Overview

EOG Resources, Inc., together with its subsidiaries (collectively, EOG), is one of the largest independent (non-integrated) oil and natural gas companies in the United States with proved reserves in the United States, Canada, Trinidad, the United Kingdom North Sea and China. EOG operates under a consistent business and operational strategy that focuses predominantly on achieving a strong reinvestment rate of return, drilling internally generated prospects, delivering long-term production growth and maintaining a strong balance sheet.

United States and Canada. EOG's effort to identify plays with larger reserve potential has proven a successful supplement to its base development and exploitation program in the United States and Canada. EOG continues to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's natural gas and crude oil production. Production in the United States and Canada accounted for approximately 86% of total company production in both the first quarter of 2009 and the first quarter of 2008. One of EOG's exploration strategies is to apply its horizontal drilling expertise gained in natural gas resources plays to unconventional oil reservoirs. During the first quarter of 2009, the Fort Worth Basin Barnett Shale and North Dakota Bakken areas produced an increasing amount of crude oil and natural gas liquids as compared to the comparable period in 2008. For the first quarter of 2009, crude oil and natural gas liquids production 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.

International. In the United Kingdom, a rig was contracted to drill two operated wells in the East Irish Sea in 2009 and drilling is expected to commence in the second quarter. In addition, EOG began drilling its first well in the Sichuan Basin, Sichuan Province, The People's Republic of China, in March 2009.

EOG continues to evaluate other select natural gas and crude oil opportunities outside the United States and Canada primarily by pursuing exploitation opportunities in countries where indigenous natural gas and crude oil reserves have been identified.

Capital Structure. One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. At March 31, 2009 EOG's debt-to-total capitalization ratio was 19% as compared to 17% at December 31, 2008. During the first quarter of 2009, EOG funded $937 million in exploration and development and other property, plant and equipment expenditures and paid $33 million in dividends to common stockholders, primarily by utilizing cash provided from its operating activities and proceeds from commercial paper and uncommitted credit facility borrowings.

For 2009, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $3.1 billion, excluding acquisitions. United States and Canada natural gas and crude oil drilling activity continues to be a key component of these expenditures. EOG intends to manage the 2009 capital budget while maintaining a strong balance sheet. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer EOG incremental exploration and/or production opportunities. Management continues to believe EOG has one of the strongest prospect inventories in EOG's history.

Results of Operations

The following review of operations for the three months ended March 31, 2009 and 2008 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included in this Quarterly Report on Form 10-Q.

Net Operating Revenues. During the first quarter of 2009, net operating revenues increased $24 million, or 2%, to $1,158 million from $1,134 million for the same period of 2008. Total wellhead revenues for the first 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 $664 million, or 46%, to $768 million from $1,432 million for the same period of 2008. During the first quarter of 2009, EOG recognized net gains on mark-to-market financial commodity derivative contracts of $351 million compared to net losses of $470 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 first quarter of 2009 increased $2 million, or 5%, to $38 million from $36 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 three-month periods ended March 31, 2009 and 2008 were as follows:

                                                           Three Months Ended
                                                               March 31,
                                                           2009         2008
Natural Gas Volumes (MMcfd) (1)
       United States                                         1,193        1,085
       Canada                                                  230          216
       Trinidad                                                263          231
       Other International (2)                                  16           17
              Total                                          1,702        1,549

Average Natural Gas Prices ($/Mcf) (3)
       United States                                   $      4.06  $      8.05
       Canada                                                 4.43         7.44
       Trinidad                                               1.32         3.87
       Other International (2)                                6.03         9.85
              Composite                                       3.71         7.36

Crude Oil and Condensate Volumes (MBbld) (1)
       United States                                          44.9         30.6
       Canada                                                  3.2          2.4
       Trinidad                                                3.0          3.6
       Other International (2)                                 0.1          0.1
              Total                                           51.2         36.7

Average Crude Oil and Condensate Prices ($/Bbl) (3)
       United States                                   $     33.24  $     92.08
       Canada                                                37.11        88.94
       Trinidad                                              33.45        87.90
       Other International (2)                               46.71        88.29
              Composite                                      33.51        91.46

Natural Gas Liquids Volumes (MBbld) (1)
       United States                                          21.7         16.7
       Canada                                                  1.1          1.0
              Total                                           22.8         17.7

