Edgar Filing: EOG RESOURCES INC

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)


ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2018


o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 1-9743

EOG RESOURCES, INC.

(Exact name of registrant as specified in its charter)



Delaware		47-0684736
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1111 Bagby, Sky Lobby 2, Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: 713-651-7000

Securities registered pursuant to Section 12(b) of the Act:



Title of each class		Name of each exchange on which registered
Common Stock, par value $0.01 per share		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ý No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer ý Accelerated filer o Non-accelerated filer o

Smaller reporting company o Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter. Common Stock aggregate market value held by non-affiliates as of June 30, 2018: $71,861 million.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. Class: Common Stock, par value $0.01 per share, 580,053,225 shares outstanding as of February 15, 2019.

Documents incorporated by reference. Portions of the Definitive Proxy Statement for the registrant's 2019 Annual Meeting of Stockholders, to be filed within 120 days after December 31, 2018, are incorporated by reference into Part III of this report.

TABLE OF CONTENTS



		Page
PART I

ITEM 1.	Business	1
	General	1
	Exploration and Production	1
	Marketing	5
	Wellhead Volumes and Prices	6
	Competition	7
	Regulation	7
	Other Matters	11
	Executive Officers of the Registrant	12
ITEM 1A.	Risk Factors	13
ITEM 1B.	Unresolved Staff Comments	22
ITEM 2.	Properties	22
	Oil and Gas Exploration and Production - Properties and Reserves	22
ITEM 3.	Legal Proceedings	26
ITEM 4.	Mine Safety Disclosures	26

PART II

ITEM 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	26
ITEM 6.	Selected Financial Data	28
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	29
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	47
ITEM 8.	Financial Statements and Supplementary Data	47
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	47
ITEM 9A.	Controls and Procedures	47
ITEM 9B.	Other Information	48

PART III

ITEM 10.	Directors, Executive Officers and Corporate Governance	48
ITEM 11.	Executive Compensation	48
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	49
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	50
ITEM 14.	Principal Accounting Fees and Services	50

PART IV

ITEM 15.	Exhibits, Financial Statement Schedules	51

ITEM 16.	Form 10-K Summary	51

SIGNATURES

(i)

PART I

ITEM 1. Business

General

EOG Resources, Inc., a Delaware corporation organized in 1985, together with its subsidiaries (collectively, EOG), explores for, develops, produces and markets crude oil and natural gas primarily in major producing basins in the United States of America (United States or U.S.), 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.

Exploration and Production

United States Operations

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.

Operations Outside the United States

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.

Marketing

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.

Wellhead Volumes and Prices

The following table sets forth certain information regarding EOG's wellhead volumes of, and average prices for, crude oil and condensate, NGLs and natural gas. The table also presents crude oil equivalent volumes which are determined using 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.

Competition

EOG competes with major integrated oil and gas companies, government-affiliated oil and gas companies and other independent oil and gas companies for the acquisition of licenses and leases, properties and reserves and access to the facilities, equipment, materials, services, and employees and other contract personnel (including geologists, geophysicists, engineers and other specialists) required to explore for, develop, produce, market and transport crude oil and natural gas. In addition, 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.

Regulation

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

Other Matters

Energy Prices. EOG is a crude oil and natural gas producer and is impacted by changes in prices of crude oil and condensate, NGLs and natural gas. 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.

Executive Officers of the Registrant

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.

ITEM 1A. Risk Factors

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.

Crude oil, natural gas and NGL prices are volatile, and a substantial and extended decline in commodity prices can have a material and adverse effect on us.

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:


•	domestic and worldwide supplies of crude oil, NGLs and natural gas;


•	domestic and international drilling activity;


•	the actions of other crude oil producing and exporting nations, including the Organization of Petroleum Exporting Countries;


•	consumer and industrial/commercial demand for crude oil, natural gas and NGLs;


•	worldwide economic conditions, geopolitical factors and political conditions, including, but not limited to, the imposition of tariffs or trade or other economic sanctions, political instability or armed conflict in oil and gas producing regions;


•	the availability, proximity and capacity of appropriate transportation, gathering, processing, compression, storage and refining facilities;


•	the price and availability of, and demand for, competing energy sources, including alternative energy sources;


•	the effect of worldwide energy conservation measures, alternative fuel requirements and climate change-related initiatives;


•	the nature and extent of governmental regulation, including environmental and other climate change-related regulation, regulation of derivatives transactions and hedging activities, tax laws and regulations and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;


•	the level and effect of trading in commodity futures markets, including trading by commodity price speculators and others; and


•	weather conditions and changes in weather patterns.

Beginning in the fourth quarter of 2014 and continuing through 2016, crude oil prices substantially declined. In addition, natural gas and NGL prices began to decline substantially in the second quarter of 2014 and such lower prices continued through 2016. While crude oil, natural gas and NGL prices improved significantly during 2017 and 2018, the above-described factors and the volatility of commodity prices make it difficult to predict future crude oil, natural gas and NGL prices. For example, during the fourth quarter of 2018, there was a substantial decline in the prices for crude oil and NGLs, whereas natural gas prices increased significantly during such period. As a result, there can be no assurance that the prices for crude oil, natural gas and/or NGLs will sustain, or increase from, their current levels and not decline.

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, the 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 portion of our exploration, development and exploitation projects, resulting in our having to make downward adjustments to our estimated proved reserves. 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.

In fact, the substantial declines in crude oil, natural gas, and NGL prices that began in 2014 and continued in 2015 and through 2016 materially and adversely affected the amount of cash flows we had available for our capital expenditures and other operating expenses and our results of operations during fiscal years 2015 and 2016. Such declines also adversely affected 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 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 is a high-risk activity and subjects us to a variety of risks that we cannot control.

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:


•	unexpected drilling conditions;


•	title problems;


•	pressure or irregularities in formations;


•	equipment failures or accidents;


•	adverse weather conditions, such as winter storms, flooding, tropical storms and hurricanes, and changes in weather patterns;

•

compliance with, or changes in, environmental, health and safety laws and regulations relating to air emissions, hydraulic fracturing, access to and use of water, disposal or other discharge (e.g., into injection wells) of produced water, drilling fluids and other wastes, laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas, and other laws and regulations, such as tax laws and regulations;


•	the availability and timely issuance of required federal, state, tribal and other permits and licenses, which may be affected by (among other things) government shutdowns or other suspensions of, or delays in, government services;


•	the availability of, costs associated with and terms of contractual arrangements for properties, including mineral licenses and leases, pipelines, crude oil hauling trucks and qualified drivers and facilities and equipment to gather, process, compress, store, transport and market crude oil, natural gas and related commodities; and


•	the costs of, or shortages or delays in the availability of, drilling rigs, hydraulic fracturing services, pressure pumping equipment and supplies, tubular materials, water, sand, disposal facilities, qualified personnel and other necessary facilities, equipment, materials, supplies and services.

