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EOG > SEC Filings for EOG > Form 10-Q on 5-Nov-2012All Recent SEC Filings

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Form 10-Q for EOG RESOURCES INC


5-Nov-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 liquids 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 liquids-rich acreage. In addition, EOG continues to evaluate certain potential liquids-rich exploration and development prospects. For the first nine months of 2012, crude oil and condensate and natural gas liquids production accounted for approximately 45% of total company production as compared to approximately 35% for the comparable period in 2011. In North America, crude oil and condensate and natural gas liquids production accounted for approximately 52% of total North American production during the first nine months of 2012 as compared to approximately 40% for the comparable period in 2011. This liquids growth primarily reflects increased production from the Eagle Ford Shale near San Antonio, Texas, the North Dakota Bakken, and the Permian Basin. 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 where sales are based upon a Light Louisiana Sweet (LLS) crude oil index. As part of its diversification strategy for its crude-by-rail shipments, in April 2012, EOG completed the construction of a crude oil unloading facility in St. James, Louisiana, where sales are based upon the LLS 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). With the addition of the St. James facility, EOG's crude-by-rail system has access to both the Gulf Coast market and the Cushing, Oklahoma, market. At the beginning of July 2012, EOG also began shipping a portion of its Eagle Ford Shale crude oil production to Gulf Coast sales points on the newly completed Enterprise Products Partners L.P. crude oil pipeline. In addition, EOG began supplying sand for a majority of its completion operations in several plays, primarily in Texas, from Wisconsin sand mines in 2012.

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 the PTP and the Kitimat LNG Terminal. Marketing efforts continue in order to support a final investment decision.

EOG's major producing areas in the United States and Canada are in Louisiana, New Mexico, North Dakota, 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.
Production from the Block 4(a) Toucan Field and the EMZ Area that began in the first quarter of 2012 is supplying 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 (DECC) in March 2012. The production platform was installed during the second quarter of 2012 and the pipelines are scheduled to be installed in the fourth quarter of 2012. EOG expects to begin processing facility installation in the first half of 2013. The Conwy development drilling program is expected to commence during the first quarter of 2013, with initial production expected in the second half of 2013. In the Central North Sea Columbus project, a revised field development plan was submitted to the DECC in the third quarter of 2012 with approval expected in the first quarter of 2013. The project participants are currently negotiating commercial agreements.

EOG's activity in Argentina is focused on the Vaca Muerta oil shale formation in the Neuquén Basin in Neuquén Province. During the first half of 2012, EOG participated in the drilling and completion of a vertical well in the Bajo del Toro Block. In the first quarter of 2012, EOG drilled a well to monitor future well completions in the Aguada del Chivato Block. During the first half of 2012, EOG drilled and completed a horizontal well in this block. Both the horizontal and vertical wells that were completed are under evaluation.

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 31% and 28% at September 30, 2012 and December 31, 2011, respectively. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

On September 10, 2012, EOG closed its sale of $1,250 million aggregate principal amount of 2.625% Senior Notes due 2023 (Notes). Interest on the Notes is payable semiannually in arrears on March 15 and September 15 of each year, beginning March 15, 2013. Net proceeds from the offering of approximately $1,234 million were used for general corporate purposes including the repayment of outstanding commercial paper borrowings and funding of capital expenditures.

EOG's total 2012 capital expenditures are estimated to total approximately $7.6 billion, excluding non-cash items. The majority of 2012 expenditures are 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. In the first nine months of 2012, to cover the anticipated shortfall, EOG sold the Notes and received proceeds of $1,214 million from the sales of producing properties and acreage primarily in the Rocky Mountain area, Upper Gulf Coast area and Canada. 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 and nine months ended September 30, 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.

Three Months Ended September 30, 2012 vs. Three Months Ended September 30, 2011

Net Operating Revenues. During the third quarter of 2012, net operating revenues increased $69 million, or 2%, to $2,955 million from $2,886 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 third quarter of 2012 increased $372 million, or 21%, to $2,109 million from $1,737 million for the same period of 2011. During the third quarter of 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $5 million compared to net gains of $358 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 third quarter of 2012 increased $186 million, or 32%, to $764 million from $578 million for the same period of 2011.
Gains on asset dispositions, net, of $67 million for the third quarter of 2012 primarily consist of gains on asset dispositions in the Rocky Mountain area.

