UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549
FORM 10-Q
(Mark One)
x
For the quarterly period ended March 31, 2008
or
¨
Commission File Number: 1-9743
EOG RESOURCES, INC.
Delaware
47-0684736
(State or other jurisdictionof incorporation or organization)
(I.R.S. Employer Identification No.)
1111 Bagby, Sky Lobby 2, Houston, Texas 77002
713-651-7000(Registrant's telephone number, including area code)
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 o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer xAccelerated filer oNon-accelerated filer oSmaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes oNo x
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.
Title of each class
Number of shares
Common Stock, par value $0.01 per share
248,307,218 (as of April 30, 2008)
TABLE OF CONTENTS
PART I.
FINANCIAL INFORMATION
Page No.
ITEM 1.
Financial Statements (Unaudited)
3
4
5
6
ITEM 2.
17
ITEM 3.
26
ITEM 4.
PART II.
OTHER INFORMATION
27
ITEM 6.
28
29
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTSEOG RESOURCES, INC.CONSOLIDATED STATEMENTS OF INCOME(In Thousands, Except Per Share Data)(Unaudited)
Three Months Ended
March 31,
2008
2007
Net Operating Revenues
Natural Gas
$
1,037,638
730,461
Crude Oil, Condensate and Natural Gas Liquids
394,848
174,864
Losses on Mark-to-Market Commodity Derivative Contracts
(469,844)
(39,801)
Other, Net
138,331
5,713
Total
1,100,973
871,237
Operating Expenses
Lease and Well
132,466
104,325
Transportation Costs
61,967
32,567
Exploration Costs
47,943
26,384
Dry Hole Costs
8,428
16,810
Impairments
32,574
24,042
Depreciation, Depletion and Amortization
297,199
244,342
General and Administrative
52,926
43,879
Taxes Other Than Income
86,750
40,648
720,253
532,997
Operating Income
380,720
338,240
Other Income, Net
1,583
4,719
Income Before Interest Expense and Income Taxes
382,303
342,959
Interest Expense, Net
12,191
7,638
Income Before Income Taxes
370,112
335,321
Income Tax Provision
129,156
117,654
Net Income
240,956
217,667
Preferred Stock Dividends
443
875
Net Income Available to Common Stockholders
240,513
216,792
Net Income Per Share Available to Common Stockholders
Basic
0.98
0.89
Diluted
0.96
0.88
Average Number of Common Shares
245,430
242,763
249,763
246,677
The accompanying notes are an integral part of these consolidated financial statements.
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EOG RESOURCES, INC.CONSOLIDATED BALANCE SHEETS(In Thousands, Except Share Data)(Unaudited)
December 31,
ASSETS
Current Assets
Cash and Cash Equivalents
204,938
54,231
Accounts Receivable, Net
1,010,020
835,670
Inventories
98,565
102,322
Assets from Price Risk Management Activities
-
100,912
Income Taxes Receivable
132,997
110,370
Deferred Income Taxes
191,072
33,533
Other
52,654
55,001
1,690,246
1,292,039
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)
17,864,994
16,981,836
Other Property, Plant and Equipment
668,208
581,402
18,533,202
17,563,238
Less: Accumulated Depreciation, Depletion and Amortization
(7,388,651)
(7,133,984)
Total Property, Plant and Equipment, Net
11,144,551
10,429,254
Long-Term Assets Held for Sale
254,376
Other Assets
115,762
113,238
Total Assets
12,950,559
12,088,907
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable
1,208,751
1,152,140
Accrued Taxes Payable
105,140
104,647
Dividends Payable
29,482
22,045
Liabilities from Price Risk Management Activities
308,504
3,404
19,545
108,980
53,496
82,954
1,724,918
1,474,170
Long-Term Debt
1,185,000
Other Liabilities
462,873
368,336
2,387,247
2,071,307
Stockholders' Equity
Preferred Stock, $0.01 Par, 10,000,000 Shares Authorized:
Series B, Cumulative, $1,000 Liquidation Preference per Share,
5,000 Shares Outstanding at December 31, 2007
4,977
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and
249,460,000 Shares Issued
202,495
Additional Paid in Capital
263,094
221,102
Accumulated Other Comprehensive Income
388,848
466,702
Retained Earnings
6,367,524
6,156,721
Common Stock Held in Treasury, 1,375,631 Shares at
March 31, 2008 and 2,935,313 Shares at December 31, 2007
(31,440)
(61,903)
Total Stockholders' Equity
7,190,521
6,990,094
Total Liabilities and Stockholders' Equity
-4-
EOG RESOURCES, INC.CONSOLIDATED STATEMENTS OF CASH FLOWS(In Thousands)(Unaudited)
Cash Flows From Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Items Not Requiring (Providing) Cash
Stock-Based Compensation Expenses
19,783
14,211
83,390
96,999
(127,968)
(2,958)
Mark-to-Market Commodity Derivative Contracts
Total Losses
469,844
39,801
Realized Gains
23,210
47,268
8,599
11,482
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable
(177,684)
22,935
3,285
(8,844)
93,452
23,431
(29,265)
1,967
(1,745)
(3,623)
(27,673)
(14,356)
Changes in Components of Working Capital Associated with
Investing and Financing Activities
5,192
(32,694)
Net Cash Provided by Operating Activities
921,577
698,480
Investing Cash Flows
Additions to Oil and Gas Properties
(1,060,035)
(812,243)
Additions to Other Property, Plant and Equipment
(87,589)
(80,287)
Proceeds from Sales of Assets
346,891
2,939
Investing Activities
(4,750)
32,959
(1,235)
(1,579)
Net Cash Used in Investing Activities
(806,718)
(858,211)
Financing Cash Flows
Net Commercial Paper and Revolving Credit Facility Borrowings
116,600
Long-Term Debt Repayments
(30,000)
Dividends Paid
(22,089)
(15,522)
Redemption of Preferred Stock
(5,395)
Excess Tax Benefits from Stock-Based Compensation
35,496
7,409
Proceeds from Stock Options Exercised
29,537
5,276
(442)
(265)
Net Cash Provided by Financing Activities
37,107
83,498
Effect of Exchange Rate Changes on Cash
(1,259)
(322)
Increase (Decrease) in Cash and Cash Equivalents
150,707
(76,555)
Cash and Cash Equivalents at Beginning of Period
218,255
Cash and Cash Equivalents at End of Period
141,700
The accompanying notes are an integral part of these consolidated financial statements
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EOG RESOURCES, INC.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Unaudited)
1.Summary of Significant Accounting Policies
General. The consolidated financial statements of EOG Resources, Inc., together with its subsidiaries (EOG), included herein have been prepared by management without audit pursuant to the rules and regulations of the Securities and Exchange Commission. 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 presented. Certain information and notes normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) have been condensed or omitted pursuant to such rules and regulations. However, management believes that the disclosures included in either on the face of the financial statements or in these notes are sufficient to make the interim information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated fina ncial statements and the notes thereto included in EOG's Annual Report on Form 10-K for the year ended December 31, 2007 (EOG's 2007 Annual Report).
