and 2002 (in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
2003 2002 2003 2002
Net Income $117,419 $ 28,887 $355,635 $ 42,754
Other Comprehensive Income (Loss), net of tax
Foreign Currency Translation Adjustments 2,935 (20,977) 90,358 2,542
Available-for-sale Security Transactions - - - 926
COMPREHENSIVE INCOME $120,354 $ 7,910 $445,993 $ 46,222
4. Selected financial information about operating segments is
reported below for the three-month and nine-month periods ended
September 30, 2003 and 2002 (in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
2003 2002 2003 2002
NET OPERATING REVENUES
United States $363,783 $219,275 $1,050,805 $588,088
Canada 69,660 37,626 223,265 113,064
Trinidad 25,268 22,966 74,036 55,418
Other 13 12 41 35
TOTAL $458,724 $279,879 $1,348,147 $756,605
OPERATING INCOME (LOSS)
United States $139,285 $ 40,044 $ 427,703 $ 61,829
Canada 36,773 7,146 128,290 16,892
Trinidad 17,679 14,642 45,386 34,132
Other (425) (122) (5,070) (2,489)
TOTAL 193,312 61,710 596,309 110,364
RECONCILING ITEMS
Other Income (Expense), Net 1,924 (74) 4,756 (2,800)
Interest Expense, Net 15,632 18,770 44,757 45,003
INCOME BEFORE INCOME TAXES $179,604 $ 42,866 $ 556,308 $ 62,561
5. EOG and numerous other companies in the natural gas industry
are named as defendants in various lawsuits alleging violations of
the Civil False Claims Act. These lawsuits have been consolidated
for pre-trial proceedings in the United States District Court for
the District of Wyoming. The plaintiffs contend that defendants
have underpaid royalties on natural gas and natural gas liquids
produced on federal and Indian lands through the use of below-market
prices, improper deductions, improper measurement techniques and
transactions with affiliated companies. Plaintiffs allege that the
royalties paid by defendants were lower than the royalties required
to be paid under federal regulations and that the forms filed by
defendants with the Minerals Management Service reporting these
royalty payments were false, thereby violating the Civil False
Claims Act. Based on EOG's present understanding of these cases,
EOG believes that it has substantial defenses to these claims and
intends to vigorously assert these defenses. However, if EOG is
found to have violated the Civil False Claims Act, EOG could be
subject to a variety of sanctions, including treble damages and
substantial monetary fines.
There are various other suits and claims against EOG that have
arisen in the ordinary course of business. However, management
does not believe these suits and claims will individually or in
the aggregate have a material adverse effect on the financial
condition or results of operations of EOG. 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.
6. EOG adopted SFAS No. 143 - "Accounting for Asset Retirement
Obligations" on January 1, 2003. The impact of adopting the
statement resulted in 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. 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 six-month period ended June 30, 2003 and for the
three-month period ended September 30, 2003 (in thousands):
Asset Retirement Obligations
Short-Term Long-Term Total
Balance at December 31, 2002 $ - $ - $ -
Carrying Amount at Adoption 6,384 92,097 98,481
Liabilities Incurred 7 3,021 3,028
Liabilities Settled (579) (475) (1,054)
Accretion 62 2,253 2,315
Foreign Currency Translation 88 1,416 1,504
Balance at June 30, 2003 5,962 98,312 104,274
Liabilities Incurred - 1,348 1,348
Liabilities Settled (8) - (8)
Accretion 30 1,197 1,227
Foreign Currency Translation 2 39 41
Balance at September 30, 2003 $ 5,986 $100,896 $106,882
Pro forma net income and earnings per share are not presented for
the comparable periods in 2002 because the pro forma application
of SFAS No. 143 to the prior period would not result in pro forma
net income and earnings per share materially different from the
actual amounts reported for the period in the accompanying
Consolidated Statements of Income.
7. EOG, through certain wholly owned subsidiaries, owns equity
interests in two Trinidadian companies: Caribbean Nitrogen
Company Limited ("CNCL") and Nitrogen (2000) Unlimited ("N2000").
