10-K 1 a2015123110-k.htm 10-K 10-K
 

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, 2015
or
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 and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted 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 and post 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, or a smaller reporting company.  See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer ý    Accelerated filer o    Non-accelerated filer o    Smaller reporting company 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, 2015: $47,957 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, 549,883,390 shares outstanding as of February 18, 2016.

Documents incorporated by reference.  Portions of the Definitive Proxy Statement for the registrant's 2016 Annual Meeting of Stockholders, to be filed within 120 days after December 31, 2015, are incorporated by reference into Part III of this report.

 



TABLE OF CONTENTS

 
 
Page
PART I
 
 
 
 
ITEM 1.
Business
 
General
 
Business Segments
 
Exploration and Production
 
Marketing
 
Wellhead Volumes and Prices
 
Competition
 
Regulation
 
Other Matters
 
Executive Officers of the Registrant
ITEM 1A.
Risk Factors
ITEM 1B.
Unresolved Staff Comments
ITEM 2.
Properties
 
Oil and Gas Exploration and Production - Properties and Reserves
ITEM 3.
Legal Proceedings
ITEM 4.
Mine Safety Disclosures
 
 
 
PART II
 
 
 
 
ITEM 5.
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
ITEM 6.
Selected Financial Data
ITEM 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
ITEM 7A.
Quantitative and Qualitative Disclosures About Market Risk
ITEM 8.
Financial Statements and Supplementary Data
ITEM 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
ITEM 9A.
Controls and Procedures
ITEM 9B.
Other Information
 
 
 
PART III
 
 
 
 
ITEM 10.
Directors, Executive Officers and Corporate Governance
ITEM 11.
Executive Compensation
ITEM 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
ITEM 13.
Certain Relationships and Related Transactions, and Director Independence
ITEM 14.
Principal Accounting Fees and Services
 
 
 
PART IV
 
 
 
 
ITEM 15.
Exhibits, Financial Statement Schedules
 
 
 
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 United Kingdom (U.K.), The People's Republic of China (China), Canada and, from time to time, select other international areas.  EOG's principal producing areas are further described in "Exploration and Production" below.  EOG's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports are made available, free of charge, through EOG's website, as soon as reasonably practicable after such reports have been filed with the United States Securities and Exchange Commission (SEC).  EOG's website address is www.eogresources.com. Information on our website is not incorporated by reference into, and does not constitute a part of, this report.

At December 31, 2015, EOG's total estimated net proved reserves were 2,118 million barrels of oil equivalent (MMBoe), of which 1,098 million barrels (MMBbl) were crude oil and condensate reserves, 383 MMBbl were natural gas liquids (NGLs) reserves and 3,825  billion cubic feet, or 637 MMBoe, were natural gas reserves (see Supplemental Information to Consolidated Financial Statements).  At such date, approximately 97% of EOG's net proved reserves, on a crude oil equivalent basis, were located in the United States and 3% in Trinidad.  Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet (Mcf) of natural gas.

As of December 31, 2015, EOG employed approximately 2,760 persons, including foreign national employees.

EOG's business strategy is to maximize the rate of return on investment of capital by controlling operating and capital costs and maximizing reserve recoveries.  This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to deliver long-term production growth while maintaining a strong balance sheet.  EOG is focused on cost-effective utilization of advanced technology associated with three-dimensional seismic and microseismic data, the development of reservoir simulation models, the use of improved drill bits, completion technologies for horizontal drilling and formation evaluation.  These advanced technologies are used, as appropriate, throughout EOG to reduce the risks associated with all aspects of oil and gas exploration, development and exploitation.  EOG implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves.  Maintaining the lowest possible operating cost structure that is consistent with prudent and safe operations is also an important goal in the implementation of EOG's strategy.

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

Business Segments

EOG's operations are all crude oil and natural gas exploration and production related. For financial information about our reportable segments (including financial information by segment geographic area), see Note 11 to Consolidated Financial Statements. For information regarding the risks associated with EOG's foreign operations, see ITEM 1A, Risk Factors.

1



Exploration and Production

United States Operations

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

At December 31, 2015, on a crude oil equivalent basis, 53% of EOG's net proved reserves in the United States were crude oil and condensate, 19% were NGLs and 28% 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 2015 and certain 2016 plans for EOG's United States operations.

The Eagle Ford continues to prove itself as a world-class oil field having produced in excess of 1.5 billion barrels of crude oil and condensate. With approximately 549,000 of its 608,000 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 285 MMBbl of oil. EOG completed 329 net wells in 2015 and net production averaged approximately 209 thousand barrels per day (MBbld) of crude oil and condensate and NGLs, an increase of 3% over 2014. The combination of self-sourced sand, dedicated frac crews and other services along with continuous well optimization programs have made this play the centerpiece of EOG's portfolio. In 2016, EOG expects to complete approximately 150 net wells, continue to improve well productivity and reduce drilling and completion costs as well as operating expenses.