The preparation of financial statements in conformity with U.S. GAAP 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. The operating results for the three months ended March 31, 2008 are not necessarily indicative of the results to be expected for the full year.
Certain reclassifications have been made to prior period financial statements to conform with the current presentation.
Derivative Instruments. As more fully discussed in Note 11 to Consolidated Financial Statements included in EOG's 2007 Annual Report, EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for natural gas and crude oil. EOG utilizes financial commodity derivative instruments, primarily collar and price swap contracts, as a means to manage this price risk. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. In addition to 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 physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.
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Recently Issued Accounting Standards and Developments. In March 2008, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 161, "Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133" (SFAS No. 161). SFAS No. 161 does not change the scope or accounting of SFAS No. 133, but expands disclosure requirements about an entity's derivative instruments and hedging activities. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. Early adoption is permitted and comparative disclosures for earlier periods are encouraged. The adoption of SFAS No. 161 is not expected to have a material impact on EOG's financial statements, but will result in additional disclosures related to derivative instruments and hedging activities.
In September 2006, the FASB issued SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R)." The requirement to measure plan assets and benefit obligations as of the date of the employer's fiscal year-end is effective for fiscal years ending after December 15, 2008, and will not have an impact on EOG's financial statements since plan assets and benefit obligations are currently measured as of the date of EOG's fiscal year-end.
In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" (SFAS No. 157). SFAS No. 157 provides a definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The standard also requires additional disclosures on the use of fair value in measuring assets and liabilities. SFAS No. 157 establishes a fair value hierarchy and requires disclosure of fair value measurements within that hierarchy. In February 2008, the FASB issued a Staff Position on SFAS No. 157, FASB Staff Position No. FAS 157-2, "Effective Date of FASB Statement No. 157" (FSP 157-2). FSP 157-2 delays the effective date of SFAS No. 157 for all nonrecurring fair value measurements of nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008, except as provided by FSP 157-2. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within those years. FS P 157-2 requires an entity that does not adopt SFAS No. 157 in its entirety to disclose, at each reporting date until fully adopted, that it has only partially adopted SFAS No. 157 and the categories of assets and liabilities recorded or disclosed at fair value to which SFAS No. 157 has not been applied. EOG partially adopted SFAS No. 157 effective January 1, 2008. See Note 12.
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2. Stock-Based Compensation
At March 31, 2008, EOG maintained various stock-based compensation plans as discussed below. Stock-based compensation expense is included in the Consolidated Statements of Income based upon job functions of the employees receiving the grants as follows (in millions):
4.4
3.0
4.0
11.4
8.2
19.8
14.2
EOG has various stock plans (Plans) under which employees and non-employee members of EOG's Board of Directors (Board) have been or may be granted certain equity compensation. At March 31, 2008, approximately 0.9 million shares of common stock remained available for grant under the Plans. EOG's policy is to issue shares related to the Plans from treasury stock or from previously authorized unissued shares. At March 31, 2008, EOG held 1.4 million shares of treasury stock.
Stock Options and Stock Appreciation Rights and Employee Stock Purchase Plan. Under the Plans, participants have been or may be granted options to purchase shares of common stock of EOG. In addition, participants have been or may be granted stock-settled stock appreciation rights (SARs), representing the right to receive shares of EOG common stock based on the appreciation in the stock price from the date of grant on the number of SARs granted. Stock options and SARs are granted at a price not less than the market price of the common stock at the date of grant. Stock options and SARs granted under the Plans vest on a graded vesting schedule up to four years from the date of grant based on the nature of the grants and as defined in individual grant agreements. Terms for stock options and SARs granted under the Plans have not exceeded a maximum term of 10 years. EOG has an employee stock purchase plan (ESPP) in place that allows eligible employees to semi-annua lly purchase, through payroll deductions, shares of EOG common stock at 85 percent of the fair market value at specified dates. Contributions to the ESPP are limited to 10 percent of the employee's pay (subject to certain ESPP limits) during each of the two six-month offering periods each year. The fair value of all grants made prior to August 2004 and all ESPP grants is estimated using the Black-Scholes-Merton model. Certain of EOG's stock options granted in 2005 and 2004 contain a feature that limits the potential gain that can be realized by requiring vested options to be exercised if the market price of EOG's common stock reaches 200% of the grant price for five consecutive trading days (Capped Option). EOG may or may not issue Capped Options in the future. The fair value of each Capped Option grant was estimated using a Monte Carlo simulation. Effective May 2005, the fair value of stock option grants not containing the Capped Option feature and SARs was estimated using the Hull-White II binomial o ption pricing model. Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $8.9 million and $8.5 million during the three months ended March 31, 2008 and 2007, respectively.
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Weighted average fair values and valuation assumptions used to value stock options, SARs and ESPP grants during the three-month periods ended March 31, 2008 and 2007 are as follows:
Stock Options/SARs
ESPP
Weighted Average Fair Value of Grants
24.13
21.16
21.86
15.07
Expected Volatility
31.84%
30.97%
31.67%
32.47%
Risk-Free Interest Rate
2.81%
4.93%
3.29%
5.07%
Dividend Yield
0.4%
0.3%
Expected Life
3.6 yrs.