During the first quarter of 2003, EOG completed separate share
purchase agreements whereby a portion of the EOG subsidiaries'
shareholdings in CNCL and N2000 was sold to a third party energy
company. The sale left EOG with equity interests of
approximately 12% in CNCL and 27% in N2000 and did not result in
any gain or loss.
8. EOG has various stock plans ("the 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 as of 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.
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, 2003 and 2002 was $1.5 million and $1.3 million,
respectively. Related compensation expense for the nine-month
periods ended September 30, 2003 and 2002 was $4.1 million and
$3.6 million, respectively.
EOG's pro forma net income and net income per share of common
stock for the three-month and nine-month periods ended September
30, 2003 and 2002, had compensation costs 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 data):
Three Months Ended Nine Months Ended
September 30, September 30,
2003 2002 2003 2002
Net Income Available to Common - As Reported $114,661 $ 26,129 $347,361 $ 34,480
Deduct: Total Stock-Based Employee
Compensation Expense (5,491) (5,110) (11,138) (11,365)
Net Income Available to Common - Pro Forma $109,170 $ 21,019 $336,223 $ 23,115
Net Income per Share Available to Common
Basic - As Reported $ 1.00 $ 0.23 $ 3.03 $ 0.30
Basic - Pro Forma $ 0.95 $ 0.18 $ 2.94 $ 0.20
Diluted - As Reported $ 0.99 $ 0.22 $ 2.99 $ 0.29
Diluted - Pro Forma $ 0.94 $ 0.18 $ 2.89 $ 0.20
The effects of applying SFAS No. 123, as amended, should not be
interpreted as being indicative of future effects. The statement
does not apply to awards prior to 1995, and the extent and timing
of additional future awards cannot be predicted.
9. On July 23, 2003, EOG entered into a new three-year credit
facility with domestic and foreign lenders which provides for $600
million in long-term committed credit, and concurrently cancelled
the existing $300 million 364-day credit facility and $300 million
five-year credit facility scheduled to expire in July 2003 and July
2004, respectively. Advances under the new agreement bear interest,
at the option of EOG, based upon a base rate or a Eurodollar rate.
The new credit facility also provides for the allocation, at the
option of EOG, of up to $75 million of the $600 million to its
Canadian subsidiary. Advances to the Canadian subsidiary, should
they occur, would be guaranteed by EOG and would bear interest at
the option of the Canadian subsidiary based upon a Canadian prime
rate or a Canadian banker's acceptance rate. EOG also has the
option to issue up to $100 million in letters of credit as part of
this new credit facility.
10. On October 1, 2003, a Canadian subsidiary of EOG closed the
previously announced asset purchase of natural gas properties in
the Wintering Hills, Drumheller East and Twining areas of
southeast Alberta from a subsidiary of Husky Energy Inc. (Husky)
for US $320 million. These properties are essentially adjacent
to existing EOG operations or are properties in which EOG already
has a working interest. The transaction value, reserves and
working interest in the properties are subject to adjustment if
preferential rights on the properties are exercised. The
transaction was partially funded by commercial paper borrowings
of US $140.5 million on October 1, 2003. The remainder of the
purchase price, US $179.5 million, was funded by EOG's available
cash balance, of which US $64 million was paid to Husky during
the third quarter of 2003 as a deposit, as included under Other
Assets in the Consolidated Balance Sheets.
PART I. FINANCIAL INFORMATION (Continued)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EOG RESOURCES, INC.
The following review of operations for the three-month periods
ended September 30, 2003 and 2002 should be read in conjunction with
the consolidated financial statements of EOG Resources, Inc. and
subsidiaries (EOG) and Notes thereto.
