The Eagle Ford continues to prove itself asis a world-class crude oil field havingwhich has produced in excess of 2.03.4 billion barrels of crude oil and condensate. With approximately 520,000516,000 of its 582,000579,000 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 420600 MMBbl of crude oil and condensate. In 2017,2019, EOG completed 217321 net Eagle Ford wells and continued to test the Austin Chalk play concept with the completion of 2814 net Austin Chalk wells. EOG is still evaluatingcontinues to evaluate the extent of prospectivity of the Austin Chalk, which overlays theEOG's Eagle Ford.Ford acreage. EOG also expandedhas approximately 150 Eagle Ford net wells in its enhanced oil recovery (EOR) gas injection program in 2017, adding 56program. The company did not add wells to the program. Based on encouraging results, EOG plansEOR program in 2019 and does not expect to include an additional 90add wells in 2018 bringing2020. EOR is a secondary recovery process and the total number of wells incompany continues to evaluate the primary development opportunities on its acreage before expanding the EOR program to 178 by year end.program. In 2018,2020, EOG expects to complete approximately 260300 net Eagle Ford wells and 256 net Austin Chalk wells while continuing to improve well productivity and operational efficiencies. The combination of self-sourced sand, dedicated completions crewsexceptional execution and other services along with continuous well optimization programsoperational improvements have made this play a centerpieceone of the foundations of EOG's portfolio.

In the PermianDelaware Basin, EOG completed 172276 net wells during 2017,2019, primarily in the Delaware Basin Wolfcamp, Shale, Second Bone Spring and Leonard plays. EOG continued to consolidatealso identified additional drilling locations in the Wolfcamp M and Third Bone Spring formations, expanding its inventory of future drilling locations across its approximately 389,000 total net acre position. The Delaware Basin consists of approximately 4,800 feet of stacked pay potential across multiple zones, offering EOG co-development opportunities across its acreage position in each of these world-class assets through small leasing transactions and the exchange of acreage with other nearby operators. position.

In the Delaware Basin Wolfcamp Shale play, where it has approximately 346,000 net acres, EOG followed acompleted 201 net wells in 2019. EOG continued its development plan with well spacing as close as 500 feet in the crude oil portion and 880 feet in the combocombination crude oil and natural gas portion. The success of the 2017 Wolfcamp program was due to precision targeting, high-density stimulations, cost reductions, and lateral length extensions. The average lateral length of completed wellsResults in the play increased from approximately 5,200 feet in 2016 to approximately 6,100 feet in 2017. The high-return Delaware Basin Wolfcamp Shaleprogram were supported by optimized well spacing, the application of enhanced well completions, precision drilling and continued cost reductions. The Delaware Basin Wolfcamp play where EOG completed 116 net wells in 2017, will continue to be ana primary area of focus in 2018.2020.

In the Third Bone Spring play, EOG completed 13 net wells in 2019 on its 200,000 net prospective acres. With multiple targets and ample co-development opportunities, the Third Bone Spring play is expected to be a large portion of EOG’s future development program. In the Second Bone Spring play, EOG holds approximately 289,000 net acres and completed 2634 net wells in 2017. With over 1,800 estimated remaining2019. EOG also continued development in the First Bone Spring play where EOG has approximately 100,000 net drilling locations,acres and completed nine net wells in 2019. Both the First and Second Bone Spring play is anotherplays continue to be an integral part of EOG's PermianEOG’s Delaware Basin portfolio.

In the Leonard Shale play, EOG has approximately 160,000 net acres and continued development with 2019 net wells completed in 2017. EOG also announced the addition of a new high-return target in the Delaware Basin First Bone Spring oil play where it holds 100,000 net prospective acres. In 2017, EOG had consistent results in the First Bone Spring completing nine net wells and estimates that it has over 540 net locations remaining. 2019.

Activity in 20182020 will continue to be focused in the Delaware Basin Wolfcamp, Shale,Third Bone Spring, Second Bone Spring, First Bone Spring and Leonard plays, where EOG expects to complete approximately 230350 net wells.

