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EOG > SEC Filings for EOG > Form 10-Q on 8-May-2012All Recent SEC Filings

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Form 10-Q for EOG RESOURCES INC


8-May-2012

Quarterly Report


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EOG RESOURCES, INC.

Overview

EOG Resources, Inc., together with its subsidiaries (collectively, 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 and China. EOG operates under a consistent business and operational strategy that focuses predominantly on maximizing the rate of return on investment of capital by controlling operating and capital costs and maximizing reserve recoveries. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to deliver long-term production growth while maintaining a strong balance sheet. EOG implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves. Maintaining the lowest possible operating cost structure that is consistent with prudent and safe operations is also an important goal in the implementation of EOG's strategy.

United States and Canada. EOG's efforts to identify plays with large reserve potential have 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 crude oil and natural gas production. EOG has placed an emphasis on applying its horizontal drilling and completion expertise gained from its natural gas resource plays to unconventional crude oil and liquids-rich reservoirs. In 2012, EOG continues to focus its efforts on developing its existing North American crude oil and condensate and liquids-rich acreage. In addition, EOG continues to evaluate certain potential liquids-rich exploration and development prospects. For the first quarter of 2012, crude oil and condensate and natural gas liquids production accounted for approximately 43% of total company production as compared to 32% for the comparable period in 2011. In North America, crude oil and condensate and natural gas liquids production accounted for approximately 49% of total North American production during the first quarter of 2012 as compared to 37% for the comparable period in 2011. This liquids growth primarily reflects increased production from the Eagle Ford Shale near San Antonio, Texas, and the Fort Worth Basin Barnett Shale area. Based on current trends, EOG expects its 2012 crude oil and condensate and natural gas liquids production to continue to increase both in total and as a percentage of total company production as compared to 2011. EOG delivers its crude oil to various markets in the United States, including sales points on the Gulf Coast. Most recently, with increases in crude oil production from the Eagle Ford Shale, EOG has increased sales to the Gulf Coast and is receiving pricing for those sales based on the Light Louisiana Sweet price. In order to access more diverse markets for its crude-by-rail shipments, EOG completed the construction of a crude oil unloading facility in St. James, Louisiana, where sales are based upon the Light Louisiana Sweet crude oil index. This facility, which received the first unit train of EOG crude oil in April 2012, has a capacity of approximately 100 thousand barrels per day (MBbld) and is able to accommodate multiple trains at a single time.

As previously reported, EOG's wholly-owned Canadian subsidiary, EOG Resources Canada Inc. (EOGRC), holds a 30% interest in both the planned liquefied natural gas export terminal to be located at Bish Cove, near the Port of Kitimat, north of Vancouver, British Columbia (Kitimat LNG Terminal) and the proposed Pacific Trail Pipelines (PTP) which is intended to link Western Canada's natural gas producing regions to the Kitimat LNG Terminal. An affiliate of Apache Corporation is the operator of both PTP and the Kitimat LNG Terminal. The front-end engineering and design study is expected to be delivered in the second half of 2012, and EOG expects to make a final investment decision at the beginning of 2013.

EOG's major producing areas in the United States and Canada are in Louisiana, New Mexico, North Dakota, Pennsylvania, Texas, Utah, Wyoming and western Canada.

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International. In Trinidad, EOG continued to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium Block, Modified U(a) Block and Modified U(b) Block, as well as the Pelican Field, have been developed and are producing natural gas and crude oil and condensate. In Block 4(a), production from the six wells in the Toucan Field and one in the EMZ Area began in February 2012 to supply natural gas under a contract with the National Gas Company of Trinidad and Tobago.

In the United Kingdom, EOG continues to make progress in field development for its East Irish Sea Conwy/Corfe crude oil discovery and its Central North Sea Columbus natural gas discovery. The field development plan for the Conwy/Corfe project was approved by the U.K. Department of Energy and Climate Change in March 2012. Fabrication of facilities and pipelines is progressing. EOG expects to begin facility and pipeline installation in the second half of 2012. The drilling of development wells is expected to commence at the beginning of 2013, with initial production expected in the second half of 2013.