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Wellhead volume and price statistics for the three-month periods ended September 30, 2012 and 2011 were as follows:

                                                        Three Months Ended
                                                           September 30,
                                                        2012           2011

Crude Oil and Condensate Volumes (MBbld) (1)
United States                                             161.3         108.9
Canada                                                      6.7           6.8
Trinidad                                                    1.2           3.1
Other International (2)                                     0.1           0.1
Total                                                     169.3         118.9

Average Crude Oil and Condensate Prices ($/Bbl) (3)
United States                                         $   97.64      $  87.22
Canada                                                    86.09         90.54
Trinidad                                                  90.84         89.70
Other International (2)                                   83.59        110.84
Composite                                                 97.13         87.49

Natural Gas Liquids Volumes (MBbld) (1)
United States                                              58.1          43.2
Canada                                                      0.9           0.8
Total                                                      59.0          44.0

Average Natural Gas Liquids Prices ($/Bbl) (3)
United States                                         $   30.95      $  50.90
Canada                                                    41.09         57.69
Composite                                                 31.11         51.02

Natural Gas Volumes (MMcfd) (1)
United States                                             1,022         1,122
Canada                                                       94           123
Trinidad                                                    387           330
Other International (2)                                       9            12
Total                                                     1,512         1,587

Average Natural Gas Prices ($/Mcf) (3)
United States                                         $    2.61      $   4.06
Canada                                                     2.39          3.81
Trinidad                                                   4.38          3.59
Other International (2)                                    5.67          5.54
Composite                                                  3.07          3.95

Crude Oil Equivalent Volumes (MBoed) (4)
United States                                             389.7         339.4
Canada                                                     23.2          27.9
Trinidad                                                   65.7          58.0
Other International (2)                                     1.7           2.0
Total                                                     480.3         427.3

Total MMBoe (4)                                            44.2          39.3

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

(2) Other International includes EOG's United Kingdom, China and Argentina 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 third quarter of 2012 increased $559 million, or 59%, to $1,512 million from $953 million for the same period of 2011, due to an increase of 50 MBbld, or 42%, in wellhead crude oil and condensate deliveries ($409 million) and a higher composite average wellhead crude oil and condensate price ($150 million). The increase in deliveries primarily reflects increased production in the Eagle Ford Shale and North Dakota Bakken. EOG's composite average wellhead crude oil and condensate price for the third quarter of 2012 increased 11% to $97.13 per barrel compared to $87.49 per barrel for the same period of 2011.

Natural gas liquids revenues for the third quarter of 2012 decreased $37 million, or 18%, to $170 million from $207 million for the same period of 2011, due to a lower composite average natural gas liquids price ($109 million), partially offset by an increase of 15 MBbld, or 34%, in natural gas liquids deliveries ($72 million). The increase in deliveries primarily reflects increased volumes in the Eagle Ford Shale, Permian Basin and Fort Worth Basin Barnett Shale. EOG's composite average natural gas liquids price for the third quarter of 2012 decreased 39% to $31.11 per barrel compared to $51.02 per barrel for the same period of 2011.

Wellhead natural gas revenues for the third quarter of 2012 decreased $150 million, or 26%, to $427 million from $577 million for the same period of 2011.
The decrease was due to a lower composite average wellhead natural gas price ($123 million) and a decrease in natural gas deliveries ($27 million). EOG's composite average wellhead natural gas price for the third quarter of 2012 decreased 22% to $3.07 per thousand cubic feet (Mcf) compared to $3.95 per Mcf for the same period of 2011.

Natural gas deliveries for the third quarter of 2012 decreased 75 MMcfd, or 5%, to 1,512 MMcfd from 1,587 MMcfd for the same period of 2011. The decrease was primarily due to lower production in the United States (100 MMcfd) and Canada (29 MMcfd), partially offset by increased production in Trinidad (57 MMcfd).
The decrease in the United States was attributable to asset sales and decreased production. The decrease in Canada was primarily due to decreased production in Alberta and the Horn River Basin area. The increase in Trinidad was primarily attributable to an increase in contractual deliveries.

