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

EOG - 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, 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.

EOG realized a net loss of $4,525 million during 2015 as compared to net income of $2,915 million for 2014. During 2015, impairments of proved oil and gas properties and other assets totaling $6,326 million, $4,141 million net of tax, were recognized primarily due to the decline in commodity prices. At December 31, 2015, EOG's total estimated net proved reserves were 2,118 million barrels of oil equivalent (MMBoe), a decrease of 379 MMBoe from December 31, 2014. During 2015, net proved crude oil and condensate and natural gas liquids (NGLs) reserves decreased by 126 million barrels (MMBbl), and net proved natural gas reserves decreased by 1,517 billion cubic feet or 253 MMBoe.

Operations

Several important developments have occurred since January 1, 2015.

United States. EOG's efforts to identify plays with large reserve potential have proven to be successful. EOG continues to drill numerous wells in large acreage plays, which in the aggregate have contributed substantially to, and are expected to continue 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 to unconventional crude oil and liquids-rich reservoirs. During 2015, EOG focused on increasing drilling and completion efficiencies, testing methods to improve the recovery factor of oil-in-place and reducing operating costs through efficiency improvements and service cost reductions. These efficiency gains along with realized lower service costs resulted in lower drilling and completion costs and decreased operating expenses. EOG continues to evaluate certain potential crude oil and liquids-rich natural gas exploration and development prospects. On a volumetric basis, as calculated using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGL production accounted for approximately 71% of United States production during 2015, consistent with 2014. During 2015, drilling occurred primarily in the Eagle Ford, Delaware Basin and North Dakota Bakken plays, where EOG has built an inventory of uncompleted wells. In addition, EOG continues to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins or tactical acquisitions and to evaluate certain potential crude oil and liquids-rich natural gas exploration and development prospects. In 2015, EOG completed four transactions to acquire certain proved crude oil properties and related assets in the Delaware Basin. The aggregate purchase price of the transactions totaled approximately $400 million. EOG's major producing areas in the United States are in New Mexico, North Dakota, Texas, Utah and Wyoming.

During 2015, due to the decline in commodity prices, proved oil and gas properties and related assets in the United States were written down to their fair value resulting in pretax impairment charges of $6,130 million, $3,945 million net of tax. Impairments were related to legacy natural gas assets and marginal liquids plays.

Trinidad. In Trinidad, EOG continued to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium (SECC) Block, Modified U(a) Block, Block 4(a) and Modified U(b) Block and the Sercan Area (formerly known as the EMZ area) have been developed and are producing natural gas which is sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary and crude oil and condensate which is sold to the Petroleum Company of Trinidad and Tobago Limited. EOG completed three net wells in 2015, finishing its SECC Block and Modified U(b) Block drilling program that was initiated in 2014. In 2016, EOG expects to complete one net well and install infrastructure in the Sercan Area.

Other International. As previously reported, during the fourth quarter of 2014, EOG completed the divestiture of substantially all its assets in Canada (see Note 17 to the Consolidated Financial Statements). At the time of the sales, production from the divested assets totaled approximately 7,050 barrels of crude oil per day, 580 barrels of NGLs per day and 43.5 million cubic feet of natural gas per day. Information related to EOG's remaining Canadian operations is presented in the "Other International" segment.

In the United Kingdom, EOG continues to make progress in the development of its 100% working interest East Irish Sea Conwy crude oil discovery. Modifications to the nearby third-party owned Douglas platform, which will be used to process Conwy production, began in 2013 and continued throughout 2014 and 2015. First production from the Conwy field is anticipated in March 2016. During 2015, EOG recognized a pretax impairment charge of $186 million for the Conwy project as a result of crude oil price declines.

In 2015, EOG drilled four wells and completed three wells, one of which was drilled in 2014, in the Sichuan Basin, Sichuan Province, China. The successful completions extended the Shaximiao development in the Chuan Zhong Block and provides additional opportunities in the future.

EOG's activity in Argentina is focused on the Vaca Muerta oil shale formation in the Neuquén Province. Management is currently evaluating options for its investment.

EOG continues to evaluate other select crude oil and natural gas opportunities outside the United States, primarily by pursuing exploitation opportunities in countries where indigenous crude oil and natural gas reserves have been identified.