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 and natural gas operations and supporting activities and operations involve many risks and expose us to potential losses and liabilities, and insurance may not fully protect us against these risks and potential losses and liabilities.

Our crude oil 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:


•	well blowouts and cratering;


•	loss of well control;


•	crude oil spills, natural gas leaks, formation water (i.e., produced water) spills and pipeline ruptures;


•	pipe failures and casing collapses;


•	uncontrollable flows of crude oil, natural gas, formation water or drilling fluids;


•	releases of chemicals, wastes or pollutants;


•	adverse weather events, such as winter storms, flooding, tropical storms and hurricanes, and other natural disasters;


•	fires and explosions;


•	terrorism, vandalism and physical, electronic and cybersecurity breaches;


•	formations with abnormal or unexpected pressures;


•	leaks or spills in connection with, or associated with, the gathering, processing, compression, storage and transportation of crude oil and natural gas; and


•	malfunctions of, or damage to, gathering, processing, compression and transportation facilities and equipment and other facilities and equipment utilized in support of our crude oil and natural gas operations.

If any of these events occur, we could incur losses, liabilities and other additional costs as a result of:


•	injury or loss of life;


•	damage to, or destruction of, property, facilities, equipment and crude oil and natural gas reservoirs;


•	pollution or other environmental damage;


•	regulatory investigations and penalties as well as cleanup and remediation responsibilities and costs;


•	suspension or interruption of our operations, including due to injunction;


•	repairs necessary to resume operations; and


•	compliance with laws and regulations enacted as a result of such events.

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. However, 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.

Our ability to sell and deliver our crude oil and natural gas production could be materially and adversely affected if adequate gathering, processing, compression, storage and transportation facilities and equipment are unavailable.

The sale of our crude oil 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 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 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.

If we fail to acquire or find sufficient additional reserves over time, our reserves and production will decline from their current levels.

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.

We incur certain costs to comply with government regulations, particularly regulations relating to environmental protection and safety, and could incur even greater costs in the future.

Our crude oil 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.

Local, state, federal and international regulatory bodies have been increasingly focused on greenhouse gas (GHG) emissions and climate change issues in recent years. For example, we are subject to the United States (U.S.) Environmental Protection Agency's (U.S. EPA) rule requiring annual reporting of GHG emissions. In addition, in May 2016, the U.S. EPA issued regulations that require operators to reduce methane emissions and emissions of volatile organic compounds 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.

It is possible that the Paris Agreement and subsequent domestic and international regulations will have adverse effects on the market for crude oil, natural gas and other fossil fuel products as well as adverse effects on the business and operations of companies engaged in the exploration for, and production of, crude oil, natural gas and other fossil fuel products. 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.

The regulation of hydraulic fracturing is primarily conducted at the state and local level through permitting and other compliance requirements. 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 September 2018, the BLM issued a final rule rescinding certain requirements of the rule). In addition, the 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 imposed on 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 or 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. 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 States and Hydraulic Fracturing - 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, see 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.

Tax laws and regulations applicable to crude oil and natural gas exploration and production companies may change over time, and such changes could materially and adversely affect our cash flows, results of operations and financial condition.

From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal income tax laws applicable to crude oil and natural gas exploration and production companies, such as with respect to the intangible drilling and development costs deduction and bonus tax depreciation. While these specific changes were not included in the 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 in the future 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 and natural gas production may be subject to interruptions that could have a material and adverse effect on us.

A portion of our crude oil 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 or refining facilities or equipment or field labor issues, or intentionally as a result of market conditions such as crude oil 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.

We have limited control over the activities on properties we do not operate.

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 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.

If we acquire crude oil and natural gas properties, our failure to fully identify existing and potential problems, to accurately estimate reserves, production rates or costs, or to effectively integrate the acquired properties into our operations could materially and adversely affect our business, 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 have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms, if at all.

We make, and will continue to make, substantial capital expenditures for the acquisition, exploration, development, production and transportation of crude oil and natural gas reserves. We intend to finance our capital expenditures primarily through our cash flows from operations, commercial paper borrowings, 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 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 or a depressed commodity price environment may increase the interest rates that lenders and commercial paper investors require us to pay or adversely affect our ability to finance our capital expenditures through equity or debt offerings or other borrowings.

Similarly, a reduction in our cash flows (for example, as a result of lower crude oil 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. A 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.

Further, our ability to obtain financings, our borrowing costs and the terms of any financings are, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. The interrelated factors that may impact our credit ratings include our debt levels; planned asset purchases or sales; near-term and long-term production growth opportunities; liquidity; asset quality; cost structure; product mix; and commodity pricing levels (including, but not limited to, the estimates and assumptions of credit rating agencies with respect to future commodity prices). We cannot provide any assurance that our current credit ratings will remain in effect for any given period of time or that our credit ratings will be raised in the future, nor can we provide any assurance that any of our credit ratings will not be lowered.

The inability of our customers and other contractual counterparties to satisfy their obligations to us may have a material and adverse effect on us.

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; the availability, proximity and capacity of appropriate gathering, processing, compression, storage, transportation and refining 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.

Competition in the oil and gas exploration and production industry is intense, and many of our competitors have greater resources than we have.

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, certain of our competitors have financial and other resources substantially greater than those we possess and have established strategic long-term positions or 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.

Reserve estimates depend on many interpretations and assumptions that may turn out to be inaccurate. Any significant inaccuracies in these interpretations and assumptions could cause the reported quantities of our reserves to be materially misstated.

Estimating quantities of crude oil, NGL 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, continual reassessment of the viability of production under varying economic conditions and improvements and other changes in geological, geophysical and engineering evaluation methods.

To prepare estimates of our economically recoverable crude oil, NGL 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.

Weather and climate may have a significant and adverse impact on us.

Demand for crude oil and natural gas is, to a 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.

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 could be adversely affected by extreme weather 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 events 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, storage and transportation facilities and the availability of, and our access to, necessary third-party services, such as gathering, processing, compression, storage and transportation services. Such extreme weather events and changes in weather patterns may materially and adversely affect our business and, in turn, our financial condition and results of operations.

Our hedging activities may prevent us from benefiting fully from increases in crude oil and natural gas prices and may expose us to other risks, including counterparty risk.

We use derivative instruments (primarily financial basis swap, price swap, option, swaption and collar contracts) to hedge the impact of fluctuations in crude oil 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 and natural gas prices above the prices established by our hedging contracts. At February 19, 2019, our forecasted crude oil production (excluding basis swap contracts) for 2019 and our forecasted natural gas production for 2019 were not hedged. As a result, our forecasted production for 2019 is subject to fluctuating market prices. If we do not hedge additional production volumes for 2019 and beyond, we will be impacted by commodity price declines, 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.