Average Natural Gas Liquids Prices ($/Bbl) (3)
       United States                                   $     22.12  $     57.26
       Canada                                                25.52        57.14
              Composite                                      22.29        57.26

Natural Gas Equivalent Volumes (MMcfed) (4)
       United States                                         1,593        1,370
       Canada                                                  255          236
       Trinidad                                                281          252
       Other International (2)                                  17           17
              Total                                          2,146        1,875

Total Bcfe (4)                                               193.1        170.6

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

Wellhead natural gas revenues for the first quarter of 2009 decreased $470 million, or 45%, to $568 million from $1,038 million for the same period of 2008 due to a lower composite average wellhead natural gas price ($560 million), partially offset by increased natural gas deliveries ($90 million). EOG's composite average wellhead natural gas price decreased 50% to $3.71 per Mcf for the first quarter of 2009 from $7.36 per Mcf for the same period of 2008.

Natural gas deliveries for the first quarter of 2009 increased 153 MMcfd, or 10%, to 1,702 MMcfd from 1,549 MMcfd for the same period of 2008. The increase was due to higher production in the United States (108 MMcfd), Trinidad (32 MMcfd) and Canada (14 MMcfd). The increase in the United States was primarily attributable to increased production from Texas (88 MMcfd) and the Rocky Mountain area (48 MMcfd), partially offset by decreased production from Pittsburgh as a result of the February 2008 sale of EOG's Appalachian assets (8 MMcfd), Oklahoma (7 MMcfd), New Mexico (7 MMcfd) and Mississippi (7 MMcfd). The increase in Trinidad was primarily due to increased contractual demand. The increase in Canada was primarily attributable to British Columbia Horn River Basin production.

Wellhead crude oil and condensate revenues for the first quarter of 2009 decreased $149 million, or 49%, to $154 million from $303 million for the same period of 2008, due to a lower composite average wellhead crude oil and condensate price ($267 million), partially offset by an increase of 15 MBbld, or 40%, in wellhead crude oil and condensate deliveries ($119 million). The increase in deliveries primarily reflects increased production in North Dakota (11 MBbld). The composite average wellhead crude oil and condensate price for the first quarter of 2009 decreased 63% to $33.51 per barrel compared to $91.46 per barrel for the same period of 2008.

Natural gas liquids revenues for the first quarter of 2009 decreased $46 million, or 50%, to $46 million from $92 million for the same period of 2008, due to a lower composite average price ($71 million), partially offset by increased natural gas liquids deliveries ($25 million). The composite average natural gas liquids price for the first quarter of 2009 decreased 61% to $22.29 per barrel compared to $57.26 per barrel for the same period of 2008. The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale and Rocky Mountain areas.

During the first quarter of 2009, EOG recognized a net gain on mark-to-market financial commodity derivative contracts of $351 million compared to a net loss of $470 million for the same period of 2008. During the first quarter of 2009, the net cash inflow related to settled natural gas and crude oil financial price swap contracts was $311 million compared to $23 million for the same period of 2008.

Gathering, processing and marketing revenues represent sales of third-party natural gas, crude oil and natural gas liquids as well as gathering fees associated with gathering third-party natural gas. During the three months ended March 31, 2009 and 2008, substantially all of such revenues were related to sales of third-party natural gas. Marketing costs represent the costs of purchasing third-party natural gas and crude oil and the associated transportation costs.

Gathering, processing and marketing revenues less marketing costs for the first quarter of 2009 increased $3 million to $6 million compared to $3 million for the same period of 2008. The increase resulted primarily from natural gas marketing operations in the Gulf Coast area.

Operating and Other Expenses. For the first quarter of 2009, operating expenses of $877 million were $124 million higher than the $753 million incurred during the first quarter of 2008. The following table presents the costs per thousand cubic feet equivalent (Mcfe) for the three-month periods ended March 31, 2009 and 2008:

                                                            Three Months Ended
                                                                 March 31,
                                                            2009           2008

    Lease and Well                                      $     0.75     $     0.73
    Transportation Costs                                      0.36           0.36
    Depreciation, Depletion and Amortization (DD&A) -
       Oil and Gas Properties                                 1.90           1.66
       Other Property, Plant and Equipment                    0.12           0.08
    General and Administrative (G&A)                          0.30           0.31
    Interest Expense, Net                                     0.10           0.07
       Total (1)                                        $     3.53     $     3.21

(1) Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and net interest expense for the three months ended March 31, 2009 compared to the same period of 2008 are set forth below.

