Summary of EOG RESOURCES INC

ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

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.

Net income available to common stockholders for 2008 of $2,436 million was up 125% compared to 2007 net income available to common stockholders of $1,083 million. At December 31, 2008, EOG's total reserves were 8.7 trillion cubic feet equivalent, an increase of 944 billion cubic feet equivalent (Bcfe) from December 31, 2007.

Operations

Several important developments have occurred since January 1, 2008.

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 87% of total company production in 2008 as compared to 83% in 2007. In 2008, the Fort Worth Basin Barnett Shale and North Dakota Bakken areas produced an increasing amount of crude oil and natural gas liquids. For 2008, crude oil and natural gas liquids production accounted for approximately 19% of total company production as compared to 15% for 2007. Based on current trends, EOG expects its 2009 crude oil and natural gas liquids production 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 February 2008, EOG closed on the sale of the majority of its producing shallow gas assets and surrounding acreage in the Appalachian Basin to a subsidiary of EXCO Resources, Inc., an independent oil and gas company, for approximately $386 million ($40 million of which was received in 2007). The Appalachian area that was divested included approximately 2,400 operated wells that accounted for approximately 1% of EOG's total 2007 production and approximately 2% of its total year-end 2007 proved reserves. EOG retained certain of its undeveloped acreage in this area, including rights in the Marcellus Shale, and continued its shale exploration program in 2008.

In the third quarter of 2008, EOG commenced production in its British Columbia, Canada shale gas play. EOG holds approximately 158,000 net acres in this play at December 31, 2008 and expects to slowly increase production until 2012, when the construction of additional infrastructure for the play is expected to be completed.

International. In Trinidad, EOG continued to deliver natural gas under existing supply contracts. In February 2008, EOG, through its subsidiary EOG Resources Trinidad Limited (EOGRT) purchased an 80% working interest in the exploration and production license covering the Pelican field and its related facilities from Trinidad and Tobago Marine Petroleum Company Limited. The acquisition includes the subsurface rights, offshore facilities, the condensate transport line and the onshore storage facilities.

In October 2008, EOG, through its subsidiaries, EOGRT, EOG Resources Trinidad-U(a) Block Limited and EOG Resources Trinidad U(b) Block Unlimited (EOGRT U(b)), finalized crude oil and condensate sales contracts with the Petroleum Company of Trinidad and Tobago. The pricing terms are based on the valuation of the distillation yield of the crude oil and condensate produced less a refining margin.

In April 2008, EOG's subsidiary, EOG Resources Trinidad-LRL Unlimited, relinquished its rights to Lower Reverse "L" Block and recorded an impairment of $20 million. In December 2008, EOG, through its subsidiaries EOGRT and EOGRT U(b), began production from the Oilbird field.

EOG continues to expand its exploration prospect portfolio in the United Kingdom (U.K.) in addition to its ongoing production from the Valkyrie and Arthur fields in the Southern Gas Basin of the North Sea Block 23/16f. There are currently two producing wells in the Arthur field, one or both of which could cease production during the second half of 2009. During the fourth quarter of 2008, EOG recorded an impairment of $6 million ($3 million after-tax) for its Arthur field based on well performance. During 2008, a field development plan was submitted for the Columbus discovery in the Central North Sea. In the fourth quarter of 2008, EOGUK was awarded three Central North Sea operated licenses in the U.K. 25th Seaward Licensing Round. A rig was contracted to drill two operated wells in the East Irish Sea in 2009. The licenses for the East Irish Sea were awarded to EOG in 2007.

In July 2008, EOG acquired rights from ConocoPhillips in a Petroleum Contract covering the Chuanzhong Block exploration area in the Sichuan Basin, Sichuan Province, The People's Republic of China. The acquisition includes production of approximately 9 million cubic feet equivalent per day, net, on approximately 130,000 acres. In October 2008, EOG obtained the rights to additional zones on the acreage purchased. EOG plans to drill its first horizontal well in 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 December 31, 2008, EOG's debt-to-total capitalization ratio was 17%. During 2008, EOG funded $5.4 billion in exploration and development and other property, plant and equipment expenditures, paid $115 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 Perpetual Senior Preferred Stock, Series B, with a $1,000 liquidation preference per share (Series B), primarily by utilizing cash provided from its operating activities, proceeds from long-term debt borrowings and proceeds from the sale of its Appalachian assets.

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 crude oil and natural gas drilling activity continues to be a key component of these expenditures. EOG intends to manage the 2009 capital budget in order to balance expenditures with operating cash flows. 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.