Federal legislation and related regulations regarding derivatives transactions could have a material and adverse impact on our hedging activities.

As discussed in the risk factor immediately above, we use derivative instruments to hedge the impact of fluctuations in crude oil 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 will 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 may not be eligible for the End-User Exception, may be subject to mandatory clearing or the Margin Rule for swaps with some or all of their other swap counterparties, and/or 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, and 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 depend to a significant extent upon the continued service and performance of our management team.

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.

We operate in other countries and, as a result, are subject to certain political, economic and other risks.

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


•	increases in taxes and governmental royalties;


•	changes in laws and policies governing operations of foreign-based companies;


•	loss of revenue, loss of or damage to equipment, property and other assets and interruption of operations as a result of expropriation, nationalization, acts of terrorism, war, civil unrest and other political risks;


•	unilateral or forced renegotiation, modification or nullification of existing contracts with governmental entities;


•	difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations; and


•	currency restrictions or exchange rate fluctuations.

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.

Unfavorable currency exchange rate fluctuations could adversely affect our 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, 2018, less than 1% of our net operating revenues related to operations of our foreign subsidiaries whose functional currency was not the U.S. dollar.

Our business could be adversely affected by security threats, including cybersecurity threats.

We face various security threats, including cybersecurity threats to gain unauthorized access to our sensitive information or to render our information or systems unusable, and threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as gathering and processing facilities, refineries, rail facilities and pipelines. The potential for such security threats subjects our operations to increased risks that could have a material adverse effect on our business, financial condition and results of operations. For example, unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruptions, or other disruptions to our operations.

Our implementation of various procedures and controls to monitor and mitigate such security threats and to increase security for our information, systems, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of, or damage to, sensitive information or facilities, infrastructure and systems essential to our business and operations, as well as data corruption, reputational damage,communication interruptions or other disruptions to our operations, which, in turn, could have a material adverse effect on our business, financial position and results of operations.

Terrorist activities and military and other actions could materially and adversely affect us.

Terrorist attacks and the threat of terrorist 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 energy assets might be specific targets of terrorist organizations. Any such actions and the threat of such actions could materially and adversely affect us in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in crude oil and natural gas prices or the possibility that the 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.

ITEM 1B. Unresolved Staff Comments

Not applicable.

ITEM 2. Properties

Oil and Gas Exploration and Production - Properties and Reserves

Reserve Information. For estimates and discussions of EOG's net proved reserves of crude oil and condensate, natural gas liquids (NGLs) and natural gas, the qualifications of the preparers of EOG's reserve estimates, EOG's independent petroleum consultants and EOG's processes and controls with respect to its reserve estimates, see "Supplemental Information to Consolidated Financial Statements."

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. Further, 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."

Acreage. The following table summarizes EOG's gross and net developed and undeveloped acreage at December 31, 2018. Excluded is acreage in which EOG's interest is limited to owned royalty, overriding royalty and other similar interests.



	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net

United States	2,618,624	1,884,489	3,280,867	2,409,792	5,899,491	4,294,281
Trinidad	79,277	67,474	201,435	115,274	280,712	182,748
China	130,548	130,548	—	—	130,548	130,548
Canada	40,000	35,771	105,560	98,436	145,560	134,207
Total	2,868,449	2,118,282	3,587,862	2,623,502	6,456,311	4,741,784

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 0.3 million net acres will expire in 2019, 0.5 million net acres will expire in 2020 and 0.3 million net acres will expire in 2021 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, 2018, there were no proved undeveloped reserves associated with such undeveloped acreage.

Productive Well Summary. The following table represents EOG's gross and net productive wells, including 2,107 wells in which we hold a royalty interest.



	Crude Oil		Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net

United States	9,023	6,422	6,360	3,658	15,383	10,080
Trinidad	2	2	33	27	35	29
China	—	—	36	36	36	36
Canada	—	—	24	23	24	23
Total ⁽¹⁾	9,025	6,424	6,453	3,744	15,478	10,168


(1)	EOG operated 11,366 gross and 9,744 net producing crude oil and natural gas wells at December 31, 2018. Gross crude oil and natural gas wells include 316 wells with multiple completions.

Drilling and Acquisition Activities. During the years ended December 31, 2018, 2017 and 2016, EOG expended $6.4 billion, $4.4 billion and $6.4 billion, respectively, for exploratory and development drilling, facilities and acquisition of leases and producing properties, including asset retirement obligations of $70 million, $56 million and $(20) million, respectively. Included in the 2016 expenditures was $3.9 billion of acquisitions of producing properties and leases in connection with the 2016 merger and related asset purchase transactions with Yates Petroleum Corporation and other affiliated entities. The following tables set forth the results of the gross crude oil and natural gas wells completed for the years ended December 31, 2018, 2017 and 2016:



	Gross Development Wells Completed				Gross Exploratory Wells Completed
	Crude Oil	Natural Gas	Dry Hole	Total	Crude Oil	Natural Gas	Dry Hole	Total
2018
United States	834	39	22	895	—	—	1	1
Trinidad	—	—	—	—	—	—	—	—
China	—	1	—	1	—	2	—	2
Total	834	40	22	896	—	2	1	3
2017
United States	568	22	13	603	—	—	1	1
Trinidad	—	8	—	8	—	1	—	1
China	—	3	—	3	—	—	1	1
Total	568	33	13	614	—	1	2	3
2016
United States	524	39	6	569	1	—	—	1
Trinidad	—	1	—	1	—	—	—	—
Total	524	40	6	570	1	—	—	1

The following tables set forth the results of the net crude oil and natural gas wells completed for the years ended December 31, 2018, 2017 and 2016:



	Net Development Wells Completed				Net Exploratory Wells Completed
	Crude Oil	Natural Gas	Dry Hole	Total	Crude Oil	Natural Gas	Dry Hole	Total
2018
United States	704	37	18	759	—	—	1	1
Trinidad	—	—	—	—	—	—	—	—
China	—	1	—	1	—	2	—	2
Total	704	38	18	760	—	2	1	3
2017
United States	490	21	13	524	—	—	1	1
Trinidad	—	6	—	6	—	1	—	1
China	—	3	—	3	—	—	1	1
Total	490	30	13	533	—	1	2	3
2016
United States	420	17	6	443	1	—	—	1
Trinidad	—	1	—	1	—	—	—	—
Total	420	18	6	444	1	—	—	1

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, 2018, 2017 and 2016:



	Wells in Progress at End of Period
	2018		2017		2016
	Gross	Net	Gross	Net	Gross	Net

United States	297	238	247	208	237	194
Trinidad	—	—	—	—	1	1
China	4	4	1	1	—	—
Total	301	242	248	209	238	195

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). In order to effectively manage its capital expenditures and to provide flexibility in managing its drilling rig and well completion schedules, EOG, from time to time, will have an inventory of DUCs. At December 31, 2018, there were approximately 78 MMBoe of net proved undeveloped reserves (PUDs) associated with EOG's inventory of DUCs. Under EOG's current drilling plan, all such DUCs are expected to be completed within five years from the original booking date of such reserves. The following table sets forth EOG's DUCs, for which PUDs had been booked, as of the end of each period.



