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 both the first six months of 2009 and the first six months of 2008. One of EOG's exploration strategies is to apply its horizontal drilling expertise gained in natural gas resources plays to unconventional oil reservoirs. During the first six 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 six months of 2009, crude oil and natural gas liquids production accounted for approximately 21% of total company production as compared to 17% for the comparable period in 2008. Based on current trends, EOG expects its 2009 crude oil and natural gas liquids production to continue to increase as compared to 2008. EOG's major producing areas are in Louisiana, New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.

In June 2009, EOG entered into an agreement 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 25,000 net unproved acres. Production from these assets has averaged approximately 2,000 barrels equivalent per day, net. The purchase price, which is subject to customary post-closing adjustments, totaled $134.1 million, consisting of cash consideration of $44.5 million and 1,450,000 shares of EOG common stock with a closing date fair market value of $89.6 million. The transaction closed on July 8, 2009.

International. In the United Kingdom, EOG drilled two operated exploratory wells in the East Irish Sea during the second quarter of 2009. The first exploratory well in Block 110/14d was unsuccessful. The second exploratory well in Block 110/12 resulted in an oil discovery. Additional drilling is planned for this block, in which EOG has a 100% working interest, in late 2009. In the Sichuan Basin, Sichuan Province, The People's Republic of China, EOG completed a monitoring well in the second quarter of 2009 and began drilling a horizontal well in June 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 June 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 six months of 2009, EOG funded $1.7 billion in exploration and development and other property, plant and equipment expenditures and paid $70 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 $3.3 billion, including acquisitions of approximately $140 million. United States and Canada natural gas and crude oil drilling activity continues to be a key component of these expenditures. EOG intends to manage the 2009 capital budget while maintaining a strong balance sheet. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer EOG incremental exploration and/or production opportunities. Management continues to believe EOG has one of the strongest prospect inventories in EOG's history.

Results of Operations

The following review of operations for the three and six months ended June 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 June 30, 2009 vs. Three Months Ended June 30, 2008

Net Operating Revenues. During the second quarter of 2009, net operating revenues decreased $235 million, or 21%, to $861 million from $1,096 million for the same period of 2008. Total wellhead revenues for the second quarter of 2009, which are revenues generated from sales of EOG's production of natural gas, crude oil and condensate and natural gas liquids, decreased $1,118 million, or 60%, to $747 million from $1,865 million for the same period of 2008. During the second quarter of 2009, EOG recognized a net gain on mark-to-market commodity derivative contracts of $34 million compared to a loss of $843 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 second quarter of 2009 increased $13 million, or 21%, to $77 million from $64 million for the same period of 2008.

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

                                                          Three Months Ended
                                                               June 30,
                                                           2009        2008
Natural Gas Volumes (MMcfd) (1)
       United States                                        1,139        1,139
       Canada                                                 225          215
       Trinidad                                               266          217
       Other International (2)                                 15           12
              Total                                         1,645        1,583

Average Natural Gas Prices ($/Mcf) (3)
       United States                                   $     3.37  $     10.36
       Canada                                                3.40         9.42
       Trinidad                                              1.51         3.64
       Other International (2)                               3.55         9.95
              Composite                                      3.07         9.31

Crude Oil and Condensate Volumes (MBbld) (1)
       United States                                         42.9         35.4
       Canada                                                 2.9          2.6
       Trinidad                                               3.0          3.2
       Other International (2)                                0.1            -
              Total                                          48.9         41.2

Average Crude Oil and Condensate Prices ($/Bbl) (3)
       United States                                   $    52.82  $    117.60
       Canada                                               52.52       112.55
       Trinidad                                             47.50       113.29
       Other International (2)                              46.75       114.40
              Composite                                     52.47       116.94

Natural Gas Liquids Volumes (MBbld) (1)
       United States                                         22.1         14.2
       Canada                                                 1.0          0.9
              Total                                          23.1         15.1

Average Natural Gas Liquids Prices ($/Bbl) (3)
       United States                                   $    25.60  $     63.62
       Canada                                               25.60        66.39
              Composite                                     25.60        63.78

Natural Gas Equivalent Volumes (MMcfed) (4)
       United States                                        1,529        1,437
       Canada                                                 249          236
       Trinidad                                               284          236
       Other International (2)                                 15           12
              Total                                         2,077        1,921

Total Bcfe (4)                                              189.0        174.8

(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) Other International includes EOG's United Kingdom operations and, effective July 1, 2008, EOG's China operations.
(3) Dollars per thousand cubic feet or per barrel, as applicable.
(4) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable; includes natural gas, crude oil and condensate and natural gas liquids. Natural gas equivalents are determined using the ratio of 6.0 thousand cubic feet of natural gas to 1.0 barrel of crude oil and condensate or natural gas liquids.