Capital Structure

One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 34% at December 31, 2015 and 25% at December 31, 2014. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity. At December 31, 2015, $400 million aggregate principal amount of its 2.500% Senior Notes due 2016 (the 2016 Notes) and $260 million principal amount of commercial paper borrowings were reclassified as long-term debt based upon EOG's intent and ability to ultimately replace such amount with other long-term debt.

On January 14, 2016, EOG closed its sale of $750 million aggregate principal amount of its 4.15% Senior Notes due 2026 and $250 million aggregate principal amount of its 5.10% Senior Notes due 2036 (collectively, the New Notes). Interest on the New Notes is payable semi-annually in arrears on January 15 and July 15 of each year, beginning July 15, 2016. Proceeds from the issuance of the New Notes totaled approximately $991 million and were used to repay the $400 million aggregate principal amount of the 2016 Notes when such notes came due on February 1, 2016 and for general corporate purposes, including the repayment of outstanding commercial paper borrowings and funding of future capital expenditures.

On July 21, 2015, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (2015 Agreement) with domestic and foreign lenders (Banks). The 2015 Agreement replaced EOG's $2.0 billion senior unsecured revolving credit agreement which was canceled by EOG upon the closing of the 2015 Agreement. The 2015 Agreement has a scheduled maturity date of July 21, 2020, and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods, subject to certain terms and conditions. The 2015 Agreement commits the Banks to provide advances up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions.

On June 1, 2015, EOG repaid upon maturity the $500 million aggregate principal amount of its 2.95% Senior Notes due 2015.

On March 17, 2015, EOG closed its sale of $500 million aggregate principal amount of its 3.15% Senior Notes due 2025 and $500 million aggregate principal amount of its 3.90% Senior Notes due 2035 (together, the Notes). Interest on the Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2015. Net proceeds from the Notes offering of approximately $990 million were used for general corporate purposes.

During 2015, EOG funded $5.2 billion in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), repaid at maturity $500 million aggregate principal amount of long-term debt, paid $367 million in dividends to common stockholders and purchased $49 million of treasury stock in connection with stock compensation plans, primarily by utilizing net cash provided from its operating activities, net proceeds from the sale of the Notes, commercial paper borrowings, net proceeds of $193 million from the sale of assets and $26 million of excess tax benefits from stock compensation.

Total anticipated 2016 capital expenditures are estimated to range from approximately $2.4 billion to $2.6 billion, excluding acquisitions. The majority of 2016 expenditures will be focused on United States crude oil drilling activities. 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 the 2015 Agreement 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.

Results of Operations

The following review of operations for each of the three years in the period ended December 31, 2015, should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning on page F-1.

Net Operating Revenues

During 2015, net operating revenues decreased $9,278 million, or 51%, to $8,757 million from $18,035 million in 2014. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, decreased $6,188 million, or 49%, to $6,404 million in 2015 from $12,592 million in 2014. Revenues from the sales of crude oil and condensate and NGLs in 2015 were approximately 83% of total wellhead revenues compared to 85% in 2014. During 2015, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $62 million compared to net gains of $834 million in 2014. Gathering, processing and marketing revenues decreased $1,793 million during 2015, to $2,253 million from $4,046 million in 2014. Net losses on asset dispositions totaled $9 million in 2015 compared to net gains on asset dispositions of $508 million in 2014.

Wellhead volume and price statistics for the years ended December 31, 2015, 2014 and 2013 were as follows:

Year Ended December 31	2015		2014		2013

Crude Oil and Condensate Volumes (MBbld) ⁽¹⁾
United States	283.3		282.0		212.1
Trinidad	0.9		1.0		1.2
Other International ⁽²⁾	0.2		5.9		7.1
Total	284.4		288.9		220.4
Average Crude Oil and Condensate Prices ($/Bbl) ⁽³⁾
United States	$	47.55	$	92.73	$	103.81
Trinidad	39.51		84.63		90.30
Other International ⁽²⁾	57.32		86.75		87.08
Composite	47.53		92.58		103.20
Natural Gas Liquids Volumes (MBbld) ⁽¹⁾
United States	76.9		79.7		64.3
Other International ⁽²⁾	0.1		0.6		0.9
Total	77.0		80.3		65.2
Average Natural Gas Liquids Prices ($/Bbl) ⁽³⁾
United States	$	14.50	$	31.84	$	32.46
Other International ⁽²⁾	4.61		40.73		39.45
Composite	14.49		31.91		32.55
Natural Gas Volumes (MMcfd) ⁽¹⁾
United States	886		920		908
Trinidad	349		363		355
Other International ⁽²⁾	30		70		84
Total	1,265		1,353		1,347
Average Natural Gas Prices ($/Mcf) ⁽³⁾
United States	$	1.97	$	3.93	$	3.32
Trinidad	2.89		3.65		3.68
Other International ⁽²⁾	5.05		4.40		3.39
Composite	2.30		3.88		3.42
Crude Oil Equivalent Volumes (MBoed) ⁽⁴⁾
United States	507.9		515.0		427.9
Trinidad	59.1		61.5		60.4
Other International ⁽²⁾	5.2		18.2		21.8
Total	572.2		594.7		510.1

Total MMBoe ⁽⁴⁾	208.9		217.1		186.2

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

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

(3)Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 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 equivalent volumes are determined using a 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.

2015 compared to 2014. Wellhead crude oil and condensate revenues in 2015 decreased $4,807 million, or 49%, to $4,935 million from $9,742 million in 2014, due to a lower composite average wellhead crude oil and condensate price ($4,677 million) and a decrease of 5 MBbld, or 2%, in wellhead crude oil and condensate deliveries ($131 million). The decrease in deliveries primarily reflects decreased production in the North Dakota Bakken, the Fort Worth Barnett Shale area and Other International, partially offset by increased production in the Permian Basin and Eagle Ford. The decrease in Other International is due to the sale of the Canadian assets. EOG's composite wellhead crude oil and condensate price for 2015 decreased 49% to $47.53 per barrel compared to $92.58 per barrel in 2014.

NGL revenues in 2015 decreased $526 million, or 56%, to $408 million from $934 million in 2014, due to a lower composite average price ($490 million) and a decrease of 3 MBbld, or 4%, in NGL deliveries ($36 million). EOG's composite NGL price in 2015 decreased 55% to $14.49 per barrel compared to $31.91 per barrel in 2014.

Wellhead natural gas revenues in 2015 decreased $855 million, or 45%, to $1,061 million from $1,916 million in 2014, primarily due to a lower composite wellhead natural gas price ($730 million) and a decrease in wellhead natural gas deliveries ($125 million). EOG's composite average wellhead natural gas price decreased 41% to $2.30 per Mcf in 2015 compared to $3.88 per Mcf in 2014. Natural gas deliveries in 2015 decreased 7% to 1,265 MMcfd as compared to 1,353 MMcfd in 2014. The decrease in production was due to decreased production in Other International (40 MMcfd), the United States (34 MMcfd) and Trinidad (14 MMcfd). In the United States, decreased production was due primarily to lower production in the Upper Gulf Coast, Fort Worth Barnett Shale and South Texas areas, partially offset by increased production of associated gas in the Eagle Ford and Permian Basin. The decline in Other International primarily reflects the sale of the Canadian assets.

During 2015, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $62 million, which included net cash received from settlements of crude oil and natural gas financial derivative contracts of $730 million. During 2014, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $834 million, which included net cash received from settlements of crude oil and natural gas financial derivative contracts of $34 million.

Gathering, processing and marketing revenues are revenues generated from sales of third-party crude oil, NGLs, and natural gas as well as gathering fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. 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 as well as costs associated with EOG-owned sand sold to third parties.

Gathering, processing and marketing revenues less marketing costs in 2015 declined $53 million compared to 2014, primarily due to lower margins on crude oil and natural gas marketing activities and losses on sand sales.

2014 compared to 2013. Wellhead crude oil and condensate revenues in 2014 increased $1,441 million, or 17%, to $9,742 million from $8,301 million in 2013, due to an increase of 68.5 MBbld, or 31%, in wellhead crude oil and condensate deliveries ($2,558 million), partially offset by a lower composite average wellhead crude oil and condensate price ($1,117 million). The increase in deliveries primarily reflects increased production in the Eagle Ford, the North Dakota Bakken and the Permian Basin. EOG's composite wellhead crude oil and condensate price for 2014 decreased 10% to $92.58 per barrel compared to $103.20 per barrel in 2013.