Activity in the Rocky Mountain area increasedwas consistent in 20172019 with a focus on the completion of the remaining legacy drilled uncompleted wells (DUCs) in the Williston Basin Bakken and continued development of theWyoming Powder River and DJ Basins.Basin. In the Powder River Basin, EOG continued to expand its development programsoperated a two-rig program and completed 32 net wells in the Niobrara, Mowry, Turner and Parkman formations,formations. The focus in 2019 was to delineate the Mowry and Niobrara plays and to begin adding infrastructure. Drilling activity and infrastructure buildout will increase significantly in 2020 as well as test new horizons. With consistent resultsactivity shifts to development drilling. The infrastructure added will lower operating costs and strong returns in 2017, the Powder River Basin will again be a focal point for EOG in 2018.increase price realizations going forward. In the Wyoming DJ Basin, drilling, completion,EOG operated one rig and operating costs continuedcompleted 44 net wells in 2019 in both the Codell and the Niobrara formations. Activity in the DJ Basin is expected to be driven downmoderate in 2020 as activity shifts to the Powder River Basin. In the Williston Basin, EOG completed 20 net wells in the Bakken and there is a significant high-return development program scheduled for 2018. ActivityThree Forks. On average, well performance in the Williston Basin Bakken for 2017 was mainly limitedgreatly improved due to better targeting and completion techniques. The seasonal program of completing DUCs and will shift to drilling and completing new wells startingmostly in the summer of 2018.while drilling throughout the year will continue in 2020, although activity will be at a slightly lower pace than 2019. EOG currently holds approximately 1.21.3 million net acres in the Rocky Mountain area.

In the Mid-Continent area, EOG proved the prospectivitycontinued its development of the Woodford Oil Window play with two30 net wells completed during 2017.2019. EOG holds 50,00041,700 net acres in the play withand plans to continue development in 2018. Alsobuild on its results in the area,Woodford Oil Window with 20 net well completions in 2020. In 2019, EOG executed a joint venture agreementcompleted 11 gross (two net) wells in the Western Anadarko Basin Marmaton Sand play. In 2017,Sand.

Net production for the Marcellus Shale in 2019 averaged approximately 68.3 MMcfd of natural gas. At December 31, 2019, EOG drilled 18 gross wells and completed 10 gross wells as operator of the joint venture. EOG divested 8,335held approximately 151,000 net acres with daily average production of 1,231 barrels of oil equivalent per day (Boed) in the Mid-Continent area. EOG plans to build on its initial success in the Woodford Oil Window with an expanded campaign of 25 net well completions in 2018. Continued development in the joint venture in the Western Anadarko Basin is also planned.Marcellus Shale.

Total net production in 2017 from the Fort Worth Basin Barnett Shale production averaged 31.7 MBbld of crude oil and condensate, 1612.2 MBbld of NGLs and 9467.4 MMcfd of natural gas. At year-end 2017, EOG held approximately 169,000 net acresgas in the Fort Worth Basin. In 2017, EOG divested 57,000 net acres and 137 net wells in the Fort Worth Basin Barnett Shale. Average daily production volumes associated with the sale were 5.5 MMcfd of natural gas.2019.

At December 31, 2017,2019, EOG held approximately 2.22.3 million net undeveloped acres in the United States.

During 2017,2019, 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, 2017,2019, 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 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.

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 under various contracts to theHeritage Petroleum Company of Trinidad and Tobago Limited (Petrotrin)(Heritage).

In 2017,2019, EOG's net production from Trinidad averaged approximately 313260 MMcfd of natural gas and approximately 0.90.6 MBbld of crude oil and condensate.

In 2020, EOG expects to drill and drilled and completed five additionalcomplete three net wells in the Banyan and Osprey fields. EOG conducted a seismic survey in the U(a) Block, participated in a seismic survey program with a joint venture partner in the SMR area and signed a new multi-year contract under which EOG will supply future natural gas volumes to NGC beginning in 2019.

In 2017, EOG's2019, EOG continued its diversified approach to marketing its wellhead crude oil and condensate production. The majority of production was transported by pipeline to downstream markets with the remainder sold into local markets or transported eithermarkets. Major U.S. sales areas accessed by pipeline or truckEOG were various locations along the U.S. Gulf coast, including Houston and Corpus Christi, Texas and Louisiana; Cushing, Oklahoma; the Permian Basin and the Midwest. In late 2019, EOG also sold crude oil at the Houston Ship Channel (HSC) for export to downstream markets.foreign destinations. 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 2018,2020, the pricing mechanism for such production is expected to remain the same. In 2020, EOG expects to sell crude oil at the Port of Corpus Christi for export, in addition to sales at the HSC. At December 31, 2019, EOG was committed to deliver to multiple parties fixed quantities of crude oil of 28 MMBbls in 2020 and 2 MMBbls in 2021, all of which is expected to be delivered from future production of available reserves.

In 2017,2019, 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, into either local markets or downstream locations. In certain instances, EOG exchanged its NGL production for purity products received downstrean, which were sold at prevailing market prices. In 2018, the2020, such pricing mechanism for such production ismechanisms are expected to remain the same.