4.8 yrs.
0.5 yrs.
Expected volatility is based on an equal weighting of historical volatility and implied volatility from traded options in EOG's stock. The risk-free interest rate is based upon United States Treasury yields in effect at the time of grant. The expected life is based upon historical experience and contractual terms of stock option, SAR and ESPP grants.
The following table sets forth stock option and SARs transactions for the three-month periods ended March 31, 2008 and 2007 (stock options and SARs in thousands):
March 31, 2008
March 31, 2007
Weighted
Number of
Average
Stock
Grant
Options/SARs
Price
Options/ SARs
Outstanding at January 1
9,373
41.04
10,150
35.29
Granted
22
99.68
72
65.69
Exercised (1)
(1,341)
(273)
19.36
Forfeited
(45)
60.90
(47)
51.37
Outstanding at March 31 (2)
8,009
43.92
9,902
35.87
Vested or Expected to Vest (3)
7,771
43.32
9,378
35.75
Exercisable at March 31 (4)
4,319
28.50
5,135
21.39
(1) The total intrinsic value of stock options/SARs exercised for the three-month periods ended March 31, 2008 and 2007 was $113.7 million and $13.4 million, respectively. The intrinsic value is based upon the difference between the market price of EOG's common stock on the date of exercise and the grant price of the stock options/SARs.(2) The total intrinsic value of stock options/SARs outstanding at March 31, 2008 and 2007 was $609.3 million and $351.7 million, respectively. At March 31, 2008 and 2007, the weighted average remaining contractual life was 4.9 years and 5.5 years, respectively.(3) The total intrinsic value of stock options/SARs vested or expected to vest at March 31, 2008 and 2007 was $595.9 million and $334.2 million, respectively. At March 31, 2008 and 2007, the weighted average remaining contractual life was 4.9 years and 5.5 years, respectively.(4) The total intrinsic value of stock options/SARs exercisable at March 31, 2008 and 2007 was $395.2 million and $256.6 million, respectively. At March 31, 2008 and 2007, the weighted average remaining contractual life was 4.2 years and 4.7 years, respectively.
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At March 31, 2008, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $64.9 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.0 years.
Restricted Stock and Restricted Stock Units. Under the Plans, employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them. The restricted stock and restricted stock units generally vest five years after the date of grant, except for certain bonus grants, and as defined in individual grant agreements. Upon vesting, restricted stock is released to the employee and restricted stock units are converted into common stock and released to the employee. Stock-based compensation expense related to restricted stock and restricted stock units totaled $10.9 million and $5.7 million for the three months ended March 31, 2008 and 2007, respectively.
The following table sets forth the restricted stock and restricted stock units transactions for the three-month periods ended March 31, 2008 and 2007 (shares and units in thousands):
Shares and
Grant Date
Units
Fair Value
3,000
50.61
2,301
36.13
203
120.01
496
67.66
Released (1)
(161)
20.77
(245)
18.36
(21)
67.85
(24)
51.84
3,021
56.73
2,528
43.87
(1) The total intrinsic value of restricted stock and restricted stock units released for the three-month periods ended March 31, 2008 and 2007 was $16.1 million and $15.9 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released. (2) The aggregate intrinsic value of restricted stock and restricted stock units outstanding at March 31, 2008 was approximately $362.5 million.
At March 31, 2008, unrecognized compensation expense related to restricted stock and restricted stock units totaled $115.0 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 3.2 years.
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3. Earnings Per Share
The following table sets forth the computation of Net Income Per Share Available to Common Stockholders for the three-month periods ended March 31, 2008 and 2007 (in thousands, except per share data):
Numerator for Basic and Diluted Earnings Per Share -
Less: Preferred Stock Dividends
Denominator for Basic Earnings Per Share -
Weighted Average Shares
Potential Dilutive Common Share -
3,077
2,949
Restricted Stock and Units
1,256
965
Denominator for Diluted Earnings Per Share -
Adjusted Weighted Average Shares
The diluted earnings per share calculation excluded 1,550 and 3.6 million stock options and SARs that were anti-dilutive for the three months ended March 31, 2008 and 2007, respectively.
4. Supplemental Cash Flow Information
Cash paid for interest and income taxes for the three-month periods ended March 31, 2008 and 2007 was as follows (in thousands):
Interest
17,479
2,328
Income Taxes
36,843
910
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5. Comprehensive Income
The following table presents the components of EOG's comprehensive income for the three-month periods ended March 31, 2008 and 2007 (in thousands):
Comprehensive Income
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustment
(77,090)
16,352
Foreign Currency Swap Transaction
(974)
2,150
Income Tax Provision Related to Foreign
Currency Swap Transaction
239
(615)
Defined Benefit Pension and Postretirement Plans
35
37
Income Tax Provision Related to Defined Benefit
Pension and Postretirement Plans
(64)
163,102
235,591
6. Segment Information
Selected financial information by reportable segment is presented below for the three-month periods ended March 31, 2008 and 2007 (in thousands):
United States
805,002
625,183
Canada
170,454
143,467
Trinidad
109,884
87,108
United Kingdom
15,633
15,479
Operating Income (Loss)
230,558
212,949
59,788
58,797
88,390
63,590
8,178
2,966
(6,194)
(62)
Reconciling Items
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Total assets by reportable segment are presented below at March 31, 2008 and December 31, 2007 (in thousands):
At
9,392,763
8,687,320
2,688,896
2,649,925
778,457
692,353
89,078
58,255
1,365
1,054
7. Asset Retirement Obligations
The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of oil and gas properties pursuant to SFAS No. 143, "Accounting for Asset Retirement Obligations," for the three-month periods ended March 31, 2008 and 2007 (in thousands):
Carrying Amount at Beginning of Period
211,124
182,406
Liabilities Incurred
10,224
7,549
Liabilities Settled
(11,460)
(929)
Accretion
2,933
2,663
Revisions
3,693
(126)
Foreign Currency Translations
(1,946)
(859)
Carrying Amount at End of Period
214,568
190,704
Current Portion
2,306
8,602
Noncurrent Portion
212,262
182,102
The current and noncurrent portions of EOG's asset retirement obligations are included in Current Liabilities - Other and Other Liabilities, respectively, on the Consolidated Balance Sheets.
