EOG RESOURCES, INC. (EOG) Business, 2018

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 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 (including related exhibits and supplemental schedules, filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act) are made available, free of charge, through EOG's website, as soon as reasonably practicable after such reports have been filed with, or furnished to, 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, 2018, EOG's total estimated net proved reserves were 2,928 million barrels of oil equivalent (MMBoe), of which 1,532 million barrels (MMBbl) were crude oil and condensate reserves, 614 MMBbl were natural gas liquids (NGLs) reserves and 4,687 billion cubic feet (Bcf), or 782 MMBoe, were natural gas reserves (see "Supplemental Information to Consolidated Financial Statements"). At such date, approximately 98% of EOG's net proved reserves, on a crude oil equivalent basis, were located in the United States, 1% in Trinidad and 1% in other international areas. 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, 2018, EOG employed approximately 2,800 persons, including foreign national employees.

EOG's operations are all crude oil and natural gas exploration and production related. For information regarding the risks associated with EOG's domestic and foreign operations, see ITEM 1A, Risk Factors.

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. Pursuant to this strategy, each prospective drilling location is evaluated by its estimated rate of return. 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 drilling equipment, completion technologies for horizontal drilling and formation evaluation. These advanced technologies are used, as appropriate, throughout EOG to reduce the risks and costs 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 efficient, safe and environmentally responsible 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 located 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, 2018, on a crude oil equivalent basis, 53% of EOG's net proved reserves in the United States were crude oil and condensate, 21% were NGLs and 26% 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 2018 and certain 2019 plans for EOG's United States operations.

2018 2019 Area of Operation Crude Oil & Condensate Volumes(MBbld) (1) Natural Gas Liquids Volumes(MBbld) (1) Natural Gas Volumes(MMcfd) (1) Total Net Acres (2) Net Well Completions Expected Net Well Completions Eagle Ford 171 31 159 579,000 304 300 Austin Chalk 20 7 42 — (3) 27 15 Permian Basin 132 46 338 913,000 265 275 Rocky Mountain Area 62 15 207 1,232,000 109 95 Upper Gulf Coast 1 — 4 441,000 1 5 Mid-Continent 6 2 12 125,000 31 35 Fort Worth Basin 2 14 78 152,000 — — South Texas 1 1 24 391,000 8 5 Marcellus Shale — — 59 172,000 15 —

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

(2) Total net acres excludes approximately 0.3 million net acres related to other areas.

(3) The Austin Chalk play encompasses the same net acres as the Eagle Ford.

The Eagle Ford continues to prove itself as a world-class crude oil field having produced in excess of 2.9 billion barrels of crude oil and condensate. With approximately 516,000 of its 579,000 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 490 MMBbl of crude oil and condensate. In 2018, EOG completed 304 net Eagle Ford wells and continued to test the Austin Chalk play concept with the completion of 27 net Austin Chalk wells. EOG is still evaluating the extent of prospectivity of the Austin Chalk, which overlays the Eagle Ford. EOG also continued its enhanced oil recovery (EOR) gas injection program in 2018, adding 54 wells to the program. EOG does not expect to add wells to the EOR program in 2019 while it evaluates additional primary development opportunities. EOG expects to complete approximately 300 net Eagle Ford wells and 15 net Austin Chalk wells in 2019 while continuing to improve well productivity and operational efficiencies. The combination of exceptional execution and continuous operational improvements have made this play one of the foundations of EOG's portfolio.

In the Permian Basin, EOG completed 265 net wells during 2018, primarily in the Delaware Basin Wolfcamp Shale, Bone Spring and Leonard plays. EOG continued to consolidate its acreage position in each of these world-class assets through small leasing transactions and the exchange of acreage with other nearby operators. EOG has approximately 346,000 net acres in the Delaware Basin Wolfcamp Shale play where it completed 219 net wells in 2018. The success of the 2018 Wolfcamp program was due to precision targeting, high-density stimulations and continued cost reductions. The program shifted toward the development of larger packages of wells during 2018, which also contributed to cost reductions. The high-return Delaware Basin Wolfcamp Shale play will continue to be a primary area of focus in 2019. In the Second Bone Spring play, EOG holds approximately 289,000 net acres and completed 18 net wells in 2018. 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 with 17 net wells completed in 2018. EOG also had strong results in the First Bone Spring where it holds approximately 100,000 net acres and completed eight net wells in 2018. Activity in 2019 will continue to be focused in the Delaware Basin Wolfcamp Shale, Second Bone Spring, First Bone Spring and Leonard plays, where EOG expects to complete approximately 270 net wells.