In 2017,2019, consistent with its diversified marketing strategy, the majority of EOG's United States wellhead natural gas production was sold into local markets or transported by pipeline to downstreamvarious locations, including Katy, Texas; East Texas; the Agua Dulce Hub in South Texas; the Cheyenne Hub in Weld County, Colorado; Southern California; and Chicago, Illinois. Remaining natural gas production was sold into local markets. PricingIn each case, pricing was based on the spot market price at the ultimate sales point. In 2018,2020, the pricing mechanism for such production is expected to remain the same. Additionally in 2019, EOG entered into an agreement, beginning in 2020, to sell natural gas to an LNG liquefaction facility near Corpus Christi, Texas and receive pricing based on the Platts Japan Korea Marker. At December 31, 2019, EOG was committed to deliver to multiple parties fixed quantities of natural gas of 159 Bcf in 2020, 108 Bcf in 2021, 82 Bcf in 2022, 82 Bcf in 2023, 31 Bcf in 2024 and 1,685 Bcf thereafter, all of which is expected to be delivered from future production of available reserves.

In 2017,2019, 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.prices and under a fixed price contract. The pricing mechanisms for these contracts in Trinidad are expected to remain the same in 2018.2020; however, we anticipate the majority of volumes will be sold under a fixed price contract.

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 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 2017,2019, two purchasers each accounted for more than 10% of EOG's total wellhead crude oil and condensate, NGLNGLs 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.

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, certainCertain of EOG's competitors have financial and other resources substantially greater than those EOG possesses and have established strategic long-term positions andor 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 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 2017.2019.

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 other 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.

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.)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.fracturing and other aspects of our operations.

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.

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. Further, the increasing attention to global climate change risks has created the potential for a greater likelihood of governmental investigations and private and public litigation, which could increase our costs or otherwise adversely affect our business.

    

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)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 has 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 June 2017, the U.S. EPA proposed to stay certain requirements of that rule for two years.

InAlso, 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. In December 2017,lands, though, in September 2018, the BLM temporarily suspended or delayedissued a final rule rescinding certain requirements of that rule until January 17, 2019.rule. There have been various other proposals to regulate hydraulic fracturing at the federal level. Any new federal regulations that may be imposedIn addition, there have been proposals and positions taken by candidates for elected office and others regarding additional restrictions on, or the complete prohibition of, hydraulic fracturing could result in additional permitting and disclosure requirements, additional operating and compliance costs and additional operating restrictions.operations.

In addition to thesethe above-described 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 or prohibition 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.

Compliance with laws and regulations relating to hydraulic fracturing and other aspects of our operations 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 that are material in relation to its total exploration and development expenditure program in order to comply with such laws and regulations. However, EOG is unable to predict (i) the timing, scope and effect of any currently proposed or future laws or regulations regarding hydraulic fracturing in the United States butor other aspects of our operations and (ii) the ultimate cost of compliance or the ultimate effect on EOG's operations, financial condition and results of operations relating to such future laws and regulations. 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.

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 the 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.

Including the impact of EOG's 2018 crude oil derivative contracts (exclusive of basis swaps) and basedBased on EOG's tax position, EOG's price sensitivity (exclusive of basis swaps) in 20182020 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 $82$117 million for net income and $106$152 million for pretax cash flows from operating activities. Including the impact of EOG's 2018 natural gas derivative contracts (exclusive of call options) and basedBased on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 20182020 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 $22$31 million for net income and $29$40 million for pretax cash flows from operating activities. For a summary of EOG's financial commodity derivative contracts through February 20, 2018,19, 2020, 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, 2017,2019, see Note 12 to Consolidated Financial Statements.

All of EOG's crude oil, NGL and natural gas activities are subject to the risks normally incident to the exploration for, and development, production and transportation of, crude oil, NGL 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 conditions.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 EOG's 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, modification or modificationnullification 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 27, 2018)2020) are as follows:

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.

DavidKenneth W. TriceBoedeker was elected Executive Vice President, Exploration and Production in August 2013.December 2018.  He served as Vice President and General Manager of EOG's Fort Worth, Texas,Denver, Colorado, office from May 2010October 2016 to August 2013.December 2018, and as Vice President, Engineering and Acquisitions from July 2015 to October 2016.  Prior to that, he served in various geologicalMr. Boedeker held technical and managementmanagerial positions atof increasing responsibility across multiple offices and functional areas within EOG.  Mr. TriceBoedeker joined EOG in November 1999.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.