In the Permian Basin, EOG completed 74 net wells primarily in the Leonard, Wolfcamp, and Second Bone Spring Sand plays during 2015, and evaluated multiple development concepts across these liquids-rich plays. In the Delaware Basin Wolfcamp Shale play, where it has approximately 168,000 net acres, EOG tested 500-foot well spacing in both the crude oil and combo portions of this play with positive results. The success of the 2015 Delaware Basin Wolfcamp program was due to refined targeting, high-density stimulations and cost reductions, which will make the play a focal point of EOG's 2016 Permian Basin program. In the Second Bone Spring Sand play, where it holds approximately 111,000 net acres, EOG tested multiple target zones and well spacing as close as 550 feet. With over 1,000 estimated remaining net drilling locations, this high-return oil play is another integral part of EOG's Permian Basin portfolio. In the Leonard Shale play, EOG has approximately 93,000 net acres and continued development at 300- to 500- foot well spacing. Additionally, EOG has approximately 71,000 net acres in the Wolfcamp Shale within the Midland Basin. Net production in the Permian Basin for 2015 averaged approximately 43 MBbld of crude oil and condensate and NGLs, an increase of 30% over 2014. Net natural gas production increased 27% to approximately 108 million cubic feet per day (MMcfd). EOG holds approximately 415,000 net acres throughout the Permian Basin. In 2016, activity will be focused primarily in the Delaware Basin Wolfcamp, Second Bone Spring Sand and Leonard plays by completing approximately 75 net wells.

During 2015, the Rocky Mountain area experienced reduced activity levels due to lower commodity prices but yielded consistent results. In 2015, EOG continued infill drilling on its crude oil acreage in the Williston Basin Bakken core, completing 25 net wells. The 2015 development program also included completing 10 net Codell formation wells in the DJ Basin and 13 net wells in the Turner, Parkman and Niobrara formations in the Powder River Basin. Infrastructure improvements allowed for a substantial reduction in lease operating expenses and a much higher natural gas recovery. Improved efficiencies, lower service company costs both for drilling and completions and lower lease operating expenses resulted in more profitable wells in this challenging price environment. Net production for the entire Rocky Mountain area for 2015 averaged approximately 65 MBbld of crude oil and condensate and NGLs. In 2016, EOG plans to complete approximately 35 net wells, primarily in the Powder River and Williston Basins. EOG holds approximately 985,000 net acres in the Rocky Mountain area.

In the Upper Gulf Coast region, EOG completed six net wells during 2015 and net production averaged approximately 54 MMcfd of natural gas and approximately 4 MBbld of crude oil and condensate and NGLs. In 2016, EOG will continue to defer dry gas drilling in the Haynesville Shale, while working to maintain base production and continue its liquids exploration program. EOG holds approximately 529,000 net acres in the Upper Gulf Coast region and plans to complete approximately five net wells in 2016.

In the Mid-Continent area, EOG continued its successful horizontal exploitation of the Pennsylvanian sandstones in the Anadarko Basin, completing five net wells in 2015. During 2015, EOG's net production averaged approximately 6 MBbld of crude oil and condensate and NGLs and approximately 29 MMcfd of natural gas. EOG holds approximately 250,000 net acres throughout the Mid-Continent area and expects to continue its exploration program in 2016.


2



During 2015, EOG performed limited development of its liquids-rich Barnett Shale Combo play in the Fort Worth Basin, completing six net wells. In 2015, net production in the Barnett Shale averaged approximately 27 MBbld of crude oil and condensate and NGLs and approximately 272 MMcfd of natural gas. For 2016, EOG will focus on maintaining base production. EOG currently holds approximately 351,000 net acres in the Barnett Shale.

In the South Texas area, total net production during 2015 averaged approximately 6 MBbld of crude oil and condensate and NGLs and approximately 66 MMcfd of natural gas. EOG completed seven net wells with activity focused in San Patricio, Kleberg and Jim Wells counties. In 2016, EOG expects to complete approximately five net wells in the Frio and Vicksburg trends, where it holds approximately 272,000 net acres. Exploration efforts will continue in this region, primarily focusing on liquids-rich hydrocarbons.

Net production in the Marcellus Shale for 2015 averaged approximately 24 MMcfd of natural gas. EOG currently holds approximately 200,000 net acres with Marcellus and Utica Shale potential.

EOG has agreements with certain crude oil refining companies to deliver an average of 58 MBbld and 9 MBbld of crude oil in 2016 and 2017, respectively, to certain refineries. EOG intends to fulfill these crude oil delivery obligations with its Eagle Ford production.

At December 31, 2015, EOG held approximately 2.0 million net undeveloped acres in the United States.

During 2015, EOG continued the expansion of its gathering and processing activities in the Eagle Ford in South Texas, the Bakken and Three Forks plays in North Dakota and the Permian Basin in West Texas and New Mexico. At December 31, 2015, EOG-owned natural gas processing capacity in the Eagle Ford and Barnett Shale totaled 305 MMcfd and 180 MMcfd, respectively.

