UNITED STATESSECURITIES AND EXCHANGE COMMISSION
FORM 10-Q
(Mark One)
x
For the quarterly period ended March 31, 2009
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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes oNo 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
250,278,726 (as of April 27, 2009)
TABLE OF CONTENTS
PART I.
FINANCIAL INFORMATION
Page No.
ITEM 1.
Financial Statements (Unaudited)
3
4
5
6
ITEM 2.
21
ITEM 3.
34
ITEM 4.
PART II.
OTHER INFORMATION
35
ITEM 6.
36
37
38
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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,
2009
2008
Net Operating Revenues
Natural Gas
$
567,578
1,037,638
Crude Oil, Condensate and Natural Gas Liquids
200,328
394,848
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
351,383
(469,844)
Gathering, Processing and Marketing
37,842
35,985
Other, Net
1,078
135,391
Total
1,158,209
1,134,018
Operating Expenses
Lease and Well
145,506
124,107
Transportation Costs
68,862
61,967
Gathering and Processing Costs
17,713
8,359
Exploration Costs
49,623
47,943
Dry Hole Costs
2,994
8,428
Impairments
65,471
32,574
Marketing Costs
31,953
33,045
Depreciation, Depletion and Amortization
389,329
297,199
General and Administrative
57,946
52,926
Taxes Other Than Income
47,400
86,750
876,797
753,298
Operating Income
281,412
380,720
Other Income, Net
1,739
1,583
Income Before Interest Expense and Income Taxes
283,151
382,303
Interest Expense, Net
18,376
12,191
Income Before Income Taxes
264,775
370,112
Income Tax Provision
106,065
129,156
Net Income
158,710
240,956
Preferred Stock Dividends
-
443
Net Income Available to Common Stockholders
240,513
Net Income Per Share Available to Common Stockholders
Basic
0.64
0.98
Diluted
0.63
0.96
Dividends Declared per Common Share
0.145
0.120
Average Number of Common Shares
247,991
245,430
250,204
249,763
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
85,214
331,311
Accounts Receivable, Net
558,119
722,695
Inventories
242,627
187,970
Assets from Price Risk Management Activities
856,982
779,483
Income Taxes Receivable
5,199
27,053
Deferred Income Taxes
6,822
Other
54,776
59,939
1,809,739
2,108,451
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)
21,460,167
20,803,629
Other Property, Plant and Equipment
1,086,093
1,057,888
Total Property, Plant and Equipment
22,546,260
21,861,517
Less: Accumulated Depreciation, Depletion and Amortization
(8,539,730)
(8,204,215)
Total Property, Plant and Equipment, Net
14,006,530
13,657,302
Other Assets
167,440
185,473
Total Assets
15,983,709
15,951,226
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable
774,434
1,122,209
Accrued Taxes Payable
78,866
86,265
Dividends Payable
35,943
33,461
Liabilities from Price Risk Management Activities
9,610
4,429
296,468
368,231
Current Portion of Long-Term Debt
37,000
87,976
113,321
1,283,297
1,764,916
Long-Term Debt
2,105,100
1,860,000
Other Liabilities
514,143
498,291
2,965,632
2,813,522
Commitments and Contingencies (Note 9)
Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and
250,338,160 Shares Issued at March 31, 2009 and 249,758,577
Shares Issued at December 31, 2008
202,503
202,498
Additional Paid in Capital
349,210
323,805
Accumulated Other Comprehensive (Loss) Income
(21,694)
27,787
Retained Earnings
8,588,650
8,466,143
Common Stock Held in Treasury, 62,402 Shares at March 31, 2009
and 126,911 Shares at December 31, 2008
(3,132)
(5,736)
Total Stockholders' Equity
9,115,537
9,014,497
Total Liabilities and Stockholders' Equity
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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
26,407
19,783
83,215
83,390
(652)
(127,968)
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses
(351,383)
469,844
Realized Gains
310,964
23,210
2,940
8,599
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable
156,926
(177,684)
(22,896)
3,285
(352,622)
93,452
14,478
(29,265)
1,430
(1,745)
(18,070)
(22,165)
Changes in Components of Working Capital Associated with
Investing and Financing Activities
138,598
5,192
Net Cash Provided by Operating Activities
605,839
927,085
Investing Cash Flows
Additions to Oil and Gas Properties
(822,583)
(1,060,035)
Additions to Other Property, Plant and Equipment
(65,013)
(87,589)
Proceeds from Sales of Assets
447
346,891
Investing Activities
(138,532)
(4,750)
554
(1,235)
Net Cash Used in Investing Activities
(1,025,127)
(806,718)
Financing Cash Flows
Net Commercial Paper and Uncommitted Credit Facility Borrowings
208,100
Dividends Paid
(33,491)
(22,089)
Redemption of Preferred Stock
(5,395)
Excess Tax Benefits from Stock-Based Compensation
4,688
35,496
Treasury Stock Purchased
(4,904)
(5,508)
Proceeds from Stock Options Exercised
1,152
29,537
(66)
(442)
Net Cash Provided by Financing Activities
175,479
31,599
Effect of Exchange Rate Changes on Cash
(2,288)
(1,259)
Increase (Decrease) in Cash and Cash Equivalents
(246,097)
150,707
Cash and Cash Equivalents at Beginning of Period
54,231
Cash and Cash Equivalents at End of Period
204,938
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 (collectively, EOG), included herein have been prepared by management without audit pursuant to the rules and regulations of the United States 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 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 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 conjunc tion 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, 2008, filed on February 25, 2009 (EOG's 2008 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, 2009 are not necessarily indicative of the results to be expected for the full year.