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 (collectively, 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 were used for general corporate purposes, including repayment of outstanding commercial paper and borrowings under other uncommitted credit facilities.

Results of Operations

The following review of operations for each of the three years in the period ended December 31, 2008 should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning with page F-1.

Net Operating Revenues

During 2008, net operating revenues increased $2,888 million, or 68%, to $7,127 million from $4,239 million in 2007. Total wellhead revenues, which are revenues generated from sales of EOG's production of natural gas, crude oil and condensate and natural gas liquids, increased $2,202 million, or 55%, to $6,222 million from $4,020 million in 2007. During 2008, EOG recognized net gains on mark-to-market commodity derivative contracts of $598 million compared to net gains of $93 million in 2007. Gathering, processing and marketing revenues, which are revenues generated from sales of third-party natural gas and natural gas liquids as well as gathering fees associated with gathering third-party natural gas, increased $91 million, or 124%, to $165 million in 2008 from $74 million in 2007. Other, net operating revenues in 2008 primarily consist of the gain of $128 million on the sale of the Appalachian assets in February 2008. The following review of operations gives effect to the reclassifications discussed in Note 1 to Consolidated Financial Statements.

Wellhead volume and price statistics for the years ended December 31, 2008, 2007 and 2006 were as follows:

Year Ended December 31                                   2008    2007    2006
Natural Gas Volumes (MMcfd) (1)
       United States                                     1,162     971     817
       Canada                                              222     224     226
       Trinidad                                            218     252     264
       Other International (2)                              17      23      30
              Total                                      1,619   1,470   1,337

Average Natural Gas Prices ($/Mcf) (3)
       United States                                   $  8.22 $  6.27 $  6.52
       Canada                                             7.64    6.25    6.41
       Trinidad                                           3.58    2.71    2.44
       Other International (2)                            8.18    6.19    7.69
              Composite                                   7.51    5.65    5.72

Crude Oil and Condensate Volumes (MBbld) (1)
       United States                                      39.5    24.6    20.7
       Canada                                              2.7     2.4     2.5
       Trinidad                                            3.2     4.1     4.8
       Other International (2)                             0.1     0.1     0.1
              Total                                       45.5    31.2    28.1

Average Crude Oil and Condensate Prices ($/Bbl) (3)
       United States                                   $ 87.68 $ 68.85 $ 62.68
       Canada                                            89.70   65.27   57.32
       Trinidad                                          92.90   69.84   63.87
       Other International (2)                           99.30   66.84   57.74
              Composite                                  88.18   68.69   62.38

Natural Gas Liquids Volumes (MBbld) (1)
       United States                                      15.0    11.1     8.5
       Canada                                              1.0     1.1     0.8
              Total                                       16.0    12.2     9.3

Average Natural Gas Liquids Prices ($/Bbl) (3)
       United States                                   $ 53.33 $ 47.63 $ 39.95
       Canada                                            54.77   44.54   43.69
              Composite                                  53.42   47.36   40.25

Natural Gas Equivalent Volumes (MMcfed) (4)
       United States                                     1,490   1,184     992
       Canada                                              244     245     246
       Trinidad                                            237     276     292
       Other International (2)                              17      24      31
              Total                                      1,988   1,729   1,561

Total Bcfe (4)                                           727.6   631.3   569.9

(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.

2008 compared to 2007. Wellhead natural gas revenues in 2008 increased $1,419 million, or 47%, to $4,452 million from $3,033 million for 2007 due to a higher composite average wellhead natural gas price ($1,101 million) and increased natural gas deliveries ($318 million). EOG's composite average wellhead natural gas price increased 33% to $7.51 per Mcf in 2008 from $5.65 per Mcf in 2007.

Natural gas deliveries increased 149 MMcfd, or 10%, to 1,619 MMcfd in 2008 from 1,470 MMcfd in 2007. The increase was due to higher production of 191 MMcfd in the United States and initial production of 5 MMcfd in China, partially offset by lower production of 34 MMcfd in Trinidad, 11 MMcfd in the United Kingdom and 2 MMcfd in Canada. The increase in the United States was primarily attributable to increased production from Texas (140 MMcfd), the Rocky Mountain area (54 MMcfd), Mississippi (8 MMcfd) and Kansas (4 MMcfd), partially offset by decreased production due to the February 2008 sale of the Appalachian assets (15 MMcfd). The decline in Trinidad was primarily due to decreased deliveries as a result of plant shutdowns due to unplanned maintenance activities (29 MMcfd) and reduced deliveries due to lower demand in 2008 (10 MMcfd), partially offset by increased deliveries to Atlantic LNG Train 4 (ALNG) (5 MMcfd). The decrease in production in the United Kingdom was a result of production declines in both the Arthur and Valkyrie fields.

