EOG RESOURCES INC - 10-K - Management's Discussion and Analysis of Financial Condition and Results of Operations

(Edgar Glimpses Via Acquire Media NewsEdge) 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, China and Argentina. 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.

Net income for 2012 totaled $570 million as compared to $1,091 million for 2011.

At December 31, 2012, EOG's total estimated net proved reserves were 1,811 million barrels of oil equivalent (MMBoe), a decrease of 243 MMBoe from December 31, 2011. During 2012, net proved crude oil and condensate and natural gas liquids (NGLs) reserves increased by 276 million barrels (MMBbl), and net proved natural gas reserves decreased by 3,111 billion cubic feet or 519 MMBoe.

Operations Several important developments have occurred since January 1, 2012.

United States and Canada. EOG's efforts to identify plays with large 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 crude oil and liquids-rich 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 focused its efforts on developing its existing North American crude oil and liquids-rich acreage. In addition, EOG continues to evaluate certain potential crude oil and, to a lesser extent, liquids-rich natural gas exploration and development prospects. During 2012, crude oil and condensate and NGLs production accounted for approximately 46% of total company production as compared to 37% during 2011. In North America, crude oil and condensate and NGLs production accounted for approximately 53% of total North American production during 2012 as compared to 42% 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. In 2012, EOG's net Eagle Ford Shale production averaged 83.5 thousand barrels per day (MBbld) of crude oil and condensate and NGLs as compared to 34.1 MBbld in 2011. Based on current trends, EOG expects its 2013 crude oil and condensate and NGLs production to continue to increase both in total and as a percentage of total company production as compared to 2012.

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

EOG delivers its crude oil to various markets in the United States, including sales points on the Gulf Coast where sales are based upon the 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 120 MBbld, of which 100 MBbld belongs to EOG. To support its Permian Basin operations, EOG commissioned a crude oil loading facility in Barnhart, Texas, in 2012. EOG believes that its crude-by-rail facilities provide a distinct competitive advantage giving it the ability to direct its crude oil shipments via rail car to the most favorable markets, including both the Gulf Coast and Cushing, Oklahoma, markets. Additionally, in July 2012, EOG 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.

32 -------------------------------------------------------------------------------- During 2012, EOG increased production of processed sand at its state-of-the-art Chippewa Falls, Wisconsin, sand plant. The plant processes sand from multiple nearby EOG-owned sand mines. The first unit train of processed sand was dispatched from Chippewa Falls in January 2012. During 2012, EOG shipped 70 sand unit trains of approximately 100 cars each to a new EOG sand storage facility in Refugio, Texas, where sand can also be coated for added strength.

From Refugio, the sand is shipped primarily to the South Texas Eagle Ford Shale. EOG also ships its processed sand to other plays, including the North Dakota Bakken and the Permian Basin.

EOG Resources Canada Inc. (EOGRC) owned a 30% interest in both the planned liquefied natural gas export terminal to be located near the Port of Kitimat, 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. In December 2012, EOGRC signed a purchase and sale agreement for the sale of its entire interest in the Kitimat LNG Terminal and PTP, as well as approximately 28,500 undeveloped net acres in the Horn River Basin, to Chevron Canada Limited. The transaction closed in February 2013.

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 February 2012, production from both the Toucan Field in Block 4(a) and the adjacent EMZ Area began supplying natural gas under a contract with the Natural Gas Company of Trinidad and Tobago.

During the fourth quarter of 2012, EOG began drilling an exploratory well in the Modified U(a) Block which was successful. This well and three additional wells to be drilled in 2013 will be completed in the first half of 2013.

In 2006, EOG Resources United Kingdom Limited (EOGUK) participated in the drilling and successful testing of the Columbus prospect in the Central North Sea Block 23/16f. EOG has a 25% non-operating working interest in this block.

A successful Columbus natural gas prospect appraisal well was drilled during the third quarter of 2007. The field operator submitted a revised field development plan to the U.K. Department of Energy and Climate Change (DECC) during the third quarter of 2012 and anticipates receiving approval of this plan in the second quarter of 2013. The project participants are currently negotiating commercial agreements.

In 2007, EOGUK was awarded a license for two blocks in the East Irish Sea - Blocks 110/7b and 110/12a. In 2009, EOGUK drilled a successful exploratory well in its East Irish Sea Block 110/12a. Well 110/12-6, in which EOGUK has a 100% working interest, was an oil discovery and was designated the Conwy field. In 2010, EOGUK added an adjoining field in its East Irish Sea block, designated Corfe, to its overall development plans. Field development plans for the Conwy and Corfe fields were approved by the DECC in March 2012. The production platform and pipelines were installed in 2012, and EOG expects to begin processing facility installation during the first half of 2013. The Conwy development drilling program is expected to commence during the second quarter of 2013, with initial production expected in the fourth quarter of 2013.

In 2009, EOGUK was awarded a license for Block 21/12b in the Central North Sea where it expects to drill an exploratory well to test a crude oil prospect in late 2013. EOGUK has 100% interest in this block.

In 2011, EOG signed two exploration contracts and one farm-in agreement covering approximately 80,000 net acres in the Neuquén Basin in Neuquén Province, Argentina. 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 half of 2012, EOG drilled a well to monitor future well completions in the Aguada del Chivato Block and drilled and completed a horizontal well in this block. Both the horizontal and vertical wells that were completed are under evaluation.

During the first quarter of 2013, EOG plans to complete the monitoring well in the Aguada del Chivato Block.

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.

33 -------------------------------------------------------------------------------- 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 32% and 28% at December 31, 2012 and 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 semi-annually in arrears on March 15 and September 15 of each year, beginning March 15, 2013. Net proceeds from the Notes 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.