	Drilled Uncompleted Wells at End of Period
	2018		2017		2016
	Gross	Net	Gross	Net	Gross	Net

United States	168	137	147	121	173	137
China	3	3	1	1	—	—
Total	171	140	148	122	173	137

EOG acquired wells as set forth in the following tables as of the end of each period (excluding the acquisition of additional interests in 114, 29 and 63 net wells in which EOG previously owned an interest for the years ended December 31, 2018, 2017 and 2016, respectively):



	Gross Acquired Wells			Net Acquired Wells
	Crude Oil	Natural Gas	Total	Crude Oil	Natural Gas	Total
2018
United States	15	13	28	10	6	16
Total	15	13	28	10	6	16
2017
United States	12	3	15	6	2	8
Total	12	3	15	6	2	8
2016
United States	4,112	4,144	8,256	1,228	2,297	3,525
Total	4,112	4,144	8,256	1,228	2,297	3,525

All of EOG's drilling and completion activities are conducted on a contractual basis with independent drilling contractors and other third-party service contractors. EOG's other property, plant and equipment primarily includes gathering, transportation and processing infrastructure assets, buildings, crude-by-rail assets, and sand mine and sand processing assets which support EOG's exploration and production activities. EOG does not own drilling rigs, hydraulic fracturing equipment or rail cars.

ITEM 3. Legal Proceedings

See the information set forth under the "Contingencies" caption in Note 8 of the Notes to Consolidated Financial Statements, which is incorporated by reference herein.

ITEM 4. Mine Safety Disclosures

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.

PART II

ITEM 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

EOG's common stock is traded on the New York Stock Exchange (NYSE) under the ticker symbol "EOG."

As of February 14, 2019, there were approximately 2,100 record holders and approximately 454,000 beneficial owners of EOG's common stock.

The following table sets forth, for the periods indicated, EOG's share repurchase activity:



Period	(a) Total Number of Shares Purchased ⁽¹⁾	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs ⁽²⁾

October 1, 2018 - October 31, 2018	29,765	$	128.17	—	6,386,200
November 1, 2018 - November 30, 2018	2,062	104.60		—	6,386,200
December 1, 2018 - December 31, 2018	7,415	98.11		—	6,386,200
Total	39,242	$	121.26

(1)

The 39,242 total shares for the quarter ended December 31, 2018, and the 538,892 total shares for the full year 2018, consist solely of shares that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or stock-settled stock appreciation rights or the vesting of restricted stock, restricted stock unit or performance unit grants or (ii) in payment of the exercise price of employee stock options. These shares do not count against the 10 million aggregate share repurchase authorization of EOG's Board discussed below.


(2)	In September 2001, the Board authorized the repurchase of up to 10,000,000 shares of EOG's common stock. During 2018, EOG did not repurchase any shares under the Board-authorized repurchase program.

Comparative Stock Performance

The following performance graph and related information shall not be deemed "soliciting material" or to be "filed" with the United States Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended, except to the extent that EOG specifically requests that such information be treated as "soliciting material" or specifically incorporates such information by reference into such a filing.

The performance graph shown below compares the cumulative five-year total return to stockholders on EOG's common stock as compared to the cumulative five-year total returns on the Standard and Poor's 500 Index (S&P 500) and the Standard and Poor's 500 Oil & Gas Exploration & Production Index (S&P O&G E&P). The comparison was prepared based upon the following assumptions:


1.	$100 was invested on December 31, 2013 in each of the following: common stock of EOG, the S&P 500 and the S&P O&G E&P.


2.	Dividends are reinvested.

Comparison of Five-Year Cumulative Total Returns

EOG, S&P 500 and S&P O&G E&P

(Performance Results Through December 31, 2018)



	2013		2014		2015		2016		2017		2018
EOG	$	100.00	$	110.30	$	85.45	$	123.08	$	132.28	$	107.59
S&P 500	$	100.00	$	113.69	$	115.27	$	129.06	$	157.23	$	150.34
S&P O&G E&P	$	100.00	$	89.41	$	58.88	$	78.21	$	73.28	$	58.99

ITEM 6. Selected Financial Data

(In Thousands, Except Per Share Data)

The following selected consolidated financial information should be read in conjunction with ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations and ITEM 8, Financial Statements and Supplementary Data.



Year Ended December 31	2018		2017		2016			2015			2014

Statement of Income Data:
Operating Revenues and Other ⁽¹⁾	$	17,275,399	$	11,208,320	$	7,650,632		$	8,757,428		$	18,035,340
Operating Income (Loss)	$	4,469,346	$	926,402	$	(1,225,281	)	$	(6,686,079	)	$	5,241,823
Net Income (Loss)	$	3,419,040	$	2,582,579	$	(1,096,686	)	$	(4,524,515	)	$	2,915,487
Net Income (Loss) Per Share
Basic	$	5.93	$	4.49	$	(1.98	)	$	(8.29	)	$	5.36
Diluted	$	5.89	$	4.46	$	(1.98	)	$	(8.29	)	$	5.32
Dividends Per Common Share	$	0.810	$	0.670	$	0.670		$	0.670		$	0.585
Average Number of Common Shares
Basic	576,578		574,620		553,384			545,697			543,443
Diluted	580,441		578,693		553,384			545,697			548,539



At December 31	2018		2017		2016		2015		2014

Balance Sheet Data:
Total Property, Plant and Equipment, Net	$	28,075,519	$	25,665,037	$	25,707,078	$	24,210,721	$	29,172,644
Total Assets ^{(2) (3)}	33,934,474		29,833,078		29,299,201		26,834,908		34,758,599
Total Debt ⁽³⁾	6,083,262		6,387,071		6,986,358		6,655,490		5,905,846
Total Stockholders' Equity	19,364,188		16,283,273		13,981,581		12,943,035		17,712,582

(1)

Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs instead of as a deduction to Natural Gas Revenues. There was no impact to operating income, net income or cash flows resulting from changes to the presentation of natural gas processing fees. EOG elected to adopt ASU 2014-09 using the modified retrospective approach with no reclassification of amounts for the years ended December 31, 2017, 2016, 2015 and 2014 (see Note 1 to Consolidated Financial Statements).