During the first quarter of 2012, EOG drilled a monitoring well targeting the Vaca Muerta oil shale in the Aguada del Chivato Block in the Neuquén Basin in Neuquén Province, Argentina. In addition, EOG drilled a horizontal well in this formation that it plans to complete in the second quarter of 2012. EOG is also participating in the drilling of a well in the Bajo de Toro Block, also targeting the Vaca Muerta oil shale. This well is expected to be completed in the second quarter of 2012.

EOG continues to evaluate other select crude oil and natural gas opportunities outside the United States and Canada, primarily by pursuing exploitation opportunities in countries where indigenous crude oil and natural gas 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 28% at both March 31, 2012 and December 31, 2011. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

EOG's total anticipated 2012 capital expenditures are estimated to range from $7.4 billion to $7.6 billion, excluding acquisitions. The majority of 2012 expenditures will be focused on United States and Canada crude oil and liquids-rich gas drilling activity and, to a much lesser extent, natural gas drilling activity in the Haynesville, Marcellus and British Columbia Horn River Basin plays to hold acreage. EOG expects capital expenditures to be greater than cash flow from operating activities for 2012. EOG's business plan includes selling certain non-core assets in 2012 to partially cover the anticipated shortfall. In the first quarter of 2012, proceeds of approximately $450 million were received from the sale of producing properties and acreage, primarily in the Upper Gulf Coast area, the Rocky Mountain area and the Permian Basin. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program and other uncommitted credit facilities, bank borrowings, borrowings under its revolving credit facility and equity and debt offerings. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer incremental exploration and/or production opportunities. Management continues to believe EOG has one of the strongest prospect inventories in EOG's history.

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Results of Operations

The following review of operations for the three months ended March 31, 2012 and 2011 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 2012, net operating revenues increased $910 million, or 48%, to $2,807 million from $1,897 million for the same period of 2011. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, natural gas liquids and natural gas, for the first quarter of 2012 increased $386 million, or 26%, to $1,876 million from $1,490 million for the same period of 2011. During the first quarter of 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $134 million compared to net losses of $67 million for the same period of 2011. Gathering, processing and marketing revenues, which are revenues generated from sales of third-party crude oil and condensate, natural gas liquids and natural gas, as well as, fees associated with gathering third-party natural gas, for the first quarter of 2012 increased $322 million, or 82%, to $718 million from $396 million for the same period of 2011. Gains on asset dispositions, net, of $67 million for the first quarter of 2012 primarily consist of gains on asset dispositions in the Rocky Mountain area and Texas.

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Wellhead volume and price statistics for the three-month periods ended March 31, 2012 and 2011 were as follows:

                                                        Three Months Ended
                                                             March 31,
                                                         2012          2011

Crude Oil and Condensate Volumes (MBbld) (1)
United States                                               131.0        81.4
Canada                                                        7.5         8.5
Trinidad                                                      2.2         4.4
Other International (2)                                       0.1         0.1
Total                                                       140.8        94.4

Average Crude Oil and Condensate Prices ($/Bbl) (3)
United States                                         $    101.81     $ 88.00
Canada                                                      89.39       84.24
Trinidad                                                    99.25       86.84
Other International (2)                                    107.15       85.57
Composite                                                  101.12       87.61

Natural Gas Liquids Volumes (MBbld) (1)
United States                                                50.3        34.5
Canada                                                        0.8         0.9
Total                                                        51.1        35.4

Average Natural Gas Liquids Prices ($/Bbl) (3)
United States                                         $     42.49     $ 46.63
Canada                                                      50.88       47.11
Composite                                                   42.62       46.65

Natural Gas Volumes (MMcfd) (1)
United States                                               1,062       1,134
Canada                                                        105         143
Trinidad                                                      369         385
Other International (2)                                        11          14
Total                                                       1,547       1,676

Average Natural Gas Prices ($/Mcf) (3)
United States                                         $      2.46     $  4.10
Canada                                                       2.45        3.67
Trinidad                                                     2.98        3.20
Other International (2)                                      5.79        5.63
Composite                                                    2.61        3.87

Crude Oil Equivalent Volumes (MBoed) (4)
United States                                               358.5       304.9
Canada                                                       25.7        33.2
Trinidad                                                     63.8        68.6
Other International (2)                                       1.8         2.4
Total                                                       449.8       409.1

Total MMBoe (4)                                              40.9        36.8

(1) Thousand barrels per day or million cubic feet per day, as applicable.