Gathering, processing and marketing revenues represent sales of third-party natural gas, crude oil and natural gas liquids as well as gathering fees associated with gathering third-party natural gas. EOG's gathering, processing and marketing revenues were previously presented
Recently Issued Accounting Standards and Developments. In December 2008, the SEC released a final rule, "Modernization of Oil and Gas Reporting," which amends the oil and gas reporting requirements. The key revisions to the reporting requirements include: using a 12-month average price to determine reserves; including nontraditional resources in reserves if they are intended to be upgraded to synthetic oil and gas; ability to use new technologies to determine and estimate reserves; and permitting the disclosure of probable and possible reserves. In addition, the final rule includes the requirements to report the independence and qualifications of the reserve preparer or auditor; to file a report as an exhibit when a third party is relied upon to prepare reserve estimates or conduct reserve audits; and to disclose the development of any proved undeveloped reserves (PUDs), including the total quantity of PUDs at year-end, material changes to PUDs during the year, investments an d progress toward the development of PUDs and an explanation of the reasons why material concentrations of PUDs have remained undeveloped for five years or more after disclosure as PUDs. The accounting changes resulting from changes in definitions and pricing assumptions should be treated as a change in accounting principle that is inseparable from a change in accounting estimate, which is to be applied prospectively. The final rule is effective for annual reports for fiscal years ending on or after December 31, 2009. Early adoption is not permitted. EOG is assessing the impact that this final rule will have on its financial statements.
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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, "Accounting for Derivative Instruments and Hedging Activities," as amended (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. EOG adopted the provisions of SFAS No. 161 effective January 1, 2009. See Note 13.
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 (FSP) 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. EOG partially adopted SFAS No. 157 effective January 1, 2008 and adopted the provisions related to nonfinancial assets and liabilities effective Ja nuary 1, 2009. See Note 12.
2. Stock-Based Compensation
As more fully discussed in Note 6 to the Consolidated Financial Statements included in EOG's 2008 Annual Report, EOG maintains various stock-based compensation plans. 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):
6.0
4.4
5.2
4.0
15.2
11.4
26.4
19.8
The EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) provides for grants of stock options, stock-settled stock appreciation rights (SARs), restricted stock, restricted stock units and other stock-based awards, up to an aggregate maximum of 6.0 million shares of common stock, plus shares underlying forfeited or cancelled grants under the prior stock plans. At March 31, 2009, approximately 3.9 million common shares remained available for grant under the 2008 Plan. Effective with the adoption of the 2008 Plan, EOG's policy is to issue shares related to the 2008 Plan from previously authorized unissued shares.
Stock Options and Stock Appreciation Rights and Employee Stock Purchase Plan. The fair value of all Employee Stock Purchase Plan (ESPP) grants is estimated using the Black-Scholes-Merton model. Certain of EOG's stock options granted in 2005 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 SAR grants was estimated using the Hull-White II binomial option pricing model. Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $8.7 million and $8.9 million during the three months ended March 31, 2009 and 2 008, respectively.
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Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants during the three-month periods ended March 31, 2009 and 2008 are as follows:
Stock Options/SARs
ESPP
Weighted Average Fair Value of Grants
20.63
24.13
25.78
21.86
Expected Volatility
67.20%
31.84%
78.89%
31.67%
Risk-Free Interest Rate
0.60%
2.81%
0.25%
3.29%
Dividend Yield
1.0%
0.4%
Expected Life
2.7 yrs.
3.6 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 SAR transactions for the three-month periods ended March 31, 2009 and 2008 (stock options and SARs in thousands):
March 31, 2009
March 31, 2008
Weighted
Number of
Average
Stock
Grant
Options/SARs
Price
Options/ SARs
Outstanding at January 1
7,802
52.56
9,373
41.04
Granted
17
67.64
22
99.68
Exercised (1)
(79)
18.16
(1,341)
Forfeited
(32)
71.90
(45)
60.90
Outstanding at March 31 (2)
7,708
52.86
8,009
43.92
Vested or Expected to Vest (3)
7,478
52.12
7,771
43.32
Exercisable at March 31 (4)
4,651
37.71
4,319
28.50
(1) The total intrinsic value of stock options/SARs exercised for the three-month periods ended March 31, 2009 and 2008 was $3.7 million and $113.7 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, 2009 and 2008 was $97.7 million and $609.3 million, respectively. At March 31, 2009 and 2008, the weighted average remaining contractual life was 4.3 years and 4.9 years, respectively. (3) The total intrinsic value of stock options/SARs vested or expected to vest at March 31, 2009 and 2008 was $97.7 million and $595.9 million, respectively. At March 31, 2009 and 2008, the weighted average remaining contractual life was 4.3 years and 4.9 years, respectively. (4) The total intrinsic value of stock options/SARs exercisable at March 31, 2009 and 2008 was $97.6 million and $395.2 million, respectively. At March 31, 2009 and 2008, the weighted average remaining contractual life was 3.6 years and 4.2 years, respectively.
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At March 31, 2009, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $68.9 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.3 years.
Restricted Stock and Restricted Stock Units. Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them. Stock-based compensation expense related to restricted stock and restricted stock units totaled $17.7 million and $10.9 million for the three months ended March 31, 2009 and 2008, respectively.
The following table sets forth the restricted stock and restricted stock units transactions for the three-month periods ended March 31, 2009 and 2008 (shares and units in thousands):
Shares and
Grant Date
Units
Fair Value
3,048
70.24
3,000
50.61
664
48.67
203
120.01
Released (1)
(277)
22.33
(161)
20.77
(15)
84.01
(21)
67.85
3,420
69.87
3,021
56.73
(1) The total intrinsic value of restricted stock and restricted stock units released for the three-month periods ended March 31, 2009 and 2008 was $15.0 million and $16.1 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, 2009 and 2008 was approximately $187.3 million and $362.5 million, respectively.
At March 31, 2009, unrecognized compensation expense related to restricted stock and restricted stock units totaled $136.0 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, 2009 and 2008 (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 Shares -
1,362
3,077
Restricted Stock and Restricted Stock Units
851
1,256
Denominator for Diluted Earnings Per Share -
Adjusted Diluted Weighted Average Shares
The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive. The excluded stock options and SARs totaled 4.4 million shares and 3,826 shares for the three months ended March 31, 2009 and 2008, respectively.