Our business and operations are subject to many risks. The risks described below may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. If any of the events or circumstances described below actually occurs, our business, financial condition, results of operations or cash flows could be materially and adversely affected and the trading price of our common stock could decline. The following risk factors should be read in conjunction with the other information contained herein, including the consolidated financial statements and the related notes. Unless the context requires otherwise, "we," "us," "our" and "EOG" refer to EOG Resources, Inc. and its subsidiaries.

Prices for crude oil and natural gas (including prices for natural gas liquids (NGLs) and condensate) fluctuate widely. Among the interrelated factors that can or could cause these price fluctuations are:

Our cash flows and results of operations depend to a great extent on prevailing commodity prices. Accordingly, substantial and extended declines in commodity prices can materially and adversely affect the amount of cash flows we have available for our capital expenditures and other operating expenses, our ability tothe terms on which we can access the credit and capital markets and our results of operations.

Lower commodity prices can also reduce the amount of crude oil, natural gas and NGLs that we can produce economically. Substantial and extended declines in the prices of these commodities can render uneconomic a significant portion of our exploration, development and exploitation projects, resulting in our having to make significant downward adjustments to our estimated proved reserves.reserves and also possibly shut in or plug and abandon certain wells. In addition, significant prolonged decreases in commodity prices may cause the expected future cash flows from our properties to fall below their respective net book values, which will require us to write down the value of our properties. Such reserve write-downs and asset impairments could materially and adversely affect our results of operations and financial position and, in turn, the trading price of our common stock.

If commodity prices decline from current levels for an extended period of time, our financial condition, cash flows and results of operations will be adversely affected and we may be limited in our ability to maintain our current level of dividends on our common stock. In addition, we may be required to incur impairment charges and/or make significant additional downward adjustments to our proved reserve estimates. As a result, our financial condition and results of operations and the trading price of our common stock may be adversely affected.

Drilling crude oil and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive crude oil and natural gas reserves (including "dry holes"). As a result, we may not recover all or any portion of our investment in new wells.

Specifically, we often are uncertain as to the future cost or timing of drilling, completing and operating wells, and our drilling operations and those of our third-party operators may be curtailed, delayed or canceled, the cost of such operations may increase and/or our results of operations and cash flows from such operations may be impacted, as a result of a variety of factors, including:

Our failure to recover our investment in wells, increases in the costs of our drilling operations or those of our third-party operators, and/or curtailments, delays or cancellations of our drilling operations or those of our third-party operators, in each case, due to any of the above factors or other factors, may materially and adversely affect our business, financial condition and results of operations. For related discussion of the risks and potential losses and liabilities inherent in our crude oil and natural gas operations generally, see the immediately following risk factor.

Our crude oil, NGLs and natural gas operations and supporting activities and operations are subject to all of the risks associated with exploring and drilling for, and producing, gathering, processing, compressing, storing and transporting, crude oil and natural gas, including the risks of:

We maintain insurance against many, but not all, such losses and liabilities in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. TheHowever, the occurrence of any of these events and any losses or liabilities incurred as a result of such events, if uninsured or in excess of our insurance coverage, would reduce the funds available to us for our operations and could, in turn, have a material adverse effect on our business, financial condition and results of operations.

The sale of our crude oil, NGLs and natural gas production depends on a number of factors beyond our control, including the availability, proximity and capacity of, and costs associated with, gathering, processing, compression, storage and transportation facilities and equipment owned by third parties. These facilities may be temporarily unavailable to us due to market conditions, regulatory reasons, mechanical reasons or other factors or conditions, and may not be available to us in the future on terms we consider acceptable, if at all. In particular, in certain newer plays, the capacity of gathering, processing, compression, storage and transportation facilities and equipment may not be sufficient to accommodate potential production from existing and new wells. In addition, lack of financing, construction and permitting delays, permitting costs and regulatory or other constraints could limit or delay the construction, manufacture or other acquisition of new gathering, processing, compression, storage and transportation facilities, export facilities and equipment by third parties or us, and we may experience delays or increased costs in accessing the pipelines, gathering systems or rail systems necessary to transport our production to points of sale or delivery.

Any significant change in market or other conditions affecting gathering, processing, compression, storage or transportation facilities, export facilities and equipment or the availability of these facilities, including due to our failure or inability to obtain access to these facilities and equipment on terms acceptable to us or at all, could materially and adversely affect our business and, in turn, our financial condition and results of operations.

The rate of production from crude oil and natural gas properties generally declines as reserves are produced. Except to the extent that we conduct successful exploration, exploitation and development activities resulting in additional reserves, acquire additional properties containing reserves or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our reserves will decline as they are produced. Maintaining our production of crude oil and natural gas at, or increasing our production from, current levels, is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves. To the extent we are unsuccessful in acquiring or finding additional reserves, our future cash flows and results of operations and, in turn, the trading price of our common stock could be materially and adversely affected.