During 2012, EOG funded $7.5 billion in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), paid $181 million in dividends to common stockholders and purchased $59 million of treasury stock in connection with stock compensation plans, primarily by utilizing cash provided from its operating activities, net proceeds of $1,234 million from the issuance of the Notes, proceeds of $1,310 million from the sale of certain North American assets and proceeds of $83 million from stock options exercised and employee stock purchase plan activity.

Total anticipated 2013 capital expenditures are estimated to range from approximately $7.0 billion to $7.2 billion, excluding acquisitions. The majority of 2013 expenditures will be focused on United States crude oil and, to a lesser extent, liquids-rich natural gas drilling activity. EOG expects capital expenditures to be greater than cash flow from operating activities for 2013. EOG's business plan includes selling certain non-core assets in 2013, realizing proceeds of approximately $550 million, to cover the anticipated shortfall. 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 $2.0 billion senior unsecured Revolving Credit Agreement (2011 Facility) and equity and debt offerings.

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.

34 -------------------------------------------------------------------------------- Results of Operations The following review of operations for each of the three years in the period ended December 31, 2012, should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning on page F-1.

Net Operating Revenues During 2012, net operating revenues increased $1,557 million, or 15%, to $11,683 million from $10,126 million in 2011. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, in 2012 increased $1,100 million, or 16%, to $7,958 million from $6,858 million in 2011. During 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $394 million compared to net gains of $626 million in 2011. Gathering, processing and marketing revenues, which are revenues generated from sales of third-party crude oil and condensate, NGLs and natural gas as well as gathering fees associated with gathering third-party natural gas, increased $981 million, or 46%, during 2012, to $3,097 million from $2,116 million in 2011. Gains on asset dispositions, net, totaled $193 million and $493 million in 2012 and 2011, respectively.

35 -------------------------------------------------------------------------------- Wellhead volume and price statistics for the years ended December 31, 2012, 2011 and 2010 were as follows: Year Ended December 31 2012 2011 2010 Crude Oil and Condensate Volumes (MBbld) (1) United States 149.3 102.0 63.2 Canada 7.0 7.9 6.7 Trinidad 1.5 3.4 4.7 Other International (2) 0.1 0.1 0.1 Total 157.9 113.4 74.7 Average Crude Oil and Condensate Prices ($/Bbl) (3) United States $ 98.38 $ 92.92 $ 74.88 Canada 86.08 91.92 72.66 Trinidad 92.26 90.62 68.80 Other International (2) 89.57 100.11 73.11 Composite 97.77 92.79 74.29 Natural Gas Liquids Volumes (MBbld) (1) United States 55.1 41.5 29.5 Canada 0.8 0.9 0.9 Total 55.9 42.4 30.4 Average Natural Gas Liquids Prices ($/Bbl) (3) United States $ 35.41 $ 50.37 $ 41.68 Canada 44.13 52.69 43.40 Composite 35.54 50.41 41.73 Natural Gas Volumes (MMcfd) (1) United States 1,034 1,113 1,133 Canada 95 132 200 Trinidad 378 344 341 Other International (2) 9 13 14 Total 1,516 1,602 1,688 Average Natural Gas Prices ($/Mcf) (3) United States $ 2.51 $ 3.92 $ 4.30 Canada 2.49 3.71 3.91 Trinidad 3.72 3.53 2.65 Other International (2) 5.71 5.62 4.90 Composite 2.83 3.83 3.93 Crude Oil Equivalent Volumes (MBoed) (4) United States 376.6 329.1 281.5 Canada 23.6 30.7 40.9 Trinidad 64.5 60.7 61.5 Other International (2) 1.7 2.2 2.5 Total 466.4 422.7 386.4 Total MMBoe (4) 170.7 154.3 141.1 (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 (see Note 11 to Consolidated Financial Statements).

(4) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or NGLs 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.

36-------------------------------------------------------------------------------- 2012 compared to 2011. Wellhead crude oil and condensate revenues in 2012 increased $1,821 million, or 47%, to $5,659 million from $3,838 million in 2011, due to an increase of 45 MBbld, or 39%, in wellhead crude oil and condensate deliveries ($1,533 million) and a higher composite average wellhead crude oil and condensate price ($288 million). The increase in deliveries primarily reflects increased production in the Eagle Ford Shale and Bakken. EOG's composite average wellhead crude oil and condensate price for 2012 increased 5% to $97.77 per barrel compared to $92.79 per barrel in 2011.

NGLs revenues in 2012 decreased $52 million, or 7%, to $727 million from $779 million in 2011, due to a lower composite average price ($304 million), partially offset by an increase of 14 MBbld, or 32%, in NGLs deliveries ($252 million). The increase in deliveries primarily reflects increased volumes in the Eagle Ford Shale (7 MBbld), the Fort Worth Basin Barnett Shale (3 MBbld) and the Permian Basin (2 MBbld). EOG's composite average NGLs price in 2012 decreased 30% to $35.54 per barrel compared to $50.41 per barrel in 2011.

Wellhead natural gas revenues in 2012 decreased $669 million, or 30%, to $1,572 million from $2,241 million in 2011. The decrease was due to a lower composite average wellhead natural gas price ($554 million) and decreased natural gas deliveries ($115 million). Natural gas deliveries in 2012 decreased 86 MMcfd, or 5%, to 1,516 MMcfd from 1,602 MMcfd in 2011. The decrease was primarily due to lower production in the United States (79 MMcfd) and Canada (37 MMcfd), partially offset by increased production in Trinidad (34 MMcfd). The decrease in the United States was primarily attributable to asset sales and reduced natural gas drilling activity. The decrease in Canada primarily reflects decreased production in Alberta and the Horn River Basin area. The increase in Trinidad was primarily attributable to an increase in contractual deliveries.

EOG's composite average wellhead natural gas price decreased 26% to $2.83 per Mcf in 2012 from $3.83 per Mcf in 2011.

During 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $394 million, which included net realized gains of $711 million. During 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $626 million, which included net realized gains of $181 million.

Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, NGLs and natural gas as well as fees associated with gathering third-party natural gas. For the years ended December 31, 2012, 2011 and 2010, 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 2012, gathering, processing and marketing revenues and marketing costs increased, compared to 2011, primarily as a result of increased crude oil marketing activities. Gathering, processing and marketing revenues less marketing costs in 2012 totaled $61 million compared to $44 million in 2011.

2011 compared to 2010. Wellhead crude oil and condensate revenues in 2011 increased $1,839 million, or 92%, to $3,838 million from $1,999 million in 2010, due to an increase of 39 MBbld, or 52%, in wellhead crude oil and condensate deliveries ($1,074 million) and a higher composite average wellhead crude oil and condensate price ($765 million). The increase in deliveries primarily reflects increased production in Texas (35 MBbld) and Colorado (3 MBbld).

Production increases in Texas were the result of increased production from the Eagle Ford Shale (26 MBbld) and Fort Worth Basin Barnett Combo (8 MBbld) plays.

EOG's composite average wellhead crude oil and condensate price for 2011 increased 25% to $92.79 per barrel compared to $74.29 per barrel in 2010.

37 -------------------------------------------------------------------------------- NGLs revenues in 2011 increased $317 million, or 69%, to $779 million from $462 million in 2010, due to an increase of 12 MBbld, or 39%, in NGLs deliveries ($183 million) and a higher composite average price ($134 million). The increase in deliveries primarily reflects increased volumes in the Fort Worth Basin Barnett Shale (6 MBbld), the Eagle Ford Shale (4 MBbld) and the Rocky Mountain area (3 MBbld). EOG's composite average NGLs price in 2011 increased 21% to $50.41 per barrel compared to $41.73 per barrel in 2010.

Wellhead natural gas revenues in 2011 decreased $179 million, or 7%, to $2,241 million from $2,420 million in 2010. The decrease was due to reduced natural gas deliveries ($123 million) and a lower composite average wellhead natural gas price ($56 million). EOG's composite average wellhead natural gas price decreased 3% to $3.83 per Mcf in 2011 from $3.93 per Mcf in 2010.

Natural gas deliveries in 2011 decreased 86 MMcfd, or 5%, to 1,602 MMcfd from 1,688 MMcfd in 2010. The decrease was primarily due to lower production in Canada (68 MMcfd) and the United States (20 MMcfd). The decrease in Canada primarily reflects sales of certain shallow natural gas assets in 2010, partially offset by increased production from the Horn River Basin area. The decrease in the United States was primarily attributable to decreased production in the Rocky Mountain area (36 MMcfd), Louisiana (17 MMcfd), Mississippi (11 MMcfd), New Mexico (8 MMcfd) and Kansas (5 MMcfd), partially offset by increased production in Texas (38 MMcfd) and Pennsylvania (23 MMcfd).

During 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $626 million, which included net realized gains of $181 million. During 2010, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $62 million, which included net realized gains of $7 million.

During 2011, 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 in 2011 increased $19 million to $44 million from $25 million in 2010, primarily as a result of increased crude oil marketing activities.

Operating and Other Expenses 2012 compared to 2011. During 2012, operating expenses of $10,203 million were $2,190 million higher than the $8,013 million incurred in 2011. The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2012 and 2011: 2012 2011 Lease and Well $ 5.85 $ 6.11 Transportation Costs 3.52 2.79 Depreciation, Depletion and Amortization (DD&A) - Oil and Gas Properties 17.71 15.52 Other Property, Plant and Equipment 0.85 0.79 General and Administrative (G&A) 1.94 1.98 Net Interest Expense 1.25 1.36 Total (1) $ 31.12 $ 28.55 (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 2012 compared to 2011 are set forth below.

38 -------------------------------------------------------------------------------- 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 $1,000 million in 2012 increased $58 million from $942 million in 2011 primarily due to higher operating and maintenance expenses in the United States ($60 million) and Trinidad ($5 million) and increased lease and well administrative expenses in the United States ($15 million), partially offset by lower operating and maintenance expenses in Canada ($12 million) and decreased workover expenditures in Canada ($6 million) and the United States ($5 million).

Transportation costs represent costs associated with the delivery of hydrocarbon products from the lease to a downstream point of sale. Transportation costs include transportation fees, costs associated with crude-by-rail operations, 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 and fuel costs.

Transportation costs of $601 million in 2012 increased $171 million from $430 million in 2011 primarily due to increased transportation costs related to production from the Eagle Ford Shale ($101 million) and the Rocky Mountain area ($73 million).

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, 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 generally calculated using the straight-line depreciation method over the useful lives of the assets. Other property, plant and equipment consists of gathering, transportation and processing infrastructure assets, compressors, crude-by-rail assets, sand mine and sand processing assets, vehicles, buildings and leasehold improvements, furniture and fixtures, and computer hardware and software.

DD&A expenses in 2012 increased $654 million to $3,170 million from $2,516 million in 2011. DD&A expenses associated with oil and gas properties in 2012 were $631 million higher than in 2011 primarily due to higher unit rates ($379 million), increased production in the United States ($296 million) and Trinidad ($7 million), partially offset by a decrease in production in Canada ($57 million). DD&A rates increased due primarily to a proportional increase in production from higher cost properties in the United States ($331 million), Trinidad ($33 million) and Canada ($20 million).

DD&A expenses associated with other property, plant and equipment were $23 million higher in 2012 than in 2011 primarily due to gathering and processing assets being placed in service in the Eagle Ford Shale.

G&A expenses of $332 million in 2012 were $27 million higher than 2011 due primarily to higher employee-related costs ($22 million) and higher information systems costs ($5 million).

39 -------------------------------------------------------------------------------- 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 $17 million to $98 million in 2012 compared to $81 million in 2011. The increase primarily reflects increased activities in the Eagle Ford Shale ($21 million), partially offset by decreased costs in the Fort Worth Basin Barnett Shale area ($7 million).

