EOG RESOURCES, INC. (EOG) Business, 2016

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.), The Republic of Trinidad and Tobago (Trinidad), the United Kingdom (U.K.), The People's Republic of China (China), Canada 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. Information on our website is not incorporated by reference into, and does not constitute a part of, this report.

At December 31, 2016, EOG's total estimated net proved reserves were 2,147 million barrels of oil equivalent (MMBoe), of which 1,178 million barrels (MMBbl) were crude oil and condensate reserves, 416 MMBbl were natural gas liquids (NGLs) reserves and 3,318 billion cubic feet (Bcf), or 553 MMBoe, were natural gas reserves (see "Supplemental Information to Consolidated Financial Statements"). At such date, approximately 97% of EOG's net proved reserves, on a crude oil equivalent basis, were located in the United States and 3% in Trinidad. 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 (Mcf) of natural gas.

As of December 31, 2016, EOG employed approximately 2,650 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, allowing EOG to deliver long-term production growth while maintaining a strong balance sheet. 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, completion technologies for horizontal drilling and formation evaluation. 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 primarily 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.

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 11 to Consolidated Financial Statements. For information regarding the risks associated with EOG's foreign operations, see ITEM 1A, Risk Factors.

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

At December 31, 2016, on a crude oil equivalent basis, 56% of EOG's net proved reserves in the United States were crude oil and condensate, 20% were NGLs and 24% 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 2016 and certain 2017 plans for EOG's United States operations.

The Eagle Ford continues to prove itself as a world-class crude oil field having produced in excess of 2.0 billion barrels of crude oil and condensate. With approximately 528,000 of its 590,000 total net acres in the prolific oil window, EOG continues to be the largest crude oil producer in the Eagle Ford with cumulative gross production in excess of 365 MMBbl of crude oil. In 2016, EOG completed 236 net Eagle Ford wells and also tested a new Austin Chalk play concept with the completion of 14 net Austin Chalk wells. EOG is still evaluating the extent of prospectivity of the Austin Chalk, which overlays the Eagle Ford. Net production from the Eagle Ford averaged approximately 166 thousand barrels per day (MBbld) of crude oil and condensate, 27 MBbld of NGLs and 161 million cubic feet per day (MMcfd) of natural gas. EOG also expanded its enhanced oil recovery (EOR) gas injection program with the implementation of a 32-well commercialization pilot which is showing favorable early results. In 2017, EOG expects to complete approximately 195 net Eagle Ford wells and 25 net Austin Chalk wells, continue to improve well productivity and reduce drilling and completion costs as well as operating expenses. In addition, based on encouraging results, EOG will continue to expand the implementation of the EOR gas injection program into additional areas. The combination of self-sourced sand, dedicated completions crews and other services along with continuous well optimization programs have made this play a centerpiece of EOG's portfolio.

In the Permian Basin, EOG completed 92 net wells primarily in the Delaware Basin Wolfcamp Shale, Second Bone Spring and Leonard plays during 2016, and significantly increased its acreage position in each of these world-class assets. In the Delaware Basin Wolfcamp Shale play, where it has approximately 346,000 net acres, EOG followed a development plan with well spacing as close as 660 feet in the crude oil portion and 880 feet in the combo portion. The success of the 2016 Delaware Basin Wolfcamp Shale program was due to precision targeting, high-density stimulations, cost reductions, and lateral length extensions. The average lateral length of completed wells in the Delaware Basin Wolfcamp Shale play increased from approximately 4,600 feet in 2015 to approximately 5,200 feet in 2016. The high-return Delaware Basin Wolfcamp Shale play, where EOG completed 71 net wells in 2016, will continue to be an area of focus in 2017. In the Second Bone Spring play, where it holds approximately 289,000 net acres, EOG completed 13 net wells. With over 1,800 estimated remaining net drilling locations, the Second Bone Spring play is another integral part of EOG's Permian Basin portfolio. In the Leonard Shale play, EOG has approximately 160,000 net acres and continued development in 2016 with eight net wells completed. Net production in the Permian Basin for 2016 averaged approximately 47 MBbld of crude oil and condensate, and 16 MBbld of NGLs, an increase of 47% over 2015. Net natural gas production increased 29% to approximately 139 MMcfd. EOG holds approximately 630,000 net acres throughout the Permian Basin. In 2017, activity will be focused primarily in the Delaware Basin Wolfcamp Shale, Second Bone Spring and Leonard plays, where EOG expects to complete approximately 140 net wells.