Our crude oil, NGLs and natural gas operations and supporting activities are regulated extensively by federal, state, tribal and local governments and regulatory agencies, both domestically and in the foreign countries in which we do business, and are subject to interruption or termination by governmental and regulatory authorities based on environmental, health, safety or other considerations. Moreover, we have incurred and will continue to incur costs in our efforts to comply with the requirements of environmental, health, safety and other regulations. Further, the regulatory environment could change in ways that we cannot predict and that might substantially increase our costs of compliance and, in turn, materially and adversely affect our business, results of operations and financial condition.

Specifically, as a current or past owner or lessee and operator of crude oil and natural gas properties, we are subject to various federal, state, tribal, local and foreign regulations relating to the discharge of materials into, and the protection of, the environment. These regulations may, among other things, impose liability on us for the cost of pollution cleanup resulting from current or past operations, subject us to liability for pollution damages and require suspension or cessation of operations in affected areas. Changes in, or additions to, these regulations could lead to increased operating and compliance costs and, in turn, materially and adversely affect our business, results of operations and financial condition.

The regulation of hydraulic fracturing is primarily conducted at the state and local level through permitting and other compliance requirements.requirements and, further, some state and local governments have imposed or have considered imposing various conditions and restrictions on drilling and completion operations. In November 2016, however, the U.S. Bureau of Land Management (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. In December 2017,lands (in September 2018, the BLM temporarily suspended or delayedissued a final rule rescinding certain requirements of that rule until January 17, 2019.the rule). In addition, the U.S. EPAEnvironmental Protection Agency (U.S. EPA) has issued regulations relating to hydraulic fracturing and there have been various other proposals to regulate hydraulic fracturing at the federal level. Any new federal regulations that may be imposedFurther, there have been proposals and positions taken by candidates for elected office and others regarding additional restrictions on, or the complete prohibition of, hydraulic fracturing could result in additional permitting and disclosure requirements, additional operating and compliance costs and additional operating restrictions. Moreover, some state and local governments have imposed or have considered imposing various conditions and restrictions on drilling and completion operations.

Any such federal or state requirements, restrictions, conditions or conditionsprohibition could lead to operational delays and increased operating and compliance costs and, moreover,further, 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. Accordingly, our production of crude oil and natural gas could be materially and adversely affected. For additional discussion regarding climate change regulation and hydraulic fracturing regulation, see Climate Change - United StatesRegulation of Hydraulic Fracturing and Hydraulic FracturingOther Operations - United States under ITEM 1, Business - Regulation.

We will continue to monitor and assess any proposed or new policies, legislation, regulations and treaties in the areas where we operate to determine the impact on our operations and take appropriate actions, where necessary. We are unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect our business, results of operations and financial condition. For related discussion, seeSee also the risk factor below regarding the provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act with respect to regulation of derivatives transactions and entities (such as EOG) that participate in such transactions.

In addition, fromFrom time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws includingapplicable to crude oil and natural gas exploration and production companies, such as with respect to the elimination of the immediate deduction for intangible drilling and development costs.costs deduction and bonus tax depreciation. While these specific changes arewere not included in the TCJA,Tax Cuts and Jobs Act signed into law in December 2017, no accurate prediction can be made as to whether any such legislative changes or similar or other tax law changes will be proposed or enacted in the future or,and, if enacted, what the specific provisions or the effective date of any such legislation would be. The elimination of certain U.S. federal income tax deductions, as well as any other changes to, or the imposition of new, federal, state, local or non-U.S. taxes (including the imposition of, or increases in, production, severance or similar taxes), could materially and adversely affect our cash flows, results of operations and financial condition.

A portion of our crude oil, NGLs and natural gas production may be interrupted, or shut in, from time to time for various reasons, including, but not limited to, as a result of accidents, weather conditions, the unavailability of gathering, processing, compression, storage, transportation, refining or refiningexport facilities or equipment or field labor issues, or intentionally as a result of market conditions such as crude oil, NGLs or natural gas prices that we deem uneconomic. If a substantial amount of our production is interrupted or shut in, our cash flows and, in turn, our financial condition and results of operations could be materially and adversely affected.

Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. In addition, a third-party operator could also decide to shut-in or curtail production from wells, or plug and abandon marginal wells, on properties owned by that operator during periods of lower crude oil, NGLs or natural gas prices. These limitations and our dependence on the operator and third-party working interest owners for these projects could cause us to incur unexpected future costs, lower production and materially and adversely affect our financial condition and results of operations.