Exploration costs of $186 million in 2012 increased $14 million from $172 million for the same prior year period primarily due to increased expenditures in the United States.

Impairments include amortization of unproved oil and gas property costs, as well as impairments of proved oil and gas properties and other assets. 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 (ASC). For certain assets held for sale, EOG utilizes accepted bids as the basis for determining fair value.

Impairments of $1,271 million in 2012 increased $240 million from $1,031 million in 2011 primarily due to increased impairments of proved and unproved properties in Canada ($534 million), partially offset by decreased impairments of proved properties and other assets in the United States ($232 million) and decreased amortization of unproved property costs ($50 million) in the United States. EOG recorded impairments of proved and unproved properties; other property, plant and equipment; and other assets of $1,133 million and $834 million in 2012 and 2011, respectively. The 2012 and 2011 amounts include impairments of $1,022 million and $745 million related to certain North American assets as a result of declining commodity prices and using accepted bids for determining fair value.

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 in 2012 increased $84 million to $495 million (6.2% of wellhead revenues) from $411 million (6.0% of wellhead revenues) in 2011. The increase in taxes other than income was primarily due to increased severance/production taxes in the United States ($70 million) primarily as a result of increased wellhead revenues and a newly enacted fee imposed by the State of Pennsylvania on certain wells drilled in the state in 2012 and prior years and higher ad valorem/property taxes in the United States ($30 million), partially offset by decreased severance/production taxes in Trinidad ($17 million).

Other income, net was $14 million in 2012 compared to $7 million in 2011. The increase of $7 million was primarily due to higher interest income ($8 million) primarily as a result of interest on severance tax refunds, an increase in foreign currency transaction gains ($8 million) and higher equity income from ammonia plants in Trinidad ($3 million), partially offset by increased losses on warehouse stock ($5 million) and higher operating losses on EOG's investment in the PTP ($4 million).

Income tax provision of $710 million in 2012 decreased $109 million from $819 million in 2011 due primarily to lower pretax income. The net effective tax rate for 2012 increased to 55% from 43% in 2011. The effective tax rate for 2012 exceeded the United States statutory tax rate (35%) due primarily to foreign losses in Canada (26% statutory tax rate) and Canadian valuation allowances.

40 -------------------------------------------------------------------------------- 2011 compared to 2010. During 2011, operating expenses of $8,013 million were $2,436 million higher than the $5,577 million incurred in 2010. The following table presents the costs per Boe for the years ended December 31, 2011 and 2010: 2011 2010 Lease and Well $ 6.11 $ 4.96 Transportation Costs 2.79 2.74 DD&A- Oil and Gas Properties (1) 15.52 13.19 Other Property, Plant and Equipment 0.79 0.79 G&A 1.98 1.99 Net Interest Expense 1.36 0.92 Total (2) $ 28.55 $ 24.59 (1) The 2010 amount excludes the reductions in the estimated fair value of the contingent consideration liability of $24 million, or $0.17 per Boe, related to the acquisition of certain unproved acreage.

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

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and net interest expense for 2011 compared to 2010 are set forth below.

Lease and well expenses of $942 million in 2011 increased $244 million from $698 million in 2010 primarily due to higher operating and maintenance expenses in the United States ($188 million), increased lease and well administrative expenses in the United States ($33 million), increased workover expenditures in the United States ($11 million) and Canada ($4 million) and unfavorable changes in the Canadian exchange rate ($6 million), partially offset by lower operating and maintenance costs in Canada ($4 million).

Transportation costs of $430 million in 2011 increased $45 million from $385 million in 2010 primarily due to increased transportation costs in the Eagle Ford Shale ($30 million), the Upper Gulf Coast region ($16 million) and the Fort Worth Basin Barnett Shale area ($9 million), partially offset by decreased transportation costs in Canada ($4 million), the Rocky Mountain area ($2 million) and the South Texas area ($2 million). The net increase in transportation costs primarily reflects increased volumes transported to downstream markets.

DD&A expenses in 2011 increased $574 million to $2,516 million from $1,942 million in 2010. DD&A expenses associated with oil and gas properties in 2011 were $563 million higher than in 2010 primarily due to higher unit rates ($375 million), increased production in the United States ($249 million), a reduction during 2010 in the fair value of the contingent consideration liability ($24 million) and unfavorable changes in the Canadian exchange rate ($11 million), partially offset by a decrease in production in Canada ($77 million). DD&A rates increased due primarily to a proportional increase in production from higher cost properties in the United States ($306 million), Trinidad ($37 million) and Canada ($9 million).

DD&A expenses associated with other property, plant and equipment were $11 million higher in 2011 than in 2010 primarily due to gathering and processing assets being placed in service in the Eagle Ford Shale ($5 million) and the Rocky Mountain area ($3 million).

G&A expenses of $305 million in 2011 were $25 million higher than 2010 due primarily to higher employee-related costs.

Net interest expense of $210 million in 2011 increased $80 million from $130 million in 2010 primarily due to a higher average debt balance ($56 million), lower capitalized interest ($18 million) and the write-off of fees associated with revolving credit facilities cancelled in 2011 in connection with the establishment of the 2011 Facility ($6 million).

41 -------------------------------------------------------------------------------- Gathering and processing costs increased $14 million to $81 million in 2011 compared to $67 million in 2010. The increase primarily reflects increased activities in the Fort Worth Basin Barnett Shale area ($10 million), the Eagle Ford Shale ($5 million) and Canada ($5 million), partially offset by decreased activities in the Upper Gulf Coast region ($5 million) and the Rocky Mountain area ($4 million).

Exploration costs of $172 million in 2011 decreased $15 million from $187 million for the same prior year period primarily due to decreased geological and geophysical expenditures in the United States.