Results of Operations
Three Months Ended September 30, 2003 vs. Three Months Ended September 30, 2002
Net Operating Revenues. During the third quarter of 2003, net
operating revenues increased $179 million to $459 million. Total
wellhead revenues of $432 million increased by $164 million, or 61%,
as compared to a year ago. Wellhead volume and price statistics for
the specified quarters were as follows:
Three Months Ended
September 30,
2003 2002
Natural Gas Volumes (MMcf per day)(1)
United States 644 630
Canada 152 152
North America 796 782
Trinidad 155 164
TOTAL 951 946
Average Natural Gas Prices ($/Mcf)(2)
United States $ 4.78 $2.75
Canada 4.47 2.17
North America Composite 4.72 2.63
Trinidad 1.34 1.09
COMPOSITE 4.17 2.37
Crude Oil/Condensate Volumes (MBbl per day)(1)
United States 18.0 18.1
Canada 2.3 2.2
North America 20.3 20.3
Trinidad 2.5 2.9
TOTAL 22.8 23.2
Average Crude Oil/Condensate Prices ($/Bbl)(2)
United States $29.43 $27.50
Canada 28.11 25.83
North America Composite 29.28 27.33
Trinidad 26.80 24.22
COMPOSITE 29.01 26.93
Natural Gas Liquids Volumes (MBbl per day)(1)
United States 2.9 2.7
Canada 0.8 0.7
TOTAL 3.7 3.4
Average Natural Gas Liquids Prices ($/Bbl)(2)
United States $20.53 $15.92
Canada 18.23 11.23
COMPOSITE 20.06 14.96
Natural Gas Equivalent Volumes (MMcfe per day)(3)
United States 770 755
Canada 170 169
North America 940 924
Trinidad 170 181
TOTAL 1,110 1,105
Total Bcfe(3) Deliveries 102 102
(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 third quarter of 2003
increased approximately $158 million, or 77%, primarily due to an
increase in average wellhead natural gas prices. The average
wellhead price for natural gas increased 76% to $4.17 per Mcf for
the third quarter of 2003 from $2.37 per Mcf for the same quarter of
2002.
Natural gas deliveries were 5 MMcf per day higher for the third
quarter of 2003 as compared to a year ago. Natural gas deliveries
increased 14 MMcf per day, or 2%, in the United States due to higher
production. Natural gas deliveries decreased 9 MMcf per day in
Trinidad due to lower production as a result of downtime in the
third quarter of 2003 related to pipeline maintenance (3 MMcf per
day) and a favorable adjustment in the third quarter of 2002 related
to the commencement of production from the U(a) Block (6 MMcf per
day).
Wellhead crude oil and condensate revenues for the third quarter
of 2003 increased approximately $3 million, or 6% as compared to the
prior year period, primarily due to an increase in the average
wellhead crude oil and condensate prices, partially offset by lower
crude oil and condensate deliveries. The average wellhead price for
crude oil and condensate increased 8% to $29.01 per barrel from
$26.93 per barrel for the same quarter of 2002.
Crude oil and condensate deliveries for the third quarter of 2003
were 0.4 MBbl per day, or 2%, lower as compared to the prior year
period.
Natural gas liquids revenues were approximately $2 million higher
than a year ago primarily due to a 34% increase in prices and a 9%
increase in deliveries.
Other marketing activities associated with sales and purchases of
natural gas increased net operating revenues by $0.6 million for the
third quarter of 2003 compared to an increase of $18.0 million in
the third quarter of 2002.
During the third quarter of 2003, EOG recognized a gain from mark-
to-market financial commodity price swap and collar contracts of
$23.6 million compared to a loss of $7.8 million for the prior year
period. During the third quarter of 2003, net cash outflows related
to settled natural gas and crude oil financial price swap contracts,
settled natural gas financial collar contracts and premium payments
associated with certain 2004 natural gas financial collar contracts
were $10.0 million compared to a net cash outflow of $2.9 million
for the period in 2002.
Operating Expenses. For the third quarter of 2003, operating
expenses of $265 million were approximately $47 million higher than
the third quarter of 2002.
Impairments increased $14 million to $26 million in the third
quarter of 2003 compared to a year ago due to higher amortization of
unproved leases and 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. For the three-month
periods ended September 30, 2003 and 2002, total impairments under
SFAS No. 144 - "Accounting for the Impairment or Disposal of Long-
Lived Assets" were $8 million and $4 million, respectively.