Also during 2015, EOG continued to use its crude oil loading facility near Stanley, North Dakota, to transport its Williston Basin crude oil production. During 2015, EOG loaded 81 unit trains (each unit train typically consists of 100 cars and has a total aggregate capacity of approximately 70,000 barrels of crude oil) with crude oil for transport to St. James, Louisiana and Stroud, Oklahoma. EOG has net unloading capacity of 100 MBbld and 90 MBbld at St. James and Stroud, respectively. During 2015, a total of 18 crude oil unit trains carrying EOG production were received at the crude oil unloading facility in St. James, Louisiana, which provides access to one of the key markets in the U.S., where sales are based upon the Light Louisiana Sweet (LLS) crude oil index. In addition, EOG utilized its Stroud, Oklahoma, crude oil unloading facility and pipeline to transport 63 unit trainloads of crude oil to the Cushing, Oklahoma trading hub. EOG believes that its marketing and related logistics processes, including crude-by-rail facilities, provide a competitive advantage, giving EOG the flexibility to direct its crude oil shipments via rail car to the most favorable markets. EOG expects to utilize its crude-by-rail network when it is advantageous.

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

In 2015, EOG continued to process sand from its Chippewa Falls, Wisconsin, sand plant on an as-needed basis.

EOG placed in service an additional sand unloading facility in Loving, New Mexico, during the first quarter of 2015 to support well completions in the Delaware Basin.

During 2015, EOG shipped the equivalent of 173 sand unit trains from various sources, to support well completions in the Eagle Ford and other plays.

3



Operations Outside the United States

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

Trinidad. EOG, through several of its subsidiaries, including EOG Resources Trinidad Limited,
holds an 80% working interest in the exploration and production license covering the South East Coast Consortium (SECC) Block offshore Trinidad, except in the Deep Ibis area in which EOG's working interest decreased as a result of a third-party farm-out agreement;
holds an 80% working interest in the exploration and production license covering the Pelican Field and its related facilities;
holds a 50% working interest in the exploration and production licenses covering the Sercan Area (formerly known as the EMZ Area) offshore Trinidad;
holds a 100% working interest in a production sharing contract with the Government of Trinidad and Tobago for each of the Modified U(a) Block, Modified U(b) Block and Block 4(a);
owns a 12% equity interest in an anhydrous ammonia plant in Point Lisas, Trinidad, that is owned and operated by Caribbean Nitrogen Company Limited; and
owns a 10% equity interest in an anhydrous ammonia plant in Point Lisas, Trinidad, that is owned and operated by Nitrogen (2000) Unlimited.

Several fields in the SECC Block, Modified U(a) Block, Modified U(b) Block, Block 4(a) and the Sercan Area have been developed and are producing natural gas and crude oil and condensate. Natural gas from EOG's Trinidad operations currently is sold under various contracts with the National Gas Company of Trinidad and Tobago Limited and its subsidiary (NGC). Crude oil and condensate from EOG's Trinidad operations currently is sold to the Petroleum Company of Trinidad and Tobago Limited (Petrotrin).  In 2015, EOG's net production from Trinidad averaged approximately 349 MMcfd of natural gas and approximately 0.9 MBbld of crude oil and condensate.

EOG completed three net wells in 2015, finishing its SECC Block and Modified U(b) Block drilling program which was initiated in 2014.

In 2016, it is anticipated that EOG's Trinidad operations will supply approximately 430 MMcfd (290 MMcfd, net) of natural gas from its existing proved reserves. All of the natural gas produced from EOG's Trinidad operations in 2016 is expected to be supplied to NGC under various contracts with NGC. All crude oil and condensate produced from EOG's Trinidad operations in 2016 is expected to be supplied to Petrotrin under various contracts with Petrotrin. In 2016, EOG expects to complete one net well and install infrastructure in the Sercan Area.

At December 31, 2015, EOG held approximately 40,000 net undeveloped acres in Trinidad.

United Kingdom. EOG's subsidiary, EOG Resources United Kingdom Limited (EOGUK), owns a 25% non-operating working interest in a portion of Block 49/16a, located in the Southern Gas Basin of the North Sea. During 2015, a limited amount of production continued from the Valkyrie field in this block. Production ceased at the end of the third quarter of 2015, and decommissioning is planned for the fourth quarter of 2016.

In 2007, EOGUK was awarded a license for two blocks in the East Irish Sea – Blocks 110/7b and 110/12a. In 2009, EOGUK drilled a successful exploratory well in the East Irish Sea Block 110/12a. The well, in which EOGUK has a 100% working interest, was an oil discovery and was designated the Conwy field. During 2012 and 2013, the Conwy production platform and pipelines were installed. Modifications to the nearby third-party owned Douglas platform, which will be used to process Conwy production, began in 2013 and continued throughout 2014 and 2015. First production from the Conwy field is anticipated in March 2016.

In 2015, production averaged less than 0.1 MMcfd of natural gas, net, in the United Kingdom.

At December 31, 2015, EOG held approximately 7,000 net undeveloped acres in the United Kingdom.


4



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. In 2015, EOG drilled four wells and completed three wells, one of which was drilled in 2014, in the Sichuan Basin, Sichuan Province, China. The successful completions extended the Shaximiao development in the Chuan Zhong Block and provides additional opportunities in the future.

In 2015, production averaged approximately 14 MMcfd of natural gas, net, in China.

Canada. During 2014, EOG sold all of its assets in Manitoba and the majority of its assets in Alberta in two separate transactions that closed on or about December 1, 2014. EOG divested 1.3 million gross acres (1.1 million net), 97 percent of which were in Alberta. Of the approximate 5,800 net producing wells sold, 5,155 were natural gas. In 2015, net production averaged approximately 15 MMcfd of natural gas and less than 0.1 MBbld of NGLs.