Activity in the Rocky Mountain area increased in 2018 with a focus on the Wyoming Powder River and DJ Basins. In the Powder River Basin, EOG operated a two-rig program, completing 41 net wells, and identified future drilling locations, mostly in the Mowry and Niobrara formations. The focus in 2019 will be to add infrastructure and operate a drilling program to further delineate the basin and test additional targets, to better position the company for a more robust development program in 2020 and beyond. In the Wyoming DJ Basin, drilling, completion, and operating costs continued to decline and there is a significant high-return development program scheduled for 2019. Drilling activity increased in the Williston Basin in 2018 after pausing for several years while the company reduced its inventory of drilled uncompleted wells (DUCs). The 20 net wells completed in 2018 targeted the Bakken and Three Forks formations and benefited from the application of precision targeting. Activity in 2019 will be similar, as will the seasonal program of completing wells mostly in the summer while drilling operations are conducted throughout the year. EOG currently holds approximately 1.2 million net acres in the Rocky Mountain area.

In the Mid-Continent area, EOG continued its development of the Woodford Oil Window play with 26 net wells completed during 2018. EOG holds 47,000 net acres in the play and plans to build on its initial success in the Woodford Oil Window with 30 net well completions in 2019. In 2018, EOG completed 22 gross (four net) wells in the Western Anadarko Basin Marmaton Sand.

Total net production in 2018 from the Fort Worth Basin Barnett Shale and Marcellus Shale averaged 2 MBbld of crude oil and condensate, 14 MBbld of NGLs and 137 MMcfd of natural gas. Development activity in these areas was concentrated in the Marcellus Shale in 2018, where EOG completed 15 net DUCs. Net production in the Marcellus Shale for 2018 averaged 59 MMcfd of natural gas, with a peak net rate of 102 MMcfd. EOG currently holds approximately 172,000 net acres with Marcellus potential. At year-end 2018, EOG held approximately 152,000 net acres in the Fort Worth Basin.

At year-end 2018, EOG held approximately 441,000 net acres in the Upper Gulf Coast region. EOG remained focused on exploration and evaluation efforts last year with minimal activity and expects these efforts will continue in 2019.

In the South Texas area, EOG completed eight net liquids-rich natural gas wells in 2018, including three net DUCs from prior years. EOG has deferred completion of five additional net wells, and expects to complete these liquids-rich natural gas wells in 2019 in the Frio and Vicksburg trends, where it holds approximately 391,000 net acres. In addition, exploration and evaluation efforts will continue in this region in 2019.

At December 31, 2018, EOG held approximately 2.4 million net undeveloped acres in the United States.

During 2018, EOG continued to operate its gathering and processing facilities in the Eagle Ford in South Texas, the Williston Basin Bakken and Three Forks plays in North Dakota, the Fort Worth Basin Barnett Shale and the Permian Basin in West Texas and New Mexico. At December 31, 2018, EOG-owned natural gas processing capacity in the Eagle Ford and the Fort Worth Basin Barnett Shale totaled 325 MMcfd and 180 MMcfd, respectively.

EOG has operations offshore Trinidad, in the China Sichuan Basin and in Canada and is evaluating additional exploration, development and exploitation opportunities in these and other select international areas. EOG sold its operations in the United Kingdom (U.K.) East Irish Sea in the fourth quarter of 2018.

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 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);

• holds a 50% working interest in the exploration and production license covering the Banyan Field;

• holds a 50% working interest in the exploration and production license covering the Ska, Mento, Reggae Area deep Teak, deep Saaman and deep Poui offshore Trinidad (collectively SMR Area);

• 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), the Banyan Field 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 and its successor, Heritage Petroleum Company Limited. In 2018, EOG's net production from Trinidad averaged approximately 266 MMcfd of natural gas and approximately 0.8 MBbld of crude oil and condensate.

In 2018, EOG conducted an ocean bottom nodal seismic survey in the SECC Block and the Pelican Field and continues to process and review the initial data.

In 2019, EOG expects to drill five wells of which two of these wells are expected to be completed during the second quarter of 2019 and one well is expected to be completed in the fourth quarter of 2019. All of the natural gas produced from EOG's Trinidad operations in 2019 is expected to be supplied to NGC under various contracts with NGC. All crude oil and condensate produced from EOG's Trinidad operations in 2019 is expected to be supplied to Heritage Petroleum Company Limited under various contracts with Heritage Petroleum Company Limited.

At December 31, 2018, EOG held approximately 115,000 net undeveloped acres in Trinidad.

