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

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.

Wellhead volume and price statistics for the three-month periods ended September 30, 2008 and 2007 were as follows:

                                                          Three Months Ended
                                                             September 30,
                                                           2008         2007
Natural Gas Volumes (MMcfd) (1)
       United States                                         1,196         997
       Canada                                                  224         216
       Trinidad                                                240         262
       Other International (4)                                  19          22
              Total                                          1,679       1,497

Average Natural Gas Prices ($/Mcf) (2)
       United States                                   $      8.99  $     5.52
       Canada                                                 8.15        5.49
       Trinidad                                               4.04        2.20
       Other International (4)                                7.41        5.89
              Composite                                       8.15        4.94

Crude Oil and Condensate Volumes (MBbld) (1)
       United States                                          41.8        25.3
       Canada                                                  3.0         2.4
       Trinidad                                                3.4         4.2
       Other International (4)                                 0.1         0.1
              Total                                           48.3        32.0

Average Crude Oil and Condensate Prices ($/Bbl) (2)
       United States                                   $    109.86  $    70.86
       Canada                                               109.71       69.99
       Trinidad                                             111.39       67.03
       Other International (4)                              112.77       66.96
              Composite                                     109.96       70.27

Natural Gas Liquids Volumes (MBbld) (1)
       United States                                          13.2        10.8
       Canada                                                  1.1         0.9
              Total                                           14.3        11.7

Average Natural Gas Liquids Prices ($/Bbl) (2)
       United States                                   $     69.79  $    47.94
       Canada                                                64.01       46.71
              Composite                                      69.33       47.84

Natural Gas Equivalent Volumes (MMcfed) (3)
       United States                                         1,525       1,213
       Canada                                                  249         236
       Trinidad                                                261         288
       Other International (4)                                  20          22
              Total                                          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.

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:

                                                           Three Months Ended
                                                              September 30,
                                                           2008           2007

     Lease and Well                                    $     0.80     $     0.74
     Transportation Costs                                    0.41           0.25
     Depreciation, Depletion and Amortization (DD&A)         1.83           1.73
     General and Administrative (G&A)                        0.38           0.30
     Interest Expense, Net                                   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.

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.

Transportation costs of $78 million for the third quarter of 2008 increased $38 million from $40 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 Play ($23 million) and the Rocky Mountain area ($10 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 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.

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 million, or 83%, to $5,353 million from $2,926 million for the same period of 2007. Total wellhead revenues for the first nine months of 2008 increased $2,283 million, or 80%, to $5,131 million from $2,848 million for the same period of 2007. 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. Other, net revenues for the first nine months of 2008 include a $129 million gain recognized on the sale of the Appalachian assets.

Wellhead volume and price statistics for the nine-month periods ended September 30, 2008 and 2007 were as follows:

                                                       Nine Months Ended
                                                         September 30,
                                                       2008         2007
Natural Gas Volumes (MMcfd)
       United States                                     1,141         958
       Canada                                              218         223
       Trinidad                                            229         255
       Other International                                  16          25
              Total                                      1,604       1,461

Average Natural Gas Prices ($/Mcf)
       United States                               $      9.15  $     6.19
       Canada                                             8.33        6.22
       Trinidad                                           3.86        2.35
       Other International                                8.90        5.29
              Composite                                   8.28        5.51

Crude Oil and Condensate Volumes (MBbld)
       United States                                      35.9        23.6
       Canada                                              2.7         2.4
       Trinidad                                            3.4         4.2
       Other International                                 0.1         0.1
              Total                                       42.1        30.3

Average Crude Oil and Condensate Prices ($/Bbl)
       United States                               $    107.36  $    62.52
       Canada                                           104.57       60.54
       Trinidad                                         103.80       67.22
       Other International                              104.66       61.57
              Composite                                 106.89       63.01

Natural Gas Liquids Volumes (MBbld)
       United States                                      14.7        10.3
       Canada                                              1.0         1.0
              Total                                       15.7        11.3

Average Natural Gas Liquids Prices ($/Bbl)
       United States                               $     63.08  $    43.73
       Canada                                            62.45       41.52
              Composite                                  63.04       43.52

Natural Gas Equivalent Volumes (MMcfed)
       United States                                     1,445       1,161
       Canada                                              240         244
       Trinidad                                            250         280
       Other International                                  16          25
              Total                                      1,951       1,710

Total Bcfe                                               534.5       466.8

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 million were $540 million higher than the $1,797 million incurred in the same period of 2007. The following table presents the costs per Mcfe for the nine-month periods ended September 30, 2008 and 2007:

                                                Nine Months Ended
                                                  September 30,
                                               2008          2007

                  Lease and Well            $    0.79     $    0.75
                  Transportation Costs           0.38          0.24
                  DD&A                           1.80          1.68
                  G&A                            0.35          0.30
                  Interest Expense, Net          0.06          0.07
                    Total Per-Unit Costs(1) $    3.38     $    3.04

(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, 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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