UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549
FORM 10-Q
(Mark One)
x
For the quarterly period ended September 30, 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
249,580,653 (as of October 27, 2008)
TABLE OF CONTENTS
PART I.
FINANCIAL INFORMATION
Page No.
ITEM 1.
Financial Statements (Unaudited)
3
4
5
6
ITEM 2.
17
ITEM 3.
32
ITEM 4.
PART II.
OTHER INFORMATION
33
ITEM 6.
34
35
36
-2-
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTSEOG RESOURCES, INC.CONSOLIDATED STATEMENTS OF INCOME(In Thousands, Except Per Share Data)(Unaudited)
Three Months Ended
Nine Months Ended
September 30,
2008
2007
Net Operating Revenues
Natural Gas
$
1,259,130
679,992
3,637,325
2,196,290
Crude Oil, Condensate and Natural Gas Liquids
574,402
258,273
1,494,043
651,833
Gains on Mark-to-Market Commodity
Derivative Contracts
1,381,733
43,591
69,067
47,893
Other, Net
4,241
4,307
152,570
29,871
Total
3,219,506
986,163
5,353,005
2,925,887
Operating Expenses
Lease and Well
151,342
120,091
422,679
347,604
Transportation Costs
78,136
39,913
203,205
109,452
Exploration Costs
37,943
38,840
145,397
106,440
Dry Hole Costs
12,849
46,046
28,062
74,672
Impairments
32,142
42,014
113,591
86,860
Depreciation, Depletion and Amortization
346,247
279,189
958,740
783,311
General and Administrative
70,893
48,101
185,459
139,163
Taxes Other Than Income
97,771
47,111
279,866
149,806
827,323
661,305
2,336,999
1,797,308
Operating Income
2,392,183
324,858
3,016,006
1,128,579
Other Income, Net
13,864
6,311
28,756
22,236
Income Before Interest Expense and Income Taxes
2,406,047
331,169
3,044,762
1,150,815
Interest Expense, Net
12,095
12,571
33,315
31,027
Income Before Income Taxes
2,393,952
318,598
3,011,447
1,119,788
Income Tax Provision
837,667
114,595
1,036,000
391,065
Net Income
1,556,285
204,003
1,975,447
728,723
Preferred Stock Dividends
-
1,637
443
3,502
Net Income Available to Common Stockholders
202,366
1,975,004
725,221
Net Income Per Share Available to Common Stockholders
Basic
6.30
0.83
8.02
2.98
Diluted
6.20
0.82
7.88
2.93
Average Number of Common Shares
247,155
243,486
246,343
243,140
250,930
247,425
250,765
247,275
The accompanying notes are an integral part of these consolidated financial statements.
-3-
EOG RESOURCES, INC.CONSOLIDATED BALANCE SHEETS(In Thousands, Except Share Data)(Unaudited)
December 31,
ASSETS
Current Assets
Cash and Cash Equivalents
885,977
54,231
Accounts Receivable, Net
1,048,385
835,670
Inventories
146,571
102,322
Assets from Price Risk Management Activities
317,994
100,912
Income Taxes Receivable
8,789
110,370
Deferred Income Taxes
33,533
Other
68,801
55,001
2,476,517
1,292,039
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)
20,216,168
16,981,836
Other Property, Plant and Equipment
901,209
581,402
21,117,377
17,563,238
Less: Accumulated Depreciation, Depletion and Amortization
(7,985,007)
(7,133,984)
Total Property, Plant and Equipment, Net
13,132,370
10,429,254
Long-Term Assets Held for Sale
254,376
Other Assets
223,843
113,238
Total Assets
15,832,730
12,088,907
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable
1,340,822
1,152,140
Accrued Taxes Payable
136,254
104,647
Dividends Payable
33,325
22,045
Liabilities from Price Risk Management Activities
118
3,404
200,118
108,980
Current Portion of Long-Term Debt
37,000
85,443
82,954
1,833,080
1,474,170
Long-Term Debt
1,860,000
1,185,000
Other Liabilities
512,006
368,336
2,707,684
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:
249,752,807 Shares Issued at September 30, 2008 and 249,460,000
Shares Issued at December 31, 2007
202,498
202,495
Additional Paid in Capital
369,128
221,102
Accumulated Other Comprehensive Income
314,982
466,702
Retained Earnings
8,038,477
6,156,721
Common Stock Held in Treasury, 168,395 Shares at
September 30, 2008 and 2,935,313 Shares at December 31, 2007
(5,125)
(61,903)
Total Stockholders' Equity
8,919,960
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
76,344
46,732
790,699
328,005
(135,325)
(21,080)
Mark-to-Market Commodity Derivative Contracts
Total Gains
(69,067)
(47,893)
Realized (Losses) Gains
(237,326)
99,188
14,390
20,778
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable
(219,947)
78,283
(45,354)
4,232
221,449
42,830
135,747
(22,834)
(18,756)
(7,780)
(3,397)
2,732
Changes in Components of Working Capital Associated with
Investing and Financing Activities
14,389
(44,314)
Net Cash Provided by Operating Activities
3,599,686
2,152,445
Investing Cash Flows
Additions to Oil and Gas Properties
(3,532,343)
(2,472,902)
Additions to Other Property, Plant and Equipment
(320,699)
(204,000)
Proceeds from Sales of Assets
369,669
43,972
Investing Activities
(14,501)
44,325
(1,316)
(3,966)
Net Cash Used in Investing Activities
(3,499,190)
(2,592,571)
Financing Cash Flows
Long-Term Debt Borrowings
750,000
610,000
Long-Term Debt Repayments
(38,000)
(60,000)
Dividends Paid
(81,453)
(61,253)
Redemptions of Preferred Stock
(5,395)
(10,641)
Excess Tax Benefits from Stock-Based Compensation
69,824
17,422
Treasury Stock Purchased
(11,266)
(6,497)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan
67,414
32,747
Debt Issuance Costs
(6,704)
(4,752)
112
(11)
Net Cash Provided by Financing Activities
744,532
517,015
Effect of Exchange Rate Changes on Cash
(13,282)
6,800
Increase in Cash and Cash Equivalents
831,746
83,689
Cash and Cash Equivalents at Beginning of Period
218,255
Cash and Cash Equivalents at End of Period
301,944
-5-
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 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 financi al 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 and nine months ended September 30, 2008 are not necessarily indicative of the results to be expected for the full year.