(2)

Effective January 1, 2017, EOG adopted the provisions of ASU 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes" (ASU 2015-17), which simplifies the presentation of deferred taxes in a classified balance sheet by eliminating the requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. Instead, ASU 2015-17 requires that all deferred tax liabilities and assets be shown as noncurrent in a classified balance sheet. In connection with the adoption of ASU 2015-17, EOG restated its Consolidated Balance Sheets at December 31, 2016 and 2015 by $160 million and $136 million, respectively, from deferred tax liabilities to deferred tax assets.

(3)

Effective January 1, 2016, EOG adopted the provisions of ASU 2015-03, "Interest - Computation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" (ASU 2015-03). ASU 2015-03 requires that debt issuance costs be presented in the balance sheet as a direct reduction from the related debt liability rather than as an asset. In connection with the adoption of ASU 2015-03, EOG restated its Consolidated Balance Sheets at December 31, 2015 and 2014 by $4.8 million and $4.1 million, respectively, of unamortized debt issuance costs from Other Assets to Long-Term Debt.

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

Overview

EOG Resources, Inc., together with its subsidiaries (collectively, EOG), is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad and China. EOG operates under a consistent business and operational strategy that focuses predominantly on maximizing the rate of return on investment of capital by controlling operating and capital costs and maximizing reserve recoveries. 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 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.

EOG realized net income of $3,419 million during 2018 as compared to net income of $2,583 million for 2017. At December 31, 2018, EOG's total estimated net proved reserves were 2,928 million barrels of oil equivalent (MMBoe), an increase of 401 MMBoe from December 31, 2017. During 2018, net proved crude oil and condensate and natural gas liquids (NGLs) reserves increased by 330 million barrels (MMBbl), and net proved natural gas reserves increased by 424 billion cubic feet or 71 MMBoe, in each case from December 31, 2017.

Operations

Several important developments have occurred since January 1, 2018.

United States. EOG's efforts to identify plays with large reserve potential have proven to be successful. EOG continues to drill numerous wells in large acreage plays, which in the aggregate have contributed substantially to, and are expected to continue to contribute substantially to, EOG's crude oil and liquids-rich natural gas production. EOG has placed an emphasis on applying its horizontal drilling and completion expertise to unconventional crude oil and liquids-rich reservoirs.

During 2018, EOG continued to focus on increasing drilling, completion and operating efficiencies gained in prior years. In addition, EOG continued to evaluate certain potential crude oil and liquids-rich natural gas exploration and development prospects and to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins, exchanges or tactical acquisitions. On a volumetric basis, as calculated using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGL production accounted for approximately 77% of United States production during 2018 and 2017. During 2018, drilling and completion activities occurred primarily in the Eagle Ford play, Delaware Basin play and Rocky Mountain area. EOG's major producing areas in the United States are in New Mexico, North Dakota, Texas, Utah and Wyoming.

Trinidad. In Trinidad, EOG continued to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium (SECC) Block, Modified U(a) Block, Block 4(a), Modified U(b) Block, the Banyan Field and the Sercan Area have been developed and are producing natural gas which is sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary and crude oil and condensate which is sold to the Petroleum Company of Trinidad and Tobago Limited and its successor, Heritage Petroleum Company Limited. In 2018, EOG conducted an ocean bottom nodal seismic survey in the SECC Block and the Pelican Field and continued to process and review the initial data.

Other International. In the Sichuan Basin, Sichuan Province, China, EOG entered 2018 with two drilled uncompleted wells 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.

In the U.K., EOG produced crude oil from its 100% working interest East Irish Sea Conwy development project. 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.

Capital Structure

One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 24% at December 31, 2018 and 28% at December 31, 2017. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

On October 1, 2018, EOG repaid upon maturity the $350 million aggregate principal amount of its 6.875% Senior Notes due 2018.

During 2018, EOG funded $6.6 billion ($411 million of which was non-cash) in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), repaid $350 million aggregate principal amount of long-term debt, paid $438 million in dividends to common stockholders and purchased $63 million of treasury stock in connection with stock compensation plans, primarily by utilizing net cash provided from its operating activities and net proceeds of $227 million from the sale of assets.

Total anticipated 2019 capital expenditures are estimated to range from approximately $6.1 billion to $6.5 billion, excluding acquisitions and non-cash exchanges. The majority of 2019 expenditures will be focused on United States crude oil drilling activities. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program and other uncommitted credit facilities, bank borrowings, borrowings under its $2.0 billion senior unsecured revolving credit facility, joint development agreements and similar agreements and equity and debt offerings.

Management continues to believe EOG has one of the strongest prospect inventories in EOG's history. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer incremental exploration and/or production opportunities.

Results of Operations

The following review of operations for each of the three years in the period ended December 31, 2018, should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning on page F-1.

Operating Revenues and Other

During 2018, operating revenues increased $6,067 million, or 54%, to $17,275 million from $11,208 million in 2017. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, increased $4,039 million, or 51%, to $11,946 million in 2018 from $7,907 million in 2017. Revenues from the sales of crude oil and condensate and NGLs in 2018 were approximately 89% of total wellhead revenues compared to 88% in 2017. During 2018, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $166 million compared to net gains of $20 million in 2017. Gathering, processing and marketing revenues increased $1,932 million during 2018, to $5,230 million from $3,298 million in 2017. Net gains on asset dispositions of $175 million in 2018 were primarily as a result of exchanges of producing properties and acreage in Texas and sales of producing properties and acreage in the United Kingdom, Texas and the Rocky Mountain area compared to net losses on asset dispositions of $99 million in 2017.

Wellhead volume and price statistics for the years ended December 31, 2018, 2017 and 2016 were as follows:



Year Ended December 31	2018			2017		2016

Crude Oil and Condensate Volumes (MBbld) ⁽¹⁾
United States	394.8			335.0		278.3
Trinidad	0.8			0.9		0.8
Other International ⁽²⁾	4.3			0.8		3.4
Total	399.9			336.7		282.5
Average Crude Oil and Condensate Prices ($/Bbl) ⁽³⁾
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
Natural Gas Liquids Volumes (MBbld) ⁽¹⁾
United States	116.1			88.4		81.6
Other International ⁽²⁾	—			—		—
Total	116.1			88.4		81.6
Average Natural Gas Liquids Prices ($/Bbl) ⁽³⁾
United States	$	26.60		$	22.61	$	14.63
Other International ⁽²⁾	—			—		—
Composite	26.60			22.61		14.63
Natural Gas Volumes (MMcfd) ⁽¹⁾
United States	923			765		810
Trinidad	266			313		340
Other International ⁽²⁾	30			25		25
Total	1,219			1,103		1,175
Average Natural Gas Prices ($/Mcf) ⁽³⁾
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		(4)	2.29		1.73
Crude Oil Equivalent Volumes (MBoed) ⁽⁵⁾
United States	664.7			551.0		494.9
Trinidad	45.1			53.0		57.5
Other International ⁽²⁾	9.4			4.9		7.6
Total	719.2			608.9		560.0

Total MMBoe ⁽⁵⁾	262.5			222.3		205.0


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


(2)	Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The United Kingdom operations were sold in the fourth quarter of 2018. The Argentina operations were sold in the third quarter of 2016.