Depreciation, depletion and amortization ("DD&A") expenses of $110
million increased $10 million from the prior year period due
primarily to increased DD&A expenses related to more relative
production from higher cost properties in the United States ($5
million), increased production in the United States ($2 million) and
changes in the Canadian exchange rate ($2 million). Also, included
in the DD&A expenses for the third quarter 2003 was $1 million of
accretion expense related to SFAS No. 143 - "Accounting for Asset
Retirement Obligations."
Lease and well expenses of $54 million were $9 million higher than
the period a year ago due primarily to a general increase in service
costs related to expanded activities in the United States ($5
million), increased lease and well administrative expenses ($2
million) and changes in the Canadian exchange rate ($1 million).
General and administrative ("G&A") expenses of $26 million were $5
million higher than the period a year ago due primarily to expanded
operations ($3 million) and increased insurance expense ($1
million).
Exploration costs of $18 million were $5 million higher than a
year ago due primarily to increased geological and geoscience
expenditures in the United States ($4 million) and increased
technical staff costs across EOG ($1 million).
Taxes other than income of $21 million were $4 million higher than
the prior year period primarily due to an increase of $8 million as
a result of increased wellhead revenue as previously discussed,
partially offset by a $4 million credit from severance tax
adjustments resulting from the qualification of additional wells for
a Texas high cost gas severance tax exemption.
Interest Expense, Net. For the third quarter of 2003, net
interest expense of $16 million decreased approximately $3 million,
or 17%, compared to the third quarter of 2002. This decrease is due
primarily to the $5 million one-time close-out fees recorded in the
third quarter of 2002 associated with the completion of the Section
29 (Tight Gas Sands Federal Income Tax Credits) financing.
Per-Unit Costs. The following table presents the costs per Mcfe
for the three-month periods ended September 30, 2003 and 2002.
Three Months Ended September 30,
2003 2002
Lease and Well $0.53 $0.45
DD&A 1.08 0.99
G&A 0.26 0.21
Taxes Other than Income 0.21 0.17
Interest Expense, Net 0.15 0.18
Total Per-Unit Costs $2.23 $2.00
The higher per-unit rates of lease and well, DD&A, G&A and taxes
other than income and the lower per-unit rate of net interest
expense for the three-month period ended September 30, 2003 compared
to the same period in 2002 were due primarily to the reasons set
forth above.
Income Tax Provision. For the third quarter of 2003, income tax
provision of $62 million increased $48 million as compared to the
third quarter of 2002 due to increases in both pre-tax income and
effective tax rate. The increase in the effective tax rate for the
third quarter of 2003 to 35% from 33% for the same period in 2002
was due primarily to the expiration of the Section 29 Credit
provision in the Internal Revenue Code as of December 31, 2002.
Results of Operations
Nine Months Ended September 30, 2003 vs. Nine Months Ended September 30, 2002
Net Operating Revenues. During the first nine months of 2003, net
operating revenue increased $592 million to $1,348 million. Total
wellhead revenues increased 79% to $1,380 million in the first nine
months of 2003 from $769 million in the first nine months of 2002.
Wellhead volume and price statistics for the specified periods were
as follows:
Nine Months Ended
September 30,
2003 2002
Natural Gas Volumes (MMcf per day)
United States 641 631
Canada 154 152
North America 795 783
Trinidad 152 128
TOTAL 947 911
Average Natural Gas Prices ($/Mcf)
United States $5.25 $2.68
Canada 4.80 2.41
North America Composite 5.16 2.63
Trinidad 1.33 1.19
COMPOSITE 4.54 2.43
Crude Oil/Condensate Volumes (MBbl per day)
United States 17.9 19.1
Canada 2.2 2.0
North America 20.1 21.1
Trinidad 2.4 2.2
TOTAL 22.5 23.3
Average Crude Oil/Condensate Prices ($/Bbl)
United States $30.22 $24.05
Canada 28.86 23.19
North America Composite 30.07 23.97
Trinidad 28.75 22.47
COMPOSITE 29.93 23.82
Natural Gas Liquids Volumes (MBbl per day)
United States 3.0 3.1
Canada 0.6 0.8
TOTAL 3.6 3.9
Average Natural Gas Liquids Prices ($/Bbl)
United States $21.16 $13.72
Canada 18.80 10.05
COMPOSITE 20.76 13.03
Natural Gas Equivalent Volumes (MMcfe per day)
United States 766 765
Canada 172 168
North America 938 933
Trinidad 166 141
TOTAL 1,104 1,074
Total Bcfe Deliveries 302 293
Wellhead natural gas revenues increased approximately $571
million, or 95%, due to increases in average wellhead natural gas
prices and natural gas deliveries. The average wellhead price for
natural gas increased 87% to $4.54 per Mcf for the first nine months
of 2003 from $2.43 per Mcf for the same period a year ago.