On October 4, 2016, EOG completed its previously announced merger and related asset purchase transactions with Yates Petroleum Corporation (YPC), Abo Petroleum Corporation (ABO), MYCO Industries, Inc. (MYCO), and certain affiliated entities (collectively with YPC, ABO and MYCO, the "Yates Entities"), thereby gaining a presence in Artesia, New Mexico. The Yates transaction added, among other acreage, highly-prospective core acreage of approximately 180,000 net acres in the Delaware Basin Core and approximately 200,000 net acres in the Powder River Basin that will be exploited by existing EOG operations. In 2017, EOG will be focused on fully integrating the existing Yates Entities personnel, exploring its approximate 130,000 net acres in the Permian Basin Northwest Shelf in New Mexico (acquired from the Yates Entities) and optimizing the legacy Yates net production of approximately 28,600 barrels of oil equivalent per day (Boed). In 2017, EOG plans to drill and complete approximately five net wells in the Permian Basin Northwest Shelf and assess the remaining 1.1 million net acres acquired from the Yates Entities in New Mexico, Wyoming, Colorado, Montana, North Dakota, and Utah.

In 2016, the Rocky Mountain area experienced increased EOG activity, driven in large part by the completion of the majority of its drilled uncompleted wells (DUCs). This area also achieved significant reductions in lease operating expenses and capital costs while making gains in well productivity. In the Powder River Basin, EOG successfully expanded development programs in both the Turner and Parkman formations, completing 20 net wells. EOG increased its net acreage position in the Powder River Basin from approximately 376,000 net acres to approximately 572,000 net acres, largely driven by the Yates transaction. Given EOG's sizable acreage footprint and improving well results, the Powder River Basin will be one focal point of EOG's 2017 development program. In 2016, EOG continued successful infill drilling in the Williston Basin Bakken , completing 48 net wells, including DUCs. The Bakken continues to produce superior wells, and EOG plans to continue development operations in this area in 2017. In the DJ Basin, EOG completed 30 net wells, including the majority of its DUCs drilled in 2014. Substantial reductions in capital costs, driven by drilling, completion, and facility design changes coupled with improvements in well productivity and formation targeting, have significantly increased the rates of return of future wells in the DJ Basin. EOG plans to continue development in the DJ Basin in 2017. Net production for the entire Rocky Mountain area for 2016 averaged approximately 48 MBbld of crude oil and condensate, 11 MBbld of NGLs and 154 MMcfd of natural gas. In 2017, EOG plans to complete approximately 80 net wells in the Rocky Mountain area. EOG holds approximately 1.7 million net acres in the Rocky Mountain area, an increase of approximately 880,000 from 2015 largely driven by the Yates transaction.

In the Upper Gulf Coast region, EOG focused on portfolio enhancement through an active exploration, evaluation and disposition program in 2016. Total net production in 2016 from the Upper Gulf Coast averaged approximately 2 MBbld of crude oil and condensate, 1 MBbld of NGLs and 34 MMcfd of natural gas. In the fourth quarter of 2016, EOG divested all of its Haynesville natural gas assets which included average net production of approximately 30 MMcfd on 90,000 net acres. Additional smaller asset sales occurred throughout the year. EOG completed seven net wells in 2016 and plans to complete approximately 10 net wells in 2017 in this region. At year-end 2016, EOG held approximately 370,000 net acres in the Upper Gulf Coast region.

