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 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 the first nine months of both 2009 and 2008. One of EOG's exploration strategies is to apply its horizontal drilling expertise gained in natural gas resource plays to unconventional oil reservoirs. During the first nine months 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 nine months of 2009, crude oil and natural gas liquids production accounted for approximately 22% of total company production as compared to approximately 18% 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.

During the third quarter of 2009, EOG completed three transactions to acquire certain crude oil and natural gas properties and related assets located in Montague and Cooke Counties, Texas (Barnett Shale Combo Assets). The Barnett Shale Combo Assets consist of proved developed and undeveloped reserves and approximately 33,000 net unproved acres. Production from these assets averaged approximately 2,300 barrels equivalent per day, net, at the time of acquisition. The aggregate purchase price of the transactions, which is subject to customary post-closing adjustments, totaled $196.7 million, consisting of cash consideration of $107.1 million and 1,450,000 shares of EOG common stock valued at $89.6 million at the closing date of the applicable transaction.

International. In the United Kingdom, EOG completed a farm-in agreement with owners of the Central North Sea Block 15/30a Area AB during the third quarter of 2009. An exploratory well, which EOG will operate with a 65% working interest, is planned for the fourth quarter of 2009. Subsequent to its June 2009 oil discovery in the East Irish Sea Block 110/12, EOG plans to drill two additional exploratory wells during the fourth quarter of 2009 and first quarter of 2010. EOG has a 100% working interest in this Block. In the Sichuan Basin, Sichuan Province, The People's Republic of China, EOG drilled a horizontal well in the third quarter of 2009 and plans to complete and test this well during the fourth quarter of 2009 and first quarter of 2010. In addition, to evaluate a different zone, EOG began drilling a second monitoring well during the third quarter of 2009 and plans to begin a second horizontal well in the fourth quarter of 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 September 30, 2009, EOG's debt-to-total capitalization ratio was 23% as compared to 17% at December 31, 2008. On May 21, 2009, EOG completed its public offering of $900 million aggregate principal amount of 5.625% Senior Notes due 2019 (Notes). Interest on the Notes is payable semi-annually in arrears on June 1 and December 1 of each year, beginning December 1, 2009. Net proceeds from the offering of approximately $891 million were used for general corporate purposes, including repayment of outstanding commercial paper borrowings. During the first nine months of 2009, EOG funded $2.7 billion in exploration and development and other property, plant and equipment expenditures (including $206 million of acquisitions) and paid $106 million in dividends to common stockholders, primarily by utilizing cash provided from its operating activities, proceeds from commercial paper and uncommitted credit facility borrowings and proceeds from the offering of the Notes.

For 2009, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $3.7 billion, including acquisitions of approximately $300 million. United States and Canada natural gas and crude oil 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 EOG 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, 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.

Three Months Ended September 30, 2009 vs. Three Months Ended September 30, 2008

Net Operating Revenues. During the third quarter of 2009, net operating revenues decreased $2,257 million, or 69%, to $1,007 million from $3,264 million for the same period of 2008. Total wellhead revenues for the third quarter of 2009, which are revenues generated from sales of natural gas, crude oil and condensate and natural gas liquids, decreased $985 million, or 54%, to $849 million from $1,834 million for the same period of 2008. During the third quarter of 2009, EOG recognized a net gain on mark-to-market commodity derivative contracts of $21 million compared to a net gain of $1,382 million for the same period of 2008. Gathering, processing and marketing revenues, which are revenues generated from sales of third-party natural gas, crude oil and natural gas liquids as well as gathering fees associated with gathering third-party natural gas, for the third quarter of 2009 increased $84 million, or 163%, to $135 million from $51 million for the same period of 2008.

Wellhead volume and price statistics for the three-month periods ended September 30, 2009 and 2008 were as follows:

                                                          Three Months Ended
                                                             September 30,
                                                           2009        2008
Natural Gas Volumes (MMcfd) (1)
       United States                                        1,128        1,196
       Canada                                                 219          224
       Trinidad                                               268          240
       Other International (2)                                 13           19
              Total                                         1,628        1,679

Average Natural Gas Prices ($/Mcf) (3)
       United States                                   $     3.27  $      8.99
       Canada                                                3.15         8.15
       Trinidad                                              1.77         4.04
       Other International (2)                               3.53         7.41
              Composite                                      3.01         8.15

Crude Oil and Condensate Volumes (MBbld) (1)
       United States                                         51.7         41.8
       Canada                                                 4.7          3.0
       Trinidad                                               3.0          3.4
       Other International (2)                                0.1          0.1
              Total                                          59.5         48.3

Average Crude Oil and Condensate Prices ($/Bbl) (3)
       United States                                   $    60.79  $    109.86
       Canada                                               61.43       109.71
       Trinidad                                             57.07       111.39
       Other International (2)                              57.93       112.77
              Composite                                     60.65       109.96

Natural Gas Liquids Volumes (MBbld) (1)
       United States                                         23.1         13.2
       Canada                                                 1.0          1.1
              Total                                          24.1         14.3

Average Natural Gas Liquids Prices ($/Bbl) (3)
       United States                                   $    31.15  $     69.79
       Canada                                               30.96        64.01
              Composite                                     31.14        69.33

Natural Gas Equivalent Volumes (MMcfed) (4)
       United States                                        1,577        1,525
       Canada                                                 253          249
       Trinidad                                               286          261
       Other International (2)                                 13           20
              Total                                         2,129        2,055

Total Bcfe (4)                                              195.9        189.1

(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, 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.