Natural gas deliveries increased 4% to 947 MMcf per day for the
first nine months of 2003 from 911 MMcf per day a year ago. The
increase in natural gas deliveries was primarily due to the
additional production of 23 MMcf per day from the U(a) Block in
Trinidad where production commenced May 2002, and to increased
production in North America. The increase in North America was due
to increased production of 10 MMcf per day, or 2%, in the United
States and 2 MMcf per day, or 1%, in Canada.
Wellhead crude oil and condensate revenues for the first nine
months of 2003 increased approximately $32 million, or 21%, as
compared to the prior year period, primarily due to an increase in
the average wellhead crude oil and condensate prices, partially
offset by lower crude oil and condensate deliveries. The average
wellhead price for crude oil and condensate increased 26% to $29.93
per barrel from $23.82 per barrel for the period a year ago.
Crude oil and condensate deliveries decreased 3% to 22.5 MBbl per
day for the first nine months of 2003 from 23.3 MBbl per day a year
ago.
Natural gas liquids revenues were approximately $7 million higher
than a year ago primarily due to a 59% increase in prices, partially
offset by an 8% decrease in deliveries.
Other marketing activities associated with sales and purchases of
natural gas increased net operating revenues by $1.5 million for the
first nine months of 2003 compared to an increase of $28.0 million
for the same period in 2002.
During the first nine months of 2003, EOG recognized a loss from
mark-to-market financial commodity price swap and collar contracts
of $37.3 million compared to a loss of $41.5 million for the prior
year period. During the same period of 2003, net cash outflows
related to settled natural gas and crude oil financial price swap
contracts, settled natural gas financial collar contracts and
premium payments associated with certain 2004 natural gas financial
collar contracts were $49.1 million compared to a net cash outflow
of $11.7 million for the comparable period in 2002.
Operating Expenses. For the first nine months of 2003, operating
expenses of $752 million were approximately $106 million higher than
the first nine months of 2002.
Impairments increased $29 million to $64 million in the first nine
months of 2003 compared to a year ago due to higher amortization of
unproved leases and 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. For the nine-month
periods ended September 30, 2003 and 2002, total impairments under
SFAS No. 144 - "Accounting for the Impairment or Disposal of Long-
Lived Assets" were $16 million and $9 million, respectively.
DD&A expenses of $321 million increased $28 million from the prior
year period due primarily to more relative production from higher
cost properties in the United States ($15 million) and Canada ($4
million), increased production in Trinidad ($2 million) and changes
in the Canadian exchange rate ($2 million). Also, included in the
DD&A expenses for the first nine months of 2003 was $4 million of
accretion expense related to SFAS No. 143 - "Accounting for Asset
Retirement Obligations."
Lease and well expenses of $156 million were $26 million higher
than the period a year ago due primarily to general increases in
service costs related to expanded activities in the United States
($11 million), Canada ($6 million) and Trinidad ($1 million), lease
and well administrative expenses ($7 million) and changes in the
Canadian exchange rate ($1 million).
Exploration costs of $57 million were $16 million higher than a
year ago due primarily to increased geological and geoscience
expenditures in the United States ($7 million), increased technical
staff costs across EOG ($7 million) and certain seismic projects in
Trinidad ($3 million).
Taxes other than income of $63 million were $12 million higher
than the prior year period primarily due an increase of $34 million
as a result of increased wellhead revenue as previously discussed,
partially offset by a $22 million credit from severance tax
adjustments resulting from the qualification of additional wells for
a Texas high cost gas severance tax exemption.