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, price swap and basis 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.
As of January 1, 2008, EOG adopted Financial Accounting Standards Board (FASB) Staff Position (FSP) FASB Interpretation (FIN) No. 39-1, "Amendment of FASB Interpretation No. 39," (FSP FIN No. 39-1) which effectively amends FIN No. 39, "Offsetting of Amounts Related to Certain Contracts." FSP FIN No. 39-1 permits the netting of fair values of derivative assets and liabilities for financial reporting purposes, if such assets and liabilities are with the same counterparty and subject to a master netting arrangement. EOG has elected to employ net presentation of derivative assets and liabilities when FSP FIN No. 39-1 conditions are met. FSP FIN No. 39-1 also requires that when derivative assets and liabilities are presented net, the fair value of the right to reclaim collateral assets (receivable) or the obligation to return cash collateral (payable) is also offset against the net fair value of the corresponding derivative. Netting collateral assets and liabilities against corresponding de rivative balances represents a change in accounting policy. At September 30, 2008 and December 31, 2007, there were no collateral assets or liabilities associated with derivative assets and liabilities.
-6-
Recently Issued Accounting Standards and Developments. In March 2008, the 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 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 Post Retirement 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 FSP on SFAS No. 157, 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. 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. FSP 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.
2. Stock-Based Compensation
During 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):
5.7
3.7
14.2
9.5
5.1
3.6
13.5
9.6
20.9
9.9
48.6
27.6
31.7
17.2
76.3
46.7
EOG's stockholders approved the EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) at the 2008 Annual Meeting of Stockholders. The 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. Under the 2008 Plan, grants may be made to employees and non-employee members of EOG's Board of Directors (Board). At September 30, 2008, approximately 4.5 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.
-7-
Stock Options and Stock Appreciation Rights and Employee Stock Purchase Plan. Participants in EOG's stock plans (including the 2008 Plan) have been or may be granted options to purchase shares of common stock of EOG. In addition, participants in EOG's stock plans (including the 2008 Plan) have been or may be granted 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 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 have not exceeded a maximum term of 10 years. EOG also has an employee stock purchase plan (ESPP) in place that allows eligible employees to se mi-annually 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 stock option 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 option pricing model. Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $11.1 million and $9.3 million for the three months ended September 30, 2008 and 2007, respectively. Such expense totaled $28.9 million and $26.5 million for the nine months ended September 30, 2008 and 2007, respectively.
Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants during the nine-month periods ended September 30, 2008 and 2007 are as follows:
Stock Options/SARs
ESPP
Weighted Average Fair Value of Grants
32.17
24.20
27.81
16.11
Expected Volatility
38.40%
30.67%
36.17%
29.76%
Risk-Free Interest Rate
2.55%
4.49%
2.79%
5.01%
Dividend Yield
0.60%
0.30%
0.50%
Expected Life
5.3 yrs
5.2 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 options, SARs and ESPP grants.
-8-
The following table sets forth the stock option and SAR transactions for the nine-month periods ended September 30, 2008 and 2007 (stock options and SARs in thousands):
September 30, 2008
September 30, 2007
Weighted
Number of
Average
Grant Price
Outstanding at January 1
9,373
41.04
10,150
35.29
Granted
1,211
90.70
1,188
73.36
Exercised (1)
(2,544)
27.99
(1,140)
27.76
Forfeited
(116)
65.67
(145)
54.97
Outstanding at September 30 (2)
7,924
52.46
10,053
40.36
Vested or Expected to Vest (3)
7,685
51.70
9,802
39.78
Exercisable at September 30 (4)
4,759
36.99
6,182
27.23
(1) The total intrinsic value of stock options/SARs exercised for the nine months ended September 30, 2008 and 2007 was $214 million and $50 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 September 30, 2008 and 2007 was $295 million and $324 million, respectively. At September 30, 2008 and 2007, the weighted average remaining contractual life was 4.8 years and 5.1 years, respectively.(3) The total intrinsic value of stock options/SARs vested or expected to vest at September 30, 2008 and 2007 was $292 million and $321 million, respectively. At September 30, 2008 and 2007, the weighted average remaining contractual life was 4.7 years and 5.1 years, respectively.(4) The total intrinsic value of stock options/SARs exercisable at September 30, 2008 and 2007 was $250 million and $279 million, respectively. At September 30, 2008 and 2007, the weighted average remaining contractual life was 4.1 years and 4.5 years, respectively.