United Kingdom. EOG completed the sale of all of its interest in EOG Resources United Kingdom Limited during the fourth quarter of 2018. EOG no longer has any presence in the U.K.

In 2018, production averaged approximately 4.2 MBbld of crude oil, net, in the U.K.

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 entered 2018 with two DUCs and completed both wells. In addition, EOG drilled five natural gas wells and completed one of those wells in 2018 as part of the continuing development of the Bajiaochang Field, which natural gas is sold under a long-term contract to PetroChina. EOG plans to drill two additional wells in 2019 and complete the remaining 2018 wells in progress as pipeline capacity allows.

In 2018, production averaged approximately 23 MMcfd of natural gas, net, in China.

Canada. EOG maintains approximately 134,000 net acres with 23 net producing wells in the Horn River area in Northeast British Columbia.

In 2018, net production in Canada averaged approximately 8 MMcfd of natural gas.

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 2018, EOG's wellhead crude oil and condensate production was transported either by pipeline or truck to downstream markets or sold into local 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; Houston and Corpus Christi, Texas; and Louisiana; and other points along the U.S. Gulf Coast. In 2019, the pricing mechanism for such production is expected to remain the same. At December 31, 2018, EOG is committed to deliver fixed quantities of crude oil of 69.9 MMBbls in 2019, 13.7 MMBbls in 2020 and 1.4 MMBbls in 2021, all of which is expected to be delivered from future production of available reserves.

In 2018, 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 2019, the pricing mechanism for such production is expected to remain the same.

In 2018, EOG's United States wellhead natural gas production was sold into local markets or transported by pipeline to Katy, Texas; East Texas; the Cheyenne Hub; Southern California; or Chicago, Illinois. Pricing was based on the spot market price at the ultimate sales point. In 2019, the pricing mechanism for such production is expected to remain the same. At December 31, 2018, EOG is committed to deliver fixed quantities of natural gas of 64 Bcf in 2019, 15 Bcf in 2020, 10 Bcf in 2021, 2 Bcf in 2022 and 11 Bcf thereafter, all of which is expected to be delivered from future production of available reserves.

In 2018, 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 and a fixed price contract. The pricing mechanisms for these contracts in Trinidad are expected to remain the same in 2019.

In 2018, 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 2019.

Through November 2018, EOG marketed and sold its U.K. wellhead crude oil production from the Conwy field. The crude oil sales were based on a Dated Brent price or other market prices, as applicable.

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 2018, two 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. The two 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, 2018, 2017 and 2016. 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 2018 2017 2016 Crude Oil and Condensate Volumes (MMBbl) (1) United States: Eagle Ford 62.4 57.4 60.7 Delaware Basin 46.3 31.6 17.0 Other 35.4 33.2 24.2 United States 144.1 122.2 101.9 Trinidad 0.3 0.3 0.3 Other International (2) 1.6 0.2 1.2 Total 146.0 122.7 103.4 Natural Gas Liquids Volumes (MMBbl) (1) United States: Eagle Ford 11.4 9.4 10.0 Delaware Basin 15.8 8.8 5.8 Other 15.3 14.1 14.1 United States 42.5 32.3 29.9 Other International (2) — — — Total 42.5 32.3 29.9 Natural Gas Volumes (Bcf) (1) United States: Eagle Ford 58 55 59 Delaware Basin 110 81 50 Other 169 143 187 United States 337 279 296 Trinidad 97 114 125 Other International (2) 11 9 9 Total 445 402 430 Crude Oil Equivalent Volumes (MMBoe) (3) United States: Eagle Ford 83.5 76.0 80.6 Delaware Basin 80.3 53.9 31.2 Other 78.8 71.2 69.3 United States 242.6 201.1 181.1 Trinidad 16.5 19.4 21.1 Other International (2) 3.4 1.8 2.8 Total 262.5 222.3 205.0

Year Ended December 31 2018 2017 2016 Average Crude Oil and Condensate Prices ($/Bbl) (4) United States $ 65.16 $ 50.91 $ 41.84 Trinidad 57.26 42.30 33.76 Other International (2) 71.45 57.20 36.72 Composite 65.21 50.91 41.76 Average Natural Gas Liquids Prices ($/Bbl) (4) United States $ 26.60 $ 22.61 $ 14.63 Other International (2) — — — Composite 26.60 22.61 14.63 Average Natural Gas Prices ($/Mcf) (4) United States $ 2.88 $ 2.20 $ 1.60 Trinidad 2.94 2.38 1.88 Other International (2) 4.08 3.89 3.64 Composite 2.92 (5) 2.29 1.73

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

(2) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The United Kingdom operations were sold in the fourth quarter of 2018. 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).