Argentina. EOG's activity in Argentina is focused on the Vaca Muerta oil shale formation in the Neuquén Province. Management is currently evaluating options for its investment.

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 2015, EOG's wellhead crude oil and condensate production was sold into local markets or transported either by pipeline, truck or EOG's crude-by-rail assets to downstream markets. In each case, the price received was based on market prices at that specific sales point or based on the price index applicable for that location. Major U.S. sales areas included the Midwest, the Permian Basin, Cushing, Oklahoma, St. James, Louisiana, and other points along the U.S. Gulf Coast. In 2016, the pricing mechanism for such production is expected to remain the same.

In 2015, 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 2016, the pricing mechanism for such production is expected to remain the same.

In 2015, EOG's United States and Canada wellhead natural gas production was sold into local markets or transported by pipeline to downstream markets. Pricing was based on the spot market at the ultimate sales point. In 2016, the pricing mechanism for such production is expected to remain the same.
 
In 2015, a large majority of the wellhead natural gas volumes from Trinidad were sold under contracts with prices which were either wholly or partially dependent on Caribbean ammonia index prices and/or methanol prices. The remaining volumes were sold under a contract at prices partially dependent on United States Henry Hub market prices. The pricing mechanisms for these contracts in Trinidad are expected to remain the same in 2016.

In 2015, all wellhead natural gas volumes from the U.K. were sold on the spot market. In December 2014, EOG put in place arrangements to market and sell its U.K. wellhead crude oil production from the Conwy field, which is anticipated to begin in March 2016. The crude oil sales will be based on a Dated Brent price or other market prices, as applicable.

In 2015, 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 2016.

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 2015, 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. Both purchasers are in the crude oil refining industry. EOG does not believe that the loss of any single purchaser would have a material adverse effect on its financial condition or results of operations.


5



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, 2015, 2014 and 2013.
Year Ended December 31
2015
 
2014
 
2013
 
 
 
 
 
 
Crude Oil and Condensate Volumes (MBbld) (1)
 
 
 
 
 
United States:
 
 
 
 
 
Eagle Ford
181.7

 
178.0

 
122.3

Other
101.6

 
104.0

 
89.8

United States
283.3

 
282.0

 
212.1

Trinidad
0.9

 
1.0

 
1.2

Other International (2)
0.2

 
5.9

 
7.1

Total
284.4

 
288.9

 
220.4

Natural Gas Liquids Volumes (MBbld) (1)
 

 
 

 
 

United States:
 

 
 

 
 

Eagle Ford
27.2

 
24.7

 
18.6

Other
49.7

 
55.0

 
45.7

United States
76.9

 
79.7

 
64.3

Other International (2)
0.1

 
0.6

 
0.9

Total
77.0

 
80.3

 
65.2

Natural Gas Volumes (MMcfd) (1)
 

 
 

 
 
United States:
 

 
 

 
 
Eagle Ford
179

 
164

 
115

Other
707

 
756

 
793

United States
886

 
920

 
908

Trinidad
349

 
363

 
355

Other International (2)
30

 
70

 
84

Total
1,265

 
1,353

 
1,347

Crude Oil Equivalent Volumes (MBoed) (3)
 

 
 

 
 
United States:
 

 
 

 
 
Eagle Ford
238.8

 
230.0

 
160.2

Other
269.1

 
285.0

 
267.7

United States
507.9

 
515.0

 
427.9

Trinidad
59.1

 
61.5

 
60.4

Other International (2)
5.2

 
18.2

 
21.8

Total
572.2

 
594.7

 
510.1

 
 
 
 
 
 
Total MMBoe (3)
208.9

 
217.1

 
186.2


6



Year Ended December 31
2015
 
2014
 
2013
 
 
 
 
 
 
Average Crude Oil and Condensate Prices ($/Bbl) (4)
 
 
 
 
 
United States
$
47.55

 
$
92.73

 
$
103.81

Trinidad
39.51

 
84.63

 
90.30

Other International (2)
57.32

 
86.75

 
87.08

Composite
47.53

 
92.58

 
103.20

Average Natural Gas Liquids Prices ($/Bbl) (4)
 
 
 
 
 

United States
$
14.50

 
$
31.84

 
$
32.46

Other International (2)
4.61

 
40.73

 
39.45

Composite
14.49

 
31.91

 
32.55

Average Natural Gas Prices ($/Mcf) (4)
 
 
 
 
 

United States
$
1.97

 
$
3.93

 
$
3.32

Trinidad
2.89

 
3.65

 
3.68

Other International (2)
5.05

 
4.40

 
3.39

Composite
2.30

 
3.88

 
3.42

 
(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.
(3)
Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas.  MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.
(4)
Dollars per barrel or per thousand cubic feet, as applicable.  Excludes the impact of financial commodity derivative instruments (see Note 12 to Consolidated Financial Statements).

Competition

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

Regulation

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

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

    

7



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

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.