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8. Suspended Well Costs
EOG's net changes in suspended well costs for the three-month period ended March 31, 2008 in accordance with FASB Staff Position No. 19-1, "Accounting for Suspended Well Costs," are presented below (in thousands):
Three Months
Ended
Balance at December 31, 2007
148,881
Additions Pending the Determination of Proved Reserves
58,262
Reclassifications to Proved Properties
(63,465)
Charged to Dry Hole Costs
(4,971)
(2,352)
Balance at March 31, 2008
136,355
The following table provides an aging of suspended well costs at March 31, 2008 (in thousands, except project count):
Capitalized exploratory well costs that have been
capitalized for a period less than one year
76,078
capitalized for a period greater than one year
60,277
(1)
Number of projects that have exploratory well costs that have been
(1) Costs related to two shale projects in British Columbia (B.C.), Canada ($46.7 million) and an outside operated, offshore Central North Sea project in the United Kingdom ($13.6 million). In the B.C. projects, drilling activity is continuing and further reserve evaluation will be made based on initial production anticipated during the second half of 2008. EOG is evaluating infrastructure alternatives for the B.C. shale projects. In the Central North Sea project, EOG is considering alternative export routes in parallel with discussions with adjacent block owners concerning additional appraisal drilling to extend the boundary of this prospect to the south. A development plan decision is expected in early 2009.
9. Commitments and Contingencies
There are currently various suits and claims pending against EOG that have arisen in the ordinary course of EOG's business, including contract disputes, personal injury and property damage claims and title disputes. While the ultimate outcome and impact on EOG cannot be predicted with certainty, management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material adverse effect on EOG's consolidated financial position, results of operations or cash flow. In accordance with SFAS No. 5, "Accounting for Contingencies," EOG records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.
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10. Pension and Postretirement Benefits
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. For the three months ended March 31, 2008 and 2007, EOG's total costs recognized for these pension plans were $5.1 million and $4.2 million, respectively.
In addition, as more fully discussed in Note 6 to Consolidated Financial Statements included in EOG's 2007 Annual Report, EOG's Canadian, Trinidadian and United Kingdom subsidiaries maintain various pension and savings plans for most of their respective employees. For the three months ended March 31, 2008 and 2007, combined contributions to these plans were $0.6 million and $0.5 million, respectively.
Postretirement Plan. EOG has postretirement medical and dental benefits in place for eligible United States and Trinidad employees and their eligible dependents. For the three months ended March 31, 2008, EOG's total contributions to these plans were approximately $36,000. The net periodic benefit costs recognized for the postretirement medical and dental plans were approximately $186,500 and $179,000, respectively, for the three months ended March 31, 2008 and 2007.
11. Long-Term Debt, Preferred Stock and Common Stock
Long-Term Debt. EOG utilizes commercial paper and short-term borrowings from uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes. EOG had no outstanding borrowings from commercial paper or uncommitted credit facilities at March 31, 2008. The weighted average interest rates for commercial paper and uncommitted credit facility borrowings for the three months ended March 31, 2008 were 3.76% and 3.85%, respectively.
EOG currently has a $1.0 billion unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders. The Agreement matures on June 28, 2012. At March 31, 2008, there were no borrowings or letters of credit outstanding under the Agreement. Advances under the Agreement accrue interest based, at EOG's option, on either the London InterBank Offering Rate plus an applicable margin (Eurodollar rate) or the base rate of the Agreement's administrative agent. At March 31, 2008, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 2.89% and 5.25%, respectively.
In May 2006, EOG Resources Trinidad Limited, a wholly owned foreign subsidiary of EOG, entered into a 3-year, $75 million Revolving Credit Agreement (Credit Agreement). Borrowings under the Credit Agreement accrue interest based, at EOG's option, on either the Eurodollar rate or the base rate of the Credit Agreement's administrative agent. At March 31, 2008, EOG had $75 million outstanding under the Credit Agreement. The applicable Eurodollar rate at March 31, 2008 was 3.65%. The weighted average Eurodollar rate for the amounts outstanding during the first three months of 2008 was 4.24%.
Preferred Stock. In January 2008, EOG repurchased the remaining outstanding 5,000 shares of its 7.195% Fixed Rate Cumulative Senior Perpetual Preferred Stock, Series B, with a $1,000 liquidation preference per share (Series B), for approximately $5.4 million plus accrued dividends up to the date of repurchase. The premium of $0.4 million associated with the repurchase has been included as a component of preferred stock dividends. In March 2008, the Board approved the filing with the Delaware Secretary of State of a Certificate of Elimination with respect to the Series B. The Certificate of Elimination provides that all matters set forth in the Certificate of Designation, Preferences and Rights, filed on July 19, 2000 with the Delaware Secretary of State with respect to the Series B, are eliminated from EOG's Restated Certificate of Incorporation.
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Common Stock. On February 7, 2008, the Board increased the quarterly cash dividend on EOG's common stock from the previous $0.09 per share to $0.12 per share effective with the dividend paid on April 30, 2008 to record holders as of April 16, 2008.
12. Fair Value Measurements
Certain of EOG's financial and non-financial assets and liabilities are reported at fair value in the accompanying balance sheets. Effective January 1, 2008, EOG adopted the provisions of SFAS No. 157 for its financial assets and liabilities. SFAS No. 157 defines fair value, establishes a hierarchy for measuring fair value and expands disclosures about fair value measurements. To increase consistency and comparability in fair value measurements and related disclosures, SFAS No. 157 establishes a fair value hierarchy that prioritizes the relative reliability of inputs used in fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy. The following table provides fair value measurement information within the hierarchy for EOG's financial assets and liabilities at March 31, 2008. In accordance with FSP 157, EOG has not applied the provisions of SFAS No. 157 to its asset retirement obligations or in the measurement of nonfinancial long-lived assets under SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets."