(3)	Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to Consolidated Financial Statements).

(4)

(5)

Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

2018 compared to 2017. Wellhead crude oil and condensate revenues in 2018 increased $3,261 million, or 52%, to $9,517 million from $6,256 million in 2017, due primarily to a higher composite average wellhead crude oil and condensate price ($2,088 million) and an increase in production ($1,173 million). EOG's composite wellhead crude oil and condensate price for 2018 increased 28% to $65.21 per barrel compared to $50.91 per barrel in 2017. Wellhead crude oil and condensate production in 2018 increased 19% to 400 MBbld as compared to 337 MBbld in 2017. The increased production was primarily in the Permian Basin and the Eagle Ford.

NGL revenues in 2018 increased $398 million, or 55%, to $1,127 million from $729 million in 2017 primarily due to an increase in production ($229 million) and a higher composite average wellhead NGL price ($169 million). EOG's composite average wellhead NGL price increased 18% to $26.60 per barrel in 2018 compared to $22.61 per barrel in 2017. NGL production in 2018 increased 31% to 116 MBbld as compared to 88 MBbld in 2017. The increased production was primarily in the Permian Basin and the Eagle Ford.

Wellhead natural gas revenues in 2018 increased $380 million, or 41%, to $1,302 million from $922 million in 2017, primarily due to a higher composite wellhead natural gas price ($282 million) and an increase in wellhead natural gas deliveries ($98 million). EOG's composite average wellhead natural gas price increased 28% to $2.92 per Mcf in 2018 compared to $2.29 per Mcf in 2017. This increase in composite wellhead natural gas prices includes a positive revenue adjustment of $0.44 per Mcf related to the adoption of ASU 2014-09. Natural gas deliveries in 2018 increased 11% to 1,219 MMcfd as compared to 1,103 MMcfd in 2017. The increase in production was primarily due to increased production in the United States (158 MMcfd), partially offset by decreased production in Trinidad (47 MMcfd). The increased production in the United States was due primarily to increased production of associated gas in the Permian Basin and Rocky Mountain area and higher volumes in the Marcellus Shale. The decrease in Trinidad was primarily attributable to higher contractual deliveries in 2017.

During 2018, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $166 million, which included net cash paid for settlements of crude oil and natural gas financial derivative contracts of $259 million. During 2017, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $20 million, which included net cash received from settlements of crude oil and natural gas financial derivative contracts of $7 million.

Gathering, processing and marketing revenues are revenues generated from sales of third-party crude oil, NGLs and natural gas, as well as gathering fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. Purchases and sales of third-party crude oil and natural gas may be utilized in order to balance firm transportation capacity with production in certain areas and to utilize excess capacity at EOG-owned facilities. EOG sells sand in order to balance the timing of firm purchase agreements with completion operations and to utilize excess capacity at EOG-owned facilities. Marketing costs represent the costs to purchase third-party crude oil, natural gas and sand and the associated transportation costs, as well as costs associated with EOG-owned sand sold to third parties.

Gathering, processing and marketing revenues less marketing costs in 2018 increased $59 million compared to 2017, primarily due to higher margins on crude oil and condensate marketing activities.

2017 compared to 2016. Wellhead crude oil and condensate revenues in 2017 increased $1,939 million, or 45%, to $6,256 million from $4,317 million in 2016, due primarily to a higher composite average wellhead crude oil and condensate price ($1,124 million) and an increase in production ($815 million). EOG's composite wellhead crude oil and condensate price for 2017 increased 22% to $50.91 per barrel compared to $41.76 per barrel in 2016. Wellhead crude oil and condensate deliveries in 2017 increased 19% to 337 MBbld as compared to 283 MBbld in 2016. The increased production was primarily due to higher production in the Permian Basin and Rocky Mountain area.

NGL revenues in 2017 increased $292 million, or 67%, to $729 million from $437 million in 2016 primarily due to a higher composite wellhead NGL price ($257 million) and an increase in production ($35 million). EOG's composite average wellhead NGL price increased 55% to $22.61 per barrel in 2017 compared to $14.63 per barrel in 2016. The increased production was primarily due to higher production in the Permian Basin and Rocky Mountain area, partially offset by decreased production in the Fort Worth Barnett Shale, largely resulting from 2016 asset sales in this region.

Wellhead natural gas revenues in 2017 increased $180 million, or 24%, to $922 million from $742 million in 2016, primarily due to a higher composite wellhead natural gas price ($227 million), partially offset by a decrease in wellhead natural gas deliveries ($47 million). EOG's composite average wellhead natural gas price increased 32% to $2.29 per Mcf in 2017 compared to $1.73 per Mcf in 2016. Natural gas deliveries in 2017 decreased 6% to 1,103 MMcfd as compared to 1,175 MMcfd in 2016. The decrease in production was primarily due to decreased production in the United States (45 MMcfd) and Trinidad (27 MMcfd). The decreased production in the United States was due primarily to lower volumes in the Fort Worth Barnett Shale, Upper Gulf Coast and South Texas areas, largely resulting from 2016 asset sales in these regions, partially offset by increased production of associated gas in the Permian Basin and Rocky Mountain area and from the 2016 mergers and related asset purchase transactions with Yates Petroleum Corporation and other affiliated entities (collectively, the Yates Entities). The decrease in Trinidad was primarily attributable to higher contractual deliveries in 2016.

During 2017, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $20 million, which included net cash received from settlements of crude oil and natural gas financial derivative contracts of $7 million. During 2016, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $100 million, which included net cash paid for settlements of crude oil and natural gas financial derivative contracts of $22 million.

Gathering, processing and marketing revenues less marketing costs in 2017 increased $9 million compared to 2016, primarily due to higher margins on natural gas and NGL marketing activities ($16 million), partially offset by lower margins on sand sales ($9 million).