    

8



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

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

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

Climate Change - United States. Local, state, national and international regulatory bodies have been increasingly focused on GHG emissions and climate change issues. In addition to the U.S. EPA's rule requiring annual reporting of GHG emissions, recent U.S. EPA rulemaking may result in the regulation of GHG emissions as pollutants under the federal Clean Air Act. Also, in December 2015, the U.S. participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement (adopted at the conference) calls for nations to undertake efforts with respect to global temperatures and GHG emissions. If ratified, the Paris Agreement will take effect in 2020.

EOG believes that its strategy to reduce GHG emissions throughout its operations is in the best interest of the environment and is a generally good business practice. EOG has developed a system that is utilized in calculating GHG emissions from its operating facilities. This emissions management system calculates emissions based on recognized regulatory methodologies, where applicable, and on commonly accepted engineering practices. EOG reports GHG emissions for facilities covered under the U.S. EPA's Mandatory Reporting of Greenhouse Gases Rule published in 2009.

EOG is unable to predict the timing, scope and effect of any currently proposed or future investigations, laws, regulations or treaties regarding climate change and GHG emissions, but the direct and indirect costs of such investigations, laws, regulations and treaties (if enacted) could materially and adversely affect EOG's operations, financial condition and results of operations.

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

    

9



The regulation of hydraulic fracturing is primarily conducted at the state and local level through permitting and other compliance requirements. In March 2015, the BLM issued new regulations applicable to hydraulic fracturing activities on federal and Indian lands, including requirements for chemical disclosure, wellbore integrity and handling of flowback and produced water. In addition, 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 April 2012, the U.S. EPA issued regulations specifically applicable to the oil and gas industry that will require operators to significantly reduce volatile organic compounds (VOC) emissions from natural gas wells that are hydraulically fractured through the use of "green completions" to capture natural gas that would otherwise escape into the air. The U.S. EPA also issued regulations that establish standards for VOC emissions from several types of equipment, including storage tanks, compressors, dehydrators, and valves and sweetening units at gas processing plants. In addition, the U.S. EPA recently proposed regulations that would require operators to reduce methane and VOC emissions from 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 addition to these federal regulations, some state and local governments have imposed or have considered imposing various conditions and restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; disclosure of the chemical additives used in hydraulic fracturing operations; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations. Such federal, state and local permitting and disclosure requirements and operating restrictions and conditions could lead to operational delays and increased operating and compliance costs and, moreover, could delay or effectively prevent the development of crude oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing.

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

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

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

Other Matters

Energy Prices. EOG is a crude oil and natural gas producer and is impacted by changes in prices of crude oil and condensate, NGLs and natural gas. Crude oil and condensate and NGL production comprised a larger portion of EOG's production mix in 2015 than in prior years. Average crude oil and condensate prices received by EOG for production in the United States decreased 49% in 2015, decreased 11% in 2014 and increased 6% in 2013, each as compared to the immediately preceding year. Average NGL prices received by EOG for production in the United States decreased 54% in 2015, 2% in 2014 and 8% in 2013, 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 50% decrease in the average wellhead natural gas price received by EOG for production in the United States in 2015, an 18% increase in 2014 and a 32% increase in 2013, each as compared to the immediately preceding year. In addition, as of February 12, 2016, the average 2016 U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $34.97 per barrel and $2.23 per million British thermal units, respectively, representing declines of 28% and 17%, respectively, from the average NYMEX prices in 2015. Due to the many uncertainties associated with the world political environment (for example, the actions of other crude oil exporting nations, including the

10



Organization of Petroleum Exporting Countries), the global supply of and demand for crude oil and the availability of other energy supplies, the relative competitive relationships of the various energy sources in the view of consumers and other factors, EOG is unable to predict what changes may occur in prices of crude oil and condensate, NGLs and natural gas in the future. For additional discussion regarding changes in crude oil and natural gas prices and the risks that such changes may present to EOG, see ITEM 1A, Risk Factors.

Based on EOG's tax position, EOG's price sensitivity in 2016 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 $65 million for net income and $81 million for cash flows from operating activities. Including the impact of EOG's 2016 natural gas derivative contracts (exclusive of options) and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2016 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 $15 million for net income and $18 million for cash flows from operating activities. For a summary of EOG's financial commodity derivative contracts at February 25, 2016, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Derivative Transactions.

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 at February 25, 2016, 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 onshore and offshore operations are also subject to certain perils, including hurricanes and other adverse weather conditions. Moreover, EOG's activities are subject to governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. Losses and liabilities arising from such events could reduce revenues and increase costs to EOG to the extent not covered by insurance.

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

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

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


11



Executive Officers of the Registrant

The current executive officers of EOG and their names and ages (as of February 25, 2016) are as follows:
Name
 
Age
 
Position
 
 
 
 
 
William R. Thomas
 
63
 
Chairman of the Board and Chief Executive Officer
 
 
 
 
 
Gary L. Thomas
 
66
 
President and Chief Operating Officer
 
 
 
 
 
Lloyd W. Helms, Jr.
 
