EOG RESOURCES, INC. (EOG) Business, 2013

General

EOG Resources, Inc., a Delaware corporation organized in 1985, together with its subsidiaries (collectively, EOG), explores for, develops, produces and markets crude oil and natural gas primarily in major producing basins in the United States of America (United States or U.S.), Canada, The Republic of Trinidad and Tobago (Trinidad), the United Kingdom (U.K.), The People's Republic of China (China), the Argentine Republic (Argentina) and, from time to time, select other international areas. EOG's principal producing areas are further described in "Exploration and Production" below. EOG's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports are made available, free of charge, through EOG's website, as soon as reasonably practicable after such reports have been filed with the United States Securities and Exchange Commission (SEC). EOG's website address is www.eogresources.com.

At December 31, 2013, EOG's total estimated net proved reserves were 2,119 million barrels of oil equivalent (MMBoe), of which 901 million barrels (MMBbl) were crude oil and condensate reserves, 377 MMBbl were natural gas liquids (NGLs) reserves and 5,045 billion cubic feet, or 841 MMBoe, were natural gas reserves (see Supplemental Information to Consolidated Financial Statements). At such date, approximately 94% of EOG's net proved reserves, on a crude oil equivalent basis, were located in the United States, 4% in Trinidad, 1% in Canada and 1% in Other International. Crude oil equivalent volumes are determined using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet (Mcf) of natural gas.

As of December 31, 2013, EOG employed approximately 2,800 persons, including foreign national employees.

EOG's business strategy is to maximize 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. EOG is focused on cost-effective utilization of advanced technology associated with three-dimensional seismic and microseismic data, the development of reservoir simulation models, the use of improved drill bits, mud motors and mud additives for horizontal drilling, formation evaluation, and horizontal completion methods. These advanced technologies are used, as appropriate, throughout EOG to reduce the risks associated with all aspects of oil and gas exploration, development and exploitation. 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.

With respect to information on EOG's working interest in wells or acreage, "net" oil and gas wells or acreage are determined by multiplying "gross" oil and gas wells or acreage by EOG's working interest in the wells or acreage.

Business Segments

EOG's operations are all crude oil and natural gas exploration and production related. For financial information about our reportable segments (including financial information by segment geographic area), see Note 10 to Consolidated Financial Statements. For information regarding the risks associated with EOG's foreign operations, see ITEM 1A. Risk Factors.

Exploration and Production

United States and Canada Operations

EOG's operations are focused in most of the productive basins in the United States and Canada, with a current focus on crude oil and, to a lesser extent, liquids-rich natural gas plays.

At December 31, 2013, on a crude oil equivalent basis, 44% of EOG's net proved reserves in the United States and Canada were crude oil and condensate, 19% were NGLs and 37% were natural gas. The majority of these reserves are in long-lived fields with well-established production characteristics. EOG believes that opportunities exist to increase production through continued development in and around many of these fields and through the utilization of applicable technologies. EOG also maintains an active exploration program designed to extend fields and add new trends and resource plays to its already broad portfolio. The following is a summary of significant developments during 2013 and certain 2014 plans for EOG's United States and Canada operations.

United States. The Eagle Ford continues to prove itself as among the best resource plays in the world. With approximately 564,000 of the 632,000 total net acres that EOG controls within the prolific oil window, EOG completed 466 net wells in 2013 yielding a direct after-tax rate of return(1) in excess of 100%. In 2013, EOG continued to decrease well costs and believes it has the lowest completed well costs in the play, while continuing to have the most productive wells. The combination of self-sourced sand, dedicated frac crews and other services along with continual well optimization programs have made this play the centerpiece of EOG's portfolio.

EOG is the biggest oil producer in the Eagle Ford play with year-end, net volumes of approximately 142 thousand barrels per day (MBbld) of crude oil and condensate, an increase of 79% over year-end 2012. In addition to being an anchor shipper on the Enterprise Products Partners L.P. Eagle Ford crude oil pipeline, EOG began shipping its crude oil on the Kinder Morgan crude oil and condensate pipeline into the Houston market in December 2013. EOG's capacity on the Kinder Morgan crude oil and condensate pipeline provides further diversification and the security of firm transportation capacity for its Eagle Ford production. EOG's large contiguous acreage position allows for low transportation and operating costs which adds to the overall return for the play. In 2014, EOG plans to drill approximately 520 net wells and build infrastructure to accommodate production from its western Eagle Ford acreage.

The Rocky Mountain area continues to provide strong liquids growth. In 2013, EOG began infill drilling on its crude oil acreage in the Williston Basin Bakken core, drilling 39 net wells. EOG continued its development program in the Powder River Basin, drilling 20 net wells in the Turner Sand formation. Net average production for the entire Rocky Mountain area for 2013 was approximately 61 MBbld of crude oil and condensate and NGLs, an increase of 17% over the prior year. Natural gas production decreased 6% compared to 2012 with activity focused on liquids growth. EOG plans to increase activity in the Rocky Mountain area in 2014.

In 2013, EOG drilled and participated in 61 net wells in the Permian Basin to develop its liquids-rich Leonard and Wolfcamp plays. EOG is well positioned with approximately 73,000 net acres in the Leonard Shale, and 134,000 net acres in the Wolfcamp Shale, all within the Delaware Basin. Additionally, EOG has approximately 113,000 net acres in the Wolfcamp Shale within the Midland Basin. Net production in the Permian Basin for 2013 averaged 23 MBbld of crude oil and condensate and NGLs, an increase of 40% over 2012. Natural gas production increased 24% to 54 million cubic feet per day (MMcfd). After divestitures in 2013, EOG holds approximately 413,000 net acres throughout the Permian Basin. In 2014, EOG plans to continue the expansion and development of the Leonard and Wolfcamp plays by drilling approximately 65 net wells.