At September 30, 2008, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $84.5 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.7 years.
Restricted Stock and Restricted Stock Units. 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 of restricted stock, common shares are released to the employee. Restricted stock units are converted into common shares upon vesting and released to the employee. Stock-based compensation expense related to restricted stock and restricted stock units totaled $20.6 million and $7.9 million for the three months ended September 30, 2008 and 2007, respectively, and $47.4 million and $20.2 million for the nine months ended September 30, 2008 and 2007, respectively.
-9-
The following table sets forth the restricted stock and restricted stock unit transactions for the nine-month periods ended September 30, 2008 and 2007 (shares and units in thousands):
Shares and
Grant Date
Units
Fair Value
3,000
50.61
2,301
36.13
788
106.88
1,120
71.08
Released (1)
(330)
20.97
(301)
19.62
(71)
69.04
(75)
52.41
3,387
66.19
3,045
50.23
At September 30, 2008, unrecognized compensation expense related to restricted stock and restricted stock units totaled $135.4 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 3.0 years.
3. Earnings Per Share
The following table sets forth the computation of Net Income Per Share Available to Common Stockholders for the three-month and nine-month periods ended September 30, 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 Shares -
2,409
2,828
2,927
2,926
Restricted Stock and Restricted Stock Units
1,366
1,111
1,495
1,209
Denominator for Diluted Earnings Per Share -
Adjusted Diluted Weighted Average Shares
Net Income Per Share Available to Common
Stockholders
-10-
The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive. The excluded stock options and SARs totaled 40,800 and 2.5 million for the three months ended September 30, 2008 and 2007, respectively, and 21,170 and 3.7 million for the nine months ended September 30, 2008 and 2007, respectively.
4. Supplemental Cash Flow Information
Cash paid for interest and income taxes for the nine-month periods ended September 30, 2008 and 2007 was as follows (in thousands):
Interest
46,309
26,551
Income Taxes
76,412
80,009
5. Comprehensive Income
The following table presents the components of EOG's comprehensive income for the three-month and nine-month periods ended September 30, 2008 and 2007 (in thousands):
Comprehensive Income
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments
(87,094)
120,246
(148,371)
268,735
Foreign Currency Swap Transaction
(1,533)
1,965
(4,502)
7,318
Income Tax Benefit (Provision) Related
to Foreign Currency Swap Transaction
392
(666)
1,137
(2,371)
Defined Benefit Pension and
Postretirement Plans
37
105
114
Income Tax Provision Related to Defined
Benefit Pension and Postretirement Plans
(13)
(89)
1,468,072
325,585
1,823,727
1,002,519
-11-
6. Segment Information
Selected financial information by reportable segment is presented below for the three-month and nine-month periods ended September 30, 2008 and 2007 (in thousands):
United States
2,880,857
765,959
4,386,867
2,217,617
Canada
206,237
128,502
591,752
430,795
Trinidad
118,425
79,315
333,440
240,253
Other International (1)
13,987
12,387
40,946
37,222
Operating Income (Loss)
2,196,363
273,786
2,491,392
828,844
101,186
14,987
276,509
143,922
95,946
42,619
248,507
159,019
(1,312)
(6,534)
(402)
(3,206)
Reconciling Items
(1) Other International primarily includes EOG's United Kingdom and China operations.
Total assets by reportable segment are presented below at September 30, 2008 and December 31, 2007 (in thousands):
At
11,932,842
8,687,320
2,828,574
2,649,925
950,170
692,353
121,144
59,309
-12-
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 nine-month periods ended September 30, 2008 and 2007 (in thousands):
Carrying Amount at Beginning of Period
211,124
182,407
Liabilities Incurred
31,312
12,767
Liabilities Settled
(18,734)
(4,768)
Accretion
10,262
7,616
Revisions (1)
131,098
(126)
Foreign Currency Translations
(4,297)
1,442
Carrying Amount at End of Period
360,765
199,338
Current Portion
17,619
8,709
Noncurrent Portion
343,146
190,629
(1) Revisions to asset retirement obligations recognized during the first nine months of 2008 primarily reflect increases 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.
8. Suspended Well Costs
EOG's net changes in suspended well costs for the nine-month period ended September 30, 2008 in accordance with FSP No. 19-1, "Accounting for Suspended Well Costs," are presented below (in thousands):
Nine Months
Ended
Balance at December 31, 2007
148,881
Additions Pending the Determination of Proved Reserves
144,516
Reclassifications to Proved Properties
(105,337)
Charged to Dry Hole Costs
(9,567)
(7,066)
Balance at September 30, 2008
171,427
-13-
The following table provides an aging of suspended well costs at September 30, 2008 (in thousands, except project count):
Capitalized exploratory well costs that have been
capitalized for a period less than one year
120,128
capitalized for a period greater than one year
51,299
(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 ($39.1 million) and an outside-operated offshore Central North Sea project in the United Kingdom ($12.2 million). In the B.C. projects, further reserve evaluations will be made based on ongoing drilling and completion activities. In addition, EOG is evaluating infrastructure alternatives for the B.C. shale projects. In the Central North Sea project, EOG is planning a phased development and considering alternative export routes. 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.