Similar to the Upper Gulf Coast region, the Mid-Continent area has been an area of active portfolio management. Total net production in 2016 from the Mid-Continent area averaged approximately 3 MBbld of crude oil and condensate, 2 MBbld of NGLs and 21 MMcfd of natural gas. EOG held approximately 300,000 net acres throughout the Mid-Continent area at year-end 2016 and expects to continue its exploration program in 2017.

In the Fort Worth Basin, EOG divested all of its Barnett Shale natural gas assets in Johnson County, Texas, in the fourth quarter of 2016. Net production from the divested properties in 2016 was approximately 135 MMcfd of natural gas and 4 MBbld of NGLs, and included 85,000 net acres. EOG still operates a large liquids-rich Barnett Shale acreage position (Barnett Combo) located primarily in Montague and Cooke Counties. Daily average net production in the Barnett Shale was approximately 3 MBbld of crude oil and condensate, 22 MBbld of NGLs and 217 MMcfd of natural gas during 2016. EOG held approximately 234,000 net acres in the Fort Worth Basin as of year-end 2016.

In the South Texas area, total net production during 2016 averaged approximately 2 MBbld of crude oil and condensate, 2 MBbld of NGLs and 42 MMcfd of natural gas. EOG drilled three net natural gas wells in 2016 and deferred additional completions until market conditions become more favorable. In 2017, EOG expects to complete approximately 10 net liquids-rich natural gas wells in the Frio and Vicksburg trends, where it holds approximately 205,000 net acres. Exploration efforts will continue in this region, primarily focusing on liquids-rich exploration plays.

Net production in the Marcellus Shale for 2016 averaged approximately 17 MMcfd of natural gas. EOG currently holds approximately 210,000 net acres with Marcellus and Utica Shale potential. EOG plans to complete approximately five net wells in 2017.

EOG has agreements with certain crude oil refining companies to deliver an average of 46 MBbld of crude oil in 2017. EOG intends to fulfill these crude oil delivery obligations with its Eagle Ford production.

At December 31, 2016, EOG held approximately 2.2 million net undeveloped acres in the United States.

During 2016, EOG continued to operate its gathering and processing activities in the Eagle Ford in South Texas, the Bakken and Three Forks plays in North Dakota and the Permian Basin in West Texas and New Mexico. At December 31, 2016, EOG-owned natural gas processing capacity in the Eagle Ford and Barnett Shale totaled 325 MMcfd and 180 MMcfd, respectively.

In 2016, EOG continued to own its crude oil facilities near Stanley, North Dakota, St. James, Louisiana, and Stroud, Oklahoma.

EOG operates its own sand mine and sand processing plants in Hood County, Texas, to reduce costs and to help fulfill EOG's sand needs for its well completion operations in Texas. Additionally, EOG owns a second Hood County sand processing plant, which processes sand sourced from the north Texas area, as needed.

In 2016, EOG continued to process sand from its Chippewa Falls, Wisconsin, sand plant on an as-needed basis.

EOG operates three sand unloading facilities to support well completions in the Delaware Basin, Eagle Ford and the Williston Basin Bakken.

During 2016, EOG shipped the equivalent of 152 sand unit trains from various sources to support well completions in the Delaware Basin, Eagle Ford and other plays.

EOG has operations offshore Trinidad, in the U.K. East Irish Sea, in the China Sichuan Basin and in Canada 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 licenses covering the Sercan Area (formerly known as 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 Sercan 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 Limited and its subsidiary (NGC). Crude oil and condensate from EOG's Trinidad operations currently is sold to the Petroleum Company of Trinidad and Tobago Limited (Petrotrin). In 2016, EOG's net production from Trinidad averaged approximately 340 MMcfd of natural gas and approximately 0.8 MBbld of crude oil and condensate.