NGL revenues in 2014 increased $160 million, or 21%, to $934 million from $774 million in 2013, due to an increase of 15 MBbld, or 23%, in NGL deliveries ($179 million), partially offset by a lower composite average price ($19 million). The increase in deliveries primarily reflects increased volumes in the Eagle Ford and the Permian Basin. EOG's composite NGL price in 2014 decreased 2% to $31.91 per barrel compared to $32.55 per barrel in 2013.

Wellhead natural gas revenues in 2014 increased $235 million, or 14%, to $1,916 million from $1,681 million in 2013, primarily due to a higher composite wellhead natural gas price. EOG's composite average wellhead natural gas price increased 13% to $3.88 per Mcf in 2014 compared to $3.42 per Mcf in 2013. Natural gas deliveries in 2014 increased less than 1% to 1,353 MMcfd as compared to 1,347 MMcfd in 2013. Increased production in the United States (12 MMcfd) and Trinidad (8 MMcfd) was offset by lower production in Canada (15 MMcfd). In the United States, increased production of associated natural gas in the Eagle Ford and Permian Basin areas was partially offset by lower production in the Upper Gulf Coast and Fort Worth Basin Barnett Shale areas.

During 2014, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $834 million, which included net cash received from settlements of crude oil and natural gas financial derivative contracts of $34 million. During 2013, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $166 million, which included net cash received from settlements of crude oil and natural gas financial derivative contracts of $116 million.

Gathering, processing and marketing revenues less marketing costs in 2014 declined $75 million compared to 2013, primarily due to lower margins on crude oil marketing activities.

Operating and Other Expenses

2015 compared to 2014. During 2015, operating expenses of $15,444 million were $2,650 million higher than the $12,794 million incurred during 2014. Operating expenses for 2015 included impairments of proved properties, other property, plant and equipment and other assets of $6,326 million primarily due to commodity price declines. The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2015 and 2014:

	2015		2014

Lease and Well	$	5.66	$	6.53
Transportation Costs	4.07		4.48
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties	15.27		17.90
Other Property, Plant and Equipment	0.59		0.53
General and Administrative (G&A)	1.75		1.85
Net Interest Expense	1.14		0.93
Total ⁽¹⁾	$	28.48	$	32.22

(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, G&A and net interest expense for 2015 compared to 2014 are set forth below. See "Net Operating Revenues" above for a discussion of production volumes.

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.

Lease and well expenses of $1,182 million in 2015 decreased $234 million from $1,416 million in 2014 primarily due to lower operating and maintenance costs in the United States ($125 million), lower lease and well expenses in Other International ($99 million) primarily due to the sale of the Canadian assets and lower workover expenditures in the United States ($21 million), partially offset by increased lease and well administrative expenses in the United States ($12 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 $849 million in 2015 decreased $123 million from $972 million in 2014 primarily due to decreased transportation costs in the Rocky Mountain area ($81 million) and the Eagle Ford ($48 million) primarily due to an increase in the use of pipelines to transport crude oil production, partially offset by increased transportation costs related to higher production from the Permian Basin ($19 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 DD&A group 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 and 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 period to period. 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.

DD&A expenses in 2015 decreased $683 million to $3,314 million from $3,997 million in 2014. DD&A expenses associated with oil and gas properties in 2015 were $691 million lower than in 2014 primarily due to lower unit rates in the United States ($513 million) and Trinidad ($28 million), a decrease in production in the United States ($44 million) and lower DD&A expense in Other International ($104 million) primarily due to the sale of the Canadian assets. Unit rates in the United States decreased primarily due to impairments of proved oil and gas properties (see Note 14 to the Consolidated Financial Statements), upward reserve revisions and reserves added at lower costs as a result of increased efficiencies.

G&A expenses of $367 million in 2015 were $35 million lower than 2014 primarily due to lower employee-related expenses.

Net interest expense of $237 million in 2015 was $36 million higher than 2014 primarily due to interest incurred on the Notes issued in March 2015 ($28 million), as well as a decrease in capitalized interest ($15 million). This was partially offset by the reduction of interest on debt repaid in June 2015 and during 2014 ($11 million).

Exploration costs of $149 million in 2015 decreased $35 million from $184 million in 2014 primarily due to decreased geological and geophysical expenditures in the United States ($19 million) and lower exploration administrative expenses in Other International ($10 million) primarily due to the sale of the Canadian assets.