Wellhead natural gas revenues for the second quarter of 2009 decreased $881 million, or 66%, to $460 million from $1,341 million for the same period of 2008. The decrease was due to a lower composite average wellhead natural gas price ($933 million), partially offset by increased natural gas deliveries ($52 million). EOG's composite average wellhead natural gas price decreased 67% to $3.07 per thousand cubic feet (Mcf) for the second quarter of 2009 from $9.31 per Mcf for the same period of 2008.

Natural gas deliveries for the second quarter of 2009 increased 62 MMcfd, or 4%, to 1,645 MMcfd from 1,583 MMcfd for the same period of 2008. The increase was primarily due to higher production in Trinidad (49 MMcfd) and Canada (10 MMcfd). The increase in Trinidad was primarily due to increased net contractual deliveries and reduced plant shutdowns for maintenance during 2009. The increase in Canada was primarily attributable to British Columbia Horn River Basin production.

Wellhead crude oil and condensate revenues for the second quarter of 2009 decreased $204 million, or 47%, to $233 million from $437 million for the same period of 2008, due to a lower composite average wellhead crude oil and condensate price ($287 million), partially offset by an increase of 8 MBbld, or 19%, in wellhead crude oil and condensate deliveries ($83 million). The increase in deliveries primarily reflects increased production in North Dakota. The composite average wellhead crude oil and condensate price for the second quarter of 2009 decreased 55% to $52.47 per barrel compared to $116.94 per barrel for the same period of 2008.

Natural gas liquids revenues for the second quarter of 2009 decreased $34 million, or 39%, to $54 million from $88 million for the same period of 2008, due to a lower composite average price ($80 million), partially offset by an increase of 8 MBbld, or 53%, in natural gas liquids deliveries ($46 million). The composite average natural gas liquids price for the second quarter of 2009 decreased 60% to $25.60 per barrel compared to $63.78 per barrel for the same period of 2008. The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale area.

During the second quarter of 2009, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $34 million compared to a loss of $843 million for the same period of 2008. During the second quarter of 2009, the net cash inflow related to settled natural gas financial collar, price swap and basis swap contracts was $345 million compared to the cash outflow related to settled natural gas and crude oil financial price swap contracts of $138 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 June 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 second quarter of 2009 were $2 million higher compared to the same period of 2008. The increase resulted primarily from increased natural gas marketing operations in the Gulf Coast area.

Operating and Other Expenses. For the second quarter of 2009, operating expenses of $861 million were $9 million higher than the $852 million incurred in the second quarter of 2008. The following table presents the costs per thousand cubic feet equivalent (Mcfe) for the three-month periods ended June 30, 2009 and 2008:

                                                            Three Months Ended
                                                                 June 30,
                                                            2009           2008

    Lease and Well                                      $     0.71     $     0.74
    Transportation Costs                                      0.35           0.36
    Depreciation, Depletion and Amortization (DD&A) -
       Oil and Gas Properties                                 1.86           1.71
       Other Property, Plant and Equipment                    0.12           0.09
    General and Administrative (G&A)                          0.31           0.35
    Interest Expense, Net                                     0.13           0.05
       Total (1)                                        $     3.48     $     3.30

(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 June 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 of $135 million for the second quarter of 2009 increased $5 million from $130 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($9 million) and Canada ($2 million), partially offset by changes in the Canadian exchange rate ($4 million) and decreased expenditures for workovers in the United States ($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 $66 million for the second quarter of 2009 increased $3 million from $63 million for the same prior year period primarily due to increased production and costs associated with marketing arrangements to transport production from the Rocky Mountain area ($2 million) and the South Texas area ($2 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 second quarter of 2009 increased $61 million to $376 million from $315 million for the same prior year period. DD&A expenses associated with oil and gas properties for the second quarter of 2009 were $53 million higher than the same prior year period primarily due to higher unit rates in the United States ($29 million), Trinidad ($3 million) and Canada ($3 million) and as a result of increased production in the United States ($16 million) and in Canada ($2 million), partially offset by changes in the Canadian exchange rate ($7 million).

DD&A expenses associated with other property, plant and equipment for the second quarter of 2009 were $8 million higher than the same prior year period primarily due to increased expenditures associated with natural gas gathering systems and processing plants in the Fort Worth Basin Barnett Shale area ($5 million) and Rocky Mountain area ($2 million).

G&A expenses of $59 million for the second quarter of 2009 decreased $3 million from the same prior year period primarily due to lower employee-related costs ($4 million), partially offset by higher insurance costs ($1 million).

Interest expense, net of $25 million for the second quarter of 2009 increased $16 million compared to the same prior year period primarily due to a higher average debt balance ($18 million), partially offset by higher capitalized interest ($2 million).

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

Gathering and processing costs for the second quarter of 2009 increased $5 million to $14 million as compared to the same prior year period primarily due to increased activities in the Rocky Mountain area ($3 million) and Fort Worth Basin Barnett Shale area ($1 million).