At March 31, 2008
Fair Value Measurements Using:
Quoted
Significant
Prices in
Active
Observable
Unobservable
Markets
Inputs
(Level 1)
(Level 2)
(Level 3)
(In millions)
Financial Assets (Liabilities):
Crude oil and natural gas price swaps
(393)
Foreign currency rate swap
(51)
The estimated fair value of crude oil and natural gas price swap contracts was based upon forward commodity price curves based on quoted market prices. The estimated fair value of the foreign currency rate swap was based upon forward currency rates.
13. Sale of Appalachian Properties
In February 2008, EOG completed a sale of the majority of its producing shallow gas assets and surrounding acreage in the Appalachian Basin to a subsidiary of EXCO Resources, Inc., an independent oil and gas company. The Appalachian area divested included approximately 2,400 operated wells that accounted for approximately 1% of EOG's total 2007 production and approximately 2% of its total year-end 2007 proved reserves. Net proceeds from the sale, including a $40 million deposit received in December 2007, totaled $386 million. The purchase price is subject to customary adjustments under the agreement. EOG retained certain of its undeveloped acreage in this area, including rights in the Marcellus Shale, and will continue its shale exploration program. EOG recognized a pre-tax gain of $130 million on the sale of these properties in the first quarter of 2008 that is included in Net Operating Revenues - Other, Net on the Consolidated Statements of Income.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OFFINANCIAL CONDITION AND RESULTS OF OPERATIONSEOG RESOURCES, INC.
Overview
EOG Resources, Inc., together with its subsidiaries (EOG), is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Canada, offshore Trinidad and the United Kingdom North Sea. EOG operates under a consistent business and operational strategy that focuses predominantly on achieving a strong reinvestment rate of return, drilling internally generated prospects, delivering long-term production growth and maintaining a strong balance sheet.
Operations. 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 continues to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's natural gas and crude oil production. Production in the United States and Canada accounted for approximately 86% of total company production in the first three months of 2008 as compared to 81% in the same period of 2007. First quarter 2008 crude oil and natural gas liquids production accounted for approximately 17% of total company production as compared to 14% for the same period of 2007. Based on current trends, EOG expects its production profile for the remainder of 2008 to be similar to the first quarter. EOG's major producing areas are in Louisiana, New Mexico, Texas, Utah, Wyoming and western Canada.
In February 2008, EOG completed a sale of the majority of its producing shallow gas assets and surrounding acreage in the Appalachian Basin to a subsidiary of EXCO Resources, Inc., an independent crude oil and natural gas company. Net proceeds from the sale, including a $40 million deposit received in December 2007, totaled $386 million. The purchase price is subject to customary adjustments under the agreement. EOG retained certain of its undeveloped acreage in this area, including rights in the Marcellus Shale, and will continue its shale exploration program. EOG recognized a pre-tax gain of $130 million on the sale of these properties in the first quarter of 2008 that is included in Net Operating Revenues - Other, Net on the Consolidated Statements of Income.
In the first quarter of 2008, EOG's Trinidad operation realized higher prices for natural gas sales as compared to the first quarter of 2007. This increase was due to higher ammonia, methanol and liquefied natural gas prices.
In the first quarter of 2008, EOG purchased an 80% interest in the Pelican field facilities from the subsidiaries of the other participants in the South East Coast Consortium Block. Also, in the first quarter of 2008, EOG finalized a crude oil and condensate sales contract with the Petroleum Company of Trinidad and Tobago. The pricing terms are based on the valuation of the distillation yield of the crude oil and condensate produced less a refining margin.
In addition to EOG's ongoing production from the Valkyrie and Arthur Fields in the United Kingdom North Sea, EOG is evaluating development plans for its Columbus prospect in the Central North Sea Block 23/16f. Alternative export routes are being considered in parallel with discussions with adjacent block owners concerning additional appraisal drilling to extend the boundary of this prospect to the south. A development plan decision is expected in early 2009.
EOG continues to evaluate other select natural gas and crude oil opportunities outside the United States and Canada primarily by pursuing exploitation opportunities in countries where indigenous natural gas and crude oil reserves have been identified.
Capital Structure. One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 14% at both March 31, 2008 and December 31, 2007. During the first quarter of 2008, EOG funded $1.2 billion in exploration and development and other property, plant and equipment expenditures, paid $22 million in dividends to common and preferred stockholders and paid $5 million for the redemption of all remaining shares of its outstanding 7.195% Fixed Rate Cumulative Perpetual Senior Preferred Stock by utilizing cash provided from its operating activities and proceeds from the sale of its Appalachian properties. Cash on hand increased to $205 million at March 31, 2008 from $54 million at December 31, 2007. Management continues to assess price
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forecast and demand trends for 2008 and believes that operations and capital expenditure activity can be funded with cash from operating activities.
EOG's 2008 budget for exploration and development and other property, plant and equipment expenditures is approximately $4.4 billion, excluding acquisitions. United States and Canada natural gas drilling activity continues to be a key component of these expenditures. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer EOG incremental exploration and/or production opportunities. Management continues to believe that EOG currently has one of the strongest prospect inventories in EOG's history.
Results of Operations
The following review of operations for the three-month periods ended March 31, 2008 and 2007 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included with this Quarterly Report on Form 10-Q.
Net Operating Revenues. During the first quarter of 2008, net operating revenues increased $230 million to $1,101 million from $871 million for the same period of 2007. Total wellhead revenues for the first quarter of 2008, which are revenues generated from sales of natural gas, crude oil, condensate and natural gas liquids, increased $527 million, or 58%, to $1,432 million as compared to $905 million for the first quarter of 2007.