Lease and well expenses include expenses for EOG-operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property. Lease and well expenses can be divided into the following categories:
costs to operate and maintain EOG's natural gas and crude oil wells, the cost of workovers and lease and well administrative expenses. Operating and maintenance expenses include, among other things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. Workovers are costs of operations to restore or maintain production from existing wells.

Each of these categories of costs individually fluctuates from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.

Lease and well expenses of $146 million for the first quarter of 2009 increased $22 million from $124 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($18 million) and Canada ($5 million) and higher lease and well administrative expenses ($4 million), partially offset by changes in the Canadian exchange rate ($7 million).

Transportation costs represent costs incurred directly by EOG from third-party carriers associated with the delivery of hydrocarbon products from the lease to a downstream point of sale. Transportation costs include the cost of compression (the cost of compressing natural gas to meet pipeline pressure requirements), dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees, fuel costs and transportation fees.

Transportation costs of $69 million for the first quarter of 2009 increased $7 million from $62 million for the same prior year period primarily due to increased production and costs associated with marketing arrangements to transport production from the Fort Worth Basin Barnett Shale area ($5 million) and the Rocky Mountain area ($3 million) to downstream markets.

DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or acquisition of new wells, disposition of existing wells, reserve revisions (upward or downward) primarily related to well

performance and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from year to year. DD&A of the cost of other property, plant and equipment is calculated using the straight-line depreciation method over the useful lives of the assets. Other property, plant and equipment consist of natural gas gathering and processing facilities, compressors, vehicles, buildings and leasehold improvements, furniture and fixtures, and computer hardware and software.

DD&A expenses for the first quarter of 2009 increased $92 million to $389 million from $297 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first quarter of 2009 were $82 million higher than the same prior year period primarily due to higher unit rates in the United States ($45 million), Canada ($5 million) and Trinidad ($4 million) and as a result of increased production in the United States ($34 million) and in Canada ($3 million), partially offset by changes in the Canadian exchange rate ($11 million).

DD&A expenses associated with other property, plant and equipment for the first quarter of 2009 were $10 million higher than the same prior year period primarily due to increased expenditures associated with natural gas gathering systems and processing plants in the Fort Worth Basin Barnett Shale area ($5 million) and Rocky Mountain area ($2 million).

G&A expenses of $58 million for the first quarter of 2009 increased $5 million from the same prior year period primarily due to higher employee related costs.

Interest expense, net of $18 million for the first quarter of 2009 increased $6 million as compared to the same prior year period primarily due to a higher average debt balance ($9 million), partially offset by higher capitalized interest ($3 million).

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

Gathering and processing costs for the first quarter of 2009 increased $9 million to $18 million as compared to the same prior year period primarily due to increased activities in the Rocky Mountain area ($4 million) and Fort Worth Basin Barnett Shale area ($3 million).

Impairments include amortization of unproved leases, as well as impairments under Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144), which requires an entity to compute impairments to the carrying value of long-lived assets based on future cash flow analysis. Impairments of $65 million for the first quarter of 2009 were $32 million higher than impairments of $33 million for the same prior year period primarily due to increased amortization costs of unproved leases in the United States ($18 million) and increased SFAS No. 144 related impairments in the United States ($16 million), partially offset by decreased SFAS No. 144 related impairments in Canada ($2 million). Under SFAS No. 144, EOG recorded impairments of $23 million and $9 million for the first quarter of 2009 and 2008, respectively.

Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are determined based on wellhead revenues and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.

Taxes other than income were $47 million (6.2% of wellhead revenues) for the first quarter of 2009 compared to $87 million (6.1% of wellhead revenues) for the same prior year period. The decrease in taxes other than income was primarily due to decreased severance/production taxes as a result of decreased wellhead revenues in the United States ($28 million) and Trinidad ($6 million) and an increase in credits taken in 2009 for Texas high cost gas severance tax rate reductions ($5 million).