Impairments of $1,031 million in 2011 increased $288 million from $743 million in 2010 primarily due to increased impairments of proved properties and other property, plant and equipment in the United States. EOG recorded impairments of proved properties and other property, plant and equipment of $834 million and $526 million in 2011 and 2010, respectively. The 2011 amount includes impairments of $745 million related to certain North American natural gas assets as a result of declining commodity prices and accepted bids.

Taxes other than income in 2011 increased $94 million to $411 million (6.0% of wellhead revenues) from $317 million (6.5% of wellhead revenues) in 2010. The increase in taxes other than income was primarily due to increased severance/production taxes primarily as a result of increased wellhead revenues in the United States ($101 million) and a decrease in credits available to EOG in 2011 for Texas high cost gas severance tax rate reductions as a result of fewer wells qualifying for such credit ($8 million), partially offset by lower ad valorem/property taxes in the United States ($9 million) and Canada ($4 million) and decreased severance/production taxes in Trinidad ($4 million).

Other income, net was $7 million in 2011 compared to $14 million in 2010. The decrease of $7 million was primarily due to operating losses on EOG's investment in the PTP ($5 million) and an increase in foreign currency transaction losses ($5 million), partially offset by higher equity income from ammonia plants in Trinidad ($3 million).

Income tax provision of $819 million in 2011 increased $572 million from $247 million in 2010 due primarily to greater pretax income. The net effective tax rate for 2011 decreased to 43% from 61% in 2010. The effective tax rate for 2011 exceeded the United States statutory tax rate (35%) due mostly to foreign earnings in Trinidad (55% statutory tax rate) combined with losses in Canada (27% statutory tax rate).

Capital Resources and Liquidity Cash Flow The primary sources of cash for EOG during the three-year period ended December 31, 2012, were net funds generated from operations, net proceeds from issuances of long-term debt, proceeds from asset sales, net proceeds from the sale of Common Stock, proceeds from stock options exercised and employee stock purchase plan activity, net commercial paper borrowings and borrowings under other uncommitted credit facilities and revolving credit facilities. The primary uses of cash were exploration and development expenditures; other property, plant and equipment expenditures; dividend payments; and repayments of debt.

2012 compared to 2011. Net cash provided by operating activities of $5,237 million in 2012 increased $659 million from $4,578 million in 2011 primarily reflecting an increase in wellhead revenues ($1,100 million) and a favorable change in the net cash flow from the settlement of financial commodity derivative contracts ($531 million), partially offset by unfavorable changes in working capital and other assets and liabilities ($422 million), an increase in cash operating expenses ($369 million) and an increase in net cash paid for income taxes ($100 million).

Net cash used in investing activities of $6,119 million in 2012 increased by $364 million from $5,755 million for the same period of 2011 due primarily to an increase in additions to oil and gas properties ($441 million) and a decrease in proceeds from sales of assets ($123 million), partially offset by favorable changes in working capital associated with investing activities ($163 million) and a decrease in additions to other property, plant and equipment ($37 million).

42 -------------------------------------------------------------------------------- Net cash provided by financing activities of $1,140 million in 2012 included net proceeds from the issuance of the Notes ($1,234 million), proceeds from stock options exercised and employee stock purchase plan activity ($83 million) and excess tax benefits from stock-based compensation ($67 million). Cash used in financing activities during 2012 included cash dividend payments ($181 million) and treasury stock purchases in connection with stock compensation plans ($59 million).

2011 compared to 2010. Net cash provided by operating activities of $4,578 million in 2011 increased $1,869 million from $2,709 million in 2010 primarily reflecting an increase in wellhead revenues ($1,977 million), favorable changes in the net cash flow from the settlement of financial commodity derivative contracts ($174 million) and favorable changes in working capital and other assets and liabilities ($137 million), partially offset by an increase in cash operating expenses ($383 million), an increase in cash paid for interest expense ($40 million) and an increase in cash paid for income taxes ($27 million).

Net cash used in investing activities of $5,755 million in 2011 increased by $852 million from $4,903 million for the same period of 2010 due primarily to an increase in additions to oil and gas properties ($1,084 million), unfavorable changes in working capital associated with investing activities ($446 million) and an increase in additions to other property, plant and equipment ($286 million), partially offset by an increase in proceeds from sales of assets ($761 million) and the acquisition of Galveston LNG Inc. in 2010 ($210 million).

Net cash provided by financing activities of $1,009 million in 2011 included net proceeds from the sale of Common Stock ($1,388 million) and proceeds from stock options exercised and employee stock purchase plan activity ($36 million). Cash used in financing activities during 2011 included the repayment of long-term debt ($220 million), cash dividend payments ($167 million), treasury stock purchases in connection with stock compensation plans ($24 million) and debt issuance costs associated with the establishment of the 2011 Facility ($5 million).

Total Expenditures The table below sets out components of total expenditures for the years ended December 31, 2012, 2011 and 2010 (in millions): 2012 2011 2010 Expenditure Category Capital Drilling and Facilities $ 6,184 $ 5,878 $ 4,634 Leasehold Acquisitions (1) 505 301 399 Property Acquisitions 1 4 18 Capitalized Interest 50 58 76 Subtotal 6,740 6,241 5,127 Exploration Costs 186 172 187 Dry Hole Costs 15 53 72 Exploration and Development Expenditures 6,941 6,466 5,386 Asset Retirement Costs 127 133 72 Total Exploration and Development Expenditures 7,068 6,599 5,458 Other Property, Plant and Equipment (2) 686 656 581 Total Expenditures $ 7,754 $ 7,255 $ 6,039 (1) In 2012, leasehold acquisitions included $20 million related to non-cash property exchanges.

(2) In 2012, other property, plant and equipment included non-cash additions of $66 million in connection with a capital lease transaction in the Eagle Ford Shale.