Wellhead crude oil and condensate revenues increased $680 million, or 87%, to $1,458 million in 2008 from $778 million in 2007, due to an increase of 14.3 MBbld, or 46%, in wellhead crude oil and condensate deliveries ($358 million) and a higher composite average wellhead crude oil and condensate price ($322 million). The increase in deliveries primarily reflects increased production in North Dakota (12 MBbld). The composite average wellhead crude oil and condensate price for 2008 increased 28% to $88.18 per barrel compared to $68.69 per barrel for 2007.

Natural gas liquids revenues increased $102 million, or 49%, to $312 million in 2008 from $210 million in 2007, due to increases in deliveries ($67 million) and a higher composite average price ($35 million). The composite average natural gas liquids price for 2008 increased 13% to $53.42 per barrel compared to $47.36 per barrel for 2007. The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale and Rocky Mountain areas.

During 2008, EOG recognized net gains on mark-to-market financial commodity derivative contracts of $598 million, which included realized losses of $137 million. During 2007, EOG recognized net gains on mark-to-market financial commodity derivative contracts of $93 million, which included realized gains of $128 million.

Gathering, processing and marketing revenues represent sales of third-party natural gas and natural gas liquids as well as gathering fees associated with gathering third-party natural gas. For the years ended December 31, 2008, 2007 and 2006, 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 the associated transportation costs.

Gathering, processing and marketing revenues less marketing costs increased $5 million to $12 million in 2008 compared to $7 million in 2007. The increase resulted primarily from natural gas marketing operations in the Gulf Coast area.

2007 compared to 2006. Wellhead natural gas revenues in 2007 increased $240 million, or 9%, to $3,033 million from $2,793 million in 2006 due to increased natural gas deliveries ($277 million), partially offset by a lower composite average wellhead natural gas price ($37 million). The composite average wellhead natural gas price decreased to $5.65 per Mcf in 2007 from $5.72 per Mcf in 2006.

Natural gas deliveries increased 133 MMcfd, or 10%, to 1,470 MMcfd in 2007 from 1,337 MMcfd in 2006. The increase was due to higher production of 154 MMcfd in the United States, partially offset by lower production of 12 MMcfd in Trinidad, 7 MMcfd in the United Kingdom and 2 MMcfd in Canada. The increase in the United States was primarily attributable to increased production from Texas (119 MMcfd), the Rocky Mountain area (13 MMcfd), Kansas (13 MMcfd) and Mississippi (10 MMcfd). The decline in Trinidad was due to reduced 2007 deliveries to ALNG (10 MMcfd) and a decrease in contractual demand (2 MMcfd). During 2006, EOG supplied gas for use in ALNG's start-up phase. In 2007, ALNG remained in the start-up phase, but did not require any gas from EOG until May 2007 when ALNG reached commercial status and EOG began supplying gas under the ALNG take-or-pay contract. The decrease in production in the United Kingdom was a result of production declines in both the Arthur and Valkyrie fields.

Wellhead crude oil and condensate revenues increased $153 million, or 24%, to $778 million in 2007 from $625 million in 2006, due to an increase in wellhead crude oil and condensate deliveries ($81 million) and a higher composite average wellhead crude oil and condensate price ($72 million). The increase in deliveries primarily reflects increased production in North Dakota. The composite average wellhead crude oil and condensate price in 2007 was $68.69 per barrel compared to $62.38 per barrel in 2006.

Natural gas liquids revenues increased $73 million, or 53%, to $210 million in 2007 from $137 million in 2006, due to increases in deliveries ($42 million) and a higher composite average price ($31 million). The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale and South Texas areas.

During 2007, EOG recognized net gains on mark-to-market financial commodity derivative contracts of $93 million, which included realized gains of $128 million. During 2006, EOG recognized gains on mark-to-market financial commodity derivative contracts of $334 million, which included realized gains of $215 million.

Gathering, processing and marketing revenues less marketing costs in 2007 increased $4 million to $7 million in 2007 from $3 million in 2006 primarily as a result of increased natural gas marketing operations in the Gulf Coast area.