(2) Other International includes EOG's United Kingdom and China operations.

(3) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments.

(4) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

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Wellhead crude oil and condensate revenues for the first quarter of 2012 increased $553 million, or 73%, to $1,310 million from $757 million for the same period of 2011, due to an increase of 46 MBbld, or 49%, in wellhead crude oil and condensate deliveries ($378 million) and a higher composite average wellhead crude oil and condensate price ($175 million). The increase in deliveries primarily reflects increased production in the Eagle Ford Shale. EOG's composite average wellhead crude oil and condensate price for the first quarter of 2012 increased 15% to $101.12 per barrel compared to $87.61 per barrel for the same period of 2011.

Natural gas liquids revenues for the first quarter of 2012 increased $49 million, or 33%, to $198 million from $149 million for the same period of 2011, due to an increase of 16 MBbld, or 44%, in natural gas liquids deliveries ($68 million), partially offset by a lower composite average price ($19 million). The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale area and the Eagle Ford Shale. EOG's composite average natural gas liquids price for the first quarter of 2012 decreased 9% to $42.62 per barrel compared to $46.65 per barrel for the same period of 2011.

Wellhead natural gas revenues for the first quarter of 2012 decreased $217 million, or 37%, to $367 million from $584 million for the same period of 2011. The decrease was due to a lower composite average wellhead natural gas price ($178 million) and a decrease in natural gas deliveries ($39 million). EOG's composite average wellhead natural gas price for the first quarter of 2012 decreased 33% to $2.61 per Mcf compared to $3.87 per Mcf for the same period of 2011.

Natural gas deliveries for the first quarter of 2012 decreased 129 MMcfd, or 8%, to 1,547 MMcfd from 1,676 MMcfd for the same period of 2011. The decrease was primarily due to lower production in the United States (72 MMcfd), Canada (38 MMcfd) and Trinidad (16 MMcfd). The decrease in the United States was primarily attributable to asset sales that occurred subsequent to the first quarter of 2011 and decreased production in the Rocky Mountain area and Kansas, partially offset by increased production in Pennsylvania and Louisiana. The decrease in Canada was primarily due to decreased production in Alberta and the Horn River Basin area. The decrease in Trinidad was primarily attributable to a decrease in contractual deliveries.

During the first quarter of 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $134 million compared to net losses of $67 million for the same period of 2011. During the first quarter of 2012, the net cash inflow related to settled crude oil and natural gas derivative contracts was $134 million compared to $25 million for the same period of 2011.

Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, natural gas liquids and natural gas, as well as, fees associated with gathering third-party natural gas. For the three months ended March 31, 2012 and 2011, gathering, processing and marketing revenues were primarily related to sales of third-party crude oil and natural gas. The purchase and sale of third-party crude oil and natural gas are utilized in order to balance firm transportation capacity with production in certain areas and to utilize excess capacity at EOG-owned facilities. Marketing costs represent the costs of purchasing third-party crude oil and natural gas and the associated transportation costs.

During the first quarter of 2012, gathering, processing and marketing revenues and marketing costs increased primarily as a result of increased crude oil marketing activities. Gathering, processing and marketing revenues less marketing costs for the first quarter of 2012 totaled $13 million compared to $10 million for the same period of 2011, primarily as a result of increased crude oil marketing activities.

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Operating and Other Expenses. For the first quarter of 2012, operating expenses of $2,247 million were $622 million higher than the $1,625 million incurred during the first quarter of 2011. The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended March 31, 2012 and 2011:

                                                      Three Months Ended
                                                           March 31,
                                                       2012          2011

Lease and Well                                      $     6.37      $  5.82
Transportation Costs                                      3.21         2.64
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties                                   17.32        14.57
Other Property, Plant and Equipment                       0.90         0.83
General and Administrative (G&A)                          1.86         1.89
Interest Expense, Net                                     1.22         1.36
Total (1)                                           $    30.88      $ 27.11

(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 and G&A for the three months ended March 31, 2012 compared to the same period of 2011 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 costs include, among other things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. Workovers are 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 and maintenance costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time. In general, operating and maintenance costs for wells producing crude oil are higher than operating and maintenance costs for wells producing natural gas.