Wellhead natural gas revenues for the third quarter of 2009 decreased $809 million, or 64%, to $450 million from $1,259 million for the same period of 2008. The decrease was due to a lower composite average wellhead natural gas price ($770 million) and decreased natural gas deliveries ($39 million). EOG's composite average wellhead natural gas price decreased 63% to $3.01 per thousand cubic feet (Mcf) for the third quarter of 2009 from $8.15 per Mcf for the same period of 2008.

Natural gas deliveries for the third quarter of 2009 decreased 51 MMcfd, or 3%, to 1,628 MMcfd from 1,679 MMcfd for the same period of 2008. The decrease was primarily due to lower production in the United States (68 MMcfd), Canada (5 MMcfd) and the United Kingdom (5 MMcfd), partially offset by increased production in Trinidad (28 MMcfd). The decrease in the United States was primarily attributable to decreased production in Texas (50 MMcfd), the Rocky Mountain area (14 MMcfd), New Mexico (8 MMcfd), Kansas (5 MMcfd) and Mississippi (3 MMcfd), partially offset by increased production in Louisiana (14 MMcfd). The decrease in the United Kingdom primarily resulted from reduced production in the Arthur field. The increase in Trinidad was primarily due to increased net contractual deliveries.

Wellhead crude oil and condensate revenues for the third quarter of 2009 decreased $153 million, or 32%, to $330 million from $483 million for the same period of 2008, due to a lower composite average wellhead crude oil and condensate price ($268 million), partially offset by an increase of 11 MBbld, or 23%, in wellhead crude oil and condensate deliveries ($115 million). The increase in deliveries primarily reflects increased production in North Dakota (9 MBbld), Texas (2 MBbld) and Canada (2 MBbld). The composite average wellhead crude oil and condensate price for the third quarter of 2009 decreased 45% to $60.65 per barrel compared to $109.96 per barrel for the same period of 2008.

Natural gas liquids revenues for the third quarter of 2009 decreased $22 million, or 24%, to $69 million from $91 million for the same period of 2008, due to a lower composite average price ($84 million), partially offset by an increase of 10 MBbld, or 69%, in natural gas liquids deliveries ($62 million). The composite average natural gas liquids price for the third quarter of 2009 decreased 55% to $31.14 per barrel compared to $69.33 per barrel for the same period of 2008. The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale area (6 MBbld) and the Mid-Continent area (2 MBbld).

During the third quarter of 2009, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $21 million compared to a net gain of $1,382 million for the same period of 2008. During the third quarter of 2009, the net cash inflow related to settled natural gas financial collar, price swap and basis swap contracts was $331 million compared to the net cash outflow related to settled natural gas and crude oil financial price swap contracts of $122 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 September 30, 2009 and 2008, substantially all of such revenues were related to sales of third-party natural gas and crude oil. 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 third quarter of 2009 decreased $4 million to $3 million compared to $7 million for the same period of 2008, reflecting lower margins associated with natural gas marketing activities.

Operating and Other Expenses. For the third quarter of 2009, operating expenses of $972 million were $100 million higher than the $872 million incurred in the third quarter of 2008. The following table presents the costs per thousand cubic feet equivalent (Mcfe) for the three-month periods ended September 30, 2009 and 2008:

                                                             Three Months Ended
                                                                September 30,
                                                             2009           2008

    Lease and Well                                       $     0.73     $     0.75
    Transportation Costs                                       0.36           0.41
    Depreciation, Depletion and Amortization (DD&A) -
                     Oil and Gas Properties                    1.84           1.73
                     Other Property, Plant and Equipment       0.13           0.10
    General and Administrative (G&A)                           0.32           0.38
    Interest Expense, Net                                      0.16           0.06
       Total (1)                                         $     3.54     $     3.43

(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 interest expense, net for the three months ended September 30, 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 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 were $142 million for the third quarter of both 2009 and 2008. During 2009, increased operating and maintenance expenses in Canada ($5 million) and China ($1 million) and increased lease and well administrative expenses in Canada ($1 million) were offset by decreased lease and well administrative expenses in the United States ($3 million), decreased operating and maintenance expenses in the United States ($2 million) and changes in the Canadian exchange rate ($2 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 $71 million for the third quarter of 2009 decreased $7 million from $78 million for the same prior year period primarily due to decreased costs associated with marketing arrangements to transport production from the Fort Worth Basin Barnett Shale area ($10 million) to downstream markets, partially offset by increased costs associated with marketing arrangements to transport production from the Rocky Mountain area ($5 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 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 third quarter of 2009 increased $39 million to $385 million from $346 million for the same prior year period. DD&A expenses associated with oil and gas properties for the third quarter of 2009 were $32 million higher than the same prior year period primarily due to higher unit rates in the United States ($18 million), Trinidad ($3 million) and Canada ($3 million) and as a result of increased production in the United States ($9 million), partially offset by changes in the Canadian exchange rate ($3 million).