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 nine months ended September 30, 2008 and 2007, EOG's total costs recognized for these pension plans were $14.4 million and $11.6 million, respectively.
In addition, as more fully discussed in Note 6 to Consolidated Financial Statements in EOG's 2007 Annual Report, EOG's subsidiaries in Canada, Trinidad and the United Kingdom maintain various pension and savings plans for most of their respective employees. For the nine months ended September 30, 2008 and 2007, combined contributions to these pension plans were $1.9 million and $1.5 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 nine months ended September 30, 2008, EOG's total contributions to these plans amounted to approximately $85,000. The net periodic benefit costs recognized for the postretirement medical and dental plans were approximately $526,000 and $536,000 for the nine months ended September 30, 2008 and 2007, respectively.
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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 September 30, 2008. The weighted average interest rates for commercial paper and uncommitted credit facility borrowings for the nine months ended September 30, 2008 were 3.18% and 3.36%, respectively.
On September 30, 2008, EOG completed its public offering of $400 million aggregate principal amount of 6.125% Senior Notes due 2013 and $350 million aggregate principal amount of 6.875% Senior Notes due 2018 (Notes). Interest on the Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning April 1, 2009. Net proceeds from the offering of approximately $743 million (a portion of which was used to repay the then outstanding commercial paper and borrowings under other uncommitted credit facilities) will be used for general corporate purposes.
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 September 30, 2008, $37 million remained outstanding under the Credit Agreement. The applicable Eurodollar rate at September 30, 2008 was 3.58%. The weighted average Eurodollar rate for the amounts outstanding during the first nine months of 2008 was 3.39%.
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.
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. On July 28, 2008, the Board increased the quarterly cash dividend on EOG's common stock from the previous $0.12 per share to $0.135 per share effective with the dividend payable on October 31, 2008 to record holders as of October 17, 2008.
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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 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 are unobservable inputs and h ave 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 FSP 157-2, 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."
The following table provides fair value measurement information within the hierarchy for EOG's financial assets and liabilities at September 30, 2008 (in millions):
At September 30, 2008
Fair Value Measurements Using:
Quoted
Significant
Prices in
Active
Observable
Unobservable
Markets
Inputs
(Level 1)
(Level 2)
(Level 3)
Financial Assets (Liabilities):
Crude oil and natural
gas collars, price swaps
and basis swaps
407
Foreign currency rate
swap
(48)
The estimated fair value of crude oil and 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.
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. 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 $129 million on the sale of these properties 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, 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.
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 nine months of 2008 as compared to 82% in the same period of 2007. For the first nine months of 2008, crude oil and natural gas liquids production accounted for approximately 18% of total company production as compared to 15% 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 nine months of 2008. EOG's major producing areas are in New Mexico, North Dakota, Texas, Utah, Wyoming, Trinidad and western Canada.
In the third quarter of 2008, EOG commenced production in its British Columbia shale gas play. EOG holds approximately 150,000 net acres in this play and expects significant production beginning in 2011, pending the construction of additional infrastructure.
In the first nine months of 2008, EOG's Trinidad operations realized higher prices for natural gas sales as compared to the same period of 2007. This increase was due to higher ammonia, methanol and liquefied natural gas prices as certain of EOG's contracts provide for prices which are either entirely or partially dependent upon the prices of these commodities.
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 discovery in the Central North Sea Block 23/16f. A phased development and alternative export routes are being considered and a development plan decision is expected in early 2009.
On July 1, 2008, EOG acquired rights under a Petroleum Contract covering the Chuanzhong Block exploration area in Sichuan Basin, Sichuan Province, The People's Republic of China from ConocoPhillips. The acquisition includes production of approximately 9 million cubic feet equivalent per day, net, on 130,000 acres.
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 18% at September 30, 2008 compared to 14% at December 31, 2007. During the first nine months of 2008, EOG funded $4.0 billion in exploration and development and other property, plant and equipment expenditures, paid $81 million in dividends to common and preferred stockholders, repaid $38 million of debt and paid $5 million for the redemption of all remaining shares of its outstanding 7.195% Fixed Rate Cumulative Senior Perpetual Preferred Stock, Series B, primarily by utilizing cash provided from its operating activities and proceeds from the sale of its Appalachian properties. On September 30, 2008, EOG completed its public offering of $400 million aggregate principal amount of 6.125% Senior Notes due 2013 and $350 million aggregate principal amount of 6.875% Senior Notes due 2018 (Notes). Interest on the Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning April 1, 2009. Net proceeds from the offering of approximately $743
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million (a portion of which was used to repay the then outstanding commercial paper and borrowings under other uncommitted credit facilities) will be used for general corporate purposes. Cash on hand increased to $886 million at September 30, 2008 from $54 million at December 31, 2007. Management continues to assess price forecast and demand trends for the remainder of 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 $5.0 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 and nine months ended September 30, 2008 and 2007 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included in this Quarterly Report on Form 10-Q.
Three Months Ended September 30, 2008 vs. Three Months Ended September 30, 2007
Net Operating Revenues. During the third quarter of 2008, net operating revenues increased $2,234 million, or 227%, to $3,220 million from $986 million for the same period of 2007. Total wellhead revenues for the third quarter of 2008, which are revenues generated from sales of natural gas, crude oil, condensate and natural gas liquids, increased $895 million, or 95%, to $1,833 million from $938 million for the same period of 2007. During the third quarter of 2008, EOG recognized a net gain on mark-to-market commodity derivative contracts of $1,382 million compared to a net gain of $44 million for the same period of 2007.