4. Supplemental Cash Flow Information
Cash paid (received) for interest and income taxes was as follows for the three-month periods ended March 31, 2009 and 2008 (in thousands):
Interest
10,037
17,479
Income Taxes
(6,581)
36,843
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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, 2009 and 2008 (in thousands):
Comprehensive Income
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments
(51,288)
(77,090)
Foreign Currency Swap Transaction
2,394
(974)
Income Tax Related to Foreign
Currency Swap Transaction
(609)
239
Defined Benefit Pension and Postretirement Plans
Income Tax Related to Defined Benefit
Pension and Postretirement Plans
(12)
(64)
109,229
163,102
6. Segment Information
Selected financial information by reportable segment is presented below for the three-month periods ended March 31, 2009 and 2008 (in thousands):
United States
1,002,904
838,047
Canada
104,902
170,454
Trinidad
41,262
109,884
Other International (1)
9,141
15,633
Operating Income (Loss)
261,718
230,558
2,389
59,788
21,498
88,390
(4,193)
1,984
Reconciling Items
(1) Other International includes EOG's United Kingdom operations and, effective July 1, 2008, EOG's China operations.
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Total assets by reportable segment are presented below at March 31, 2009 and December 31, 2008 (in thousands):
At
12,855,740
12,668,763
2,331,095
2,421,979
708,116
735,387
88,758
125,097
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," at March 31, 2009 and 2008 (in thousands):
Carrying Amount at Beginning of Period
368,159
211,124
Liabilities Incurred
11,670
10,224
Liabilities Settled
(5,992)
(11,460)
Accretion
4,559
2,933
Revisions (1)
(8)
3,693
Foreign Currency Translations
(2,030)
(1,946)
Carrying Amount at End of Period
376,358
214,568
Current Portion
17,557
2,306
Noncurrent Portion
358,801
212,262
(1) Revisions to asset retirement obligations reflect changes in abandonment cost estimates.
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, 2009 in accordance with FSP No. 19-1, "Accounting for Suspended Well Costs," are presented below (in thousands):
Three Months
Ended
Balance at December 31, 2008
85,255
Additions Pending the Determination of Proved Reserves
53,488
Reclassifications to Proved Properties
(10,804)
Charged to Dry Hole Costs
(2,707)
(1,676)
Balance at March 31, 2009
123,556
The following table provides an aging of suspended well costs at March 31, 2009 (in thousands, except well count):
Capitalized exploratory well costs that have been
capitalized for a period less than one year
67,381
capitalized for a period greater than one year
56,175
(1)
Number of exploratory wells that have been capitalized
for a period greater than one year
(1) Costs related to three shale projects in British Columbia, Canada (B.C.) ($38 million) and an outside operated, offshore Central North Sea project in the United Kingdom ($18 million). In the B.C. projects, further reserve evaluations will be made based on drilling and completion activities during 2009 and 2010. In addition, EOG is evaluating infrastructure alternatives for the B.C. shale projects. In the Central North Sea project, the operator submitted a field development plan to the Department of Energy and Climate Change during the fourth quarter of 2008. EOG is currently focused on securing an export route for production from the Central North Sea project.
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, 2009 and 2008, EOG's total costs recognized for these pension plans were $5.6 million and $5.1 million, respectively.
In addition, as more fully discussed in Note 6 to Consolidated Financial Statements included in EOG's 2008 Annual Report, EOG's Canadian, Trinidadian and United Kingdom subsidiaries maintain various pension and savings plans for most of their respective employees. For each of the three-month periods ended March 31, 2009 and 2008, combined contributions to these plans totaled $0.6 million.
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, 2009, EOG's total contributions to these plans were approximately $31,000. The net periodic benefit costs recognized for the postretirement medical and dental plans were approximately $203,000 and $186,500, respectively, for the three months ended March 31, 2009 and 2008.
11. Long-Term Debt 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 $191 million of outstanding borrowings from commercial paper and $17 million from uncommitted credit facilities at March 31, 2009. The weighted average interest rates for commercial paper and uncommitted credit facility borrowings at March 31, 2009 were 0.84% and 1.10%, respectively. The weighted average interest rates for commercial paper and uncommitted credit facility borrowings for the three months ended March 31, 2009 were 0.88% and 1.10%, respectively. Commercial paper and uncommitted credit facility borrowings outstanding at March 31, 2009 were classified as long-term debt based upon EOG's intent and ability to replace such amounts with other long-term debt.
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, 2009, 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, 2009, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 0.69% and 3.25%, 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. In the second quarter of 2008, EOG repaid $38 million of the $75 million outstanding and at March 31, 2009, $37 million remained outstanding under the Credit Agreement. The remaining outstanding balance was classified as long-term debt based upon EOG's intent and ability to replace such amount with other long-term debt. The applicable Eurodollar rate at March 31, 2009 was 2.89%. The weighted average Eurodollar rate for the amount outstanding during the first three months of 2009 was 2.79%. The Credit Agreement is scheduled to mature on May 12, 2009. EOG is currently negotiating an amendment to the Credit Agreement to extend the scheduled maturity date of the remaining outstanding balance of $37 million to May 12, 2010. EOG expects to enter into this amendment prior to the scheduled maturity date.
Common Stock. On February 4, 2009, the Board increased the quarterly cash dividend on EOG's common stock from the previous $0.135 per share to $0.145 per share effective with the dividend paid on April 30, 2009 to record holders as of April 16, 2009.
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12. Fair Value Measurements
Certain of EOG's financial and nonfinancial 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, "Fair Value Measurements," for its financial assets and liabilities. SFAS No. 157 defines fair value, establishes a framework 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 a re unobservable inputs and have the lowest priority in the hierarchy. SFAS No. 157 requires that an entity give consideration to the credit risk of its counterparties, as well as its own credit risk, when measuring financial assets and liabilities at fair value. In accordance with the provisions of FSP 157-2, "Effective Date of FASB Statement No. 157," EOG adopted the provisions of SFAS No. 157 relating to its nonfinancial assets and liabilities effective January 1, 2009.