Operating and Other Expenses

2008 compared to 2007. During 2008, operating expenses of $3,360 million were
$769 million higher than the $2,591 million incurred in 2007. The following
table presents the costs per Mcfe for the years ended December 31, 2008 and
2007:

                                                                 2008   2007

          Lease and Well                                       $ 0.77 $ 0.72
          Transportation Costs                                   0.38   0.24
          Depreciation, Depletion and Amortization (DD&A) -
                           Oil and Gas Properties                1.74   1.63
                           Other Property, Plant and Equipment   0.09   0.06
          General and Administrative (G&A)                       0.34   0.33
          Net Interest Expense                                   0.07   0.07
             Total Per-Unit Costs (1)                          $ 3.39 $ 3.05

(1) Total per-unit costs do not include 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 2008 as compared to 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 expenses, 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 $559 million in 2008 increased $107 million from $452 million in 2007 due primarily to higher operating and maintenance expenses ($78 million) and higher lease and well administrative expenses ($28 million), both in the United States.

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 $274 million in 2008 increased $122 million from $152 million in 2007 primarily due to increased production and costs associated with marketing arrangements to transport production from the Fort Worth Basin Barnett Shale area ($64 million) and the Rocky Mountain area ($38 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 in 2008 increased $261 million to $1,327 million from $1,066 million in 2007. DD&A expenses associated with oil and gas properties were $236 million higher than in 2007 primarily due to higher unit rates described below and as a result of increased production in the United States ($210 million), partially offset by a decrease in production in the United Kingdom ($10 million) and in Trinidad ($3 million). DD&A rates increased due primarily to a proportional increase in production from higher cost properties in the United States ($15 million) and Canada ($8 million). Changes in the Canadian exchange rate ($11 million) also contributed to the DD&A expense increase.

DD&A expenses associated with other property, plant and equipment were $25 million higher in 2008 than in 2007 primarily due to increased expenditures associated with natural gas gathering systems in the Fort Worth Basin Barnett Shale area.

G&A expenses of $244 million in 2008 were $38 million higher than 2007 due primarily to higher employee-related costs ($33 million). The increase in employee-related costs primarily reflects higher stock-based compensation expenses ($18 million).

Net interest expense of $52 million in 2008 increased $5 million from $47 million in 2007 primarily due to a higher average debt balance ($18 million), partially offset by higher capitalized interest ($13 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 increased $13 million to $41 million in 2008 as compared to $28 million in 2007. The increase primarily reflects increased activities in the Fort Worth Basin Barnett Shale and Rocky Mountain areas.

Exploration costs of $194 million in 2008 increased $44 million from $150 million for the same prior year period primarily due to increased geological and geophysical expenditures in the United States ($27 million) and higher employee-related costs ($15 million). The increase in geological and geophysical expenditures in the United States was primarily attributable to activities in the Fort Worth Basin Barnett Shale area ($21 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 $193 million in 2008 were $45 million higher than impairments of $148 million in 2007 due primarily to increased amortization costs as a result of increased leasehold acquisition expenditures in the United States ($30 million) and Canada ($12 million), an SFAS No. 144 related impairment in Trinidad as a result of EOG's relinquishment of its rights to Lower Reverse "L" Block ($20 million) and an SFAS No. 144 related

impairment in the United Kingdom for the Arthur field ($6 million), partially offset by decreased SFAS No. 144 related impairments in Canada ($20 million). Under SFAS No. 144, EOG recorded impairments of $86 million and $82 million for 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 revenue and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.

Taxes other than income in 2008 increased $113 million to $321 million (5.2% of wellhead revenues) from $208 million (5.2% of wellhead revenues) in 2007 primarily due to an increase in severance/production taxes in the United States as a result of increased wellhead revenues ($86 million), a decrease in credits taken in 2008 for Texas high cost gas severance tax rate reductions ($13 million) and increased ad valorem/property taxes as a result of higher property valuations in the United States ($20 million).

Income tax provision of $1,310 million in 2008 increased $769 million compared to 2007 due primarily to increased pretax income. The net effective tax rate for 2008 increased to 35% from 33% in 2007. The increase in the 2008 net effective tax rate is primarily due to a Canadian federal tax rate reduction in 2007.

2007 compared to 2006. During 2007, operating expenses of $2,591 million were $566 million higher than the $2,025 million incurred in 2006. The following table presents the costs per Mcfe for the years ended December 31, 2007 and 2006:

                                                          2007   2006

                 Lease and Well                         $ 0.72 $ 0.63
                 Transportation Costs                     0.24   0.18
                 DD&A -
                    Oil and Gas Properties                1.63   1.39
. . .