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Wellhead volume and price statistics for the three-month periods ended September 30, 2008 and 2007 were as follows:
Natural Gas Volumes (MMcfd) (1)
1,196
997
224
216
240
262
Other International (4)
19
22
1,679
1,497
Average Natural Gas Prices ($/Mcf) (2)
8.99
5.52
8.15
5.49
4.04
2.20
7.41
5.89
Composite
4.94
Crude Oil and Condensate Volumes (MBbld) (1)
41.8
25.3
3.0
2.4
3.4
4.2
0.1
48.3
32.0
Average Crude Oil and Condensate Prices ($/Bbl) (2)
109.86
70.86
109.71
69.99
111.39
67.03
112.77
66.96
109.96
70.27
Natural Gas Liquids Volumes (MBbld) (1)
13.2
10.8
1.1
0.9
14.3
11.7
Average Natural Gas Liquids Prices ($/Bbl) (2)
69.79
47.94
64.01
46.71
69.33
47.84
Natural Gas Equivalent Volumes (MMcfed) (3)
1,525
1,213
249
236
261
288
20
2,055
1,759
Total Bcfe (3)
189.1
161.9
(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.(4) Other International includes EOG's United Kingdom and China operations.
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Wellhead natural gas revenues for the third quarter of 2008 increased $579 million, or 85%, to $1,259 million from $680 million for the same period of 2007. The increase was due to a higher composite average wellhead natural gas price ($496 million) and increased natural gas deliveries ($83 million). The composite average wellhead price for natural gas increased 65% to $8.15 per Mcf for the third quarter of 2008 from $4.94 per Mcf for the same period of 2007.
Natural gas deliveries increased 182 MMcfd, or 12%, to 1,679 MMcfd for the third quarter of 2008 from 1,497 MMcfd for the same period of 2007. The increase was due primarily to higher production in the United States (199 MMcfd) and Canada (8 MMcfd), partially offset by decreased production in Trinidad (22 MMcfd) and the United Kingdom (10 MMcfd). The increase in the United States was primarily attributable to increased production in Texas (133 MMcfd), the Rocky Mountain area (61 MMcfd) and Mississippi (8 MMcfd), partially offset by decreased production due to the February 2008 sale of the Appalachian assets (17 MMcfd). The decline in Trinidad was due primarily to reduced deliveries due to lower demand in 2008. The decrease in the United Kingdom was due primarily to production declines in both the Arthur and Valkyrie fields.
Wellhead crude oil and condensate revenues for the third quarter of 2008 increased $276 million, or 134%, to $483 million from $207 million for the same period of 2007. The increase was due to a higher composite average wellhead crude oil and condensate price ($174 million) and increased wellhead crude oil and condensate deliveries ($102 million). The composite average wellhead crude oil and condensate price increased 56% to $109.96 per barrel for the third quarter of 2008 from $70.27 per barrel for the same period of 2007. The increase in deliveries was primarily due to increased production in North Dakota.
Natural gas liquids revenues for the third quarter of 2008 increased $40 million, or 77%, to $91 million from $51 million for the same period of 2007. The increase was due to a higher composite average price ($28 million) and increased deliveries ($12 million). The composite average natural gas liquids price for the third quarter of 2008 increased 45% to $69.33 per barrel from $47.84 per barrel for the same period of 2007. The increase in deliveries primarily reflects increased production in the Fort Worth Basin Barnett Shale Play.
During the third quarter of 2008, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $1,382 million compared to a net gain of $44 million for the same period of 2007. During the third quarter of 2008, the net cash outflow related to settled natural gas and crude oil financial price swap contracts was $122 million compared to a cash inflow of $33 million for the same period of 2007.
Operating and Other Expenses. For the third quarter of 2008, operating expenses of $827 million were $166 million higher than the $661 million incurred in the third quarter of 2007. The following table presents the costs per Mcfe for the three-month periods ended September 30, 2008 and 2007:
0.80
0.74
0.41
0.25
Depreciation, Depletion and Amortization (DD&A)
1.83
1.73
General and Administrative (G&A)
0.38
0.30
0.06
0.08
Total Per-Unit Costs (1)
3.48
3.10
(1) Total per-unit costs do not include exploration costs, dry hole costs, impairments and taxes other than income.
The primary factors impacting the cost components of the per-unit rates of lease and well, transportation costs, DD&A and G&A for the three months ended September 30, 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 fluctuate 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 $151 million for the third quarter of 2008 increased $31 million from $120 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($22 million) and higher lease and well administrative expenses ($9 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.
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 $346 million for the third quarter of 2008 increased $67 million from $279 million for the same prior year period primarily due to increased production in the United States ($58 million) and Canada ($2 million) and increased DD&A rates in Canada ($6 million) and the United States ($2 million), partially offset by decreased production in the United Kingdom ($3 million).
G&A expenses of $71 million for the third quarter of 2008 increased $23 million from $48 million for the same prior year period primarily due to higher employee-related costs.