In the Upper Gulf Coast region, EOG drilled 21 net wells, and net production averaged 124 MMcfd of natural gas and 1.9 MBbld of crude oil and condensate and NGLs in 2013. The Haynesville and Bossier Shale plays located near the Texas-Louisiana border continue to be core natural gas assets. EOG controls approximately 143,000 net acres, all within the highly productive areas of these plays. Due to low natural gas prices, EOG plans to defer dry gas drilling until natural gas economics improve sufficiently to support the activity. However, in 2013, EOG successfully tested and confirmed high NGLs and condensate production in the Panola County region of EOG's Haynesville leasehold. Total net liquids volumes increased to 4 MBbld at year-end 2013. EOG holds approximately 593,000 net acres in the Upper Gulf Coast region and plans to increase activity during 2014.

In the Mid-Continent area, EOG continued to expand its activities in the Western Anadarko Basin. During 2013, EOG averaged net production of 8.0 MBbld of crude oil and condensate and NGLs and 33 MMcfd of natural gas. Crude oil volumes increased 6% in 2013 compared to 2012. In 2013, EOG continued its successful horizontal exploitation of the Pennsylvanian sandstones in the Anadarko Basin, drilling 36 net wells. EOG holds approximately 200,000 net acres throughout the trend, and plans to drill approximately 25 net crude oil wells in 2014.

During 2013, EOG continued development of its liquids-rich Barnett Shale Combo play in the Fort Worth Basin. EOG drilled 142 net Barnett Combo wells and continued to upgrade the quality of its acreage position and add potential drilling locations in the Barnett Combo core area. In 2013, net daily total production in the Barnett Shale averaged approximately 36 MBbld of crude oil and condensate and NGLs and approximately 305 MMcfd of natural gas. For 2014, EOG will continue to be active in this play with plans to drill approximately 105 net Barnett Shale Combo wells.

In the South Texas area, EOG drilled 30 net wells in 2013. Net production during 2013 averaged 6 MBbld of crude oil and condensate and NGLs and 86 MMcfd of natural gas. EOG's activity was focused in San Patricio, Nueces, Brooks, Kenedy and Kleberg Counties. In 2014, EOG will continue to exploit the liquids-rich Frio and Vicksburg sands on its approximately 320,000 net acre position in these counties and plans to drill approximately 24 net wells.

During 2013, EOG significantly slowed development of the Marcellus Shale, drilling a total of four net wells and completing one net well to hold its acreage position. Net production for 2013 averaged 36 MMcfd of natural gas. For 2014, Marcellus Shale development plans are minimal, focusing on infrastructure projects that will support additional Marcellus Shale development in the coming years. EOG currently holds approximately 195,000 net acres with Marcellus Shale potential, most of which is held as fee or by production.

At December 31, 2013, EOG held approximately 2.7 million net undeveloped acres in the United States.

During 2013, EOG continued the expansion of its gathering and processing activities in the Eagle Ford in South Texas, the Bakken and Three Forks plays in North Dakota, the Permian Basin in West Texas and New Mexico and the Barnett Shale in North Texas. At December 31, 2013, EOG-owned natural gas processing capacity in the Eagle Ford and Barnett Shale was 225 MMcfd and 180 MMcfd, respectively.

In support of its operations in the Williston Basin, EOG continued to increase the utilization of its crude oil loading facility near Stanley, North Dakota, to transport its crude oil production and, from time to time, crude oil purchased from third-party producers. EOG loaded 406 unit trains (each unit train typically consists of 100 cars and has a total aggregate capacity of approximately 70,000 barrels of crude oil) with crude oil for transport to St. James, Louisiana, Stroud, Oklahoma, and certain other destinations in the U.S.

Additionally, in support of EOG operations in the Eagle Ford, the Permian Basin and the Barnett Shale, EOG continued to use its crude oil loading facilities in Harwood and Barnhart, Texas, and established a new crude oil loading facility near Fort Worth, Texas. At these facilities, crude oil is loaded onto unit trains of approximately 70 cars each, with aggregate capacity of approximately 45,000 barrels per train, and shipped to St. James, Louisiana, or to other destinations on the U.S. Gulf Coast. During 2013, a total of 89 unit train shipments were made from these three facilities.

A total of 372 crude oil unit trains carrying EOG production were received at a crude oil unloading facility in St. James, Louisiana, during 2013. Owned by EOG and NuStar Energy L.P., this facility provides access to one of the key markets in the U.S., where sales are based upon the Light Louisiana Sweet (LLS) crude oil index. The St. James facility accommodates multiple trains at a single time and has a capacity of approximately 120 MBbld. EOG's share of that capacity is 100 MBbld.

During 2013, EOG utilized its Stroud, Oklahoma, crude oil unloading facility and pipeline to transport 50 unit trainloads of crude oil to the Cushing, Oklahoma, trading hub. These facilities have the capacity to unload approximately 90 MBbld of crude oil. EOG also delivered crude by rail to certain other third-party operated facilities in the U.S.

EOG believes that its crude-by-rail facilities and logistics processes provide a competitive advantage, giving EOG the flexibility to direct its crude oil shipments via rail car to the most favorable markets.

Since 2008, EOG has been operating its own sand mine and sand processing plant located in Hood County, Texas, to reduce costs and to help fulfill EOG's sand needs for its well completion operations in the Barnett Shale Combo play. EOG purchased a second Hood County sand processing plant in 2011, and utilizes that facility to process raw EOG-owned sand from Wisconsin, as needed, to support EOG's well completion activities in several key EOG plays.

In 2013, EOG increased the use of processed sand from its Chippewa Falls, Wisconsin, sand plant, which processes sand from multiple EOG-owned mines nearby.