The following table provides fair value measurement information within the hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at March 31, 2009 and December 31, 2008 (in millions):
Fair Value Measurements Using:
Quoted
Significant
Prices in
Active
Observable
Unobservable
Markets
Inputs
(Level 1)
(Level 2)
(Level 3)
At March 31, 2009
Financial Assets:
Natural gas collars, price swaps
and basis swaps
898
Financial Liabilities:
27
Foreign currency rate swap
19
At December 31, 2008
836
12
26
The estimated fair value of natural gas collar, price swap and basis 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.
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The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of EOG's asset retirement obligations is presented in Note 7.
In accordance with the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," proved oil and gas properties with a carrying amount of $32 million were written down to their fair value of $9 million at March 31, 2009, resulting in a pretax impairment charge of $23 million for the three months ended March 31, 2009. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include EOG's estimate of future natural gas and crude oil prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data.
13. Risk Management Activities
Effective January 1, 2009, EOG adopted the provisions of SFAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133." SFAS No. 161 requires expanded disclosure about an entity's use of derivative instruments and the impact of those instruments on the Consolidated Statements of Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows. Information concerning EOG's derivative instruments and hedging activities is presented below.
Commodity Price Risk. As more fully discussed in Note 11 to the Consolidated Financial Statements included in EOG's 2008 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, price swap and basis swap contracts as a means to manage this price risk. EOG has not designated any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income. The related cash flow im pact is reflected as Cash Flows from Operating Activities. 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.
Foreign Currency Exchange Rate Risk. As more fully described in Note 2 to the Consolidated Financial Statements included in EOG's 2008 Annual Report, EOG is party to a foreign currency swap transaction with multiple banks to eliminate any exchange rate impacts that may result from the $150 million principal amount of notes issued by one of EOG's Canadian subsidiaries. EOG accounts for the foreign currency swap transaction using the hedge accounting method, pursuant to the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. Changes in the fair value of the foreign currency swap do not impact Net Income Available to Common Stockholders. The after-tax net impact from the foreign currency swap transaction was an increase in Other Comprehensive Income of $1.8 million and a reduction in Other Comprehensive Income of $0.7 million for the three months ended March 31, 2009 and 2008, respectively (see Note 5).
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The following table sets forth the amount, on a gross basis, and classification of EOG's outstanding derivative financial instruments at March 31, 2009 and December 31, 2008. Certain amounts may be presented on a net basis in the financial statements in accordance with master netting arrangements between EOG and the counter-parties to the transactions (in millions):
Fair Value at
Description
Location on Balance Sheet
Asset Derivatives
and basis swaps -
Current portion
Assets from Price Risk
Management Activities
876
786
Noncurrent portion
58
63
Liability Derivatives
Natural gas basis swaps
Liabilities from Price Risk
28
11
14
Foreign currency rate swaps -
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Financial Collar Contracts. Presented below is a comprehensive summary of EOG's natural gas financial collar contracts at March 31, 2009. The notional volumes are expressed in million British thermal units per day (MMBtud) and prices are expressed in dollars per million British thermal units ($/MMBtu). The average floor price of EOG's outstanding natural gas financial collar contracts for 2010 was $10.00 per million British thermal units (MMBtu) and the average ceiling price was $12.32 per MMBtu.
Natural Gas Financial Collar Contracts
Floor Price
Ceiling Price
Volume
Floor Range
Ceiling Range
(MMBtud)
($/MMBtu)
2010
January
40,000
$11.44 - 11.47
$11.45
$13.79 - 13.90
$13.85
February
11.38 - 11.41
11.40
13.75 - 13.85
13.80
March
11.13 - 11.15
11.14
13.50 - 13.60
13.55
April
9.40 - 9.45
9.42
11.55 - 11.65
11.60
May
9.24 - 9.29
9.26
11.41 - 11.55
11.48
June
9.31 - 9.36
9.34
11.49 - 11.60
11.55
July
9.43
11.60 - 11.70
11.65
August
9.47 - 9.52
9.50
11.68 - 11.80
11.74
September
9.50 - 9.55
9.52
11.73 - 11.85
11.79
October
9.58 - 9.63
9.61
11.83 - 11.95
11.89
November
9.88 - 9.93
9.91
12.30 - 12.40
12.35
December
9.87 - 10.30
10.09
12.55 - 12.71
12.63
Subsequent to March 31, 2009, EOG settled its natural gas financial collar contracts for the period July 1, 2010 to December 31, 2010 and received proceeds of $26.5 million. An updated summary of EOG's natural gas financial price collar contracts as of May 4, 2009 is presented in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - - Commodity Derivative Transactions."
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Financial Price Swap Contracts. Presented below is a comprehensive summary of EOG's natural gas financial price swap contracts at March 31, 2009. The notional volumes are expressed in MMBtud and prices are expressed in $/MMBtu. The average price of EOG's outstanding natural gas financial price swap contracts for 2009 was $8.98 per MMBtu and for 2010 was $9.87 per MMBtu.
Natural Gas Financial Price Swap Contracts
Average Price
January (closed)
585,000
$10.76
February (closed)
10.73
March (closed)
10.50
April (closed)
610,000
9.24
9.16
710,000
8.53
8.62
8.67
8.69
8.76
9.66
9.99
20,000
$11.20
11.15
10.89
9.29
9.13
9.21
9.31
9.38
9.40
9.49
9.80
10.21
Subsequent to March 31, 2009, EOG settled its natural gas financial price swap contracts for the period July 1, 2010 to December 31, 2010 and received proceeds of $12.1 million. An updated summary of EOG's natural gas financial price swap contracts as of May 4, 2009 is presented in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - - Commodity Derivative Transactions."