Exploration costs of $34 million for the second quarter of 2009 decreased $25 million from the same prior year period primarily due to decreased geological and geophysical expenditures in the United States ($22 million) and the United Kingdom ($3 million).

Impairments include amortization of unproved leases, as well as impairments under Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144), which requires an entity to compute impairments to the carrying value of long-lived assets based on future cash flow analysis. Impairments of $47 million for the second quarter of 2009 decreased $2 million from $49 million for the same prior year period primarily due to decreased SFAS No. 144 related impairments ($24 million), partially offset by increased amortization costs of unproved leases in the United States ($22 million). The decreased SFAS No. 144 related impairments is a result of no SFAS No. 144 related impairments recorded in the second quarter of 2009 and SFAS No. 144 related impairments recorded in the second quarter of 2008 in Trinidad as a result of EOG's relinquishment of its rights to Block Lower Reverse "L" (LRL) ($20 million) and in the United States ($4 million). Under SFAS No. 144, EOG recorded impairments of zero and $24 million for the second 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 second quarter of 2009 decreased $72 million to $23 million (3.1% of wellhead revenues) from $95 million (5.1% 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 ($43 million) and Trinidad ($5 million), an increase in credits taken in 2009 for Texas high cost gas severance tax rate reductions ($15 million) and lower ad valorem/property taxes in the United States ($13 million), partially offset by an increase in franchise taxes in the United States ($6 million). The decline in taxes other than income as a percentage of wellhead revenues primarily reflects an increase in credits taken in 2009 for Texas high cost gas severance tax rate reductions combined with a decline in non-revenue based taxes.

Other income, net was $1 million for the second quarter of 2009 compared to $13 million for the same prior year period. The decrease of $12 million was primarily due to lower equity income from ammonia plants in Trinidad ($6 million), lower interest income ($2 million) and settlements received related to the Enron Corp. bankruptcy in the second quarter of 2008 ($2 million).

EOG recognized an income tax benefit of $7 million for the second quarter of 2009 compared to an income tax provision of $69 million for the same prior year period. The change was primarily due to decreased pretax income ($95 million), partially offset by the absence of 2008 tax benefits related to the impairment of LRL ($18 million). The net effective tax rate for the second quarter of 2009 increased to 29% from 28% for the same prior year period.

Six Months Ended June 30, 2009 vs. Six Months Ended June 30, 2008

Net Operating Revenues. During the first six months of 2009, net operating revenues decreased $211 million, or 9%, to $2,019 million from $2,230 million for the same period of 2008. Total wellhead revenues for the first six months of 2009 decreased $1,783 million, or 54%, to $1,515 million from $3,298 million for the same period of 2008. During the first six months of 2009, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $385 million compared to a net loss of $1,313 million for the same period of 2008. Gathering, processing and marketing revenues for the first six months of 2009 increased $15 million, or 15%, to $115 million from $100 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 six-month periods ended June 30, 2009 and 2008 were as follows:

                                                      Six Months Ended
                                                          June 30,
                                                       2009       2008
Natural Gas Volumes (MMcfd)
       United States                                    1,167      1,112
       Canada                                             227        215
       Trinidad                                           264        224
       Other International                                 15         15
              Total                                     1,673      1,566

Average Natural Gas Prices ($/Mcf)
       United States                               $     3.72 $     9.23
       Canada                                            3.92       8.42
       Trinidad                                          1.42       3.76
       Other International                               4.84       9.89
              Composite                                  3.39       8.34

Crude Oil and Condensate Volumes (MBbld)
       United States                                     43.8       33.0
       Canada                                             3.1        2.5
       Trinidad                                           3.0        3.4
       Other International                                0.1          -
              Total                                      50.0       38.9

Average Crude Oil and Condensate Prices ($/Bbl)
       United States                               $    42.85 $   105.78
       Canada                                           44.53     101.41
       Trinidad                                         40.49      99.92
       Other International                              46.73      96.84
              Composite                                 42.82     104.97

Natural Gas Liquids Volumes (MBbld)
       United States                                     21.9       15.5
       Canada                                             1.1        0.9
              Total                                      23.0       16.4

Average Natural Gas Liquids Prices ($/Bbl)
       United States                               $    23.88 $    60.19
       Canada                                           25.56      61.52
              Composite                                 23.96      60.26

Natural Gas Equivalent Volumes (MMcfed)
       United States                                    1,561      1,403
       Canada                                             252        236
       Trinidad                                           282        244
       Other International                                 16         15
              Total                                     2,111      1,898

Total Bcfe                                              382.1      345.4

Wellhead natural gas revenues for the first six months of 2009 decreased $1,350 million, or 57%, to $1,028 million from $2,378 million for the same period of 2008. The decrease was due to a lower composite average wellhead natural gas price ($1,499 million), partially offset by increased natural gas deliveries ($149 million). EOG's composite average wellhead natural gas price decreased 59% to $3.39 per Mcf for the first six months of 2009 from $8.34 per Mcf for the same period of 2008.

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