Impairments include amortization of unproved oil and gas property costs; as well as impairments of proved oil and gas properties; other property, plant and equipment; and other assets. 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 DD&A group level to the unamortized capitalized cost of the asset. If the expected undiscounted future 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 described in the Fair Value Measurement Topic of the Financial Accounting Standards Board's Accounting Standards Codification (ASC). In certain instances, EOG utilizes accepted bids as the basis for determining fair value.

Impairments of $6,614 million in 2015 increased $5,870 million from $744 million in 2014 primarily due to increased impairments of proved properties and other assets in the United States ($5,959 million), primarily due to commodity price declines; and increased amortization of unproved property costs in the United States ($112 million), which was caused by higher amortization rates being applied to undeveloped leasehold costs in response to the significant decrease in commodity prices and an increase in EOG's estimates of undeveloped properties not expected to be developed before lease expiration; partially offset by decreased impairments of proved properties in the United Kingdom ($156 million) and Argentina ($43 million). Proved property and other asset impairments in the United States were primarily related to legacy natural gas assets and marginal liquids plays. EOG recorded impairments of proved properties; other property, plant and equipment; and other assets of $6,326 million and $575 million in 2015 and 2014, respectively.

Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are 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 2015 decreased $336 million to $422 million (6.6% of wellhead revenues) from $758 million (6.0% of wellhead revenues) in 2014. The decrease in taxes other than income was primarily due to decreases in severance/production taxes ($307 million), primarily as a result of decreased wellhead revenues and lower ad valorem/property taxes ($17 million), both in the United States.

Other income, net, was $2 million in 2015 compared to other expense, net, of $45 million in 2014. The increase of $47 million was primarily due to a decrease in net foreign currency transaction losses and decreased deferred compensation expense.

EOG recognized an income tax benefit of $2,397 million in 2015 compared to an income tax expense of $2,080 million in 2014 primarily due to impairments recognized in the United States in 2015. The net effective tax rate for 2015 decreased to 35% from 42% in the prior year primarily due to the effects of recording valuation allowances in the United Kingdom and deferred tax in the United States related to undistributed foreign earnings in 2014.

2014 compared to 2013. During 2014, operating expenses of $12,794 million were $1,982 million higher than the $10,812 million incurred during 2013. The following table presents the costs per Boe for the years ended December 31, 2014 and 2013:

	2014		2013

Lease and Well	$	6.53	$	5.94
Transportation Costs	4.48		4.58
DD&A -
Oil and Gas Properties	17.90		18.79
Other Property, Plant and Equipment	0.53		0.55
G&A	1.85		1.87
Net Interest Expense	0.93		1.26
Total ⁽¹⁾	$	32.22	$	32.99

(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, G&A and net interest expense for 2014 compared to 2013 are set forth below. See "Net Operating Revenues" above for a discussion of production volumes.

Lease and well expenses of $1,416 million in 2014 increased $310 million from $1,106 million in 2013 primarily due to higher operating and maintenance costs ($209 million), increased workover expenditures ($69 million) and increased lease and well administrative expenses ($32 million), all in the United States.

Transportation costs of $972 million in 2014 increased $119 million from $853 million in 2013 primarily due to increased transportation costs related to production from the Eagle Ford ($99 million) and the Rocky Mountain area ($15 million).

DD&A expenses in 2014 increased $396 million to $3,997 million from $3,601 million in 2013. DD&A expenses associated with oil and gas properties in 2014 were $384 million higher than in 2013 primarily due to increased production in the United States ($630 million), partially offset by lower unit rates in the United States ($191 million) and Canada ($37 million) and a decrease in production in Canada ($31 million). Unit rates in the United States decreased primarily due to upward reserve revisions and reserves added at lower costs as a result of increased efficiencies.

G&A expenses of $402 million in 2014 were $54 million higher than 2013 primarily due to higher costs associated with supporting expanding operations.

Net interest expense of $201 million in 2014 was $34 million lower than 2013 primarily due to repayment of the $400 million aggregate principal amount of the 6.125% Senior Notes due 2013, the Subsidiary Debt and the Floating Rate Notes ($31 million), as well as an increase in capitalized interest across the company ($8 million). This was partially offset by interest expense on the Notes issued in March 2014 ($10 million).