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Financial Basis Swap Contracts. Prices received by EOG for its natural gas production generally vary from New York Mercantile Exchange (NYMEX) prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas financial basis swap contracts in order to fix the differential between prices in the Rocky Mountain area and NYMEX Henry Hub prices. Presented below is a comprehensive summary of EOG's natural gas financial basis swap contracts at March 31, 2009. The weighted average price differential represents the amount of reduction to NYMEX gas prices per MMBtu for the notional volumes covered by the basis swap. Notional volumes are expressed in MMBtud and price differentials are expressed in $/MMBtu.
Natural Gas Financial Basis Swap Contracts
Differential
Second Quarter*
65,000
$(2.54)
Third Quarter
(2.60)
Fourth Quarter
(3.03)
First Quarter
$(1.72)
Second Quarter
(2.56)
(3.17)
(3.73)
2011
$(1.89)
*Includes closed contracts for April 2009.
Credit Risk. Notional contract amounts are used to express the magnitude of commodity price and foreign currency swap agreements. The amounts potentially subject to credit risk, in the event of nonperformance by the other parties, are equal to the fair value of such contracts. EOG evaluates its exposure to significant counterparties on an ongoing basis, including those arising from physical and financial transactions. In some instances, EOG requires collateral, parent guarantees or letters of credit to minimize credit risk.
All of EOG's outstanding derivative instruments are covered by International Swap Dealers' Association (ISDA) Master Agreements with counterparties. The ISDAs may contain provisions that require EOG, if it is the party in a net liability position, to post collateral when the amount of the net liability exceeds the threshold level specified for EOG's then current credit rating. In addition, the ISDA may also provide that as a result of certain circumstances, including certain events that cause EOG's credit rating to become materially weaker than its then-current rating, the counterparty may require all outstanding derivatives under the ISDA to be settled immediately. See Note 12 for the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a net liability position at March 31, 2009 and December 31, 2008. EOG had zero collateral posted at March 31, 2009 and December 31, 2008.
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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 (collectively, EOG), is one of the largest independent (non-integrated) oil and natural gas companies in the United States with proved reserves in the United States, Canada, Trinidad, the United Kingdom North Sea and China. 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.
United States and Canada. EOG's effort to identify plays with larger reserve potential has proven a successful supplement to its base development and exploitation program in the United States and Canada. EOG 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 both the first quarter of 2009 and the first quarter of 2008. One of EOG's exploration strategies is to apply its horizontal drilling expertise gained in natural gas resources plays to unconventional oil reservoirs. During the first quarter of 2009, the Fort Worth Basin Barnett Shale and North Dakota Bakken areas produced an increasing amount of crude oil and natural gas liquids as compared to the comparable period in 2008. For the first quarter of 2009, crude oil and natural gas liquids production a ccounted for approximately 21% of total company production as compared to 17% for the comparable period in 2008. Based on current trends, EOG expects its 2009 crude oil and natural gas liquids production to continue to increase as compared to 2008. EOG's major producing areas are in Louisiana, New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.
International. In the United Kingdom, a rig was contracted to drill two operated wells in the East Irish Sea in 2009 and drilling is expected to commence in the second quarter. In addition, EOG began drilling its first well in the Sichuan Basin, Sichuan Province, The People's Republic of China, in March 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. At March 31, 2009 EOG's debt-to-total capitalization ratio was 19% as compared to 17% at December 31, 2008. During the first quarter of 2009, EOG funded $937 million in exploration and development and other property, plant and equipment expenditures and paid $33 million in dividends to common stockholders, primarily by utilizing cash provided from its operating activities and proceeds from commercial paper and uncommitted credit facility borrowings.
For 2009, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $3.1 billion, excluding acquisitions. United States and Canada natural gas and crude oil drilling activity continues to be a key component of these expenditures. EOG intends to manage the 2009 capital budget while maintaining a strong balance sheet. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer EOG incremental exploration and/or production opportunities. Management continues to believe EOG has one of the strongest prospect inventories in EOG's history.
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Results of Operations
The following review of operations for the three months ended March 31, 2009 and 2008 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included in this Quarterly Report on Form 10-Q.
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Wellhead volume and price statistics for the three-month periods ended March 31, 2009 and 2008 were as follows:
Natural Gas Volumes (MMcfd) (1)
1,193
1,085
230
216
263
231
Other International (2)
16
1,702
1,549
Average Natural Gas Prices ($/Mcf) (3)
4.06
8.05
4.43
7.44
1.32
3.87
6.03
9.85
Composite
3.71
7.36
Crude Oil and Condensate Volumes (MBbld) (1)
44.9
30.6
3.2
2.4
3.0
3.6
0.1
51.2
36.7
Average Crude Oil and Condensate Prices ($/Bbl) (3)
33.24
92.08
37.11
88.94
33.45
87.90
46.71
88.29
33.51
91.46
Natural Gas Liquids Volumes (MBbld) (1)
21.7
16.7
1.1
1.0
22.8
17.7
Average Natural Gas Liquids Prices ($/Bbl) (3)
22.12
57.26
25.52
57.14
22.29
Natural Gas Equivalent Volumes (MMcfed) (4)
1,593
1,370
255
236
281
252
2,146
1,875
Total Bcfe (4)
193.1
170.6
(1) Million cubic feet per day or thousand barrels per day, as applicable.(2) Other International includes EOG's United Kingdom operations and, effective July 1, 2008, EOG's China operations.(3) Dollars per thousand cubic feet or per barrel, as applicable. (4) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil and 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 and condensate or natural gas liquids.
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Wellhead natural gas revenues for the first quarter of 2009 decreased $470 million, or 45%, to $568 million from $1,038 million for the same period of 2008 due to a lower composite average wellhead natural gas price ($560 million), partially offset by increased natural gas deliveries ($90 million). EOG's composite average wellhead natural gas price decreased 50% to $3.71 per Mcf for the first quarter of 2009 from $7.36 per Mcf for the same period of 2008.