During 2013, EOG shipped 141 sand unit trains of approximately 100 cars each, from various sources, to EOG's sand storage and distribution facility in Refugio, Texas, primarily for use in its Eagle Ford well completions. Also during 2013, EOG shipped the equivalent of 89 unit trains of processed sand for well completions in other plays.

EOG also continued utilization of its resin coating plant, located at the Refugio sand storage facility. After coating for added strength and sand control, the sand is shipped primarily to the Eagle Ford. EOG also ships its coated sand to other plays, including the North Dakota Bakken and the Permian Basin.

Canada. EOG conducts operations in Canada through its wholly-owned subsidiary, EOG Resources Canada Inc. (EOGRC), from its offices in Calgary, Alberta. During 2013, EOGRC continued its focus on horizontal crude oil exploitation, mainly through its development of the shallow Spearfish formation in southwest Manitoba. Of the 93 net wells EOGRC drilled or participated in during 2013, 91 were horizontal and 2 were vertical. In 2014, EOGRC will continue to develop its Manitoba acreage as well as drill test wells on existing acreage in Alberta to identify new targets. In 2013, net crude oil and condensate and NGLs production was 7.9 MBbld and net natural gas production was 76 MMcfd.

At December 31, 2013, EOGRC held approximately 483,000 net undeveloped acres in Canada.

In December 2012, EOGRC signed a purchase and sale agreement for the sale of its entire interest in the planned Kitimat LNG Terminal and the proposed Pacific Trail Pipelines, as well as approximately 28,500 undeveloped net acres in the Horn River Basin, to Chevron Canada Limited. The transaction closed in February 2013.

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(1) Direct After-Tax Rate of Return. The calculation of our direct after-tax rate of return with respect to our capital expenditures for our net wells drilled in the Eagle Ford in 2013 is based on the estimated proved reserves ("net" to our interest) associated with such wells, the estimated present value of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling such wells. As such, our after-tax rate of return with respect to our capital expenditures for our net wells drilled in the Eagle Ford in 2013 cannot be calculated from our audited financial statements for fiscal year 2013.

Operations Outside the United States and Canada

EOG has operations offshore Trinidad, in the U.K. North Sea and East Irish Sea, in the China Sichuan Basin and in the Neuquén Basin of Argentina, and is evaluating additional exploration, development and exploitation opportunities in these and other select international areas.

Trinidad. EOG, through several of its subsidiaries, including EOG Resources Trinidad Limited,

· holds an 80% working interest in the exploration and production license covering the South East Coast Consortium (SECC) Block offshore Trinidad, except in the Deep Ibis area in which EOG's working interest decreased as a result of a third-party farm-out agreement;

· holds an 80% working interest in the exploration and production license covering the Pelican Field and its related facilities;

· holds a 50% working interest in the exploration and production license covering the EMZ Area offshore Trinidad;

· holds a 100% working interest in a production sharing contract with the Government of Trinidad and Tobago for each of the Modified U(a) Block, Modified U(b) Block and Block 4(a);

· owns a 12% equity interest in an anhydrous ammonia plant in Point Lisas, Trinidad, that is owned and operated by Caribbean Nitrogen Company Limited; and

· owns a 10% equity interest in an anhydrous ammonia plant in Point Lisas, Trinidad, that is owned and operated by Nitrogen (2000) Unlimited.

Several fields in the SECC Block, Modified U(a) Block, Modified U(b) Block, Block 4(a) and the EMZ Area have been developed and are producing natural gas and crude oil and condensate. Natural gas from EOG's Trinidad operations currently is sold under various contracts with the National Gas Company of Trinidad and Tobago (NGC). Crude oil and condensate from EOG's Trinidad operations currently is sold to the Petroleum Company of Trinidad and Tobago Limited. In 2013, EOG's average net production from Trinidad was 355 MMcfd of natural gas and 1.2 MBbld of crude oil and condensate.

During 2013, EOG completed its four-well program in the Modified U(a) Block, having drilled three development wells and one successful exploratory well. In addition, an existing well was successfully recompleted and began production in 2013. EOG expects to drill three net wells in the SECC and Modified U(b) Blocks during 2014.

In 2014, certain agreements with NGC require EOG's Trinidad operations to deliver approximately 490 MMcfd (360 MMcfd, net) of natural gas, under current economic conditions. EOG intends to fulfill these natural gas delivery obligations by using production from existing proved reserves.

At December 31, 2013, EOG held approximately 39,000 net undeveloped acres in Trinidad.

United Kingdom. EOG's subsidiary, EOG Resources United Kingdom Limited (EOGUK), owns a 25% non-operating working interest in a portion of Block 49/16a, located in the Southern Gas Basin of the North Sea. During 2013, production continued from the Valkyrie field in this block.

In 2006, EOGUK participated in the drilling and successful testing of the Columbus prospect in the Central North Sea Block 23/16f in which EOG has a 25% non-operating working interest. A successful Columbus natural gas prospect appraisal well was drilled during the third quarter of 2007. In 2013, the U.K. Department of Energy and Climate Change (DECC) extended the previously granted license by two years. Costs associated with the Central North Sea Columbus natural gas project were written off in 2013.

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 the 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. The field development plans for the Conwy/Corfe project were approved by the DECC in March 2012. In 2013, after drilling an appraisal well, EOG determined that the Corfe field did not contain proved commercial reserves. The Conwy production platform and pipelines were installed during 2012 and 2013. In 2013, modifications to the nearby third-party owned Douglas platform began and a crude oil processing module was installed. The Douglas platform will be used to process Conwy production. During 2013, the three-well Conwy development drilling program was completed with first production from the Conwy field anticipated in late 2014.

In the third quarter of 2013, EOG drilled an unsuccessful exploratory well in the Central North Sea Block 21/12b, and in January 2014, EOG drilled an unsuccessful exploratory well in the East Irish Sea Block 110/7b.

In 2013, production averaged 1 MMcfd of natural gas, net, in the United Kingdom.