43-------------------------------------------------------------------------------- Exploration and development expenditures of $6,941 million for 2012 were $475 million higher than the prior year due primarily to increased drilling and facilities expenditures in the United States ($263 million), the United Kingdom ($65 million), Argentina ($41 million) and Canada ($18 million); increased leasehold acquisition expenditures in the United States ($176 million) and Canada ($27 million); and increased exploration costs in the United States ($14 million). These increases were partially offset by decreased drilling and facilities expenditures in Trinidad ($84 million), decreased dry hole costs in the United States ($29 million) and decreased capitalized interest in the United States ($8 million). The 2012 exploration and development expenditures of $6,941 million included $5,989 million in development, $901 million in exploration and $50 million in capitalized interest. The 2011 exploration and development expenditures of $6,466 million included $5,797 million in development, $607 million in exploration, $58 million in capitalized interest and $4 million in property acquisitions. In 2011, other property, plant and equipment expenditures included $231 million for sand mine and sand processing assets. The 2010 exploration and development expenditures of $5,386 million included $4,366 million in development, $926 million in exploration, $76 million in capitalized interest and $18 million in property acquisitions. In 2010, other property, plant and equipment expenditures included $210 million for the acquisition of Galveston LNG Inc.

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

Derivative Transactions During 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $394 million, which included net realized gains of $711 million. During 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $626 million, which included net realized gains of $181 million. See Note 11 to Consolidated Financial Statements.

Commodity Derivative Contracts. The total fair value of EOG's crude oil and natural gas derivative contracts is reflected on the Consolidated Balance Sheets at December 31, 2012, as a net asset of $145 million. Presented below is a comprehensive summary of EOG's crude oil derivative contracts at February 21, 2013, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).

Crude Oil Derivative Contracts Weighted Volume (1) Average Price (Bbld) ($/Bbl) 2013 January 2013 (closed) 101,000 $99.29 February 1, 2013 through April 30, 2013 109,000 99.17 May 1, 2013 through June 30, 2013 101,000 99.29 July 1, 2013 through December 31, 2013 93,000 98.44 (1) EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional three-month or six-month periods. Options covering a notional volume of 8,000 Bbld are exercisable on April 30, 2013. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 8,000 Bbld at an average price of $97.66 per barrel for the period May 1, 2013 through July 31, 2013. Options covering a notional volume of 62,000 Bbld are exercisable on June 28, 2013. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 62,000 Bbld at an average price of $100.24 per barrel for the period July 1, 2013 through December 31, 2013. Options covering a notional volume of 54,000 Bbld are exercisable on December 31, 2013. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 54,000 Bbld at an average price of $98.91 per barrel for the period January 1, 2014 through June 30, 2014.

44-------------------------------------------------------------------------------- Presented below is a comprehensive summary of EOG's natural gas derivative contracts at February 21, 2013, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

Natural Gas Derivative Contracts Weighted Volume Average Price (MMBtud) ($/MMBtu) 2013 (1) January 1, 2013 through February 28, 2013 (closed) 150,000 $4.79 March 1, 2013 through December 31, 2013 150,000 4.79 2014 (2) (1) EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates. Such options are exercisable monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for the period from March 1, 2013 through December 31, 2013.

(2) In July 2012, EOG settled its natural gas financial price swap contracts for the period January 1, 2014 through December 31, 2014 and received proceeds of $36.6 million. In connection with these contracts, the counterparties retain an option of entering into derivative contracts at future dates. Such options are exercisable monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for each month of 2014.

Financing EOG's debt-to-total capitalization ratio was 32% at December 31, 2012, compared to 28% at December 31, 2011. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

During 2012, the principal amount of total debt outstanding increased $1,250 million to $6,290 million at December 31, 2012, from $5,040 million at December 31, 2011. The estimated fair value of EOG's debt at December 31, 2012 and 2011 was $7,032 million and $5,657 million, respectively. The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable inputs regarding interest rates available to EOG at year-end. EOG's debt is primarily at fixed interest rates. While changes in interest rates affect the fair value of EOG's debt, such changes do not expose EOG to material fluctuations in earnings or cash flow. During 2012, EOG entered into a capital lease transaction for the use of newly constructed crude oil storage tanks in the Eagle Ford Shale. At December 31, 2012, the capital lease liability totaled $63 million. See Note 2 to Consolidated Financial Statements.

During 2012, EOG utilized cash provided by operating activities, proceeds from the issuance of the Notes as further described below, proceeds from asset sales and cash provided by borrowings from its commercial paper program to fund its capital programs. While EOG maintains a $2.0 billion commercial paper program, the maximum outstanding at any time during 2012 was $959 million, and the amount outstanding at year-end was zero. The maximum amount outstanding under uncommitted credit facilities during 2012 was $6 million with zero outstanding at year-end. The average borrowings outstanding under the commercial paper program and the uncommitted credit facilities were $236 million and $41 thousand, respectively, during the year 2012. EOG considers this excess availability, which is backed by its $2.0 billion senior unsecured Revolving Credit Agreement described in Note 2 to Consolidated Financial Statements, to be ample to meet its ongoing operating needs.

On September 10, 2012, EOG closed its sale of $1.25 billion aggregate principal amount of the Notes. Interest on the Notes is payable semi-annually in arrears on March 15 and September 15 of each year, beginning March 15, 2013. Net proceeds from the Notes offering of approximately $1,234 million were used for general corporate purposes, including repayment of outstanding commercial paper borrowings and funding of capital expenditures.