From time to time, we seek to acquire crude oil and natural gas properties - for example, our October 2016 mergers and related asset purchase transactions with Yates Petroleum Corporation and certain of its affiliated entities. Although we perform reviews of properties to be acquired in a manner that we believe is duly diligent and consistent with industry practices, reviews of records and properties may not necessarily reveal existing or potential problems (such as title or environmental issues), nor may they permit us to become sufficiently familiar with the properties in order to assess fully their deficiencies and potential. Even when problems with a property are identified, we often may assume environmental and other risks and liabilities in connection with acquired properties pursuant to the acquisition agreements.

In addition, there are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves (as discussed further below), actual future production rates and associated costs with respect to acquired properties. Actual reserves, production rates and costs may vary substantially from those assumed in our estimates. In addition, an acquisition may have a material and adverse effect on our business and results of operations, particularly during the periods in which the operations of the acquired properties are being integrated into our ongoing operations or if we are unable to effectively integrate the acquired properties into our ongoing operations.

We make, and will continue to make, substantial capital expenditures for the acquisition, exploration, development, production and transportation of crude oil, NGLs and natural gas reserves. We intend to finance our capital expenditures primarily through our cash flows from operations, commercial paper borrowings and sales of non-core assets and borrowings under other uncommitted credit facilities and, to a lesser extent and if and as necessary, bank borrowings, borrowings under our revolving credit facility and public and private equity and debt offerings.

Lower crude oil, NGLs and natural gas prices, however, reduce our cash flows and could also delay or impair our ability to consummate certain planned non-core asset sales and divestitures. Further, if the condition of the credit and capital markets materially declines, we might not be able to obtain financing on terms we consider acceptable, if at all. In addition, weakness and/or volatility in domestic and global financial markets or economic conditions andor a depressed commodity price environment may increase the interest rates that lenders and commercial paper investors require us to pay andor adversely affect our ability to finance our capital expenditures through equity or debt offerings or other borrowings. A

Similarly, a reduction in our cash flows (for example, as a result of lower crude oil, NGLs and natural gas prices or unanticipated well shut-ins) and the corresponding adverse effect on our financial condition and results of operations may also increase the interest rates that lenders and commercial paper investors require us to pay. In addition, aA substantial increase in interest rates would decrease our net cash flows available for reinvestment. Any of these factors could have a material and adverse effect on our business, financial condition and results of operations.

We have various customers for the crude oil, natural gas and related commodities that we produce as well as various other contractual counterparties, including several financial institutions and affiliates of financial institutions. Domestic and global economic conditions, including the financial condition of financial institutions generally, may adversely affect the ability of our customers and other contractual counterparties to pay amounts owed to us from time to time and to otherwise satisfy their contractual obligations to us, as well as their ability to access the credit and capital markets for such purposes.

Moreover, our customers and other contractual counterparties may be unable to satisfy their contractual obligations to us for reasons unrelated to these conditions and factors, such as the unavailability of required facilities or equipment due to mechanical failure or market conditions. Furthermore, if a customer is unable to satisfy its contractual obligation to purchase crude oil, natural gas or related commodities from us, we may be unable to sell such production to another customer on terms we consider acceptable, if at all, due to the geographic location of such production,production; the availability, proximity orand capacity of appropriate gathering, processing, compression, storage, transportation and transportation facilitiesrefining facilities; or market or other factors and conditions.

The inability of our customers and other contractual counterparties to pay amounts owed to us and to otherwise satisfy their contractual obligations to us may materially and adversely affect our business, financial condition, results of operations and cash flows.

We compete 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) necessary to explore for, develop, produce, market and transport crude oil and natural gas. In addition, certainCertain of our competitors have financial and other resources substantially greater than those we possess and have established strategic long-term positions andor strong governmental relationships in countries or areas in which we may seek new or expanded entry. As a consequence, we 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, our 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. We also face competition, to a lesser extent, from competing energy sources, such as alternative energy sources.

Estimating quantities of crude oil, NGLNGLs and natural gas reserves and future net cash flows from such reserves is a complex, inexact process. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors, made by our management and our independent petroleum consultants. Any significant inaccuracies in these interpretations or assumptions could cause the reported quantities of our reserves and future net cash flows from such reserves to be overstated or understated. Also, the data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions.conditions and improvements and other changes in geological, geophysical and engineering evaluation methods.