(5) Includes a positive revenue adjustment of $0.44 per Mcf related to the adoption of ASU 2014-09, "Revenue From Contracts with Customers" (ASU 2014-09) (see Note 1 to the Consolidated Financial Statements). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees related to certain processing and marketing agreements as Gathering and Processing Costs, instead of as a deduction to Natural Gas revenues.

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 or strong governmental relationships in countries or areas 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 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 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 assets 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 2018.

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, federal 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, the U.S. EPA has adopted regulations for certain large sources regulating GHG emissions as pollutants under the federal Clean Air Act. In May 2016, the U.S. EPA issued regulations that require operators to reduce methane emissions and emissions of volatile organic compounds (VOC) 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.

At the international level, 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. However, the U.S. has announced its intention to withdraw from the Paris Agreement. In response, many state and local officials have stated their intent to intensify efforts to uphold the commitments set forth in the international accord.

EOG believes that its strategy to reduce GHG emissions throughout its operations is both in the best interest of the environment and a prudent 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, as amended.

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 typically includes water and sand, and less than 1% of highly diluted chemical additives; lists of the chemical additives 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 amount 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 periodically conducts regulatory assessments 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 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 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, though, in September 2018, the BLM issued a final rule rescinding certain requirements of that rule. 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; restrictions on the type of chemical additives that may be used in hydraulic fracturing operations; and restrictions on drilling or injection activities on certain lands lying within wilderness wetlands, ecologically or seismically sensitive areas, and other protected areas. 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, China and Canada (as earlier discussed, EOG sold its United Kingdom operations in the fourth quarter of 2018). 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. Average crude oil and condensate prices received by EOG for production in the United States increased 28% in 2018 and 22% in 2017 and decreased 12% in 2016, each as compared to the immediately preceding year. Average NGL prices received by EOG for production in the United States increased 18% in 2018, 55% in 2017, and 1% in 2016, 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 31% increase in the average wellhead natural gas price received by EOG for production in the United States in 2018 (inclusive of a positive revenue adjustment of $0.44 per Mcf related to the adoption of ASU 2014-09), a 38% increase in 2017 and a 19% decrease in 2016, each as compared to the immediately preceding year.

Due to the many uncertainties associated with the world political and economic 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, NGLs and natural gas 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 condensate, NGLs and natural gas prices and the risks that such changes may present to EOG, see ITEM 1A, Risk Factors.

Based on EOG's tax position, EOG's price sensitivity (exclusive of basis swaps) in 2019 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 $133 million for net income and $173 million for pretax cash flows from operating activities. Based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2019 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 $29 million for net income and $37 million for pretax cash flows from operating activities. For a summary of EOG's financial commodity derivative contracts through February 19, 2019, 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, 2018, 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 19, 2019, 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, flooding and other adverse weather events. 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.

The current executive officers of EOG and their names and ages (as of February 26, 2019) are as follows:

Name Age Position William R. Thomas 66 Chairman of the Board and Chief Executive Officer Lloyd W. Helms, Jr. 61 Chief Operating Officer Kenneth W. Boedeker 56 Executive Vice President, Exploration and Production Ezra Y. Yacob 42 Executive Vice President, Exploration and Production Timothy K. Driggers 57 Executive Vice President and Chief Financial Officer Michael P. Donaldson 56 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.

Lloyd W. Helms, Jr. was elected Chief Operating Officer in December 2017. Prior to that, he served as Executive Vice President, Exploration and Production from August 2013 to December 2017. 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.

Kenneth W. Boedeker was elected Executive Vice President, Exploration and Production in December 2018. He served as Vice President and General Manager of EOG's Denver, Colorado, office from October 2016 to December 2018, and as Vice President, Engineering and Acquisitions from July 2015 to October 2016. Prior to that, Mr. Boedeker held technical and managerial positions of increasing responsibility across multiple offices and functional areas within EOG. Mr. Boedeker joined EOG in July 1994.

Ezra Y. Yacob was elected Executive Vice President, Exploration and Production in December 2017. He served as Vice President and General Manager of EOG's Midland, Texas, office from May 2014 to December 2017. Prior to that, he served as Manager, Division Exploration in EOG's Fort Worth, Texas, and Midland, Texas, offices from March 2012 to May 2014 as well as in various geoscience and leadership positions. Mr. Yacob joined EOG in August 2005.

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.