During the third quarter of 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $5 million compared to net gains of $358 million for the same period of 2011. During the third quarter of 2012, the net cash inflow related to settled crude oil and natural gas derivative contracts was $249 million compared to the net cash inflow of $52 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 and nine months ended September 30, 2012 and 2011, gathering, processing and marketing revenues were primarily related to sales of third-party crude oil and natural gas. Purchases and sales 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 third quarter of 2012, gathering, processing and marketing revenues and marketing costs increased, compared to the same period of 2011, primarily as a result of increased crude oil marketing activities. Gathering, processing and marketing revenues less marketing costs for the third quarter of 2012 totaled $9 million compared to $5 million for the same period of 2011.

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Operating and Other Expenses. For the third quarter of 2012, operating expenses of $2,349 million were $413 million higher than the $1,936 million incurred in the third quarter of 2011. The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended September 30, 2012 and 2011:

                                                      Three Months Ended
                                                         September 30,
                                                       2012          2011

Lease and Well                                      $     5.73      $  6.34
Transportation Costs                                      3.72         2.77
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties                                   17.86        15.87
Other Property, Plant and Equipment                       0.81         0.73
General and Administrative (G&A)                          2.10         2.09
Interest Expense, Net                                     1.20         1.33
Total (1)                                           $    31.42      $ 29.13

(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 September 30, 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 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 $253 million for the third quarter of 2012 increased $4 million from $249 million for the same prior year period primarily due to increased lease and well administrative expenses ($9 million) and increased operating and maintenance costs in the United States ($6 million) and Trinidad ($2 million), partially offset by decreased operating and maintenance costs in Canada ($4 million) and decreased workover expenditures in Canada ($4 million) and the United States ($3 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 $164 million for the third quarter of 2012 increased $55 million from $109 million for the same prior year period primarily due to increased transportation costs related to production from the Eagle Ford Shale ($29 million) and the Rocky Mountain area ($29 million), partially offset by decreased transportation costs related to production from the Fort Worth Basin Barnett Shale area ($4 million).

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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 economic factors 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 third quarter of 2012 increased $174 million to $826 million from $652 million for the same prior year period. DD&A expenses associated with oil and gas properties for the third quarter of 2012 were $167 million higher than the same prior year period primarily due to higher unit rates in the United States ($73 million), Trinidad ($15 million) and Canada ($5 million) and as a result of increased production in the United States ($80 million) and Trinidad ($3 million), partially offset by decreased production in Canada ($10 million).

DD&A expenses associated with other property, plant and equipment for the third quarter of 2012 were $7 million higher than the same prior year period primarily due to gathering and processing assets placed in service in the Eagle Ford Shale.

G&A expenses of $93 million for the third quarter of 2012 increased $11 million compared to 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 third quarter of 2012 compared to $19 million for the same prior year period. The increase primarily reflects increased activities in the Eagle Ford Shale.

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 utilizes accepted bids as the basis for determining fair value.

Impairments of $63 million for the third quarter of 2012 were $21 million lower than impairments for the same prior year period primarily due to decreased amortization of unproved property costs in the United States ($20 million) and decreased impairments of proved properties in Canada ($15 million), partially offset by increased impairments of other assets in the United States ($18 million). EOG recorded impairments of proved properties and other assets of $33 million and $32 million for the third 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 third quarter of 2012 increased $21 million to $120 million (5.7% of wellhead revenues) compared to $99 million (5.7% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes in the United States ($16 million) and Canada ($3 million) and an increase in ad valorem/property taxes in the United States ($8 million), partially offset by decreased severance/production taxes in Trinidad ($5 million). The increase in severance/production taxes in the United States was primarily as a result of increased wellhead revenues.

Other income, net, was $8 million for the third quarter of 2012 compared to $1 million for the same prior year period. The increase of $7 million was primarily due to an increase in foreign currency transaction gains ($14 million), partially offset by an increase in deferred compensation expense ($5 million).

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