G&A expenses of $72 million were $7 million higher than a year ago
due primarily to expanded operations ($5 million) and increased
insurance expense ($4 million).
Per-Unit Costs. The following table presents the costs per Mcfe
for the nine-month periods ended September 30, 2003 and 2002.
Nine Months Ended September 30,
2003 2002
Lease and Well $0.52 $0.44
DD&A 1.06 1.00
G&A 0.24 0.22
Taxes Other than Income 0.21 0.17
Interest Expense, Net 0.15 0.15
Total Per-Unit Costs $2.18 $1.98
The higher per-unit rates of lease and well, DD&A, G&A and taxes
other than income for the nine-month period ended September 30, 2003
compared to the same period in 2002 were due primarily to the
reasons set forth above.
Income Tax Provision. For the first nine months of 2003, income
tax provision of $194 million increased $174 million as compared to
the first nine months of 2002 due to increases in both pre-tax
income and effective tax rate. The increase in the effective tax
rate for the first nine months of 2003 to 35% from 32% for the same
period of 2002 was due primarily to the expiration of the Section 29
Credit provision in the Internal Revenue Code as of December 31,
2002 and increases in the overall foreign effective tax rate.
Capital Resources and Liquidity
EOG's primary sources of cash during the nine months ended
September 30, 2003 included funds generated from operations,
proceeds from sales of partial interests in certain equity
investments and proceeds from stock options exercised. Primary cash
outflows included funds used in operations, exploration and
development expenditures, property acquisitions, repayment of debt,
common stock repurchases and dividends.
Net operating cash inflows of $1,014 million for the first nine
months of 2003 increased approximately $551 million as compared to
the first nine months of 2002 primarily reflecting higher wellhead
revenues ($611 million) and favorable changes in working capital
($130 million), partially offset by higher cash operating expenses
($134 million) and lower income from other marketing activities ($26
million).
Net investing cash outflows of approximately $677 million for the
first nine months of 2003 increased by $19 million versus the prior
year period due primarily to a $64 million deposit made in
connection with the Canadian acquisition (see below) and increased
exploration and development expenditures of $26 million, partially
offset by favorable changes in working capital of $58 million
related to investing activities. 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.
Exploration and development expenditures for the first nine months
of 2003 and 2002 were as follows (in millions):
Nine Months Ended September 30,
2003 2002
United States $490 $433
Canada 116 149
North America 606 582
Trinidad 17 33
United Kingdom 14 -
Other 4 -
Subtotal 641 615
Deferred Income Tax Gross Up - 12
TOTAL $641 $627
Total exploration and development expenditures of $641 million for
the first nine months of 2003 were $14 million higher than the prior
year period due primarily to increased United States development and
exploratory activities, partially offset by decreases in Trinidad
and lower property acquisitions in Canada during the first nine
months of 2003. Included in the 2003 expenditures are $445 million
in development, $169 million for exploration, $21 million in
property acquisitions and $6 million in capitalized interest.
On October 1, 2003, a Canadian subsidiary of EOG closed the
previously announced asset purchase of natural gas properties in the
Wintering Hills, Drumheller East and Twining areas of southeast
Alberta from a subsidiary of Husky Energy Inc. (Husky) for US $320
million. These properties are essentially adjacent to existing EOG
operations or are properties in which EOG already has a working
interest. The transaction value, reserves and working interest in
the properties are subject to adjustment if preferential rights on
the properties are exercised. The transaction was partially funded
by commercial paper borrowings of US $140.5 million on October 1,
2003. The remainder of the purchase price, US $179.5 million, was
funded by EOG's available cash balance, of which US $64 million was
paid to Husky during the third quarter of 2003 as a deposit.
The level of exploration and development expenditures varies
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.
Cash used by financing activities was $163 million for the first
nine months of 2003 versus cash provided of $200 million for the
prior year period. Financing activities for 2003 included the
repayment of the outstanding balances of commercial paper borrowings
and the uncommitted line of credit of $120 million and $14 million,
respectively, repurchases of EOG's common stock of $21 million, cash
dividend payments of $23 million and proceeds of $17 million from
sales of treasury stock attributable to employee stock option
exercises and the employee stock purchase plan.