To prepare estimates of our economically recoverable crude oil, NGLNGLs and natural gas reserves and future net cash flows from our reserves, we analyze many variable factors, such as historical production from the area compared with production rates from other producing areas. We also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also involves economic assumptions relating to commodity prices, production costs, gathering, processing, compression, storage and transportation costs, severance, ad valorem and other applicable taxes, capital expenditures and workover and remedial costs, many of which factors are or may be beyond our control. Our actual reserves and future net cash flows from such reserves most likely will vary from our estimates. Any significant variance, including any significant revisions or "write-downs" to our existing reserve estimates, could materially and adversely affect our business, financial condition and results of operations and, in turn, the trading price of our common stock. For related discussion, see ITEM 2, Properties - Oil and Gas Exploration and Production - Properties and Reserves and Supplemental Information to Consolidated Financial Statements.

Demand for crude oil and natural gas is, to a significant degree, dependent on weather and climate, which impacts, among other things, the price we receive for the commodities we produce and, in turn, our cash flows and results of operations. For example, relatively warm temperatures during a winter season generally result in relatively lower demand for natural gas (as less natural gas is used to heat residences and businesses) and, as a result, lower prices for natural gas production.production during that season.

In addition, there has been public discussion that climate change may be associated with more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, which could affect some, or all, of our operations. Our exploration, exploitation and development activities and equipment cancould be adversely affected by extreme weather conditions,events, such as winter storms, flooding and tropical storms and hurricanes in the Gulf of Mexico, which may cause a loss of production from temporary cessation of activity or damaged facilities and equipment. Such extreme weather conditionsevents could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs, the installation and operation of gathering, processing, compression, andstorage, transportation and/or export facilities and the availability of, and our access to, necessary third-party services, such as gathering, processing, compression, storage and transportation services and export services. Such extreme weather conditionsevents and changes in weather patterns may materially and adversely affect our business and, in turn, our financial condition and results of operations.

We use derivative instruments (primarily financial basis swap, price swap, option, swaption collar and basis swapcollar contracts) to hedge the impact of fluctuations in crude oil, NGLs and natural gas prices on our results of operations and cash flows. To the extent that we engage in hedging activities to protect ourselves against commodity price declines, we may be prevented from fully realizing the benefits of increases in crude oil, NGLs and natural gas prices above the prices established by our hedging contracts. At February 20, 2018, our forecasted crude oil production for 2018 is approximately 34% hedged at approximately $60.04 per barrel (excluding basis swap contracts) and our forecasted natural gas production for 2018 is approximately 12% hedged at approximately $2.96 per million British thermal units (excluding call option contracts). As a result, aA portion of our forecasted production for 2018 remains unhedged and2020 is subject to fluctuating market prices. If we are ultimately unable to hedge additional production volumes for 20182020 and beyond, we will be impacted by furtherany declines in commodity price declines,prices, which may result in lower net cash provided by operating activities. In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts.

As discussed in the risk factor immediately above, we use derivative instruments to hedge the impact of fluctuations in crude oil, NGLs and natural gas prices on our results of operations and cash flows. In 2010, Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which, among other matters, provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission (CFTC), the U.S. Securities and Exchange Commission (SEC) and certain federal agencies that regulate the banking and insurance sectors (the Prudential Regulators) adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain categories of swaps and may result in certain market participants needing to curtail their derivatives activities. Although some of the rules necessary to implement the Dodd-Frank Act are yet to be adopted, the CFTC, the SEC and the Prudential Regulators have issued numerous rules, including a rule establishing an "end-user" exception to mandatory clearing (End-User Exception), a rule regarding margin for uncleared swaps (Margin Rule) and a proposed rule imposing position limits (Position Limits Rule).

We qualify as a "non-financial entity" for purposes of the End-User Exception and, as such, we are eligible for and expect to utilize, such exception. As a result, our hedging activities willare not be subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing. We also qualify as a "non-financial end user" for purposes of the Margin Rule; therefore, our uncleared swaps are not subject to regulatory margin requirements. Finally, we believe our hedging activities would constitute bona fide hedging under the Position Limits Rule and would not be subject to limitation under such rule if it is enacted. However, many of our hedge counterparties and many other market participants mayare not be eligible for the End-User Exception, may beare subject to mandatory clearing orand the Margin Rule for swaps with some or all of their other swap counterparties, and/orand may be subject to the Position Limits Rule. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations related to derivatives (collectively, Foreign Regulations) which may apply to our transactions with counterparties subject to such Foreign Regulations.

The Dodd-Frank Act, the rules adopted thereunder and the Foreign Regulations could increase the cost of derivative contracts, alter the terms of derivative contracts, reduce the availability of derivatives to protect against the price risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, lessen the number of available counterparties and, in turn, increase our exposure to less creditworthy counterparties. If our use of derivatives is reduced as a result of the Dodd-Frank Act, related regulations or the Foreign Regulations, our results of operations may become more volatile, and our cash flows may be less predictable, which could adversely affect our ability to plan for, and fund, our capital expenditure requirements. Any of these consequences could have a material and adverse effect on our business, financial condition and results of operations.