In 2016, EOG installed a platform and pipeline in the Sercan Area in preparation for its three net well drilling program. In the fourth quarter of 2016, EOG drilled and completed one net well and began drilling a second well. EOG expects to bring the remaining two net wells of the Sercan program on-line in early 2017 and to drill an additional three net wells in the second half of 2017.

In 2017, it is anticipated that EOG's Trinidad operations will supply approximately 395 MMcfd (295 MMcfd, net) of natural gas from its existing proved reserves. All of the natural gas produced from EOG's Trinidad operations in 2017 is expected to be supplied to NGC under various contracts with NGC. All crude oil and condensate produced from EOG's Trinidad operations in 2017 is expected to be supplied to Petrotrin under various contracts with Petrotrin.

At December 31, 2016, EOG held approximately 40,000 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. Production ceased at the end of the third quarter of 2015, and decommissioning is planned for the second half of 2017.

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 oil exploratory well in the East Irish Sea Block 110/12a. EOG began production from its 100% working interest East Irish Sea Conwy crude oil project in March 2016. Modifications to the nearby third-party-owned Douglas platform, which is used to process Conwy production, were completed in the first quarter of 2016 and acceptance and performance testing is ongoing.

In 2016, production averaged approximately 3.4 MBbld of crude oil, net, in the United Kingdom.

At December 31, 2016, EOG held approximately 4,000 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. EOG plans to drill and complete four wells in 2017 in the Sichuan Basin, Sichuan Province, China.

In 2016, production averaged approximately 15 MMcfd of natural gas, net, in China.

Canada. EOG sold all of its assets in Manitoba and the majority of its assets in Alberta in two separate transactions that closed on or about December 1, 2014. EOG divested 1.3 million gross acres (1.1 million net), 97 percent of which were in Alberta. Of the approximate 5,800 net producing wells sold, 5,155 wells were natural gas. In 2016, net production in Canada averaged approximately 10 MMcfd of natural gas.

Argentina. EOG's investment in Argentina was sold during the third quarter of 2016.

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.

In 2016, EOG's wellhead crude oil and condensate production was sold into local markets or transported either by pipeline or truck 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 U.S. sales areas included the Midwest, the Permian Basin, Cushing, Oklahoma, Louisiana, and other points along the U.S. Gulf Coast. In 2017, the pricing mechanism for such production is expected to remain the same.

In 2016, 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 2017, the pricing mechanism for such production is expected to remain the same.

In 2016, EOG's United States wellhead natural gas production was sold into local markets or transported by pipeline to downstream markets. Pricing was based on the spot market at the ultimate sales point. In 2017, the pricing mechanism for such production is expected to remain the same.

In 2016, 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 2017.

In December 2014, EOG put in place arrangements to market and sell its U.K. wellhead crude oil production from the Conwy field, which commenced production in March 2016. The crude oil sales are based on a Dated Brent price or other market prices, as applicable.

In 2016, all wellhead natural gas volumes from China were sold at regulated prices based on the purchaser's pipeline sales volumes to various local market segments. The pricing mechanism for production in China is expected to remain the same in 2017.

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 2016, three purchasers each accounted for more than 10% of EOG's total wellhead crude oil and condensate, NGL and natural gas revenues and gathering, processing and marketing revenues. All three 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.

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 a 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, 2016, 2015 and 2014. See ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations, for wellhead volumes on a per-day basis.