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Wellhead volume and price statistics for the three-month periods ended March 31, 2008 and 2007 were as follows:
Natural Gas Volumes (MMcfd) (1)
1,085
915
216
222
231
253
30
1,549
1,420
Average Natural Gas Prices ($/Mcf) (2)
8.05
6.35
7.44
6.43
3.87
2.81
9.85
5.55
Composite
7.36
5.71
Crude Oil and Condensate Volumes (MBbld) (1)
30.6
21.9
2.4
2.5
3.6
4.3
0.1
36.7
28.8
Average Crude Oil and Condensate Prices ($/Bbl) (2)
92.08
53.76
88.94
51.76
87.90
59.91
88.29
52.87
91.46
54.51
Natural Gas Liquids Volumes (MBbld) (1)
16.7
9.5
1.0
1.1
17.7
10.6
Average Natural Gas Liquids Prices ($/Bbl) (2)
57.26
37.07
57.14
36.37
37.00
Natural Gas Equivalent Volumes (MMcfed) (3)
1,370
1,104
236
243
252
279
31
1,875
1,657
Total Bcfe (3) Deliveries
170.6
149.1
(1) Million cubic feet per day or thousand barrels per day, as applicable.(2) Dollars per thousand cubic feet or per barrel, as applicable. (3) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil, condensate and natural gas liquids. Natural gas equivalents are determined using the ratio of 6.0 thousand cubic feet of natural gas to 1.0 barrel of crude oil, condensate or natural gas liquids.
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Wellhead natural gas revenues for the first three months of 2008 increased $307 million, or 42%, to $1,038 million from $731 million for the same period of 2007. The increase was due to a higher composite average wellhead natural gas price ($232 million) and increased natural gas deliveries ($75 million). The composite average wellhead price for natural gas increased 29% to $7.36 per Mcf for the first three months of 2008 from $5.71 per Mcf for the same period of 2007.
Natural gas deliveries increased 129 MMcfd, or 9%, to 1,549 MMcfd for the first three months of 2008 from 1,420 MMcfd for the same period of 2007. The increase was mainly due to higher production in the United States (170 MMcfd), partially offset by decreased production in Trinidad (22 MMcfd), the United Kingdom (13 MMcfd) and Canada (6 MMcfd). The increase in the United States was attributable to increased production in Texas (132 MMcfd), the Rocky Mountain area (21 MMcfd) and Mississippi (17 MMcfd). The decline in Trinidad was due to a decrease in overall contractual demand (32 MMcfd), partially offset by an increase in deliveries to Atlantic LNG Train 4 (ALNG) (10 MMcfd). During the first quarter of 2007, ALNG was in the start-up phase but did not require any gas from EOG until May 2007 when ALNG reached commercial status and EOG began supplying gas under the ALNG take-or-pay contract. The decrease in the United Kingdom was due to production declines in both the Arthur and Valk yrie fields.
Wellhead crude oil and condensate revenues for the first three months of 2008 increased $163 million, or 117%, to $303 million from $140 million for the same period of 2007. The increase was due to a higher composite average wellhead crude oil and condensate price ($122 million) and increased wellhead crude oil and condensate deliveries ($41 million). The composite average wellhead crude oil and condensate price increased 68% to $91.46 per barrel for the first three months of 2008 from $54.51 per barrel for the same period of 2007. The increase in deliveries primarily reflects increased production in North Dakota.
Natural gas liquids revenues for the first three months of 2008 increased $57 million, or 161%, to $92 million from $35 million for the same period of 2007. The increase was due to increases in the composite average price ($33 million) and deliveries ($24 million). The increase in deliveries primarily reflects increased production in the Fort Worth area.
During the first quarter of 2008, as a result of rising commodity prices, EOG recognized a loss on mark-to-market financial commodity derivative contracts of $470 million compared to a loss of $40 million for the same period of 2007. During the first quarter of 2008, the net cash inflow related to settled natural gas and crude oil financial price swap contracts was $23 million compared to the net cash inflow of $47 million for the same period of 2007. See "Capital Resources and Liquidity - Commodity Derivative Transactions."
Operating and Other Expenses. For the first quarter of 2008, operating expenses of $720 million were $187 million higher than the $533 million incurred during the first quarter of 2007. The following table presents the costs per thousand cubic feet equivalent (Mcfe) for the three-month periods ended March 31, 2008 and 2007:
0.78
0.70
0.36
0.22
Depreciation, Depletion and Amortization (DD&A)
1.74
1.64
General and Administrative (G&A)
0.31
0.30
0.07
0.05
Total Per-Unit Costs (1)
3.26
2.91
(1) Total per-unit costs do not include exploration costs, dry hole costs, impairments and taxes other than income.
The primary factors impacting per-unit rates of lease and well, transportation costs, DD&A, G&A and interest expense, net for the three months ended March 31, 2008 compared to the same period of 2007 are set forth below.
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Lease and well expenses include expenses for EOG-operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property. Lease and well expenses can be divided into the following categories: costs to operate and maintain EOG's crude oil and natural gas wells, the cost of workovers and lease and well administrative expenses. Operating and maintenance expenses include, among other things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. Workovers are costs of operations to restore or maintain production from existing wells.
Each of these categories of costs individually fluctuates from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.
Lease and well expenses of $132 million for the first quarter of 2008 increased $28 million from $104 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($17 million), higher lease and well administrative expenses ($6 million) and changes in the Canadian exchange rate ($4 million).
Transportation costs represent costs incurred directly by EOG from third-party carriers associated with the delivery of hydrocarbon products from the lease to a downstream point of sale. Transportation costs include the cost of compression (the cost of compressing natural gas to meet pipeline pressure requirements), dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees, fuel costs and transportation fees.
Transportation costs of $62 million for the first quarter of 2008 increased $29 million from $33 million for the same prior year period primarily due to increased production and related costs associated with new marketing arrangements to transport additional production from the Fort Worth Basin Barnett Shale play ($16 million) and the Rocky Mountain area ($8 million) to new downstream markets.
DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or acquisition of new wells, disposition of existing wells, reserve revisions (upward or downward) primarily related to well performance, and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from quarter to quarter.
DD&A expenses of $297 million for the first quarter of 2008 increased $53 million from the same prior year period primarily due to increased production in the United States ($48 million) and changes in the Canadian exchange rates ($7 million), partially offset by decreased production in the United Kingdom ($3 million).
G&A expenses of $53 million for the first quarter of 2008 increased $9 million from the same prior year period primarily due to higher employee related costs ($7 million) and an increase in legal and other professional services ($3 million).
Interest expense, net of $12 million for the first quarter of 2008 increased $4 million compared to the same prior year period primarily due to a higher average debt balance ($8 million), partially offset by higher capitalized interest ($3 million).