Income tax provision of $106 million for the first quarter of 2009 decreased $23 million compared to the same prior year period primarily due to lower pretax income ($37 million), partially offset by higher state income taxes ($7 million). The net effective tax rate for the first quarter of 2009 increased to 40% from 35% in 2008.

Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the three months ended March 31, 2009 were funds generated from operations and net commercial paper and uncommitted credit facility borrowings. The primary uses of cash were funds used in operations; exploration and development expenditures; other property, plant and equipment expenditures; and dividend payments to stockholders. During the first three months of 2009, EOG's cash balance decreased $246 million to $85 million from $331 million at December 31, 2008.

Net cash provided by operating activities of $606 million for the first three months of 2009 decreased $321 million compared to the same period of 2008 primarily reflecting a decrease in wellhead revenues ($665 million), partially offset by a favorable change in net cash flow from the settlement of financial commodity derivative contracts ($288 million), a decrease in net cash paid for income taxes ($43 million), a decrease in cash paid for interest expense ($7 million) and favorable changes in working capital and other assets and liabilities ($3 million).

Net cash used in investing activities of $1,025 million for the first three months of 2009 increased by $218 million compared to the same period of 2008 due primarily to a decrease in proceeds from sales of assets ($346 million), primarily reflecting net proceeds from the sale of EOG's Appalachian assets in February 2008, and unfavorable changes in working capital associated with investing activities ($134 million), partially offset by a decrease in additions to oil and gas properties ($237 million) and a decrease in additions to other property, plant and equipment ($23 million).

Net cash provided by financing activities was $175 million for the first three months of 2009 compared to $32 million for the same period of 2008. Cash provided by financing activities for the first three months of 2009 included net commercial paper and uncommitted credit facility borrowings ($208 million) and excess tax benefits from stock-based compensation ($5 million). Cash used by financing activities for the first three months of 2009 included cash dividend payments ($33 million) and the purchase of treasury stock ($5 million).

Total Expenditures. For 2009, EOG's budget for exploration and production and other property, plant and equipment expenditures is approximately $3.1 billion. The table below sets out components of total expenditures for the three-month periods ended March 31, 2009 and 2008 (in millions):

                                                               Three Months Ended
                                                                    March 31,
                                                                2009        2008

Expenditure Category
Capital
                          Drilling and Facilities           $      731  $       888
                          Leasehold Acquisitions                    72          126
                          Producing Property Acquisitions            4           29
                          Capitalized Interest                      12            9
                            Subtotal                               819        1,052
Exploration Costs                                                   50           48
Dry Hole Costs                                                       3            8
        Exploration and Development Expenditures                   872        1,108
Asset Retirement Costs                                              12           14
          Total Exploration and Development Expenditures           884        1,122
Other Property, Plant and Equipment                                 65           88
          Total Expenditures                                $      949  $     1,210

Exploration and development expenditures of $872 million for the first three months of 2009 were $236 million lower than the same period of 2008 due primarily to decreased drilling and facilities expenditures in the United States ($128 million) and Canada ($15 million), decreased leasehold acquisition expenditures in Canada ($48 million), changes in the Canadian exchange rate ($15 million) and decreased producing property acquisition expenditures in Trinidad ($15 million) and Canada ($14 million). The exploration and development expenditures for the first three months of 2009 of $872 million include $662 million in development, $194 million in exploration, $12 million in capitalized interest and $4 million in producing property acquisitions. The exploration and development expenditures for the first three months of 2008 of $1,108 million include $801 million in development, $269 million in exploration, $29 million in producing property acquisitions and $9 million in capitalized interest.

The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other related economic factors. EOG has significant flexibility with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to operations in the United States, Canada, Trinidad, the United Kingdom and China, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.

Commodity Derivative Transactions. As more fully discussed in Note 11 to the Consolidated Financial Statements included in EOG's 2008 Annual Report, EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for natural gas and crude oil. EOG utilizes financial commodity derivative instruments, primarily collar, price swap and basis swap contracts, as a means to manage this price risk. EOG has not designated any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income. The related cash flow impact is reflected as Cash Flows from Operating Activities. In addition to financial transactions, EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.

Financial Collar Contracts. The total fair value of EOG's natural gas financial collar contracts at March 31, 2009 was a positive $59 million, which is . . .