Operating and Other Expenses

2018 compared to 2017. During 2018, operating expenses of $12,806 million were $2,524 million higher than the $10,282 million incurred during 2017. The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2018 and 2017:



	2018		2017

Lease and Well	$	4.89	$	4.70
Transportation Costs	2.85		3.33
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties	12.65		14.83
Other Property, Plant and Equipment	0.44		0.51
General and Administrative (G&A)	1.63		1.95
Net Interest Expense	0.93		1.23
Total ⁽¹⁾	$	23.39	$	26.55


(1)	Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and net interest expense for 2018 compared to 2017 are set forth below. See "Operating Revenues and Other" above for a discussion of production volumes.

Lease and well expenses include expenses for EOG-operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property. Lease and well expenses can be divided into the following categories: costs to operate and maintain crude oil and natural gas wells, the cost of workovers and lease and well administrative expenses. Operating and maintenance costs include, among other things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. Workovers are operations to restore or maintain production from existing wells.

Each of these categories of costs individually fluctuates from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating and maintenance costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.

Lease and well expenses of $1,283 million in 2018 increased $238 million from $1,045 million in 2017 primarily due to higher operating and maintenance costs ($171 million), higher workover expenditures ($44 million) and higher lease and well administrative expenses ($41 million), all in the United States, partially offset by lower operating and maintenance costs in the United Kingdom ($18 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting in increased production.

Transportation costs represent costs associated with the delivery of hydrocarbon products from the lease to a downstream point of sale. Transportation costs include transportation fees, the cost of compression (the cost of compressing natural gas to meet pipeline pressure requirements), dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees and fuel costs.

Transportation costs of $747 million in 2018 increased $7 million from $740 million in 2017 primarily due to increased transportation costs in the Permian Basin ($116 million), partially offset by decreased transportation costs in the Barnett Shale ($52 million), the Eagle Ford ($31 million) and the Rocky Mountain area ($25 million).

DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual DD&A group calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or acquisition of new wells, disposition of existing wells and reserve revisions (upward or downward) primarily related to well performance, economic factors and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from period to period. DD&A of the cost of other property, plant and equipment is generally calculated using the straight-line depreciation method over the useful lives of the assets.

DD&A expenses in 2018 increased $26 million to $3,435 million from $3,409 million in 2017. DD&A expenses associated with oil and gas properties in 2018 were $24 million higher than in 2017 primarily due to an increase in production in the United States ($647 million) and the United Kingdom ($21 million), partially offset by lower unit rates in the United States ($625 million) and a decrease in production in Trinidad ($16 million). Unit rates in the United States decreased primarily due to upward reserve revisions and reserves added at lower costs as a result of increased efficiencies.

G&A expenses of $427 million in 2018 decreased $7 million from $434 million in 2017 primarily due to decreased professional, legal and other services ($24 million); partially offset by increased employee-related expenses resulting from expanded operations ($15 million) and increased information systems costs ($10 million).

Net interest expense of $245 million in 2018 was $29 million lower than 2017 primarily due to repayment of the $600 million aggregate principal amount of 5.875% Senior Notes due 2017 in September 2017 ($25 million) and the $350 million aggregate principal amount of 6.875% Senior Notes due 2018 in October 2018 ($6 million), partially offset by a decrease in capitalized interest ($3 million).

Gathering and processing costs represent operating and maintenance expenses and administrative expenses associated with operating EOG's gathering and processing assets and beginning January 1, 2018, natural gas processing fees from third parties. EOG pays third parties to process a portion of its natural gas production to extract NGLs. See Note 1 to the Consolidated Financial Statements for discussion related to EOG's adoption of ASU 2014-09.

Gathering and processing costs increased $288 million to $437 million in 2018 compared to $149 million in 2017 primarily due to the adoption of ASU 2014-09 ($204 million) and increased operating costs in the Permian Basin ($32 million), the United Kingdom ($28 million) and the Eagle Ford ($25 million).

Exploration costs of $149 million in 2018 increased $4 million from $145 million in 2017 primarily due to increased general and administrative expenses in the United States ($7 million), partially offset by decreased geological and geophysical expenditures in Trinidad ($5 million).

Impairments include amortization of unproved oil and gas property costs as well as impairments of proved oil and gas properties; other property, plant and equipment; and other assets. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. When circumstances indicate that a proved property may be impaired, EOG compares expected undiscounted future cash flows at a DD&A group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated by using the Income Approach described in the Fair Value Measurement Topic of the Financial Accounting Standards Board's Accounting Standards Codification (ASC). In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value.

The following table represents impairments for the years ended December 31, 2018 and 2017 (in millions):



	2018		2017

Proved properties	$	121	$	224
Unproved properties	173		211
Other assets	49		28
Other property, plant and equipment	—		16
Inventories	4		—
Total	$	347	$	479

Impairments of proved properties were primarily due to the write-down to fair value of legacy natural gas assets in 2018 and 2017.

Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are generally determined based on wellhead revenues, and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.

Taxes other than income in 2018 increased $227 million to $772 million (6.5% of wellhead revenues) from $545 million (6.9% of wellhead revenues) in 2017. The increase in taxes other than income was primarily due to increases in severance/production taxes ($190 million) primarily as a result of increased wellhead revenues and an increase in ad valorem/property taxes ($33 million), both in the United States.

Other income, net, was $17 million in 2018 compared to other income, net, of $9 million in 2017. The increase of $8 million in 2018 was primarily due to a decrease in deferred compensation expense ($12 million) and an increase in interest income ($4 million); partially offset by an increase in foreign currency transaction losses ($15 million).

EOG recognized an income tax provision of $822 million in 2018 compared to an income tax benefit of $1,921 million in 2017, primarily due to the absence of certain 2017 tax benefits related to the Tax Cuts and Jobs Act (TCJA) and higher pretax income. The most significant impact of the TCJA on EOG was the reduction in the statutory income tax rate from 35% to 21% which required the existing net United States federal deferred income tax liability to be remeasured resulting in the recognition of an income tax benefit in 2017 of approximately $2.2 billion. The net effective tax rate for 2018 increased to 19% from (291%) in the prior year, primarily due to the absence of the TCJA tax benefits.

2017 compared to 2016. During 2017, operating expenses of $10,282 million were $1,406 million higher than the $8,876 million incurred during 2016. The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2017 and 2016:



	2017		2016

Lease and Well	$	4.70	$	4.53
Transportation Costs	3.33		3.73
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties	14.83		16.77
Other Property, Plant and Equipment	0.51		0.57
General and Administrative (G&A)	1.95		1.93
Net Interest Expense	1.23		1.37
Total ⁽¹⁾	$	26.55	$	28.90


(1)	Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and net interest expense for 2017 compared to 2016 are set forth below. See "Operating Revenues and Other" above for a discussion of production volumes.