Gathering and processing costs increased $38 million to $146 million in 2014 compared to $108 million in 2013 primarily due to increased activities in the Eagle Ford.

Exploration costs of $184 million in 2014 increased $23 million from $161 million in 2013 primarily due to increased geological and geophysical expenditures in the United States.

Impairments of $744 million in 2014 increased $457 million from $287 million in 2013 primarily due to increased impairments of proved properties in the United Kingdom ($351 million), the United States ($145 million) and Argentina ($39 million); and increased amortization of unproved property costs in the United States ($54 million); partially offset by decreased impairments of proved properties in Canada ($67 million) and Trinidad ($14 million); and lower impairments of other assets in the United States ($46 million). EOG recorded impairments of proved properties; other property, plant and equipment; and other assets of $575 million and $172 million in 2014 and 2013, respectively. The 2014 and 2013 amounts include impairments of $503 million and $7 million, respectively, related to certain assets as a result of declining commodity prices and using accepted bids for determining fair value.

Taxes other than income in 2014 increased $134 million to $758 million (6.0% of wellhead revenues) from $624 million (5.8% of wellhead revenues) in 2013. The increase in taxes other than income was primarily due to increases in severance/production taxes ($112 million) primarily as a result of increased wellhead revenues and higher ad valorem/property taxes ($34 million) in the United States, partially offset by an increase in credits available to EOG in 2014 for Texas high-cost gas severance tax rate reductions ($11 million).

Other expense, net, was $45 million in 2014 compared to $3 million in 2013. The increase of $42 million was primarily due to net foreign currency transaction losses.

Income tax provision of $2,080 million in 2014 increased $840 million from $1,240 million in 2013 due primarily to higher pretax income. The net effective tax rate for 2014 increased to 42% from 36% in the prior year. The net effective tax rate for 2014 exceeded the United States statutory tax rate (35%) due primarily to valuation allowances in the United Kingdom and deferred tax in the United States related to EOG's undistributed foreign earnings. EOG no longer asserts that foreign earnings will remain permanently reinvested abroad and therefore recorded deferred tax of $250 million on the accumulated balance of such earnings in the fourth quarter of 2014.

Capital Resources and Liquidity

Cash Flow

The primary sources of cash for EOG during the three-year period ended December 31, 2015, were funds generated from operations, net proceeds from issuances of long-term debt, proceeds from asset sales, excess tax benefits from stock-based compensation and net commercial paper borrowings and borrowings under other uncommitted credit facilities. The primary uses of cash were funds used in operations; exploration and development expenditures; other property, plant and equipment expenditures; repayments of debt; dividend payments to stockholders; and purchases of treasury stock in connection with stock compensation plans.

2015 compared to 2014. Net cash provided by operating activities of $3,595 million in 2015 decreased $5,054 million from $8,649 million in 2014 primarily reflecting a decrease in wellhead revenues ($6,188 million), unfavorable changes in working capital and other assets and liabilities ($591 million) and an increase in net cash paid for interest expense ($25 million), partially offset by a decrease in cash operating expenses ($741 million), a favorable change in the net cash received from the settlement of financial commodity derivative contracts ($696 million) and a decrease in net cash paid for income taxes ($302 million).

Net cash used in investing activities of $5,320 million in 2015 decreased by $2,194 million from $7,514 million in 2014 primarily due to a decrease in additions to oil and gas properties ($2,795 million); and a decrease in additions to other property, plant and equipment ($439 million); partially offset by unfavorable changes in working capital associated with investing activities ($603 million); a decrease in proceeds from sales of assets ($377 million) and the release of restricted cash in 2014 ($60 million).

Net cash provided by financing activities of $371 million in 2015 included net proceeds from the issuance of the Notes ($990 million), net commercial paper borrowings ($260 million), excess tax benefits from stock-based compensation ($26 million) and proceeds from stock options exercised and employee stock purchase plan activity ($23 million). Cash used in financing activities in 2015 included repayments of long-term debt ($500 million), cash dividend payments ($367 million) and purchases of treasury stock in connection with stock compensation plans ($49 million).