Year Ended December 31 2016 2015 2014 Crude Oil and Condensate Volumes (MMBbl) (1) United States: Eagle Ford 60.7 66.3 65.0 Delaware Basin 17.0 9.8 5.1 Other 24.2 27.3 32.8 United States 101.9 103.4 102.9 Trinidad 0.3 0.3 0.3 Other International (2) 1.2 0.1 2.2 Total 103.4 103.8 105.4 Natural Gas Liquids Volumes (MMBbl) (1) United States: Eagle Ford 10.0 9.9 9.0 Delaware Basin 5.8 3.1 2.0 Other 14.1 15.1 18.1 United States 29.9 28.1 29.1 Other International (2) — — 0.2 Total 29.9 28.1 29.3 Natural Gas Volumes (Bcf) (1) United States: Eagle Ford 59 65 60 Delaware Basin 50 27 17 Other 187 231 259 United States 296 323 336 Trinidad 125 127 132 Other International (2) 9 12 26 Total 430 462 494 Crude Oil Equivalent Volumes (MMBoe) (3) United States: Eagle Ford 80.6 87.1 84.0 Delaware Basin 31.2 17.4 9.9 Other 69.3 80.9 94.1 United States 181.1 185.4 188.0 Trinidad 21.1 21.6 22.4 Other International (2) 2.8 1.9 6.7 Total 205.0 208.9 217.1

Year Ended December 31 2016 2015 2014 Average Crude Oil and Condensate Prices ($/Bbl) (4) United States $ 41.84 $ 47.55 $ 92.73 Trinidad 33.76 39.51 84.63 Other International (2) 36.72 57.32 86.75 Composite 41.76 47.53 92.58 Average Natural Gas Liquids Prices ($/Bbl) (4) United States $ 14.63 $ 14.50 $ 31.84 Other International (2) — 4.61 40.73 Composite 14.63 14.49 31.91 Average Natural Gas Prices ($/Mcf) (4) United States $ 1.60 $ 1.97 $ 3.93 Trinidad 1.88 2.89 3.65 Other International (2) 3.64 5.05 4.40 Composite 1.73 2.30 3.88

(1) Million barrels or billion cubic feet, as applicable.

(2) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.

(3) Million barrels of oil equivalent; includes crude oil and condensate, NGLs and natural gas.

(4) 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).

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, certain 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, 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.

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 in other areas, are granted by the federal government and administered by the Bureau of Land Management (BLM) and/or the Bureau of Indian Affairs (BIA) or, in the case of offshore leases (which, for EOG, are de minimis), 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. In addition, the U.S. Department of the Interior (via various of its agencies, including the BLM, the BIA and the Office of Natural Resources Revenue) has certain authority over our calculation and payment of royalties, bonuses, fines, penalties, assessments and other revenues related to our federal and tribal oil and gas leases.

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, as amended (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, may be subject in the future to 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, nondiscrimination requirements with respect to the provision of gathering and processing services, 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, EOG could be required to incur additional capital expenditures and increased compliance and operating costs depending on the nature and extent of such future legislative and regulatory changes.

EOG also owns crude oil rail loading facilities in North Dakota, crude oil rail unloading facilities in Oklahoma and Louisiana, and crude oil truck unloading facilities in certain of its U.S. plays. 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 and the transportation of its crude oil production by truck, EOG could be required to incur additional capital expenditures and increased compliance and operating costs depending on the nature and extent of such future regulatory changes. EOG did not transport any crude oil by rail during 2016.

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, state and local regulatory commissions, agencies, councils 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 commissions, agencies, councils and courts will remain unchanged.

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 United States (U.S.) Environmental Protection Agency's (U.S. EPA) rule requiring annual reporting of greenhouse gas (GHG) emissions and, as discussed further below, is also 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. In addition, 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 addition to the U.S. EPA's rule requiring annual reporting of GHG emissions, the U.S. EPA has adopted regulations for certain large sources regulating GHG emissions as pollutants under the federal Clean Air Act. Also, in December 2015, the U.S. participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement (adopted at the conference) calls for nations to undertake efforts with respect to global temperatures and GHG emissions. The Paris Agreement went into effect on November 4, 2016. It remains unclear whether and how the results of the 2016 U.S. election could impact the regulation of GHG emissions at the federal and state level.

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 reports GHG emissions for facilities covered under the U.S. EPA's Mandatory Reporting of Greenhouse Gases Rule published in 2009.