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 $32 million for the third quarter of 2008 decreased $10 million from $42 million for the same prior year period primarily due to lower SFAS No. 144 related impairments in Canada ($21 million), related to the impairment of the Northwest Territories discovery during the third quarter of 2007, partially offset by increased amortization of unproved leases in the United States ($6 million) and increased SFAS No. 144 related impairments in the United States ($4 million). Under SFAS No. 144, EOG recorded impairments of $7 million and $24 million for the third 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.
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Taxes other than income for the third quarter of 2008 increased $51 million to $98 million (5.3% of wellhead revenues) from $47 million (5.0% of wellhead revenues) for the same prior year period primarily due to an increase in severance/production taxes in the United States as a result of increased wellhead revenues ($32 million), a decrease in credits taken in 2008 for Texas high cost gas severance tax rate reductions ($12 million) and increased ad valorem/production taxes in the United States ($6 million).
Other income, net was $14 million for the third quarter of 2008 compared to $6 million for the same prior year period. The increase of $8 million was due primarily to increased equity income from Nitrogen (2000) Unlimited (Nitro2000) ($3 million) and Carribean Nitrogen Company Limited (CNCL) Ammonia Plants ($3 million).
Income tax provision of $838 million for the third quarter of 2008 increased $723 million compared to $115 million for the same prior year period due primarily to increased pretax income. The net effective tax rate for the third quarter of 2008 decreased to 35% from 36% for the same prior year period.
Nine Months Ended September 30, 2008 vs. Nine Months Ended September 30, 2007
Net Operating Revenues. During the first nine months of 2008, net operating revenues increased $2,427
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Wellhead volume and price statistics for the nine-month periods ended September 30, 2008 and 2007 were as follows:
Natural Gas Volumes (MMcfd)
1,141
958
218
223
229
255
Other International
16
25
1,604
1,461
Average Natural Gas Prices ($/Mcf)
9.15
6.19
8.33
6.22
3.86
2.35
8.90
5.29
8.28
5.51
Crude Oil and Condensate Volumes (MBbld)
35.9
23.6
2.7
42.1
30.3
Average Crude Oil and Condensate Prices ($/Bbl)
107.36
62.52
104.57
60.54
103.80
67.22
104.66
61.57
106.89
63.01
Natural Gas Liquids Volumes (MBbld)
14.7
10.3
1.0
15.7
11.3
Average Natural Gas Liquids Prices ($/Bbl)
63.08
43.73
62.45
41.52
63.04
43.52
Natural Gas Equivalent Volumes (MMcfed)
1,445
1,161
244
250
280
1,951
1,710
Total Bcfe
534.5
466.8
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Wellhead natural gas revenues for the first nine months of 2008 increased $1,441 million, or 66%, to $3,637 million from $2,196 million for the same period of 2007. The increase was due to a higher composite average wellhead natural gas price ($1,217 million) and increased natural gas deliveries ($224 million). The composite average wellhead price for natural gas increased 50% to $8.28 per Mcf for the first nine months of 2008 from $5.51 per Mcf for the same period of 2007.
Natural gas deliveries increased 143 MMcfd, or 10%, to 1,604 MMcfd for the first nine months of 2008 from 1,461 MMcfd for the same period of 2007. The increase was mainly due to higher production in the United States (183 MMcfd), partially offset by decreased production in Trinidad (26 MMcfd), the United Kingdom (12 MMcfd) and Canada (5 MMcfd). The increase in the United States was primarily attributable to increased production in Texas (135 MMcfd), the Rocky Mountain area (45 MMcfd), Mississippi (11 MMcfd) and Kansas (5 MMcfd), partially offset by decreased production due to the February 2008 sale of the Appalachian assets (14 MMcfd). The decline in Trinidad was due primarily to decreased deliveries as a result of plant shutdowns due to maintenance activities (18 MMcfd) and reduced deliveries due to lower demand in 2008 (14 MMcfd), partially offset by increased deliveries to Atlantic LNG Train 4 (6 MMcfd). The decrease in the United Kingdom was due primarily to production declines in both the Arthur and Valkyrie fields.
Wellhead crude oil and condensate revenues for the first nine months of 2008 increased $705 million, or 136%, to $1,223 million from $518 million for the same period of 2007. The increase was due to a higher composite average wellhead crude oil and condensate price ($502 million) and increased wellhead crude oil and condensate deliveries ($203 million). The composite average wellhead crude oil and condensate price increased 70% to $106.89 per barrel for the first nine months of 2008 from $63.01 per barrel for the same period of 2007. The increase in deliveries was primarily due to increased production in North Dakota.
Natural gas liquids revenues for the first nine months of 2008 increased $137 million, or 102%, to $271 million from $134 million for the same period of 2007. The increase was due to a higher composite average price ($84 million) and increased deliveries ($53 million). The composite average natural gas liquids price for the first nine months of 2008 increased 45% to $63.04 per barrel from $43.52 per barrel for the same period of 2007. The increase in deliveries primarily reflects increased production in the Fort Worth Basin Barnett Shale Play.
During the first nine months of 2008, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $69 million compared to a net gain of $48 million for the same period of 2007. During the first nine months of 2008, the net cash outflow related to settled natural gas and crude oil financial price swap contracts was $237 million compared to a net cash inflow of $99 million for the same period of 2007.