2014 compared to 2013. Net cash provided by operating activities of $8,649 million in 2014 increased $1,320 million from $7,329 million in 2013 primarily reflecting an increase in wellhead revenues ($1,837 million), favorable changes in working capital and other assets and liabilities ($391 million) and a decrease in net cash paid for interest expense ($38 million), partially offset by an increase in cash operating expenses ($662 million), an unfavorable change in the net cash received from the settlement of financial commodity derivative contracts ($82 million) and an increase in net cash paid for income taxes ($48 million).

Net cash used in investing activities of $7,514 million in 2014 increased by $1,199 million from $6,315 million in 2013 primarily due to an increase in additions to oil and gas properties ($823 million); an increase in additions to other property, plant and equipment ($364 million); and a decrease in proceeds from sales of assets ($191 million); partially offset by the release of restricted cash ($126 million) and favorable changes in working capital associated with investing activities ($52 million).

Net cash used in financing activities of $328 million during 2014 included repayments of long-term debt ($500 million), cash dividend payments ($280 million), purchases of treasury stock in connection with stock compensation plans ($127 million) and the settlement of a foreign currency swap ($32 million). Cash provided by financing activities in 2014 included net proceeds from the issuances of long-term debt ($496 million), excess tax benefits from stock-based compensation ($99 million) and proceeds from stock options exercised and employee stock purchase plan activity ($22 million).

Total Expenditures

The table below sets out components of total expenditures for the years ended December 31, 2015, 2014 and 2013 (in millions):

	2015		2014		2013
Expenditure Category
Capital
Exploration and Development Drilling	$	3,289	$	5,543	$	5,070
Facilities	765		1,367		974
Leasehold Acquisitions ⁽¹⁾	134		370		414
Property Acquisitions	481		139		120
Capitalized Interest	42		57		49
Subtotal	4,711		7,476		6,627
Exploration Costs	149		184		161
Dry Hole Costs	15		49		75
Exploration and Development Expenditures	4,875		7,709		6,863
Asset Retirement Costs	53		196		134
Total Exploration and Development Expenditures	4,928		7,905		6,997
Other Property, Plant and Equipment	288		727		364
Total Expenditures	$	5,216	$	8,632	$	7,361

(1)Leasehold acquisitions included $5 million in both 2014 and 2013 related to non-cash property exchanges.

Exploration and development expenditures of $4,875 million for 2015 were $2,834 million lower than the prior year primarily due to decreased exploration and development drilling expenditures in the United States ($2,189 million) and Other International ($74 million); decreased facilities expenditures ($553 million), decreased leasehold acquisitions ($232 million), decreased exploration geological and geophysical expenditures ($19 million), and decreased capitalized interest ($11 million), all in the United States. These decreases were partially offset by increased property acquisitions ($342 million) in the United States. The 2015 exploration and development expenditures of $4,875 million included $4,007 million in development drilling and facilities, $481 million in property acquisitions, $345 million in exploration and $42 million in capitalized interest. The 2014 exploration and development expenditures of $7,709 million included $6,804 million in development drilling and facilities, $709 million in exploration, $139 million in property acquisitions and $57 million in capitalized interest. The 2013 exploration and development expenditures of $6,863 million included $5,952 million in development drilling and facilities, $742 million in exploration, $120 million in property acquisitions and $49 million in capitalized interest.

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

Commodity Derivative Contracts. Presented below is a comprehensive summary of EOG's natural gas derivative contracts at February 25, 2016, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

Financing

EOG's debt-to-total capitalization ratio was 34% at December 31, 2015, compared to 25% at December 31, 2014. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

At December 31, 2015 and 2014, respectively, EOG had outstanding $6,390 million and $5,890 million aggregate principal amount of senior notes which had estimated fair values of $6,524 million and $6,242 million, respectively. The estimated fair value 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 at fixed interest rates. While changes in interest rates affect the fair value of EOG's senior notes, such changes do not expose EOG to material fluctuations in earnings or cash flow.

During 2015, EOG funded its capital program primarily by utilizing cash provided by operating activities, proceeds from the issuance of the Notes, cash provided by borrowings from its commercial paper program and proceeds from asset sales. While EOG maintains a $2.0 billion commercial paper program, the maximum outstanding at any time during 2015 was $641 million, and the amount outstanding at year-end was $260 million. There were no amounts outstanding under uncommitted credit facilities during 2015. The average borrowings outstanding under the commercial paper program and the uncommitted credit facilities were $81 million and zero, respectively, during the year 2015. EOG considers this excess availability, which is backed by its 2015 Agreement described in Note 2 to Consolidated Financial Statements, to be sufficient to meet its ongoing operating needs.