Natural gas deliveries for the first quarter of 2009 increased 153 MMcfd, or 10%, to 1,702 MMcfd from 1,549 MMcfd for the same period of 2008. The increase was due to higher production in the United States (108 MMcfd), Trinidad (32 MMcfd) and Canada (14 MMcfd). The increase in the United States was primarily attributable to increased production from Texas (88 MMcfd) and the Rocky Mountain area (48 MMcfd), partially offset by decreased production from Pittsburgh as a result of the February 2008 sale of EOG's Appalachian assets (8 MMcfd), Oklahoma (7 MMcfd), New Mexico (7 MMcfd) and Mississippi (7 MMcfd). The increase in Trinidad was primarily due to increased contractual demand. The increase in Canada was primarily attributable to British Columbia Horn River Basin production.
Wellhead crude oil and condensate revenues for the first quarter of 2009 decreased $149 million, or 49%, to $154 million from $303 million for the same period of 2008, due to a lower composite average wellhead crude oil and condensate price ($267 million), partially offset by an increase of 15 MBbld, or 40%, in wellhead crude oil and condensate deliveries ($119 million). The increase in deliveries primarily reflects increased production in North Dakota (11 MBbld). The composite average wellhead crude oil and condensate price for the first quarter of 2009 decreased 63% to $33.51 per barrel compared to $91.46 per barrel for the same period of 2008.
Natural gas liquids revenues for the first quarter of 2009 decreased $46 million, or 50%, to $46 million from $92 million for the same period of 2008, due to a lower composite average price ($71 million), partially offset by increased natural gas liquids deliveries ($25 million). The composite average natural gas liquids price for the first quarter of 2009 decreased 61% to $22.29 per barrel compared to $57.26 per barrel for the same period of 2008. The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale and Rocky Mountain areas.
During the first quarter of 2009, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $351 million compared to a net loss of $470 million for the same period of 2008. During the first quarter of 2009, the net cash inflow related to settled natural gas and crude oil financial price swap contracts was $311 million compared to $23 million for the same period of 2008.
Gathering, processing and marketing revenues represent sales of third-party natural gas, crude oil and natural gas liquids as well as gathering fees associated with gathering third-party natural gas. During the three months ended March 31, 2009 and 2008, substantially all of such revenues were related to sales of third-party natural gas. Marketing costs represent the costs of purchasing third-party natural gas and crude oil and the associated transportation costs.
Gathering, processing and marketing revenues less marketing costs for the first quarter of 2009 increased $3 million to $6 million compared to $3 million for the same period of 2008. The increase resulted primarily from natural gas marketing operations in the Gulf Coast area.
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Operating and Other Expenses. For the first quarter of 2009, operating expenses of $877 million were $124 million higher than the $753 million incurred during the first quarter of 2008. The following table presents the costs per thousand cubic feet equivalent (Mcfe) for the three-month periods ended March 31, 2009 and 2008:
0.75
0.73
0.36
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties
1.90
1.66
0.12
0.08
General and Administrative (G&A)
0.30
0.31
0.10
0.07
Total (1)
3.53
3.21
(1) Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.
The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and net interest expense for the three months ended March 31, 2009 compared to the same period of 2008 are set forth below.
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 natural gas and crude oil 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 $146 million for the first quarter of 2009 increased $22 million from $124 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($18 million) and Canada ($5 million) and higher lease and well administrative expenses ($4 million), partially offset by changes in the Canadian exchange rate ($7 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 $69 million for the first quarter of 2009 increased $7 million from $62 million for the same prior year period primarily due to increased production and costs associated with marketing arrangements to transport production from the Fort Worth Basin Barnett Shale area ($5 million) and the Rocky Mountain area ($3 million) to 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
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performance and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from year to year. DD&A of the cost of other property, plant and equipment is calculated using the straight-line depreciation method over the useful lives of the assets. Other property, plant and equipment consist of natural gas gathering and processing facilities, compressors, vehicles, buildings and leasehold improvements, furniture and fixtures, and computer hardware and software.
DD&A expenses for the first quarter of 2009 increased $92 million to $389 million from $297 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first quarter of 2009 were $82 million higher than the same prior year period primarily due to higher unit rates in the United States ($45 million), Canada ($5 million) and Trinidad ($4 million) and as a result of increased production in the United States ($34 million) and in Canada ($3 million), partially offset by changes in the Canadian exchange rate ($11 million).
DD&A expenses associated with other property, plant and equipment for the first quarter of 2009 were $10 million higher than the same prior year period primarily due to increased expenditures associated with natural gas gathering systems and processing plants in the Fort Worth Basin Barnett Shale area ($5 million) and Rocky Mountain area ($2 million).
G&A expenses of $58 million for the first quarter of 2009 increased $5 million from the same prior year period primarily due to higher employee related costs.
Interest expense, net of $18 million for the first quarter of 2009 increased $6 million as compared to the same prior year period primarily due to a higher average debt balance ($9 million), partially offset by higher capitalized interest ($3 million).
Gathering and processing costs represent operation and maintenance expenses and administrative expenses associated with operating EOG's natural gas gathering and processing assets.
Gathering and processing costs for the first quarter of 2009 increased $9 million to $18 million as compared to the same prior year period primarily due to increased activities in the Rocky Mountain area ($4 million) and Fort Worth Basin Barnett Shale area ($3 million).
Impairments include amortization of unproved leases, as well as impairments under Statement of Financial Accounting Standards (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 $65 million for the first quarter of 2009 were $32 million higher than impairments of $33 million for the same prior year period primarily due to increased amortization costs of unproved leases in the United States ($18 million) and increased SFAS No. 144 related impairments in the United States ($16 million), partially offset by decreased SFAS No. 144 related impairments in Canada ($2 million). Under SFAS No. 144, EOG recorded impairments of $23 million and $9 million for the first quarter of 2009 and 2008, 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 were $47 million (6.2% of wellhead revenues) for the first quarter of 2009 compared to $87 million (6.1% of wellhead revenues) for the same prior year period. The decrease in taxes other than income was primarily due to decreased severance/production taxes as a result of decreased wellhead revenues in the United States ($28 million) and Trinidad ($6 million) and an increase in credits taken in 2009 for Texas high cost gas severance tax rate reductions ($5 million).