At December 31, 2013, EOG held approximately 54,000 net undeveloped acres in the United Kingdom.

China. In July 2008, EOG acquired rights from ConocoPhillips in a Petroleum Contract covering the Chuan Zhong Block exploration area in the Sichuan Basin, Sichuan Province, China. In October 2008, EOG obtained the rights to shallower zones on the acquired acreage. During the first half of 2013, EOG successfully recompleted a well and drilled and completed an additional well, both of which began production in the latter part of 2013. Additionally in 2013, EOG drilled one well that is expected to be completed and begin producing in 2014. EOG plans to drill six additional wells on its acreage in 2014.

In 2013, production averaged 7 MMcfd of natural gas, net, in China.

At December 31, 2013, EOG held approximately 131,000 net developed acres in China.

Argentina. In 2011, EOG signed two exploration contracts and one farm-in agreement covering approximately 95,000 net acres in the Neuquén Basin in Neuquén Province, Argentina. During 2013, EOG completed a well in the Aguada del Chivato Block that was drilled in 2012. Also, in late 2013, EOG participated in the drilling of a vertical well in the Cerro Avispa Block. In 2014, EOG plans to complete this vertical well, participate in the drilling of a well in the Cerro Avispa Block and a well in the Bajo del Toro Block. EOG continues to evaluate its drilling results and exploration program in Argentina.

Other International. 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.

Marketing

In 2013, EOG's wellhead crude oil and condensate production was sold into local markets or transported either by pipeline, truck or EOG's crude-by-rail assets to downstream markets. In each case, the price received was based on market prices at that specific sales point or based on the price index applicable for that location. Major sales points included Cushing, Oklahoma, St. James, Louisiana, and other points along the U.S. Gulf Coast. In 2014, the pricing mechanism for such production is expected to remain the same.

In 2013, EOG processed certain of its natural gas production, either at EOG-owned facilities or at third-party facilities, extracting NGLs. NGLs were sold at prevailing market prices. In 2014, the pricing mechanism for such production is expected to remain the same.

In 2013, EOG's United States and Canada wellhead natural gas production was sold into local markets or transported by pipeline to downstream markets. Pricing, based on the spot market and long-term natural gas contracts, was at prevailing market prices. In 2014, the pricing mechanism for such production is expected to remain the same.

In 2013, a large majority of the wellhead natural gas volumes from Trinidad were sold under contracts with prices which were either wholly or partially dependent on Caribbean ammonia index prices and/or methanol prices. The remaining volumes were sold under a contract at prices partially dependent on United States Henry Hub market prices. The pricing mechanisms for these contracts in Trinidad are expected to remain the same in 2014.

In 2013, all wellhead natural gas volumes from the U.K. were sold on the spot market. The 2014 marketing strategy for wellhead natural gas volumes from the U.K. is expected to remain the same. EOG is currently investigating possible marketing opportunities for its U.K. wellhead crude oil production, which is anticipated to begin in late 2014.

In 2013, all wellhead natural gas volumes from China were sold under a contract with prices based on the purchaser's pipeline sales prices to various local market segments. The pricing mechanism for the contract in China is expected to remain the same in 2014.

In certain instances, EOG purchases and sells third-party crude oil and natural gas in order to balance firm transportation capacity with production in certain areas and to utilize excess capacity at EOG-owned facilities.

During 2013, two purchasers each accounted for more than 10% of EOG's total wellhead crude oil and condensate, NGLs and natural gas revenues and gathering, processing and marketing revenues. Both purchasers are in the crude oil refining industry. EOG does not believe that the loss of any single purchaser would have a material adverse effect on its financial condition or results of operations.

Wellhead Volumes and Prices

The following table sets forth certain information regarding EOG's wellhead volumes of, and average prices for, crude oil and condensate, NGLs and natural gas. The table also presents crude oil equivalent volumes which are determined using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 Mcf of natural gas for each of the years ended December 31, 2013, 2012 and 2011.

Year Ended December 31 2013 2012 2011 Crude Oil and Condensate Volumes (MBbld) (1) United States: Eagle Ford 122.3 72.3 30.2 Barnett 11.7 13.0 15.2 Other 78.1 64.0 56.6 United States 212.1 149.3 102.0 Canada 7.0 7.0 7.9 Trinidad 1.2 1.5 3.4 Other International (2) 0.1 0.1 0.1 Total 220.4 157.9 113.4 Natural Gas Liquids Volumes (MBbld) (1) United States: Eagle Ford 18.6 11.2 3.9 Barnett 24.2 25.8 22.6 Other 21.5 18.1 15.0 United States 64.3 55.1 41.5 Canada 0.9 0.8 0.9 Total 65.2 55.9 42.4 Natural Gas Volumes (MMcfd) (1) United States: Eagle Ford 115 65 21 Barnett 305 368 403 Other 488 601 689 United States 908 1,034 1,113 Canada 76 95 132 Trinidad 355 378 344 Other International (2) 8 9 13 Total 1,347 1,516 1,602 Crude Oil Equivalent Volumes (MBoed) (3) United States: Eagle Ford 160.2 94.4 37.7 Barnett 86.8 100.1 105.0 Other 180.9 182.1 186.4 United States 427.9 376.6 329.1 Canada 20.5 23.6 30.7 Trinidad 60.4 64.5 60.7 Other International (2) 1.3 1.7 2.2 Total 510.1 466.4 422.7 Total MMBoe (3) 186.2 170.7 154.3

Year Ended December 31 2013 2012 2011 Average Crude Oil and Condensate Prices ($/Bbl) (4) United States $ 103.81 $ 98.38 $ 92.92 Canada 87.05 86.08 91.92 Trinidad 90.30 92.26 90.62 Other International (2) 89.11 89.57 100.11 Composite 103.20 97.77 92.79 Average Natural Gas Liquids Prices ($/Bbl) (4) United States $ 32.46 $ 35.41 $ 50.37 Canada 39.45 44.13 52.69 Composite 32.55 35.54 50.41 Average Natural Gas Prices ($/Mcf) (4) United States $ 3.32 $ 2.51 $ 3.92 Canada 3.08 2.49 3.71 Trinidad 3.68 3.72 3.53 Other International (2) 6.45 5.71 5.62 Composite 3.42 2.83 3.83

(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) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and 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.