45 -------------------------------------------------------------------------------- Contractual Obligations The following table summarizes EOG's contractual obligations at December 31, 2012, (in thousands): 2018 & Contractual Obligations (1) Total 2013 2014 - 2015 2016 - 2017 Beyond Current and Long-Term Debt $ 6,290,000 $ 400,000 $ 1,000,000 $ 1,000,000 $ 3,890,000 Capital Lease 62,968 6,579 11,325 12,908 32,156 Non-Cancelable Operating 523,311 152,021 97,804 78,232 195,254 Leases Interest Payments on Long-Term Debt and Capital Lease 1,690,093 269,996 460,030 416,957 543,110 Transportation and Storage Service Commitments (2) 5,129,835 1,582,227 1,267,751 1,111,416 1,168,441 Drilling Rig Commitments (3) 263,301 167,408 86,472 3,421 6,000 Seismic Purchase Obligations 15,572 15,397 175 - - Fracturing Services 275,319 220,531 51,164 3,624 - Obligations Other Purchase Obligations 104,520 76,550 18,537 9,204 229 Total Contractual $ 14,354,919 $ 2,890,709 $ 2,993,258 $ 2,635,762 $ 5,835,190 Obligations (1) This table does not include the liability for unrecognized tax benefits, EOG's pension or postretirement benefit obligations or liability for dismantlement, abandonment and asset retirement obligations (see Notes 5, 6 and 14, respectively, to Consolidated Financial Statements).

(2) Amounts shown are based on current transportation and storage rates and the foreign currency exchange rates used to convert Canadian dollars and British pounds into United States dollars at December 31, 2012. Management does not believe that any future changes in these rates before the expiration dates of these commitments will have a material adverse effect on the financial condition or results of operations of EOG.

(3) Amounts shown represent minimum future expenditures for drilling rig services. EOG's expenditures for drilling rig services will exceed such minimum amounts to the extent EOG utilizes the drilling rigs subject to a particular contractual commitment for a period greater than the period set forth in the governing contract or if EOG utilizes drilling rigs in addition to the drilling rigs subject to the particular contractual commitment (for example, pursuant to the exercise of an option to utilize additional drilling rigs provided for in the governing contract).

Off-Balance Sheet Arrangements EOG does not participate in financial transactions that generate relationships with unconsolidated entities or financial partnerships. Such entities or partnerships, often referred to as variable interest entities (VIE) or special purpose entities (SPE), are generally established for the purpose of facilitating off-balance sheet arrangements or other limited purposes. EOG was not involved in any unconsolidated VIE or SPE financial transactions or any other "off-balance sheet arrangement" (as defined in Item 303(a)(4)(ii) of Regulation S-K) during any of the periods covered by this report, and currently has no intention of participating in any such transaction or arrangement in the foreseeable future.

Foreign Currency Exchange Rate Risk During 2012, EOG was exposed to foreign currency exchange rate risk inherent in its operations in foreign countries, including Canada, Trinidad, the United Kingdom, China and Argentina. The foreign currency most significant to EOG's operations during 2012 was the Canadian dollar. The fluctuation of the Canadian dollar in 2012 impacted both the revenues and expenses of EOG's Canadian subsidiaries. However, since Canadian commodity prices are largely correlated to United States prices, the changes in the Canadian currency exchange rate have less of an impact on the Canadian revenues than the Canadian expenses. EOG continues to monitor the foreign currency exchange rates of countries in which it is currently conducting business and may implement measures to protect against foreign currency exchange rate risk.

46 -------------------------------------------------------------------------------- Effective March 9, 2004, EOG entered into a foreign currency swap transaction with multiple banks to eliminate exchange rate impacts that may result from the notes offered by one of its Canadian subsidiaries on the same date (see Note 2 to Consolidated Financial Statements). EOG accounts for the foreign currency swap transaction using the hedge accounting method, pursuant to the provisions of the Derivatives and Hedging Topic of the ASC. Under those provisions, as of December 31, 2012, EOG recorded the fair value of the foreign currency swap of $55 million in Other Liabilities on the Consolidated Balance Sheets. Changes in the fair value of the foreign currency swap resulted in no net impact to Net Income on the Consolidated Statements of Income and Comprehensive Income. The after-tax net impact from the foreign currency swap transaction resulted in an increase of $1 million to Accumulated Other Comprehensive Income in the Stockholders' Equity section of the Consolidated Balance Sheets.

Outlook Pricing. Crude oil and natural gas prices have been volatile, and this volatility is expected to continue. As a result of the many uncertainties associated with the world political environment, the availabilities of other worldwide energy supplies and the relative competitive relationships of the various energy sources in the view of consumers, EOG is unable to predict what changes may occur in crude oil and condensate, NGLs, natural gas, ammonia and methanol prices in the future. The market price of crude oil and condensate, NGLs and natural gas in 2013 will impact the amount of cash generated from operating activities, which will in turn impact EOG's financial position. See ITEM 1A. Risk Factors.

Including the impact of EOG's 2013 crude oil derivative contracts (exclusive of options) and based on EOG's tax position, EOG's price sensitivity in 2013 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGLs price, is approximately $28 million for net income and $41 million for cash flows from operating activities.

Including the impact of EOG's 2013 natural gas derivative contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2013 for which prices have not been determined under long-term marketing contracts, EOG's price sensitivity for each $0.10 per Mcf increase or decrease in wellhead natural gas price is approximately $18 million for net income and $27 million for cash flows from operating activities. For information regarding EOG's crude oil and natural gas financial commodity derivative contracts at February 21, 2013, see "Derivative Transactions" above.

Capital. EOG plans to continue to focus a substantial portion of its exploration and development expenditures in its major producing areas in the United States.

In particular, EOG will be focused on United States crude oil drilling activity in its Eagle Ford, Bakken and Three Forks plays and, to a lesser extent, liquids-rich natural gas drilling. United States natural gas drilling activity will be limited to that necessary to hold acreage, primarily in the Marcellus.

In order to diversify its overall asset portfolio, EOG expects to conduct exploratory activity in other areas outside of the United States and Canada and will continue to evaluate the potential for involvement in additional exploitation-type opportunities.

The total anticipated 2013 capital expenditures of $7.0 to $7.2 billion, excluding acquisitions, is structured to maintain the flexibility necessary under EOG's strategy of funding its exploration, development, exploitation and acquisition activities primarily from available internally generated cash flow and the sale of certain non-core assets. EOG expects capital expenditures to be greater than cash flow from operating activities for 2013. EOG's business plan includes selling certain non-core assets in 2013, realizing proceeds of approximately $550 million, to cover the anticipated shortfall. However, 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.