Income tax provision of $106 million for the first quarter of 2009 decreased $23 million compared to the same prior year period primarily due to lower pretax income ($37 million), partially offset by higher state income taxes ($7 million). The net effective tax rate for the first quarter of 2009 increased to 40% from 35% in 2008.
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Capital Resources and Liquidity
Cash Flow. The primary sources of cash for EOG during the three months ended March 31, 2009 were funds generated from operations and net commercial paper and uncommitted credit facility borrowings. 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 2009, EOG's cash balance decreased $246 million to $85 million from $331 million at December 31, 2008.
Net cash provided by operating activities of $606 million for the first three months of 2009 decreased $321 million compared to the same period of 2008 primarily reflecting a decrease in wellhead revenues ($665 million), partially offset by a favorable change in net cash flow from the settlement of financial commodity derivative contracts ($288 million), a decrease in net cash paid for income taxes ($43 million), a decrease in cash paid for interest expense ($7 million) and favorable changes in working capital and other assets and liabilities ($3 million).
Net cash used in investing activities of $1,025 million for the first three months of 2009 increased by $218 million compared to the same period of 2008 due primarily to a decrease in proceeds from sales of assets ($346 million), primarily reflecting net proceeds from the sale of EOG's Appalachian assets in February 2008, and unfavorable changes in working capital associated with investing activities ($134 million), partially offset by a decrease in additions to oil and gas properties ($237 million) and a decrease in additions to other property, plant and equipment ($23 million).
Net cash provided by financing activities was $175 million for the first three months of 2009 compared to $32 million for the same period of 2008. Cash provided by financing activities for the first three months of 2009 included net commercial paper and uncommitted credit facility borrowings ($208 million) and excess tax benefits from stock-based compensation ($5 million). Cash used by financing activities for the first three months of 2009 included cash dividend payments ($33 million) and the purchase of treasury stock ($5 million).
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Total Expenditures. For 2009, EOG's budget for exploration and production and other property, plant and equipment expenditures is approximately $3.1 billion. The table below sets out components of total expenditures for the three-month periods ended March 31, 2009 and 2008 (in millions):
Expenditure Category
Capital
Drilling and Facilities
731
888
Leasehold Acquisitions
72
126
Producing Property Acquisitions
29
Capitalized Interest
9
Subtotal
819
1,052
50
48
8
Exploration and Development Expenditures
872
1,108
Asset Retirement Costs
Total Exploration and Development Expenditures
884
1,122
65
88
Total Expenditures
949
1,210
Exploration and development expenditures of $872 million for the first three months of 2009 were $236 million lower than the same period of 2008 due primarily to decreased drilling and facilities expenditures in the United States ($128 million) and Canada ($15 million), decreased leasehold acquisition expenditures in Canada ($48 million), changes in the Canadian exchange rate ($15 million) and decreased producing property acquisition expenditures in Trinidad ($15 million) and Canada ($14 million). The exploration and development expenditures for the first three months of 2009 of $872 million include $662 million in development, $194 million in exploration, $12 million in capitalized interest and $4 million in producing property acquisitions. 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 producing property acquisitions and $9 million in capitalized inter est.
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, the United Kingdom and China, 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 the Consolidated Financial Statements included in EOG's 2008 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, price swap and basis swap contracts, as a means to manage this price risk. EOG has not designated any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income. The related cash flow impact is reflected as Cash Flows from Operating Activities. 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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Financial Collar Contracts. The total fair value of EOG's natural gas financial collar contracts at March 31, 2009 was a positive $59 million, which is reflected in the Consolidated Balance Sheets. Subsequent to March 31, 2009, EOG settled its natural gas financial collar contracts for the period July 1, 2010 to December 31, 2010 and received proceeds of $26.5 million. Presented below is a comprehensive summary of EOG's natural gas financial collar contracts at May 4, 2009. The notional volumes are expressed in million British thermal units per day (MMBtud) and prices are expressed in dollars per million British thermal units ($/MMBtu). The average floor price of EOG's outstanding natural gas financial collar contracts for 2010 is $10.33 per million British thermal units (MMBtu) and the average ceiling price is $12.63 per MMBtu.
July (closed)
August (closed)
September (closed)
October (closed)
November (closed)
December (closed)
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Financial Price Swap Contracts. The total fair value of EOG's natural gas financial price swap contracts at March 31, 2009 was a positive $874 million, which is reflected in the Consolidated Balance Sheets. Subsequent to March 31, 2009, EOG settled its natural gas financial price swap contracts for the period July 1, 2010 to December 31, 2010 and received proceeds of $12.1 million. Presented below is a comprehensive summary of EOG's natural gas financial price swap contracts at May 4, 2009. The notional volumes are expressed in MMBtud and prices are expressed in $/MMBtu. The average price of EOG's outstanding natural gas financial price swap contracts for 2009 is $8.96 per MMBtu and for 2010 is $10.14 per MMBtu.
May (closed)
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Financial Basis Swap Contracts. Prices received by EOG for its natural gas production generally vary from New York Mercantile Exchange (NYMEX) prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas financial basis swap contracts in order to fix the differential between prices in the Rocky Mountain area and NYMEX Henry Hub prices. The total fair value of EOG's natural gas financial basis swap contracts at March 31, 2009 was a negative $62 million, which is reflected in the Consolidated Balance Sheets. Presented below is a comprehensive summary of EOG's natural gas financial basis swap contracts at May 4, 2009. The weighted average price differential represents the amount of reduction to NYMEX gas prices per MMBtu for the notional volumes covered by the basis swap. The notional volumes are expressed in MMBtud and price differentials expressed in $/MMBtu.