Operating and Other Expenses. For the first nine months of 2008, operating expenses of $2,337
0.79
0.75
0.24
DD&A
1.80
1.68
G&A
0.35
0.07
Total Per-Unit Costs(1)
3.38
3.04
The primary factors impacting the cost components of the per-unit rates of lease and well, transportation costs, DD&A, G&A and interest expense, net for the nine months ended September 30, 2008 compared to the same period of 2007 are set forth below.
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Lease and well expenses of $423 million for the first nine months of 2008 increased $75 million from $348 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($51 million) and higher lease and well administrative expenses ($25 million).
DD&A expenses of $959 million for the first nine months of 2008 increased $176 million from $783 million for the same prior year period primarily due to increased production in the United States ($154 million), increased DD&A rates in Canada ($11 million) and the United States ($9 million) and changes in the Canadian exchange rate ($11 million), partially offset by decreased production ($8 million) and DD&A rates ($3 million) in the United Kingdom.
G&A expenses of $185 million for the first nine months of 2008 increased $46 million from $139 million for the same prior year period primarily due to higher employee-related expenses ($37 million) and an increase in legal fees and other professional services ($7 million).
Interest expense, net was $33 million for the first nine months of 2008, up $2 million compared to $31 million for the same prior year period primarily due to a higher average debt balance ($11 million), partially offset by higher capitalized interest ($9 million).
Exploration costs of $145 million for the first nine months of 2008 increased $39 million from $106 million for the same prior year period primarily due to increased geological and geophysical expenditures in the United States ($27 million) and higher employee-related costs ($9 million). The increase in geological and geophysical expenditures in the United States was primarily attributable to the Fort Worth Basin Barnett Shale Play ($16 million).
Impairments of $114 million for the first nine months of 2008 increased $27 million from $87 million for the same prior year period primarily due to a SFAS No. 144 related impairment in Trinidad as a result of EOG's relinquishment of its rights to Block Lower Reverse "L" ($20 million) and increased amortization of unproved leases in the United States ($18 million) and Canada ($9 million), partially offset by decreased SFAS No. 144 related impairments in Canada ($20 million). Under SFAS No. 144, EOG recorded impairments of $40 million for each of the nine-month periods ended September 30, 2008 and 2007.
Taxes other than income for the first nine months of 2008 increased $130 million to $280 million (5.5% of wellhead revenues) from $150 million (5.3% of wellhead revenues) for the same prior year period primarily due to increases in the United States ($124 million) and Trinidad ($3 million). In the United States, the increase was due primarily to an increase in severance/production taxes as a result of increased wellhead revenues ($89 million), a decrease in credits taken for Texas high cost gas severance tax rate reductions ($28 million), increased ad valorem/production taxes ($13 million) and increased payroll taxes ($4 million), partially offset by decreased franchise taxes ($10 million).
Other income, net was $29 million for the first nine months of 2008 compared to $22 million for the same prior year period. The increase of $7 million was primarily due to higher equity income from Nitro2000 ($6 million).
Income tax provision of $1,036 million for the first nine months of 2008 increased $645 million compared to $391 million for the same prior year period due primarily to increased pretax income. The net effective tax rate for the first nine months of 2008 decreased to 34% from 35% for the same prior year period.
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Capital Resources and Liquidity
Cash Flow. The primary sources of cash for EOG during the nine months ended September 30, 2008 were funds generated from operations, the issuance of long-term debt, proceeds from the sale of its producing shallow gas assets and surrounding acreage in the Appalachian Basin, proceeds from stock options exercised and employee stock purchase plan activity 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; dividend payments to stockholders; and Trinidad revolving credit facility repayment. During the first nine months of 2008, EOG's cash balance increased $832 million to $886 million from $54 million at December 31, 2007.
Net cash provided by operating activities of $3,600 million for the first nine months of 2008 increased $1,448 million compared to $2,152 million for the same period of 2007 primarily reflecting an increase in wellhead revenues ($2,283 million) and a decrease in cash paid for income taxes ($4 million), partially offset by an increase in cash operating expenses ($350 million), an unfavorable change in the net cash flow from the settlement of financial commodity derivative contracts ($337 million), unfavorable changes in working capital and other assets and liabilities ($128 million) and an increase in cash paid for interest expense ($20 million).
Net cash used in investing activities of $3,499 million for the first nine months of 2008 increased by $906 million compared to $2,593 million for the same period of 2007 due primarily to an increase in additions to oil and gas properties ($1,059 million) and an increase in additions to other property, plant and equipment ($117 million), partially offset by an increase in proceeds from sales of assets ($326 million), primarily reflecting net proceeds from the sale of EOG's Appalachian assets.
Net cash provided by financing activities was $745 million for the first nine months of 2008 compared to $517 million for the same period of 2007. Cash provided by financing activities for the first nine months of 2008 included the issuance of long-term debt ($750 million), excess tax benefits from stock-based compensation ($70 million) and proceeds from stock options exercised and employee stock purchase plan activity ($67 million). Cash used by financing activities for the first nine months of 2008 included cash dividend payments ($81 million), Trinidad revolving credit facility repayment ($38 million), treasury stock purchased ($11 million), debt issuance costs ($7 million) and the redemption of preferred stock ($5 million).