Based upon existing economic and market conditions, management
believes net operating cash flow and available financing
alternatives will be sufficient to fund net investing and other cash
requirements of EOG for the foreseeable future.
As more fully discussed in Note 11 to the consolidated financial
statements included in EOG's 2002 Annual Report, EOG engages in
price risk management activities from time to time. Derivative
financial instruments (primarily price swaps and collars) are
utilized selectively to hedge the impact of market fluctuations on
natural gas and crude oil prices. During the first nine months of
2003 and 2002, EOG elected not to designate any of its price risk
management activities as accounting hedges, and accordingly,
accounted for them using the mark-to-market accounting method.
Presented below is a summary of EOG's outstanding natural gas
financial collar contracts and natural gas and crude oil financial
price swap contracts as of September 30, 2003 with volumes expressed
in either million British thermal units per day (MMBtud) or barrels
per day (Bbld) and prices in either dollars per million British
thermal unit ($/MMBtu) or dollars per barrel ($/Bbl):
Natural Gas Financial Collar Contracts(1) Financial Price Swap Contracts(1)
Floor Price Ceiling Price Natural Gas Crude Oil
Floor Weighted Ceiling Weighted Net Weighted Weighted
Volume Range Average Range Average Volume Average Volume Average
(MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) (MMBtud) ($/MMBtu) (Bbld) ($/Bbl)
2003(2)
Oct(3) 125,000 $3.60 - 3.90 $3.75 $4.73 - 5.90 $5.27 205,000 $4.70 5,000 $24.90
Nov(3) 255,000 3.77 - 5.07 4.38 4.90 - 6.04 5.42 40,000 4.97 5,000 24.70
Dec 255,000 3.92 - 5.27 4.57 5.05 - 6.18 5.61 40,000 5.19 5,000 24.47
2004
Jan(4) 180,000 $5.06 - 5.39 $5.22 $5.86 - 6.43 $6.18 30,000 $5.57 -- --
Feb(4) 180,000 5.02 - 5.32 5.16 5.82 - 6.37 6.13 30,000 5.50 -- --
Mar(4) 180,000 4.93 - 5.19 5.05 5.73 - 6.27 6.03 30,000 5.37 -- --
Apr 225,000 4.47 - 4.71 4.58 4.93 - 5.30 5.12 30,000 4.89 -- --
May 225,000 4.47 - 4.75 4.57 4.93 - 5.17 5.05 30,000 4.80 -- --
Jun 225,000 4.47 - 4.75 4.57 4.93 - 5.17 5.05 30,000 4.80 -- --
Jul 225,000 4.47 - 4.75 4.57 4.93 - 5.17 5.05 30,000 4.80 -- --
Aug 225,000 4.47 - 4.75 4.58 4.93 - 5.17 5.05 30,000 4.80 -- --
Sep 225,000 4.47 - 4.75 4.57 4.93 - 5.17 5.05 30,000 4.78 -- --
Oct 225,000 4.47 - 4.75 4.58 4.93 - 5.17 5.05 30,000 4.80 -- --
(1) At September 30, 2003, the fair value of the natural gas
financial collar contracts, natural gas financial price swap
contracts, and crude oil financial price swap contracts was $5
million, $3 million and negative $2 million, respectively.
(2) 50,000 MMBtud of each of the 2003 monthly contract volumes were
purchased at a premium of $0.10 per MMBtu.
(3) October 2003 and November 2003 natural gas financial collar
contracts and natural gas financial price swap contracts are
closed. October 2003 crude oil financial price swap contracts
are closed.
(4) The collar contracts for January 2004 to March 2004 were
purchased at a premium of $0.10 per MMBtu.