Lease and well expenses of $1,045 million in 2017 increased $118 million from $927 million in 2016 primarily due to higher operating and maintenance costs in the United States ($71 million) and the United Kingdom ($30 million) and higher workover expenditures in the United States ($21 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting in increased production.

Transportation costs of $740 million in 2017 decreased $24 million from $764 million in 2016 primarily due to divestitures in the Barnett Shale and Upper Gulf Coast ($85 million) and decreased transportation costs in the Eagle Ford ($8 million) and the United Kingdom ($8 million), partially offset by increased transportation costs related to higher production in the Permian Basin ($47 million) and the Rocky Mountain area ($20 million) and from the 2016 transactions with the Yates Entities ($13 million).

DD&A expenses in 2017 decreased $144 million to $3,409 million from $3,553 million in 2016. DD&A expenses associated with oil and gas properties in 2017 were $141 million lower than in 2016 primarily due to lower unit rates in the United States ($449 million) and Trinidad ($19 million) and a decrease in production in the United Kingdom ($16 million) and Trinidad ($11 million), partially offset by an increase in production in the United States ($354 million). Unit rates in the United States decreased primarily due to upward reserve revisions and reserves added at lower costs as a result of increased efficiencies.

G&A expenses of $434 million in 2017 increased $39 million from $395 million in 2016 primarily due to increased employee-related expenses resulting from expanded operations and from the 2016 transactions with the Yates Entities ($45 million) and increased professional, legal and other services ($30 million), partially offset by 2016 employee related expenses in connection with certain voluntary retirements ($42 million).

Net interest expense of $274 million in 2017 was $8 million lower than 2016 primarily due to repayment of the $600 million aggregate principal amount of 5.875% Senior Notes due 2017 in September 2017 ($11 million), partially offset by a decrease in capitalized interest ($4 million).

Gathering and processing costs increased $26 million to $149 million in 2017 compared to $123 million in 2016 due to increased activities in the Permian Basin ($12 million) and the Rocky Mountain area ($8 million).

Exploration costs of $145 million in 2017 increased $20 million from $125 million in 2016 primarily due to increased geological and geophysical expenditures in Trinidad.

The following table represents impairments for the years ended December 31, 2017 and 2016 (in millions):



	2017		2016

Proved properties	$	224	$	116
Unproved properties	211		291
Other assets	28		—
Other property, plant and equipment	16		14
Inventories	—		61
Firm commitment contracts	—		138
Total	$	479	$	620

Impairments of proved properties were primarily due to the write-down to fair value of divested legacy natural gas assets in 2017 and 2016. EOG recognized additional impairment charges in 2016 of $61 million related to obsolete inventory and $138 million related to firm commitment contracts related to divested Haynesville natural gas assets.

Taxes other than income in 2017 increased $195 million to $545 million (6.9% of wellhead revenues) from $350 million (6.4% of wellhead revenues) in 2016. The increase in taxes other than income was primarily due to increases in severance/production taxes ($171 million) and in ad valorem/property taxes ($18 million), both primarily as a result of increased wellhead revenues in the United States.

Other income, net, was $9 million in 2017 compared to other expense, net, of $51 million in 2016. The increase of $60 million was primarily due to an increase in foreign currency transaction gains in 2017 ($49 million) and interest income ($5 million).

EOG recognized an income tax benefit of $1,921 million in 2017 compared to an income tax benefit of $461 million in 2016, primarily due to the enactment of the TCJA in December 2017. The most significant impact of the TCJA on EOG was the reduction in the statutory income tax rate from 35% to 21%, which required the existing net United States federal deferred income tax liability to be remeasured, resulting in the recognition of an income tax benefit of approximately $2.2 billion. Due largely to this tax rate reduction, the net effective tax rate for 2017 decreased to (291)% from 30% in the prior year.

Capital Resources and Liquidity

Cash Flow

The primary sources of cash for EOG during the three-year period ended December 31, 2018, were funds generated from operations and proceeds from asset sales. The primary uses of cash were funds used in operations; exploration and development expenditures; other property, plant and equipment expenditures; dividend payments to stockholders; repayments of debt; and purchases of treasury stock in connection with stock compensation plans.

2018 compared to 2017. Net cash provided by operating activities of $7,769 million in 2018 increased $3,504 million from $4,265 million in 2017 primarily reflecting an increase in wellhead revenues ($4,039 million), favorable changes in working capital and other assets and liabilities ($758 million) and a favorable change in the cash paid for income taxes ($113 million), partially offset by an increase in cash operating expenses ($746 million) and an unfavorable change in the net cash paid for the settlement of financial commodity derivative contracts ($266 million).

Net cash used in investing activities of $6,170 million in 2018 increased by $2,183 million from $3,987 million in 2017 primarily due to an increase in additions to oil and gas properties ($1,888 million); unfavorable changes in working capital associated with investing activities ($211 million); and an increase in additions to other property, plant and equipment ($64 million).

Net cash used in financing activities of $839 million in 2018 included cash dividend payments ($438 million), repayments of long-term debt ($350 million) and purchases of treasury stock in connection with stock compensation plans ($63 million). Cash provided by financing activities in 2018 included proceeds from stock options exercised and employee stock purchase plan activity ($21 million).

2017 compared to 2016. Net cash provided by operating activities of $4,265 million in 2017 increased $1,906 million from $2,359 million in 2016 primarily reflecting an increase in wellhead revenues ($2,411 million) and a favorable change in the net cash received from the settlement of financial commodity derivative contracts ($30 million), partially offset by an increase in cash operating expenses ($362 million), an increase in net cash paid for income taxes ($228 million), an increase in net cash paid for interest expense ($23 million) and unfavorable changes in working capital and other assets and liabilities ($10 million).

Net cash used in investing activities of $3,987 million in 2017 increased by $2,734 million from $1,253 million in 2016 primarily due to an increase in additions to oil and gas properties ($1,461 million); a decrease in proceeds from asset sales ($892 million); unfavorable changes in working capital associated with investing activities ($246 million); and an increase in additions to other property, plant and equipment ($80 million).

Net cash used in financing activities of $1,036 million in 2017 included repayments of long-term debt ($600 million), cash dividend payments ($387 million) and purchases of treasury stock in connection with stock compensation plans ($63 million). Cash provided by financing activities in 2017 included proceeds from stock options exercised and employee stock purchase plan activity ($21 million).

Total Expenditures

The table below sets out components of total expenditures for the years ended December 31, 2018, 2017 and 2016 (in millions):



	2018		2017		2016
Expenditure Category
Capital
Exploration and Development Drilling	$	4,935	$	3,132	$	1,957
Facilities	625		575		375
Leasehold Acquisitions ⁽¹⁾	488		427		3,217
Property Acquisitions ⁽²⁾	124		73