Total Expenditures. The table below sets out components of total expenditures for the nine-month periods ended September 30, 2008 and 2007 (in millions):
Expenditure Category
Capital
Drilling and Facilities
2,988
2,171
Leasehold Acquisitions
377
212
Producing Property Acquisitions
109
2
Capitalized Interest
30
21
Subtotal
3,504
2,406
145
106
28
75
Exploration and Development Expenditures
3,677
2,587
Asset Retirement Costs
164
15
Total Exploration and Development Expenditures
3,841
2,602
321
204
Total Expenditures
4,162
2,806
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Exploration and development expenditures of $3,677 million for the first nine months of 2008 increased $1,090 million from $2,587 million for the same period of 2007 due primarily to increased drilling and facilities expenditures in the United States ($852 million), increased lease acquisitions in Canada ($82 million) and the United States ($81 million), increased producing property acquisitions ($107 million) and changes in the Canadian exchange rate ($27 million), partially offset by lower drilling and facilities expenditures in Trinidad ($30 million) and Canada ($22 million). The increased producing property acquisitions of $107 million primarily resulted from higher producing property acquisitions in the United States ($68 million), Trinidad ($15 million) and Canada ($13 million). The exploration and development expenditures for the first nine months of 2008 of $3,677 million include $2,722 million in development, $816 million in exploration, $109 million in property acquisitions and $30 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 Play and North Dakota. The exploration and development expenditures for the first nine months of 2007 of $2,587 million include $1,944 million in development, $620 million in exploration, $21 million in capitalized interest and $2 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, 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 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, price swap and basis 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 hydrocarb on prices.
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Financial Collar Contracts. The total fair value of EOG's natural gas financial collar contracts at September 30, 2008 was a positive $24 million, which is reflected as an asset in the Consolidated Balance Sheets. Presented below is a comprehensive summary of EOG's natural gas financial collar contracts at October 31, 2008. The notional volumes are expressed in million British thermal units per day (MMBtud) and prices are expressed in dollars per million British thermal units ($/MMBtu). The average floor price of EOG's outstanding natural gas financial collar contracts is $10.00 per million British thermal units (MMBtu) and the average ceiling price is $12.32 per MMBtu.
Natural Gas Financial Collar Contracts
Floor Price
Ceiling Price
Ceiling
Volume
Floor Range
Price
Range
(MMBtud)
($/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
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Financial Price Swap Contracts. The total fair value of EOG's natural gas and crude oil financial price swap contracts at September 30, 2008 was a positive $382 million, which is reflected as an asset in the Consolidated Balance Sheets. Presented below is a comprehensive summary of EOG's natural gas and crude oil financial price swap contracts at October 31, 2008. The notional volumes are expressed in MMBtud and in barrels per day (Bbld) and prices are expressed in $/MMBtu and in dollars per barrel ($/Bbl), as applicable. The average price of EOG's outstanding natural gas financial price swap contracts for 2008 is $9.03 per MMBtu, for 2009 is $9.71 per MMBtu and for 2010 is $9.87 per MMBtu. The average price of EOG's outstanding crude oil financial price swap contracts is $92.17 per barrel.
Financial Price Swap Contracts
Crude Oil
Average Price
(Bbld)
($/Bbl)
January (closed)
385,000
$ 8.92
$ -
February (closed)
420,000
8.88
6,000
90.86
March (closed)
455,000
8.64
10,000
91.02
April (closed)
8.11
14,000
92.20
May (closed)
8.10
June (closed)
8.18
July (closed)
8.26
August (closed)
September (closed)
8.36
October (closed)
8.44
November (1)
8.83
9.23
4,000
91.96
2009
585,000
$10.76
10.74
10.50
9.24
9.16
9.21
9.29
9.36
9.66
9.98
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20,000
$11.20
11.15
10.89
9.13
9.31
9.38
9.40
9.49
9.80
10.21
(1) The natural gas contracts for November 2008 are closed. The crude oil contracts for November 2008 will close on November 30, 2008.
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 September 30, 2008 was a positive $1 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 October 31, 2008. 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.
Financial Basis Swap Contracts
Average Price Differential
Second Quarter
55,000
$(2.58)
Third Quarter
(2.69)
Fourth Quarter
(3.15)
First Quarter
$(1.76)
(2.63)
(3.29)
(3.83)
2011
$(1.97)
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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 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 for ward-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 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. 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 Discussion 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 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. 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)
July 1, 2008 - July 31, 2008
330
114.47
6,386,200
August 1, 2008 - August 31, 2008
39,940
97.98
September 1, 2008 - September 30, 2008
4,783
94.14
45,053
97.69
(1) Represents 45,053
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ITEM 6. EXHIBITS
4.1 -
Officers' Certificate Establishing 6.125% Senior Notes due 2013 and 6.875% Senior Notes due 2018, dated September 30, 2008 (incorporated by reference to Exhibit 4.2 to EOG's Current Report on Form8-K, filed September 30, 2008).
4.2 -
Form of Global Note with respect to the 6.125% Senior Notes due 2013 of EOG (incorporated by reference to Exhibit 4.3 to EOG's Current Report on Form 8-K, filed September 30, 2008).
4.3 -
Form of Global Note with respect to the 6.875% Senior Notes due 2018 of EOG (incorporated by reference to Exhibit 4.4 to EOG's Current Report on Form 8-K, filed September 30, 2008).
*10.1 -
First Amendment to EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, dated effective as of September 4, 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: November 3, 2008
By:
/s/ TIMOTHY K. DRIGGERS
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EXHIBIT INDEX
Exhibit No.
Description
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