Our business and prospects for future success, including the successful implementation of our strategies and handling of issues integral to our future success, depend to a significant extent upon the continued service and performance of our management team. The loss of any member of our management team, and our inability to attract, motivate and retain substitute management personnel with comparable experience and skills, could materially and adversely affect our business, financial condition and results of operations.

Our operations in jurisdictions outside the U.S. are subject to various risks inherent in foreign operations. These risks include, among other risks:

Our international operations may also be adversely affected by U.S. laws and policies affecting foreign trade and taxation, including tariffs or trade or other economic sanctions and modifications to, or withdrawal from, international trade treaties. The realization of any of these factors could materially and adversely affect our business, financial condition and results of operations.

The reporting currency for our financial statements is the U.S. dollar. However, certain of our subsidiaries are located in countries other than the U.S. and have functional currencies other than the U.S. dollar. The assets, liabilities, revenues and expenses of certain of these foreign subsidiaries are denominated in currencies other than the U.S. dollar. To prepare our consolidated financial statements, we must translate those assets, liabilities, revenues and expenses into U.S. dollars at then-applicable exchange rates. Consequently, increases and decreases in the value of the U.S. dollar versus other currencies will affect the amount of these items in our consolidated financial statements, even if the amount has not changed in the original currency. These translations could result in changes to our results of operations from period to period. For the fiscal year ended December 31, 2017,2019, less than 1% of our net operating revenues related to operations of our foreign subsidiaries whose functional currency was not the U.S. dollar.

Terrorist attacks and the threat of terrorist attacks (including cyber-related attacks), whether domestic or foreign, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. The U.S. government has at times issued public warnings that indicate that energyenergy-related assets, such as transportation and refining facilities, might be specific targets of terrorist organizations.

Any such actions and the threat of such actions, including any resulting political instability or society disruption, could materially and adversely affect us in unpredictable ways, including, but not limited to, the disruption of energy supplies and markets, the reduction of overall demand for crude oil and natural gas, increased volatility in crude oil and natural gas prices or the possibility that the facilities and other infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affect our business, financial condition and results of operations.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in "Supplemental Information to Consolidated Financial Statements" represent only estimates. Reserve engineering is a complex subjective process of estimating underground accumulations of crude oil and condensate, NGLs and natural gas that cannot be measured in an exact manner.  The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment.  As a result, estimates by different engineers normally vary.  In addition, results of drilling, testing and production or fluctuations in commodity prices subsequent to the date of an estimate may justify revision of such estimate (upward or downward).  Accordingly, reserve estimates are often different from the quantities ultimately recovered.  TheFurther, the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based.  For related discussion, see ITEM 1A, Risk Factors, and "Supplemental Information to Consolidated Financial Statements."

In general, the rate of production from crude oil and natural gas properties declines as reserves are produced.  Except to the extent EOG acquires additional properties containing proved reserves, conducts successful exploration, exploitation and development activities or, through engineering studies, identifies additional behind-pipe zones or secondary recovery reserves, the proved reserves of EOG will decline as reserves are produced.  The volumes to be generated from future activities of EOG are therefore highly dependent upon the level of success in finding or acquiring additional reserves.  For related discussion, see ITEM 1A, Risk Factors. EOG's estimates of reserves filed with other federal agencies are consistent with the information set forth in "Supplemental Information to Consolidated Financial Statements."

Most of our undeveloped oil and gas leases, particularly in the United States, are subject to lease expiration if initial wells are not drilled within a specified period, generally between three and five years. Approximately 0.20.4 million net acres will expire in 2018,2020, 0.3 million net acres will expire in 20192021 and 0.40.1 million net acres will expire in 20202022 if production is not established or we take no other action to extend the terms of the leases or obtain concessions. In the ordinary course of business, based on our evaluations of certain geologic trends and prospective economics, we have allowed certain lease acreage to expire and may allow additional acreage to expire in the future. As of December 31, 2017,2019, there were no proved undeveloped reserves associated with such undeveloped acreage.

EOG participated in the drilling of wells that were in the process of being drilled or completed at the end of the period as set out in the table below for the years ended December 31, 2017, 20162019, 2018 and 2015:2017:

Included in the previous table of wells in progress at the end of the period were wells which had been drilled, but were not completed (DUCs). The following table sets forth EOG's DUCs, for which proved undeveloped reserves had been booked, as of the end of each period.