58
 
Executive Vice President, Exploration and Production
 
 
 
 
 
David W. Trice
 
45
 
Executive Vice President, Exploration and Production
 
 
 
 
 
Timothy K. Driggers
 
54
 
Vice President and Chief Financial Officer
 
 
 
 
 
Michael P. Donaldson
 
53
 
Vice President, General Counsel and Corporate Secretary

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

Gary L. Thomas was elected Chief Operating Officer in September 2011 and President in March 2015. He was elected Executive Vice President, North America Operations in May 1998, Executive Vice President, Operations in May 2002, and served as Senior Executive Vice President, Operations from February 2007 to September 2011. He also previously served as Senior Vice President and General Manager of EOG's Midland, Texas, office. Mr. Thomas joined a predecessor of EOG in July 1978.

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

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

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

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


12



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 the substantial and extended decline in commodity prices has had, and may continue to have, a material and adverse effect on us and the trading price of our common stock.

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

the level of consumer demand;
domestic and worldwide supplies of crude oil, NGLs and natural gas;
the price and quantity of imported and exported crude oil, NGLs and natural gas;
domestic and international drilling activity;
the actions of other crude oil exporting nations, including the Organization of Petroleum Exporting Countries;
weather conditions and changes in weather patterns;
the availability, proximity and capacity of appropriate transportation facilities, gathering, processing and compression facilities and refining facilities;
worldwide economic and political conditions, including political instability or armed conflict in oil and gas producing regions;
the price and availability of, and demand for, competing energy sources, including alternative energy sources;
the nature and extent of governmental regulation, including environmental 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
the effect of worldwide energy conservation measures.

Beginning in the fourth quarter of 2014 and continuing through 2015 and into 2016, crude oil prices have substantially declined. In addition, natural gas and NGL prices began to decline substantially in the second quarter of 2014, and such declines continued during 2015 and into 2016. The above-described factors and the volatility of commodity prices make it difficult to predict future crude oil, natural gas and NGL prices. As a result, we cannot predict how long these lower prices will continue, and there can be no assurance that the prices for crude oil, natural gas and/or NGLs will not decline further.

Our cash flows and results of operations depend to a great extent on prevailing commodity prices. Accordingly, the recent substantial and extended decline in commodity prices can materially and adversely affect the amount of cash flows we have available for our capital expenditures and other operating expenses, our ability to 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 declines in the prices of these commodities can also render uneconomic a significant portion of our exploration, development and exploitation projects, resulting in our having to make significant downward adjustments to our estimated proved reserves. As a result, prolonged or substantial declines in commodity prices can materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance our capital expenditures and, in turn, the trading price of our common stock.

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 asset impairments could materially and adversely affect our results of operations and financial position.

In fact, the substantial declines in crude oil, natural gas and NGL prices that began in 2014 and which have continued into 2016 have materially and adversely affected the amount of cash flows we have available for our capital expenditures and other operating expenses, our results of operations during fiscal year 2015 and the trading price of our common stock.

13



As a result of the decreased cash flow available for capital expenditures, we have delayed our drilling and completion plans with respect to certain of our properties. These delays may result in impacts to our production volumes as well as cause us to potentially shut-in certain wells and incur associated lease payment obligations. Such commodity price declines also resulted in an impairment charge (i.e., "write-down") of $6.3 billion in 2015 with respect to our proved oil and gas properties and related assets. Such declines in commodity prices also resulted in our making a downward adjustment of 574 million barrels of oil equivalent to our estimated net proved reserves at December 31, 2015.

In addition, our 2016 financial condition, cash flows and results of operations will be adversely affected if commodity prices remain at current levels or decline further. If commodity prices remain at current levels for an extended period of time or continue to decline, we may be limited in our ability to maintain our current level of dividends on our common stock. Further, if commodity prices remain at current levels or decline further, we may be required to incur additional impairment charges and/or make significant additional downward adjustments to our proved reserve estimates. As a result, our financial condition and results of operations will be further 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 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 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, rail cars, crude oil hauling trucks and qualified drivers and facilities and equipment to gather, process, compress, 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.


14



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 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 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 conditions, such as winter storms, flooding and hurricanes, and other natural disasters;
fires and explosions;
terrorism, vandalism and physical, electronic and cyber security breaches;
formations with abnormal or unexpected pressures;
leaks or spills in connection with, or associated with, the gathering, processing, compression 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 clean-up 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. 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 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 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 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 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 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.


15



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, 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. Moreover, we are subject to the United States (U.S.) Environmental Protection Agency's (U.S. EPA) rule requiring annual reporting of greenhouse gas (GHG) emissions. 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, national and international regulatory bodies have been increasingly focused on GHG emissions and climate change issues in recent years. For example, the U.S. EPA recently proposed regulations that would require operators to reduce methane emissions and emissions of volatile organic compounds from 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 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. If ratified, the Paris Agreement will take effect in 2020. 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 March 2015, however, the U.S. Bureau of Land Management issued new regulations applicable to hydraulic fracturing activities on federal and Indian lands, including requirements for chemical disclosure, wellbore integrity, and handling of flow back and produced water. In addition, 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.
    


16



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.

Certain U.S. federal income tax deductions currently available with respect to crude oil and natural gas exploration and production may cease to be available in the future or may be otherwise modified as a result of future legislation.