(4) 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).

Competition

EOG competes with major integrated oil and gas companies, government-affiliated oil and gas companies and other independent oil and gas companies for the acquisition of licenses and leases, properties and reserves and access to the facilities, equipment, materials, services and employees and other contract personnel (including geologists, geophysicists, engineers and other specialists) required to explore for, develop, produce, market and transport crude oil and natural gas. In addition, many of EOG's competitors have financial and other resources substantially greater than those EOG possesses and have established strategic long-term positions and strong governmental relationships in countries in which EOG may seek new or expanded entry. As a consequence, EOG may be at a competitive disadvantage in certain respects, such as in bidding for drilling rights or in accessing necessary services, facilities, equipment, materials and personnel. In addition, many of EOG's larger competitors may have a competitive advantage when responding to factors that affect demand for crude oil and natural gas, such as changing worldwide prices and levels of production and the cost and availability of alternative fuels. EOG also faces competition, to a lesser extent, from competing energy sources, such as alternative energy sources.

Regulation

United States Regulation of Crude Oil and Natural Gas Production. Crude oil and natural gas production operations are subject to various types of regulation, including regulation in the United States by federal and state agencies.

United States legislation affecting the oil and gas industry is under constant review for amendment or expansion. In addition, numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations applicable to the oil and gas industry. Such rules and regulations, among other things, require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas through restrictions on flaring, require surety bonds for various exploration and production operations and regulate the calculation and disbursement of royalty payments (for federal and state leases), production taxes and ad valorem taxes.

A portion of EOG's oil and gas leases in New Mexico, North Dakota, Utah, Wyoming and the Gulf of Mexico, as well as some in other areas, are granted by the federal government and administered by the Bureau of Land Management (BLM) and the Bureau of Indian Affairs (BIA) or, in the case of offshore leases, by the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), all federal agencies. Operations conducted by EOG on federal oil and gas leases must comply with numerous additional statutory and regulatory restrictions and, in the case of leases relating to tribal lands, certain tribal environmental and permitting requirements and employment rights regulations.

BLM, BIA and BOEM leases contain relatively standardized terms requiring compliance with detailed regulations and, in the case of offshore leases, orders pursuant to the Outer Continental Shelf Lands Act (which are subject to change by the BOEM or BSEE). Under certain circumstances, the BLM, BIA, BOEM or BSEE (as applicable) may require operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect EOG's interests.

The transportation and sale for resale of natural gas in interstate commerce are regulated pursuant to the Natural Gas Act of 1938 (NGA) and the Natural Gas Policy Act of 1978. These statutes are administered by the Federal Energy Regulatory Commission (FERC). Effective January 1993, the Natural Gas Wellhead Decontrol Act of 1989 deregulated natural gas prices for all "first sales" of natural gas, which includes all sales by EOG of its own production. All other sales of natural gas by EOG, such as those of natural gas purchased from third parties, remain jurisdictional sales subject to a blanket sales certificate under the NGA, which has flexible terms and conditions. Consequently, all of EOG's sales of natural gas currently may be made at market prices, subject to applicable contract provisions. EOG's jurisdictional sales, however, are subject to the future possibility of greater federal oversight, including the possibility that the FERC might prospectively impose more restrictive conditions on such sales. Conversely, sales of crude oil and condensate and NGLs by EOG are made at unregulated market prices.

EOG owns certain gathering and/or processing facilities in the Permian Basin in West Texas and New Mexico, the Barnett Shale in North Texas, the Bakken and Three Forks plays in North Dakota, and the Eagle Ford in South Texas. State regulation of gathering and processing facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. EOG's gathering and processing operations could be materially and adversely affected should they be subject in the future to the application of state or federal regulation of rates and services.

EOG's gathering and processing operations also may be, or become, subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of such facilities. Additional rules and legislation pertaining to these matters are considered and/or adopted from time to time. Although EOG cannot predict what effect, if any, such legislation might have on its operations and financial condition, the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

EOG also owns crude oil loading facilities in North Dakota and Texas and crude oil unloading facilities in Oklahoma and Louisiana. Regulation of such facilities is conducted at the state and federal levels and generally includes various safety, environmental, permitting and packaging/labeling requirements. Additional regulation pertaining to these matters is considered and/or adopted from time to time. Although EOG cannot predict what effect, if any, any such new regulations might have on its crude-by-rail operations, EOG could be required to incur additional capital expenditures and increased compliance costs depending on the nature and extent of such future regulatory changes.

Proposals and proceedings that might affect the oil and gas industry are considered from time to time by Congress, the state legislatures, the FERC and federal and state regulatory commissions and courts. EOG cannot predict when or whether any such proposals or proceedings may become effective. It should also be noted that the oil and gas industry historically has been very heavily regulated; therefore, there is no assurance that the approach currently being followed by such legislative bodies and regulatory agencies and courts will continue indefinitely.

Canadian Regulation of Crude Oil and Natural Gas Production. The oil and gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. These regulatory authorities may impose regulations on or otherwise intervene in the oil and gas industry with respect to taxes and factors affecting prices, transportation rates, the exportation of the commodity and, possibly, expropriation or cancellation of contract rights. Such regulations may be changed from time to time in response to economic, political or other factors. The implementation of new regulations or the modification of existing regulations affecting the oil and gas industry could reduce demand for these commodities or increase EOG's costs and, therefore, may have a material adverse impact on EOG's operations and financial condition.