Operations. EOG expects to increase overall production in 2013 by 4% over 2012 levels. Total liquids production is expected to increase by 23%, comprised of an increase in crude oil and condensate and NGLs production of 28% and 10%, respectively. North American natural gas production is expected to decrease by 15% from 2012 levels.

47 -------------------------------------------------------------------------------- Summary of Critical Accounting Policies EOG prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States of America, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. EOG identifies certain accounting policies as critical based on, among other things, their impact on the portrayal of EOG's financial condition, results of operations or liquidity, and the degree of difficulty, subjectivity and complexity in their application. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of each of the critical accounting policies. Following is a discussion of EOG's most critical accounting policies: Proved Oil and Gas Reserves EOG's engineers estimate proved oil and gas reserves in accordance with United States Securities and Exchange Commission regulations, which directly impact financial accounting estimates, including depreciation, depletion and amortization. Proved reserves represent estimated quantities of crude oil and condensate, NGLs and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved oil and gas reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. For related discussion, see ITEM 1A. Risk Factors and "Supplemental Information to Consolidated Financial Statements." Oil and Gas Exploration Costs EOG accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered proved commercial reserves. Exploratory drilling costs are capitalized when drilling is complete if it is determined that there is economic producibility supported by either actual production, a conclusive formation test or by certain technical data if the discovery is located offshore. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. As of December 31, 2012 and 2011, EOG had exploratory drilling costs related to projects that have been deferred for more than one year (see Note 15 to Consolidated Financial Statements). These costs meet the accounting requirements outlined above for continued capitalization. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized.

Depreciation, Depletion and Amortization for Oil and Gas Properties The quantities of estimated proved oil and gas reserves are a significant component of EOG's calculation of depreciation, depletion and amortization expense, and revisions in such estimates may alter the rate of future expense.

Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease, respectively.

Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves.

Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.

48 -------------------------------------------------------------------------------- Oil and gas properties are grouped in accordance with the provisions of the Extractive Industries - Oil and Gas Topic of the ASC. The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

Amortization rates are updated quarterly to reflect the addition of capital costs, reserve revisions (upwards or downwards) and additions, property acquisitions and/or property dispositions and impairments.

Depreciation and amortization of other property, plant and equipment is calculated on a straight-line basis over the estimated useful life of the asset.

Impairments Oil and gas lease acquisition costs are capitalized when incurred. 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. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.

When circumstances indicate that proved oil and gas properties 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, based on EOG's estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in the Fair Value Measurement Topic of the ASC. In certain instances, EOG utilizes accepted bids as the basis for determining fair value.

Estimates of future undiscounted cash flows require significant judgment.

Crude oil and natural gas prices have exhibited significant volatility in the past, and EOG expects that volatility to continue in the future. During the past five years, West Texas Intermediate crude oil spot prices have fluctuated from approximately $34.00 per barrel to $145.00 per barrel and Henry Hub natural gas spot prices have ranged from approximately $1.82 per MMBtu to $13.31 per MMBtu. EOG's proved reserves estimates, including the timing of future production, are also subject to significant judgment, and are frequently revised (upwards and downwards) as more information becomes available. In the future, if actual crude oil and/or natural gas prices and/or actual production diverge negatively from EOG's current estimates, impairment charges may be necessary.

Income Taxes Income taxes are accounted for using the asset and liability approach. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. EOG assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate. Significant assumptions used in estimating future taxable income include future oil and gas prices and changes in tax rates. Changes in such assumptions could materially affect the recognized amounts of valuation allowances.

Stock-Based Compensation In accounting for stock-based compensation, judgments and estimates are made regarding, among other things, the appropriate valuation methodology to follow in valuing stock compensation awards and the related inputs required by those valuation methodologies. Assumptions regarding expected volatility of EOG's Common Stock, the level of risk-free interest rates, expected dividend yields on EOG's Common Stock, the expected term of the awards, expected volatility of the price of shares of EOG's peer companies and other valuation inputs are subject to change. Any such changes could result in different valuations and thus impact the amount of stock-based compensation expense recognized on the Consolidated Statements of Income and Comprehensive Income.

49 -------------------------------------------------------------------------------- Information Regarding Forward-Looking Statements This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements.

In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others: · the timing and extent of changes in prices for, and demand for, crude oil and condensate, NGLs, natural gas and related commodities; · the extent to which EOG is successful in its efforts to acquire or discover additional reserves; · the extent to which EOG can optimize reserve recovery and economically develop its plays utilizing horizontal and vertical drilling, advanced completion technologies and hydraulic fracturing; · the extent to which EOG is successful in its efforts to economically develop its acreage in, and to produce reserves and achieve anticipated production levels from, its existing and future crude oil and natural gas exploration and development projects, given the risks and uncertainties and capital expenditure requirements inherent in drilling, completing and operating crude oil and natural gas wells and the potential for interruptions of development and production, whether involuntary or intentional as a result of market or other conditions; · the extent to which EOG is successful in its efforts to market its crude oil, natural gas and related commodity production; · the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities; · the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses and leases; · the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations, environmental laws and regulations relating to air emissions, waste disposal, hydraulic fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws and regulations with respect to derivatives and hedging activities; · EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties; · the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically; · competition in the oil and gas exploration and production industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services; · the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise; · weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation of production, gathering, processing, compression and transportation facilities; 50-------------------------------------------------------------------------------- · the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG; · EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements; · the extent and effect of any hedging activities engaged in by EOG; · the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions; · political conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates; · the use of competing energy sources and the development of alternative energy sources; · the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage; · acts of war and terrorism and responses to these acts; · physical, electronic and cyber security breaches; and · the other factors described under ITEM 1A, Risk Factors, on pages 16 through 23 of this Annual Report on Form 10-K and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

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