EOG is unable to predict the timing, scope and effect of any currently proposed or future investigations, laws, regulations or treaties regarding climate change and GHG emissions, but the direct and indirect costs of such investigations, 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 otherwise would 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 applicable regulations.

The regulation of hydraulic fracturing is primarily conducted at the state and local level through permitting and other compliance requirements. In April 2012, however, the U.S. EPA issued regulations specifically applicable to the oil and gas industry that 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, in May 2016, the U.S. EPA issued regulations that require operators to reduce methane and VOC emissions from new, modified and reconstructed crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations, gas processing plants and natural gas transmission compressor stations.

In March 2015, the BLM issued new regulations applicable to hydraulic fracturing activities on federal and Indian lands, including requirements for chemical disclosure, wellbore integrity and handling of flowback and produced water. Those regulations were set aside by a federal district court in June 2016, but are on appeal to the 10th Circuit Court of Appeals. In addition, in November 2016, the BLM issued a final rule that limits venting, flaring and leaking of natural gas from oil and gas wells and equipment on federal and Indian lands. There have been various other 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, additional operating and compliance costs and additional operating restrictions.

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.

Other International Regulation. EOG's exploration and production operations outside the United States are subject to various types of regulations, including environmental 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 those countries. EOG currently has operations in Trinidad, the United Kingdom, China and Canada. 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 regulation. 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.

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. Consistent with EOG's 2015 production, crude oil and condensate and NGL production comprised a larger portion of EOG's production mix in 2016 than in historical prior years. Average crude oil and condensate prices received by EOG for production in the United States decreased 12% in 2016, 49% in 2015 and 11% in 2014, each as compared to the immediately preceding year. Average NGL prices received by EOG for production in the United States increased 1% in 2016 and decreased 54% in 2015 and 2% in 2014, each as compared to the immediately preceding year. During the last three years, average United States wellhead natural gas prices have fluctuated, at times rather dramatically. These fluctuations resulted in a 19% decrease in the average wellhead natural gas price received by EOG for production in the United States in 2016, a 50% decrease in 2015 and an 18% increase in 2014, each as compared to the immediately preceding year. Due to the many uncertainties associated with the world political environment (for example, the actions of other crude oil exporting nations, including the Organization of Petroleum Exporting Countries), the global supply of and demand for crude oil and 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 2017 crude oil derivative contracts (exclusive of options) and based on EOG's tax position, EOG's price sensitivity in 2017 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 $77 million for net income and $96 million for cash flows from operating activities. Including the impact of EOG's 2017 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 2017 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 $12 million for net income and $15 million for cash flows from operating activities. For a summary of EOG's financial commodity derivative contracts through February 20, 2017, 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 for the twelve months ended December 31, 2016, see Note 12 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 12 to Consolidated Financial Statements. For a summary of EOG's financial commodity derivative contracts through February 20, 2017, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Derivative Transactions.

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 operations are also subject to certain 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 operations (subject to policy terms and conditions). Moreover, in the event an incident involving EOG's 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 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.

The current executive officers of EOG and their names and ages (as of February 27, 2017) are as follows:

Name Age Position William R. Thomas 64 Chairman of the Board and Chief Executive Officer Gary L. Thomas 67 President and Chief Operating Officer Lloyd W. Helms, Jr. 59 Executive Vice President, Exploration and Production David W. Trice 46 Executive Vice President, Exploration and Production Timothy K. Driggers 55 Executive Vice President and Chief Financial Officer Michael P. Donaldson 54 Executive 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 and President in March 2015. 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 Executive Vice President and Chief Financial Officer in April 2016. Previously, Mr. Driggers served as Vice President and Chief Financial Officer from July 2007 to April 2016. 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 Executive Vice President, General Counsel and Corporate Secretary in April 2016. Previously, Mr. Donaldson served as Vice President, General Counsel and Corporate Secretary from May 2012 to April 2016. 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.