Legislation may be proposed in the future that could, if enacted into law, make significant changes to U.S. tax laws. Such changes may include, but not be limited to, the elimination of certain U.S. federal income tax incentives currently available to crude oil and natural gas exploration and production companies, such as with respect to the intangible drilling costs deduction and bonus tax depreciation. We can give no assurance whether such changes or similar or other tax law changes will be proposed and, if enacted, how soon any such changes would become effective. The enactment of any such changes in U.S. federal income tax laws 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, 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. 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.


17



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. The lower commodity price environment 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. Weakness and/or volatility in domestic and global financial markets or economic conditions and a depressed commodity price environment may increase the interest rates that lenders and commercial paper investors require us to pay and adversely affect our ability to finance our capital expenditures through equity or debt offerings or other borrowings. A reduction in our cash flows (for example, as a result of continued 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. In addition, 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.

Our ability to obtain financings and the terms of any financings are, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. 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). In February 2016, Standard & Poor’s Ratings Services (an independent credit rating agency), as a result of its lowered assumptions with respect to future commodity prices, lowered its credit ratings of several investment grade-rated U.S. oil and gas exploration and production companies, including its rating of our long-term debt. We expect Moody’s Investors Service, Inc. (also an independent credit rating agency) will take similar action in the near future with respect to its ratings of our debt and its ratings of the debt of other U.S. oil and gas exploration and production companies. Such ratings downgrades could increase our borrowing costs and may adversely impact our ability to access financings. In addition, we cannot provide any assurance that our 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 further 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, while weakened in recent years, have improved somewhat. However, there continues to be weakness and volatility in domestic and global financial markets and a depressed commodity price environment, and there is the possibility that lenders may react by tightening credit. These conditions and factors 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 or capacity of gathering, processing, compression and transportation 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.


18



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, many of our competitors have financial and other resources substantially greater than those we possess and have established strategic long-term positions and strong governmental relationships in countries 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, many of 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 and continual reassessment of the viability of production under varying economic conditions.

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

In addition, our exploration, exploitation and development activities and equipment can be adversely affected by extreme weather conditions, such as winter storms, flooding 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 conditions 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 and transportation facilities and the availability of, and our access to, necessary third-party services, such as gathering, processing, compression and transportation services. Such extreme weather conditions and changes in weather patterns may materially and adversely affect our business and, in turn, our financial condition and results of operations.


19



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 price swap, option, swaption, collar and basis swap 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. Our forecasted natural gas production for 2016 is currently approximately 4% hedged at approximately $2.49 per million British thermal units, and none of our forecasted crude oil production for 2016 is currently hedged. As a result, a significant portion of our forecasted production for 2016 remains unhedged and subject to fluctuating market prices. If we are ultimately unable to hedge additional production volumes for 2016 and beyond, we will be impacted by further 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 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 entity" 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.


20



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 and exchange rate fluctuations.

Our international operations may also be adversely affected by U.S. laws and policies affecting foreign trade and taxation. 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, 2015, 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.

As a producer of crude oil and natural gas, 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, 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.


21



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 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 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.  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 developed and undeveloped acreage at December 31, 2015. 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
2,168,651

 
1,700,323

 
2,895,940

 
2,006,080

 
5,064,591

 
3,706,403

Trinidad
75,667

 
65,669

 
50,338

 
39,725

 
126,005

 
105,394

United Kingdom
8,797

 
2,570

 
13,443

 
6,713

 
22,240

 
9,283

China
130,548

 
130,548

 

 

 
130,548

 
130,548

Canada
54,219

 
46,021

 
200,618

 
161,334

 
254,837

 
207,355

Argentina

 

 
183,916

 
79,451

 
183,916

 
79,451

Total
2,437,882

 
1,945,131

 
3,344,255

 
2,293,303

 
5,782,137

 
4,238,434


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 0.4 million net acres will expire in 2016, 0.3 million net acres will expire in 2017 and 0.1 million net acres will expire in 2018 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.


22



Producing Well Summary. EOG operated 10,074 gross and 8,751 net producing crude oil and natural gas wells at December 31, 2015. Gross crude oil and natural gas wells include 200 wells with multiple completions. The following table represents wells in which EOG owns a working interest, including non-EOG operated wells.
 
Crude Oil
 
Natural Gas
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
 
 
 
 
 
 
 
 
 
 
 
United States
4,842

 
3,846

 
6,024

 
5,261

 
10,866

 
9,107

Trinidad
13

 
10

 
34

 
29

 
47

 
39

China

 

 
31

 
31

 
31

 
31

Canada
10

 
1

 
24

 
23

 
34

 
24

Argentina
3

 
1

 

 

 
3

 
1

Total
4,868

 
3,858

 
6,113

 
5,344

 
10,981

 
9,202


Drilling and Acquisition Activities.  During the years ended December 31, 2015, 2014 and 2013, EOG expended $4.9 billion, $7.9 billion and $7.0 billion, respectively, for exploratory and development drilling, facilities and acquisition of leases and producing properties, including asset retirement obligations of $53 million, $196 million and $134 million, respectively.  The following tables set forth the results of the gross crude oil and natural gas wells completed for the years ended December 31, 2015, 2014 and 2013:
 