Lease and well expenses of $261 million for the first quarter of 2012 increased $46 million from $215 million for the same prior year period primarily due to higher operating and maintenance costs in the United States ($40 million) and Canada ($3 million) and increased lease and well administrative expenses in the United States ($6 million).

Transportation costs represent costs 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, transportation fees and costs associated with crude-by-rail operations.

Transportation costs of $132 million for the first quarter of 2012 increased $34 million from $98 million for the same prior year period primarily due to increased transportation costs in the Eagle Ford Shale.

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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.

DD&A expenses for the first quarter of 2012 increased $181 million to $749 million from $568 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first quarter of 2012 were $174 million higher than the same prior year period primarily due to higher unit rates described below and as a result of increased production in the United States ($79 million), partially offset by a decrease in production in Canada ($15 million). DD&A rates increased due primarily to a proportional increase in production from higher-cost properties in the United States ($109 million) and Canada ($8 million), partially offset by a decrease in rates in Trinidad ($5 million).

DD&A expenses associated with other property, plant and equipment were $7 million higher than the same prior year period primarily due to oil and gas gathering assets placed in service in the Eagle Ford Shale.

G&A expenses of $76 million for the first quarter of 2012 increased $6 million from the same prior year period primarily due to higher employee-related costs.

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

Gathering and processing costs increased $7 million to $26 million for the first quarter of 2012 compared to $19 million for the same prior year period. The increase primarily reflects increased activities in the Eagle Ford Shale.

Exploration costs of $43 million for the first quarter of 2012 decreased $8 million from $51 million for the same prior year period primarily due to decreased geological and geophysical expenditures in the United States ($10 million) and decreased delay rentals in the United States ($2 million), partially offset by increased geological and geophysical expenditures in Canada ($3 million) and increased exploration administrative expenses in the United States ($2 million).

Impairments include amortization of unproved oil and gas property costs, as well as impairments of proved oil and gas properties and other property, plant and equipment. Unproved properties with individually significant acquisition costs are amortized over the lease term and analyzed on a property-by-property basis for any impairment in value. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. When circumstances indicate that a proved property may be impaired, EOG compares expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated by using the Income Approach as described in the Fair Value Measurement Topic of the Financial Accounting Standards Board's Accounting Standards Codification. For certain natural gas assets held for sale, EOG utilized accepted bids as the basis for determining fair value.

Impairments of $133 million for the first quarter of 2012 were $44 million higher than impairments for the same prior year period primarily due to higher impairments of proved oil and gas properties and other assets in the United States. EOG recorded impairments of proved properties and other assets of $94 million and $48 million for the first quarter of 2012 and 2011, respectively.

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Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are generally 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 first quarter of 2012 increased $16 million to $122 million (6.5% of wellhead revenues) compared to $106 million (7.1% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes as a result of increased wellhead revenues in the United States ($21 million) and increased ad valorem/property taxes in the United States ($3 million), partially offset by decreased severance/production taxes in Canada ($4 million) and Trinidad ($4 million) and increased credits available to EOG in 2012 for Texas high-cost gas severance tax rate reductions ($3 million).

Other income, net was $11 million for the first quarter of 2012 compared to $4 million for the same prior year period. The increase of $7 million was primarily due to higher interest income.

Income tax provision of $196 million for the first quarter of 2012 increased $104 million from $92 million in 2011 due primarily to greater pretax income. The net effective tax rate for the first quarter of 2012 decreased to 38% from 41% in the prior year period. The net effective tax rate for the first quarter of 2012 exceeded the United States statutory tax rate (35%) due mostly to foreign earnings in Trinidad (55% statutory tax rate) combined with losses in Canada (26% statutory tax rate).

Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the three months ended March 31, 2012 were funds generated from operations, proceeds from asset sales and proceeds from stock options exercised. 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 2012, EOG's cash balance decreased $322 million to . . .

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