It is not expected that any of these controls or regulations will affect EOG's operations in a manner materially different than they would affect other oil and gas companies of similar size; however, EOG is unable to predict what additional legislation or amendments may be enacted or how such additional legislation or amendments may affect EOG's operations and financial condition.

In addition, each province has regulations that govern land tenure, royalties, production rates and other matters. The royalty system in Canada is a significant factor in the profitability of crude oil and natural gas production. Royalties payable on production from freehold lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is also subject to certain provincial taxes and royalties. Royalties payable on lands that the government has an interest in are determined by government regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends, in part, on prescribed reference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced. From time to time, the federal and provincial governments of Canada have also established incentive programs such as royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and gas exploration or enhanced recovery projects. These incentives generally have the effect of increasing EOG's revenues, earnings and cash flow.

Environmental Regulation - United States. EOG is subject to various federal, state and local laws and regulations covering the discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations affect EOG's operations and costs as a result of their effect on crude oil and natural gas exploration, development and production operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and the issuance of orders enjoining future operations or imposing additional compliance requirements.

In addition, EOG has acquired certain oil and gas properties from third parties whose actions with respect to the management and disposal or release of hydrocarbons or other wastes were not under EOG's control. Under environmental laws and regulations, EOG could be required to remove or remediate wastes disposed of or released by prior owners or operators. EOG also could incur costs related to the clean-up of third-party sites to which it sent regulated substances for disposal or to which it sent equipment for cleaning, and for damages to natural resources or other claims related to releases of regulated substances at such third-party sites. In addition, EOG could be responsible under environmental laws and regulations for oil and gas properties in which EOG previously owned or currently owns an interest, but was or is not the operator. Moreover, EOG is subject to the U.S. Environmental Protection Agency's (U.S. EPA) rule requiring annual reporting of greenhouse gas (GHG) emissions and may in the future, as discussed further below, be subject to federal, state and local laws and regulations regarding hydraulic fracturing.

Compliance with environmental laws and regulations increases EOG's overall cost of business, but has not had, to date, a material adverse effect on EOG's operations, financial condition or results of operations. It is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts (whether for environmental control facilities or otherwise) that are material in relation to its total exploration and development expenditure program in order to comply with such laws and regulations. However, given that such laws and regulations are subject to change, EOG is unable to predict the ultimate cost of compliance or the ultimate effect on EOG's operations, financial condition and results of operations.

Climate Change - United States. Local, state, national and international regulatory bodies have been increasingly focused on GHG emissions and climate change issues in recent years. In addition to the U.S. EPA's rule requiring annual reporting of GHG emissions, recent U.S. EPA rulemaking may result in the regulation of GHGs as pollutants under the federal Clean Air Act. EOG supports efforts to understand and address the contribution of human activities to global climate change through the application of sound scientific research and analysis. Moreover, EOG believes that its strategy to reduce GHG emissions throughout its operations is in the best interest of the environment and is a generally good business practice.

EOG has developed a system that is utilized in calculating GHG emissions from its operating facilities. This emissions management system calculates emissions based on recognized regulatory methodologies, where applicable, and on commonly accepted engineering practices. EOG is now reporting GHG emissions for facilities covered under the U.S. EPA's Mandatory Reporting of Greenhouse Gases Rule published in October 2009. EOG is unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties regarding climate change and GHG emissions, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect EOG's operations, financial condition and results of operations.

Hydraulic Fracturing - United States. Most onshore crude oil and natural gas wells drilled by EOG are completed and stimulated through the use of hydraulic fracturing. Hydraulic fracturing technology, which has been used by the oil and gas industry for more than 60 years and is constantly being enhanced, enables EOG to produce crude oil and natural gas from formations that would otherwise not be recovered. Specifically, hydraulic fracturing is a process in which pressurized fluid is pumped into underground formations to create tiny fractures or spaces that allow crude oil and natural gas to flow from the reservoir into the well so that it can be brought to the surface. Hydraulic fracturing generally takes place thousands of feet underground, a considerable distance below any drinking water aquifers, and there are impermeable layers of rock between the area fractured and the water aquifers. The makeup of the fluid used in the hydraulic fracturing process is typically more than 99% water and sand, and less than 1% of highly diluted chemical additives; lists of the chemical additives most typically used in fracturing fluids are available to the public via internet websites and in other publications sponsored by industry trade associations and through state agencies in those states that require the reporting of the components of fracturing fluids. While the majority of the sand remains underground to hold open the fractures, a significant percentage of the water and chemical additives flow back and are then either reused or safely disposed of at sites that are approved and permitted by the appropriate regulatory authorities. EOG regularly conducts audits of these disposal facilities to monitor compliance with all applicable regulations.

Currently, the regulation of hydraulic fracturing is primarily conducted at the state and local level through permitting and other compliance requirements. However, there have been various proposals to regulate hydraulic fracturing at the federal level. Any new federal regulations that may be imposed on hydraulic fracturing could result in additional permitting and disclosure requirements (such as the reporting and public disclosure of the chemical additives used in the fracturing process) and in additional operating restrictions. In April 2012, the U.S. EPA issued regulations specifically applicable to the oil and gas industry that will require operators to significantly reduce volatile organic compounds (VOC) emissions from natural gas wells that are hydraulically fractured through the use of "green completions" to capture natural gas that would otherwise escape into the air. The U.S. EPA also issued regulations that establish standards for VOC emissions from several types of equipment, including storage tanks, compressors, dehydrators, and valves and sweetening units at gas processing plants. In addition to these federal regulations, some state and local governments have imposed or have considered imposing various conditions and restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; disclosure of the chemical additives used in hydraulic fracturing operations; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations. Such federal, state and local permitting and disclosure requirements and operating restrictions and conditions could lead to operational delays and increased operating and compliance costs and, moreover, could delay or effectively prevent the development of crude oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing.