Average Price Differential
*Includes closed contracts for the months of April and May 2009.
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Information Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, 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 and projections regarding EOG's future financial position, operations, performance, business strategy, budgets, reserve information, levels of production and costs and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will" 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 EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production or 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 reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that these expectations will be achieved or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known and unknown risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's 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 prices for natural gas, crude oil and related commodities;
changes in demand for natural gas, crude oil and related commodities, including ammonia and methanol;
the extent to which EOG is successful in its efforts to discover, develop, market and produce reserves and to acquire natural gas and crude oil properties;
the extent to which EOG can optimize reserve recovery and economically develop its plays utilizing horizontal and vertical drilling and advanced completion technologies;
the extent to which EOG is successful in its efforts to economically develop its acreage in the Barnett Shale, the Bakken Formation, its Horn River Basin and Haynesville plays and its other exploration and development areas;
EOG's ability to achieve anticipated production levels from existing and future natural gas and crude oil development projects, given the risks and uncertainties inherent in drilling, completing and operating natural gas and crude oil wells and the potential for interruptions of production, whether involuntary or intentional as a result of market or other conditions;
the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;
the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights of way;
competition in the oil and gas exploration and production industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;
EOG's ability to obtain access to surface locations for drilling and production facilities;
the extent to which EOG's third-party-operated natural gas and crude oil properties are operated successfully and economically;
EOG's ability to effectively integrate acquired natural gas and crude oil properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;
weather, including its impact on natural gas and crude oil demand, and weather-related delays in drilling and in the installation and operation of gathering and production facilities;
the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all;
the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
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the extent and effect of any hedging activities engaged in by EOG;
the timing and impact of liquefied natural gas imports;
the use of competing energy sources and the development of alternative energy sources;
political developments around the world, including in the areas in which EOG operates;
changes in government policies, legislation and regulations, including environmental regulations;
the extent to which EOG incurs uninsured losses and liabilities;
acts of war and terrorism and responses to these acts; and
the other factors described under Item 1A, "Risk Factors," on pages 13 through 19 of EOG's Annual Report on Form 10-K for the year ended December 31, 2008 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q.
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and you should not place any undue reliance on any of EOG's forward-looking statements. 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 36 through 42 of EOG's Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 25, 2009 (EOG's 2008 Annual Report); and (ii) Note 11, "Price, Interest Rate and Credit Risk Management Activities," on pages F-26 through F-29, to EOG's Consolidated Financial Statements included in EOG's 2008 Annual Report. 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 13 to Consolidated Financial Statements in this Quarterly Report on Form 10-Q; (ii) "Management's Discussion and Analys is 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 al low 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
The following table sets forth, for the periods indicated, EOG Resources, Inc.'s (EOG) share repurchase activity:
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, 2009 - January 31, 2009
765
69.04
6,386,200
February 1, 2009 - February 28, 2009
82,197
53.71
March 1, 2009 - March 31, 2009
6,925
63.03
89,887
54.56
(1) Represents 89,887 total shares for the quarter ended March 31, 2009 that consist solely of shares that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or stock-settled stock appreciation rights or the vesting of restricted stock or restricted stock unit grants or (ii) in payment of the exercise price of employee stock options. These shares do not count against the 10 million aggregate share authorization of EOG's Board of Directors (Board) discussed below.(2) In September 2001, the Board authorized the repurchase of up to 10,000,000 shares of EOG's common stock. During the first quarter of 2009, EOG did not repurchase any shares under the Board-authorized repurchase program.
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ITEM 6. EXHIBITS
Bylaws, as amended and restated effective as of February 26, 2009 (incorporated by reference to Exhibit 3.2(a) to EOG's Current Report on Form 8-K filed March 4, 2009).
10.1(a)
First Amendment to Executive Employment Agreement between EOG and Mark G. Papa, effective as of March 16, 2009 (incorporated by reference to Exhibit 10.1 to EOG's Current Report on Form 8-K filed March 18, 2009).
*10.1(b)
First Amendment to Amended and Restated Change of Control Agreement between EOG and Mark G. Papa, effective as of April 30, 2009.
10.2(a)
First Amendment to Executive Employment Agreement between EOG and Loren M. Leiker, effective as of March 16, 2009 (incorporated by reference to Exhibit 10.2 to EOG's Current Report on Form 8-K filed March 18, 2009).
*10.2(b)
First Amendment to Amended and Restated Change of Control Agreement between EOG and Loren M. Leiker, effective as of April 30, 2009.
10.3(a)
First Amendment to Executive Employment Agreement between EOG and Gary L. Thomas, effective as of March 16, 2009 (incorporated by reference to Exhibit 10.3 to EOG's Current Report on Form 8-K filed March 18, 2009).
*10.3(b)
First Amendment to Amended and Restated Change of Control Agreement between EOG and Gary L. Thomas, effective as of April 30, 2009.
*10.4(a)
First Amendment to Executive Employment Agreement between EOG and Frederick J. Plaeger, II, effective as of April 30, 2009.
*10.4(b)
First Amendment to Change of Control Agreement between EOG and Frederick J. Plaeger, II, effective as of April 30, 2009.
*10.5
First Amendment to Amended and Restated Change of Control Agreement between EOG and Timothy K. Driggers, effective as of April 30, 2009.
*10.6
First Amendment to the EOG Resources, Inc. Change of Control Severance Plan, effective as of April 30, 2009.
10.7
EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred Compensation Plan - Plan Document, effective as of December 16, 2008 (incorporated by reference to Exhibit 10.2(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 2008).
10.8
EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred Compensation Plan - Adoption Agreement, dated as of December 16, 2008 (incorporated by reference to Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2008).
*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 4, 2009
By:
/s/ TIMOTHY K. DRIGGERS
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EXHIBIT INDEX
Exhibit No.
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