Contractual Obligations

The following table summarizes EOG's contractual obligations at December 31, 2015, (in thousands):

Contractual Obligations ⁽¹⁾	Total		2016		2017 - 2018		2019 - 2020		2021 & Beyond

Current and Long-Term Debt	$	6,390,000	$	400,000	$	950,000	$	1,900,000	$	3,140,000
Capital Lease	45,064		6,579		13,318		14,172		10,995
Non-Cancelable Operating Leases	421,189		104,459		113,953		74,842		127,935
Interest Payments on Long-Term Debt and Capital Lease	1,545,348		258,575		471,314		294,335		521,124
Transportation and Storage Service Commitments ⁽²⁾	4,070,003		936,118		1,482,446		882,849		768,590
Drilling Rig Commitments ⁽³⁾	144,540		85,933		57,107		—		1,500
Seismic Purchase Obligations	2,216		2,216		—		—		—
Fracturing Services Obligations	201,501		105,957		88,287		5,412		1,845
Other Purchase Obligations	91,309		40,967		33,834		15,417		1,091
Total Contractual Obligations	$	12,911,170	$	1,940,804	$	3,210,259	$	3,187,027	$	4,573,080

(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 6, 7 and 15, 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, 2015. 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 2015, EOG was exposed to foreign currency exchange rate risk inherent in its operations in foreign countries, including Trinidad, the United Kingdom, China, Canada and Argentina. The foreign currency most significant to EOG's operations during 2015 was the British pound. 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.

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, worldwide supplies of, and demand for, crude oil and condensate, NGL and natural gas, 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 2016 will impact the amount of cash generated from operating activities, which will in turn impact EOG's financial position. As of February 12, 2016, the average 2016 U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $34.97 per barrel and $2.23 per MMBtu, respectively, representing declines of 28% and 17%, respectively, from the average NYMEX prices in 2015. See ITEM 1A, Risk Factors.

Based on EOG's tax position, EOG's price sensitivity in 2016 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGL price, is approximately $65 million for net income and $81 million for cash flows from operating activities. Including the impact of EOG's 2016 natural gas derivative contracts (exclusive of options) and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2016 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 $15 million for net income and $18 million for cash flows from operating activities. For information regarding EOG's crude oil and natural gas financial commodity derivative contracts at February 25, 2016, 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, Delaware Basin and Bakken plays where it generates its highest rates-of-return. To further enhance the economics of these plays, EOG expects to continue to improve well performance and lower drilling and completion costs through efficiency gains and lower service costs.

The total anticipated 2016 capital expenditures of approximately $2.4 billion to $2.6 billion, excluding acquisitions, is structured to maintain EOG's strategy of capital discipline by funding its exploration, development and exploitation activities primarily from available internally generated cash flows, net proceeds from the New Notes and cash on hand. 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 2015 Agreement and equity and debt offerings.

Operations. In 2016, both total production and total crude oil production are expected to decline slightly from 2015 levels. In 2016, EOG expects to continue to focus on reducing operating costs through efficiency improvements and lower service costs.

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, 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 and impairments of proved properties and related assets. 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. 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. 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.

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.

Depreciation, depletion and 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 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 depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. If the expected undiscounted future 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 undiscounted future 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 five years ended December 31, 2015, West Texas Intermediate crude oil spot prices have fluctuated from approximately $34.55 per barrel to $113.39 per barrel, and Henry Hub natural gas spot prices have ranged from approximately $1.63 per MMBtu to $8.15 per MMBtu. EOG's proved reserves estimates, including the timing of future production, are also subject to significant assumptions and 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.

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, reduce or otherwise control operating and capital costs, 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, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, 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 is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;

• the extent to which EOG is successful in its efforts to market its crude oil and condensate, natural gas liquids, natural gas and related commodity production;

• the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, transportation and refining 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, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;

• 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 the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services;

• the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) 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 (by EOG or third parties) of production, gathering, processing, refining, compression and transportation facilities;

• 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 13 through 21 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 duration and 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.

Natural Gas Derivative Contracts

Average Price

March 1, 2016 through August 31, 2016