Exploration costs of $48 million for the first quarter of 2008 increased $22 million from $26 million for the same prior year period primarily due to increased geological and geophysical expenditures in the United States ($16 million) and Canada ($4 million). The increase in the United States was primarily attributable to the Fort Worth Basin Barnett Shale play ($13 million).
Impairments include amortization of unproved leases, as well as impairments under SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," (SFAS No. 144) which requires an entity to compute impairments to the carrying value of long-lived assets based on future cash flow analysis. Impairments of $33 million for the first quarter of 2008 were $9 million higher than the same prior year period primarily due to increased
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amortization of unproved leases in the United States ($6 million) and Canada ($3 million). Under SFAS No. 144, EOG recorded impairments of $9 million and $10 million for the first quarter of 2008 and 2007, respectively.
Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are determined based on wellhead revenues and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.
Taxes other than income for the first quarter of 2008 increased $46 million to $87 million (6.1% of wellhead revenues) from $41 million (4.5% of wellhead revenues) for the same prior year period. The increase in taxes other than income was a result of increases in both the United States and Trinidad. Severance/production taxes in the United States increased primarily due to an increase in wellhead revenues ($23 million), a decrease in credits taken for Texas high cost gas severance tax rate reductions ($15 million), and an increase in ad valorem/property taxes ($2 million). Severance/production taxes in Trinidad increased as a result of higher wellhead revenues ($2 million).
Other income, net was $2 million for the first quarter of 2008 compared to $5 million for the same prior year period. The decrease of $3 million was primarily due to increased foreign currency transaction losses ($2 million) and lower equity income from investment in Carribean Nitrogen Company Limited ammonia plant ($1 million).
Income tax provision of $129 million for the first quarter of 2008 increased $12 million compared to the same prior year period primarily due to higher pretax income. The net effective tax rate for the first quarter of 2008 remained unchanged from the 2007 rate of 35%.
Capital Resources and Liquidity
Cash Flow. The primary sources of cash for EOG during the three months ended March 31, 2008 were funds generated from operations, proceeds from the sale of its producing shallow gas assets and surrounding acreage in the Appalachian Basin, proceeds from stock options exercised and excess tax benefits from stock-based compensation. The primary uses of cash were funds used in operations; exploration and development expenditures; other property, plant and equipment expenditures; and dividend payments to stockholders. During the first three months of 2008, EOG's cash balance increased $151 million to $205 million from $54 million at December 31, 2007.
Net cash provided by operating activities of $922 million for the first three months of 2008 increased $223 million compared to the same period of 2007 primarily reflecting an increase in wellhead revenues ($527 million), partially offset by an increase in cash operating expenses ($124 million), unfavorable changes in working capital and other assets and liabilities ($92 million), an increase in cash paid for income taxes ($36 million), a decrease in the net cash inflows from the settlement of financial commodity derivative contracts ($24 million) and an increase in cash paid for interest expense ($15 million).
Net cash used in investing activities of $807 million for the first three months of 2008 decreased by $51 million compared to the same period of 2007 due primarily to an increase in proceeds from sales of assets ($344 million), primarily reflecting net proceeds from the sale of EOG's Appalachian assets, partially offset by an increase in additions to oil and gas properties ($248 million).
Net cash provided by financing activities was $37 million for the first three months of 2008 compared to $83 million for the same period of 2007. Cash provided by financing activities for the first three months of 2008 included excess tax benefits from stock-based compensation ($35 million) and proceeds from stock options exercised ($30 million). Cash used by financing activities for the first three months of 2008 included cash dividend payments ($22 million) and the redemption of preferred stock ($5 million).
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Total Expenditures. The table below sets out components of total expenditures for the three-month periods ended March 31, 2008 and 2007 (in millions):
Expenditure Category
Capital
Drilling and Facilities
888
740
Leasehold Acquisitions
126
48
Producing Property Acquisitions
1
Capitalized Interest
9
Subtotal
1,052
795
8
Exploration and Development Expenditures
1,108
838
Asset Retirement Costs
14
Total Exploration and Development Expenditures
1,122
846
88
80
Total Expenditures
1,210
926
Exploration and development expenditures of $1,108 million for the first three months of 2008 were $270 million higher than the same period of 2007 due primarily to increased drilling and facilities expenditures of $148 million, increased lease acquisitions in Canada ($43 million) and in the United States ($25 million), changes in the Canadian exchange rate ($22 million) and increased geological and geophysical expenditures in the United States ($16 million) and in Canada ($4 million). The increased drilling and facilities expenditures of $148 million primarily resulted from higher drilling and facilities expenditures in the United States ($218 million), partially offset by lower drilling and facilities expenditures in Canada ($49 million) and Trinidad ($30 million). The exploration and development expenditures for the first three months of 2008 of $1,108 million include $801 million in development, $269 million in exploration, $29 million in property acquisitions and $9 million in capitalized interest. The increase in expenditures for other property, plant and equipment was primarily related to gathering systems and processing plants in the Fort Worth Basin Barnett Shale and Rocky Mountain areas. The exploration and development expenditures for the first three months of 2007 of $838 million include $670 million in development, $161 million in exploration, $6 million in capitalized interest and $1 million in property acquisitions.
The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other related economic factors. EOG has significant flexibility with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to operations in the United States, Canada, Trinidad and the United Kingdom North Sea, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.
Commodity Derivative Transactions. As more fully discussed in Note 11 to Consolidated Financial Statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2007, EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for natural gas and crude oil. EOG utilizes financial commodity derivative instruments, primarily collar and price swap contracts, as the means to manage this price risk. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. In addition to 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 physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.
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The total fair value of the natural gas and crude oil financial price swap contracts at March 31, 2008 was a negative $393 million. Since filing its Current Report on Form 8-K on May 1, 2008, EOG has not entered into additional natural gas or crude oil financial price swap contracts. Presented below is a comprehensive summary of EOG's 2008 and 2009 natural gas and crude oil financial price swap contracts at May 8, 2008, with notional volumes expressed in MMBtud and in barrels per day (Bbld), as applicable, and prices expressed in dollars per million British thermal units ($/MMBtu) and in dollars per barrel ($/Bbl), as applicable. Currently, EOG is not a party to any financial collar contracts. The average price of EOG's outstanding natural gas financial price swap contracts for 2008 is $8.52 per million British thermal units (MMBtu) and for 2009 is $8.80 per MMBtu. The average price of EOG's outstanding crude oil financial price swap contracts is $92.19 per barrel.