EOG is unable to predict the timing, scope and effect of any currently proposed or future laws or regulations regarding hydraulic fracturing in the United States, but the direct and indirect costs of such laws and regulations (if enacted) could materially and adversely affect EOG's operations, financial condition and results of operations.

Environmental Regulation - Canada. All phases of the oil and gas industry in Canada are subject to environmental regulation pursuant to a variety of Canadian federal, provincial and municipal laws and regulations. Such laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and wastes and in connection with spills, releases and emissions of various substances into the environment. These laws and regulations also require that facility sites and other properties associated with EOG's operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, EOG could be held responsible for oil and gas properties in which EOG owns an interest but is not the operator.

These laws and regulations are subject to frequent change, and the clear trend is to place increasingly stringent limitations on activities that may affect the environment. Compliance with such laws and regulations increases EOG's overall cost of business, but has not had, to date, a material adverse effect on EOG's operations, financial condition or results of operations. It is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts (whether for environmental control facilities or otherwise) that are material in relation to its total exploration and development expenditure program in order to comply with such laws and regulations. However, given that such laws and regulations are subject to change, EOG is unable to predict the ultimate cost of compliance or the ultimate effect on EOG's operations, financial condition and results of operations.

As discussed above, local, provincial, national and international regulatory bodies have been increasingly focused on GHG emissions and climate change issues in recent years. The Canadian federal government has indicated an intention to work with the United States to regulate industrial emissions of GHG and air pollutants from a broad range of industrial sectors. In addition, regulation of GHG emissions in Canada takes place at the provincial and municipal level. For example, the governments of Alberta and British Columbia each regulate GHG emissions and the government of Manitoba is currently considering the creation of a cap-and-trade system to reduce GHG emissions in Manitoba. Canada was an original signatory to the United Nations Framework Convention on Climate Change (also known as the Kyoto Protocol), but Canada withdrew from the Kyoto Protocol, effective December 2012.

In Canada, the regulation of hydraulic fracturing is primarily conducted at the provincial and local levels through permitting and other compliance requirements. Some provinces and local governments have imposed or have considered imposing various conditions and restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; restrictions on access to and usage of water; disclosure of the chemical additives used in hydraulic fracturing operations; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations. Such provincial and local requirements, restrictions and conditions could lead to operational delays and increased operating and compliance costs and, moreover, could delay or effectively prevent the development of crude oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing. EOG is unable to predict the timing, scope and effect of any currently proposed or future laws or regulations regarding hydraulic fracturing in Canada, but the direct and indirect costs of such laws and regulations (if enacted) could materially and adversely affect EOG's operations, financial condition and results of operations.

Other International Regulation. EOG's exploration and production operations outside the United States and Canada are subject to various types of regulations imposed by the respective governments of the countries in which EOG's operations are conducted, and may affect EOG's operations and costs of compliance within that country. EOG currently has operations in Trinidad, the United Kingdom, China and Argentina. EOG is unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties, including those regarding climate change and hydraulic fracturing, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect EOG's operations, financial condition and results of operations. EOG will continue to review the risks to its business and operations associated with all environmental matters, including climate change and hydraulic fracturing. In addition, EOG will continue to monitor and assess any new policies, legislation, regulations and treaties in the areas where it operates to determine the impact on its operations and take appropriate actions, where necessary.

Other Regulation. EOG has sand mining and processing operations in Texas and Wisconsin, which support EOG's exploration and development operations. EOG's sand mining operations are subject to regulation by the federal Mine Safety and Health Administration (in respect of safety and health matters) and by state agencies (in respect of air permitting and other environmental matters). The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this report.

Other Matters

Energy Prices. EOG is a crude oil and natural gas producer and is impacted by changes in prices of crude oil and condensate, NGLs and natural gas. Crude oil and condensate and NGLs production comprised a larger portion of EOG's production mix in 2013 than in prior years and is expected to comprise an even larger portion in 2014. Average crude oil and condensate prices received by EOG for production in the United States and Canada increased 6% in 2013, 5% in 2012 and 24% in 2011, each as compared to the immediately preceding year. Average NGLs prices received by EOG for production in the United States and Canada decreased 8% in 2013 and 30% in 2012 and increased 21% in 2011, each as compared to the immediately preceding year. During the last three years, average United States and Canada wellhead natural gas prices have fluctuated, at times rather dramatically. These fluctuations resulted in a 31% increase in the average wellhead natural gas price received by EOG for production in the United States and Canada in 2013, a 36% decrease in 2012 and an 8% decrease in 2011, each as compared to the immediately preceding year. Due to the many uncertainties associated with the world political environment, the availability of other energy supplies, the relative competitive relationships of the various energy sources in the view of consumers and other factors, EOG is unable to predict what changes may occur in prices of crude oil and condensate, NGLs and natural gas in the future. For additional discussion regarding changes in crude oil and natural gas prices and the risks that such changes may present to EOG, see ITEM 1A. Risk Factors.

Including the impact of EOG's 2014 crude oil derivative contracts (exclusive of options) and based on EOG's tax position, EOG's price sensitivity in 2014 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 $44 million for net income and $65 million for cash flows from operating activities. Including the impact of EOG's 2014 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 2014 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 $13 million for net income and $19 million for cash flows from operating activities. For a summary of EOG's financial commodity derivative contracts at February 24, 2014, see ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Derivative Transactions. For a summary of EOG's financial commodity derivative contracts at December 31, 2013, see Note 11 to Consolidated Financial Statements.