Subsequent to September 30, 2003, EOG has entered into additional
natural gas financial collar contracts and crude oil financial
price swap contracts. Presented below is a summary of EOG's
outstanding natural gas financial collar contracts and
natural gas and crude oil financial price swap contracts as of
November 6, 2003:
Natural Gas Financial Collar Contracts Financial Price Swap Contracts
Floor Price Ceiling Price Natural Gas Crude Oil
Floor Weighted Ceiling Weighted Net Weighted Weighted
Volume Range Average Range Average Volume Average Volume Average
(MMBtud) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/MMBtu) (MMBtud) ($/MMBtu) (Bbld) ($/Bbl)
2003(1)
Oct(2) 125,000 $3.60 - 3.90 $3.75 $4.73 - 5.90 $5.27 205,000 $4.70 5,000 $24.90
Nov(2) 255,000 3.77 - 5.07 4.38 4.90 - 6.04 5.42 40,000 4.97 5,000 24.70
Dec 255,000 3.92 - 5.27 4.57 5.05 - 6.18 5.61 40,000 5.19 5,000 24.47
2004
Jan(3) 330,000 $5.06 - 5.88 $5.38 $5.86 - 6.69 $6.29 30,000 $5.57 2,000 $29.80
Feb(3) 330,000 5.02 - 5.78 5.31 5.82 - 6.62 6.24 30,000 5.50 2,000 29.37
Mar(3) 330,000 4.93 - 5.53 5.16 5.73 - 6.40 6.10 30,000 5.37 2,000 28.87
Apr 375,000 4.47 - 4.71 4.59 4.93 - 5.30 5.13 30,000 4.89 2,000 28.42
May 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 2,000 28.05
Jun 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 2,000 27.70
Jul 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 1,000 26.86
Aug 375,000 4.47 - 4.75 4.58 4.93 - 5.19 5.09 30,000 4.80 -- --
Sept 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 -- --
(1) 50,000 MMBtud of each of the 2003 monthly contract volumes were
purchased at a premium of $0.10 per MMBtu.
(2) October 2003 and November 2003 natural gas financial collar
contracts and natural gas financial price swap contracts are
closed. October 2003 crude oil financial price swap contracts
are closed.
(3) The collar contracts for January 2004 to March 2004 were
purchased at a premium of $0.10 per MMBtu.
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; 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; political
developments around the world, including terrorist activities and
responses to such activities; acts of war; 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 I. FINANCIAL INFORMATION (Concluded)
ITEM 4. CONTROLS AND PROCEDURES
EOG RESOURCES, INC.
Based on an evaluation of EOG's disclosure controls and procedures
conducted as of September 30, 2003, the Chairman of the Board and
Chief Executive Officer, Mark G. Papa, and the President and Chief
of Staff, and Principal Financial Officer, Edmund P. Segner, III,
have concluded that 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) are effective. There were no
significant changes in EOG's internal controls or in other factors
known to EOG that could significantly affect those controls
subsequent to the date of the evaluation thereof.
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 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 third quarter of 2003, EOG filed the following
Current Reports on Form 8-K:
- On July 1, 2003, to provide updated summaries of natural gas
and crude oil financial price swap and natural gas financial
collar contracts for the last nine months of 2003 and to report
anticipated results of the price risk management activities for
the second quarter of 2003 in Item 9 - Regulation FD Disclosure.
- On July 28, 2003, to report temporary suspension of trading
under registrant's employee benefit plans in Item 7(c) - Exhibits
and Item 11 - Temporary Suspension of Trading Under Registrant's
Employee Benefit Plans.
- On August 5, 2003, to provide estimates for the third quarter
and full year 2003 and updated summaries of natural gas and crude
oil financial price swap and natural gas financial collar contracts
for the second half of 2003 in Item 9 - Regulation FD Disclosure.
- On August 6, 2003 to furnish the press release issued on August
5, 2003 for the second quarter 2003 financial and operational
results in Item 7 - Financial Statements and Exhibits and Item 12 -
Results of Operations and Financial Condition.
- On September 10, 2003, to provide updated summaries of natural
gas and crude oil financial price swap and natural gas financial
collar contracts for 2003 second half and 2004 in Item 9 -
Regulation FD Disclosure.
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: November 6, 2003 By /s/ TIMOTHY K. DRIGGERS
Timothy K. Driggers
Vice President and Chief
Accounting Officer
(Principal Accounting Officer)
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