Financial Price Swap Contracts
Crude Oil
Volume
Average Price
(MMBtud)
($/MMBtu)
(Bbld)
($/Bbl)
April (closed)
455,000
$8.11
14,000
$92.20
May (1)
8.10
92.20
June
8.18
July
8.26
August
8.33
September
8.36
October
8.44
November
8.83
December
9.23
4,000
91.96
2009
January
400,000
$9.63
February
9.63
March
9.40
April
8.37
May
8.38
8.45
8.50
8.52
8.57
8.80
9.10
(1) The natural gas contracts for May 2008 are closed. The crude oil contracts for May 2008 will close on May 31, 2008.
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, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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 or 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 the expectations reflected in its forward-looking statements are based on reasonable assumptions, no assurance can be given that these
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expectations will be achieved. Important factors that could cause actual results to differ materially from the expectations reflected in EOG's 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, interest rates and financial market conditions;
the extent and effect of any hedging activities engaged in by EOG;
the timing and impact of liquefied natural gas imports;
changes in demand or prices for ammonia or methanol;
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 ability to achieve production levels from existing and future oil and gas development projects due to operating hazards, drilling risks and the inherent uncertainties in predicting oil and gas reservoir performance;
the availability and cost of drilling rigs, experienced drilling crews, tubular steel and other materials, equipment and services used in drilling and well completions;
the availability, terms and timing of mineral licenses and leases and governmental and other permits and rights of way;
access to surface locations for drilling and production facilities;
the availability and capacity of gathering, processing and pipeline transportation facilities;
the availability of compression uplift capacity;
the extent to which EOG can economically develop its Barnett Shale acreage outside of Johnson County, Texas;
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 and the enactment of new government policies, legislation and regulations, including environmental regulations;
acts of war and terrorism and responses to these acts; and
weather, including weather-related delays in the installation of gathering and production facilities.
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur. EOG's forward-looking statements speak only as of the date made and EOG undertakes no obligation to update or revise its forward-looking statements, whether as a result of new information, future events or otherwise.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKEOG RESOURCES, INC.
EOG's exposure to commodity price risk, interest rate risk and foreign currency exchange rate risk is discussed in (i) the "Derivative Transactions," "Financing," "Foreign Currency Exchange Rate Risk" and "Outlook" sections of "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity," on pages 32 through 36 of EOG's Annual Report on Form 10-K for the year ended December 31, 2007, filed on February 28, 2008; and (ii) Note 11, "Price, Interest Rate and Credit Risk Management Activities," on pages F-27 through F-29, to EOG's Consolidated Financial Statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2007. There have been no material changes in this information. For additional information regarding EOG's financial commodity derivative contracts and physical commodity contracts, see (i) Note 1 to Consolidated Financial Statements in this Quarterly Report on Form 10-Q; (ii) "Management's Disc ussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Net Operating Revenues" in this Quarterly Report on Form 10-Q; and (iii) "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Commodity Derivative Transactions" in this Quarterly Report on Form 10-Q.
ITEM 4. CONTROLS AND PROCEDURESEOG RESOURCES, INC.
Disclosure Controls and Procedures. EOG's management, with the participation of EOG's principal executive officer and principal financial officer, evaluated the effectiveness of EOG's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of the end of the period covered by this Quarterly Report on Form 10-Q (Evaluation Date). Based on this evaluation, EOG's principal executive officer and principal financial officer have concluded that EOG's disclosure controls and procedures were effective as of the Evaluation Date in ensuring that information that is required to be disclosed by EOG in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms and (ii) accumulated and communicated to EOG's management as appropriate to a llow timely decisions regarding required disclosure.
Internal Control Over Financial Reporting. There were no changes in EOG's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act) that occurred during the quarterly period covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting.
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PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I, Item 1, Note 9 to Consolidated Financial Statements, which is incorporated herein by reference.
ITEM 2. 9; UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Issuer Purchases of Equity Securities
Total Number of
Shares Purchased as
Maximum Number
Part of Publicly
Of Shares that May Yet
Shares
Price Paid
Announced Plans or
Be Purchased Under
Period
Purchased(1)
Per Share
Programs
The Plans or Programs(2)
January 1, 2008 - January 31, 2008
2,162
91.83
6,386,200
February 1, 2008 - February 29, 2008
51,173
101.35
March 1, 2008 - March 31, 2008
994
124.24
54,329
101.39
(1) Represents 54,329 shares that were withheld by or returned to EOG Resources, Inc. (EOG) to satisfy tax withholding obligations that arose upon the exercise of employee stock options or the vesting of restricted stock or restricted stock 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
3.1 -
Certificate of Elimination of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, dated March 6, 2008 (incorporated by reference to Exhibit 3.1 to EOG's Current Report on Form 8-K, filed March 6, 2008).
3.2 -
Bylaws, dated August 23, 1989, as amended and restated effective as of January 4, 2008 (incorporated by reference to Exhibit 3.2 to EOG's Annual Report on Form 10-K for the year ended December 31, 2007).
4.1 -
Rights Agreement Certificate, dated February 11, 2008 (incorporated by reference to Exhibit 4.20 to EOG's Annual Report on Form 10-K for the year ended December 31, 2007).
*31.1 -
Section 302 Certification of Periodic Report of Principal Executive Officer.
*31.2 -
Section 302 Certification of Periodic Report of Principal Financial Officer.
*32.1 -
Section 906 Certification of Periodic Report of Principal Executive Officer.
*32.2 -
Section 906 Certification of Periodic Report of Principal Financial Officer.
*Exhibits filed herewith
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
(Registrant)
Date: May 8, 2008
By:
/s/ TIMOTHY K. DRIGGERS
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EXHIBIT INDEX
Exhibit No.
Description