Risk Management. EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in prices of crude oil and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis swap contracts, as a means to manage this price risk. See Note 11 to Consolidated Financial Statements. In addition to financial transactions, from time to time EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. Under the provisions of the Derivatives and Hedging Topic of the Financial Accounting Standards Board's Accounting Standards Codification, these physical commodity contracts qualify for the normal purchases and normal sales exception and, therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices. For a summary of EOG's financial commodity derivative contracts at February 24, 2014, see ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Derivative Transactions. For a summary of EOG's financial commodity derivative contracts at December 31, 2013, see Note 11 to Consolidated Financial Statements.

All of EOG's crude oil and natural gas activities are subject to the risks normally incident to the exploration for, and development, production and transportation of, crude oil and natural gas, including rig and well explosions, cratering, fires, loss of well control and leaks and spills, each of which could result in damage to life, property and/or the environment. EOG's onshore and offshore operations are also subject to usual customary perils, including hurricanes and other adverse weather conditions. Moreover, EOG's activities are subject to governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. Losses and liabilities arising from such events could reduce revenues and increase costs to EOG to the extent not covered by insurance.

Insurance is maintained by EOG against some, but not all, of these risks in accordance with what EOG believes are customary industry practices and in amounts and at costs that EOG believes to be prudent and commercially practicable. Specifically, EOG maintains commercial general liability and excess liability coverage provided by third-party insurers for bodily injury or death claims resulting from an incident involving EOG's onshore or offshore operations (subject to policy terms and conditions). Moreover, in the event an incident with respect to EOG's onshore or offshore operations results in negative environmental effects, EOG maintains operators extra expense coverage provided by third-party insurers for obligations, expenses or claims that EOG may incur from such an incident, including obligations, expenses or claims in respect of seepage and pollution, cleanup and containment, evacuation expenses and control of the well (subject to policy terms and conditions). In the event of a well control incident resulting in negative environmental effects, such operators extra expense coverage would be EOG's primary coverage, with the commercial general liability and excess liability coverage referenced above also providing certain coverage to EOG. All of EOG's onshore and offshore drilling activities are conducted on a contractual basis with independent drilling contractors and other third-party service contractors. The indemnification and other risk allocation provisions included in such contracts are negotiated on a contract-by-contract basis and are each based on the particular circumstances of the services being provided and the anticipated operations.

In addition to the above-described risks, EOG's operations outside the United States are subject to certain risks, including the risk of increases in taxes and governmental royalties, changes in laws and policies governing the operations of foreign-based companies, expropriation of assets, unilateral or forced renegotiation or modification of existing contracts with governmental entities, currency restrictions and exchange rate fluctuations. Please refer to ITEM 1A. Risk Factors for further discussion of the risks to which EOG is subject with respect to its operations outside the United States.

Texas Severance Tax Rate Reduction. Natural gas production from qualifying Texas natural gas wells spudded or completed after August 31, 1996 is entitled to a reduced severance tax rate for the first 120 consecutive months of production. However, the cumulative value of the tax reduction cannot exceed 50 percent of the drilling and completion costs incurred on a well-by-well basis.

Executive Officers of the Registrant

The current executive officers of EOG and their names and ages (as of February 24, 2014) are as follows:

Name Age Position William R. Thomas 61 Chairman of the Board and Chief Executive Officer Gary L. Thomas 64 Chief Operating Officer Lloyd W. Helms, Jr. 56 Executive Vice President, Exploration and Production David W. Trice 43 Executive Vice President, Exploration and Production Timothy K. Driggers 52 Vice President and Chief Financial Officer Michael P. Donaldson 51 Vice President, General Counsel and Corporate Secretary

William R. Thomas was elected Chairman of the Board and Chief Executive Officer effective January 2014. He was elected Senior Vice President and General Manager of EOG's Fort Worth, Texas, office in June 2004, Executive Vice President and General Manager of EOG's Fort Worth, Texas, office in February 2007 and Senior Executive Vice President, Exploitation in February 2011. He subsequently served as Senior Executive Vice President, Exploration from July 2011 to September 2011, as President from September 2011 to July 2013 and as President and Chief Executive Officer from July 2013 to December 2013. Mr. Thomas joined a predecessor of EOG in January 1979. Mr. Thomas is EOG's principal executive officer.

Gary L. Thomas was elected Chief Operating Officer in September 2011. He was elected Executive Vice President, North America Operations in May 1998, Executive Vice President, Operations in May 2002, and served as Senior Executive Vice President, Operations from February 2007 to September 2011. He also previously served as Senior Vice President and General Manager of EOG's Midland, Texas, office. Mr. Thomas joined a predecessor of EOG in July 1978.

Lloyd W. Helms, Jr. was elected Executive Vice President, Exploration and Production in August 2013. He was elected Vice President, Engineering and Acquisitions in September 2006, Vice President and General Manager of EOG's Calgary, Alberta, Canada office in March 2008, and served as Executive Vice President, Operations from February 2012 to August 2013. Mr. Helms joined a predecessor of EOG in February 1981.

David W. Trice was elected Executive Vice President, Exploration and Production in August 2013. He served as Vice President and General Manager of EOG's Fort Worth, Texas, office from May 2010 to August 2013. Prior to that, he served in various geological and management positions at EOG. Mr. Trice joined EOG in November 1999.

Timothy K. Driggers was elected Vice President and Chief Financial Officer in July 2007. He was elected Vice President and Controller of EOG in October 1999, was subsequently named Vice President, Accounting and Land Administration in October 2000 and Vice President and Chief Accounting Officer in August 2003. Mr. Driggers is EOG's principal financial officer. Mr. Driggers joined a predecessor of EOG in August 1995.

Michael P. Donaldson was elected Vice President, General Counsel and Corporate Secretary in May 2012. He was elected Corporate Secretary in May 2008, and was appointed Deputy General Counsel and Corporate Secretary in July 2010. Mr. Donaldson joined EOG in September 2007.