DD&A expenses associated with other property, plant and equipment for the third quarter of 2009 were $7 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 ($3 million) and Rocky Mountain area ($3 million).

G&A expenses of $63 million for the third quarter of 2009 decreased $8 million from the same prior year period primarily due to lower employee-related costs.

Interest expense, net of $30 million for the third quarter of 2009 increased $18 million compared to the same prior year period primarily due to a higher average debt balance ($20 million), partially offset by higher capitalized interest ($2 million).

Gathering and processing costs represent operating and maintenance expenses and administrative expenses associated with operating EOG's natural gas gathering and processing assets.

Gathering and processing costs for the third quarter of 2009 increased $4 million to $13 million as compared to the same prior year period primarily due to increased activities in the Rocky Mountain area.

Exploration costs of $45 million for the third quarter of 2009 increased $7 million from the same prior year period primarily due to increased geological and geophysical expenditures in the United States ($4 million) and the United Kingdom ($2 million).

Impairments include amortization and impairments of unproved oil and gas properties, as well as impairments of proved oil and gas properties. Unproved properties with individually significant acquisition costs are assessed on a property-by-property basis, and any impairment in value is recognized. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the average holding period. When circumstances indicate that a proved property may be impaired, EOG compares expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.

Impairments of $69 million for the third quarter of 2009 increased $37 million from $32 million for the same prior year period primarily due to increased amortization and impairments of unproved properties in the United States ($28 million) and increased impairments of proved properties in the United States ($8 million). EOG recorded impairments of proved properties of $15 million and $7 million for the third 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 for the third quarter of 2009 decreased $50 million to $48 million (5.6% of wellhead revenues) from $98 million (5.3% of wellhead revenues) for the same prior year period. The decrease in taxes other than income was primarily due to a decrease in severance/production taxes as a result of decreased wellhead revenues in the United States ($33 million) and Trinidad ($4 million) and an increase in credits taken in 2009 for Texas high cost gas severance tax rate reductions ($12 million).

Other income (expense), net for the third quarter of 2009 decreased $14 million from the same prior year period. The decrease was primarily due to lower equity income from ammonia plants in Trinidad ($7 million) and lower interest income ($3 million).

EOG recognized an income tax provision of less than $1 million for the third quarter of 2009 compared to $838 million for the same prior year period. The change was primarily due to decreased pretax income. The net effective tax rate for the third quarter of 2009 decreased to 8% from 35% for the same prior year period due primarily to lower pretax income and lower Canadian taxes.

Nine Months Ended September 30, 2009 vs. Nine Months Ended September 30, 2008

Net Operating Revenues. During the first nine months of 2009, net operating revenues decreased $2,467 million, or 45%, to $3,026 million from $5,493 million for the same period of 2008. Total wellhead revenues for the first nine months of 2009 decreased $2,767 million, or 54%, to $2,364 million from $5,131 million for the same period of 2008. During the first nine months of 2009, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $406 million compared to a net gain of $69 million for the same period of 2008. Gathering, processing and marketing revenues for the first nine months of 2009 increased $99 million, or 66%, to $250 million from $151 million for the same period of 2008. Other, net operating revenues in 2008 primarily consist of a gain of $128 million on the sale of EOG's Appalachian assets in February 2008.

Wellhead volume and price statistics for the nine-month periods ended September 30, 2009 and 2008 were as follows:

                                                       Nine Months Ended
                                                         September 30,
                                                       2009        2008
Natural Gas Volumes (MMcfd)
       United States                                    1,153        1,141
       Canada                                             224          218
       Trinidad                                           266          229
       Other International                                 15           16
              Total                                     1,658        1,604

Average Natural Gas Prices ($/Mcf)
       United States                               $     3.57  $      9.15
       Canada                                            3.67         8.33
       Trinidad                                          1.54         3.86
       Other International                               4.45         8.90
              Composite                                  3.27         8.28

Crude Oil and Condensate Volumes (MBbld)
       United States                                     46.5         35.9
       Canada                                             3.6          2.7
       Trinidad                                           3.0          3.4
       Other International                                0.1          0.1
              Total                                      53.2         42.1

Average Crude Oil and Condensate Prices ($/Bbl)
       United States                               $    49.54  $    107.36
       Canada                                           51.91       104.57
       Trinidad                                         46.13       103.80
       Other International                              50.11       104.66
              Composite                                 49.51       106.89

Natural Gas Liquids Volumes (MBbld)
       United States                                     22.2         14.7
       Canada                                             1.1          1.0
              Total                                      23.3         15.7

Average Natural Gas Liquids Prices ($/Bbl)
       United States                               $    26.42  $     63.08
       Canada                                           27.29        62.45
              Composite                                 26.46        63.04

Natural Gas Equivalent Volumes (MMcfed)
       United States                                    1,566        1,445
       Canada                                             252          240
       Trinidad                                           284          250
       Other International                                 15           16
              Total                                     2,117        1,951

Total Bcfe                                              578.1        534.5
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