Gross Development Wells Completed
 
Gross Exploratory Wells Completed
 
Crude Oil
 
Natural Gas
 
Dry Hole
 
Total
 
Crude Oil
 
Natural Gas
 
Dry Hole
 
Total
2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
494

 
16

 
9

 
519

 
2

 

 

 
2

Trinidad

 
3

 

 
3

 

 
1

 

 
1

China

 

 

 

 

 
3

 
2

 
5

Total
494

 
19

 
9

 
522

 
2

 
4

 
2

 
8

2014
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

United States
901

 
47

 
8

 
956

 
12

 

 
5

 
17

Trinidad

 
1

 

 
1

 

 

 

 

United Kingdom

 

 

 

 

 

 
1

 
1

China

 

 

 

 

 
2

 

 
2

Canada
42

 

 

 
42

 

 

 

 

Argentina

 

 

 

 

 

 
3

 
3

Total
943

 
48

 
8

 
999

 
12

 
2

 
9

 
23

2013
 
 
 
 
 
 
 
 
 
 
 
 


 
 
United States
909

 
57

 
22

 
988

 
7

 
2

 
3

 
12

Trinidad

 
1

 

 
1

 

 
1

 

 
1

United Kingdom
3

 

 

 
3

 

 

 
1

 
1

China

 

 

 

 

 
1

 

 
1

Canada
85

 

 

 
85

 
1

 

 

 
1

Argentina

 

 

 

 
1

 

 

 
1

Total
997

 
58

 
22

 
1,077

 
9

 
4

 
4

 
17



23



The following tables set forth the results of the net crude oil and natural gas wells completed for the years ended December 31, 2015, 2014 and 2013:
 
Net Development Wells Completed
 
Net Exploratory Wells Completed
 
Crude Oil
 
Natural Gas
 
Dry Hole
 
Total
 
Crude Oil
 
Natural Gas
 
Dry Hole
 
Total
2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
457

 
14

 
8

 
479

 
2

 

 

 
2

Trinidad

 
2

 

 
2

 

 
1

 

 
1

China

 

 

 

 

 
3

 
2

 
5

Total
457

 
16

 
8

 
481

 
2

 
4

 
2

 
8

2014
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

United States
807

 
39

 
7

 
853

 
11

 

 
5

 
16

Trinidad

 
1

 

 
1

 

 

 

 

United Kingdom

 

 

 

 

 

 
1

 
1

China

 

 

 

 

 
2

 

 
2

Canada
35

 

 

 
35

 

 

 

 

Argentina

 

 

 

 

 

 
1

 
1

Total
842

 
40

 
7

 
889

 
11

 
2

 
7

 
20

2013
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

United States
788

 
50

 
15

 
853

 
6

 
2

 
3

 
11

Trinidad

 
1

 

 
1

 

 
1

 

 
1

United Kingdom
3

 

 

 
3

 

 

 
1

 
1

China

 

 

 

 

 
1

 

 
1

Canada
76

 

 

 
76

 
1

 

 

 
1

Argentina

 

 

 

 
1

 

 

 
1

Total
867

 
51

 
15

 
933

 
8

 
4

 
4

 
16


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, 2015, 2014 and 2013:
 
Wells in Progress at End of Period
 
2015
 
2014
 
2013
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
 
 
 
 
 
 
 
 
 
 
 
United States
516

 
429

 
388

 
327

 
320

 
280

Trinidad

 

 
1

 
1

 

 

China

 

 
2

 
2

 
2

 
2

Canada

 

 

 

 
13

 
8

Argentina

 

 

 

 
1

 
1

Total
516

 
429

 
391

 
330

 
336

 
291


24



EOG acquired wells, which includes the acquisition of additional interests in certain wells in which EOG previously owned an interest, as set out in the tables below for the years ended December 31, 2015, 2014 and 2013:
 
Gross Acquired Wells
 
Net Acquired Wells
 
Crude
Oil
 
Natural Gas
 
Total
 
Crude
Oil
 
Natural Gas
 
Total
2015
 
 
 
 
 
 
 
 
 
 
 
United States
24

 

 
24

 
23

 

 
23

Total
24

 

 
24

 
23

 

 
23

2014
 

 
 

 
 

 
 

 
 

 
 

United States
91

 
10

 
101

 
41

 
9

 
50

Total
91

 
10

 
101

 
41

 
9

 
50

2013
 

 
 

 
 

 
 

 
 

 
 

United States
68

 
27

 
95

 
50

 
21

 
71

Total
68

 
27

 
95

 
50

 
21

 
71

 
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, 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

The information required by this Item is set forth under the "Contingencies" caption in Note 8 of the Notes to Consolidated Financial Statements and 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.

25



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." The following table sets forth, for the periods indicated, the high and low sales price per share for EOG's common stock, as reported by the NYSE, and the amount of the cash dividend declared per share. The quarterly cash dividend on EOG's common stock has historically been declared in the quarter immediately preceding the quarter of payment and paid on January 31, April 30, July 31 and October 31 of each year (or, if such day is not a business day, the immediately preceding business day).
 
Price Range
 
 
 
High
 
Low
 
Dividend Declared
2015
 
 
 
 
 
First Quarter
$
97.88

 
$
82.72

 
$
0.1675

Second Quarter
101.36

 
86.15

 
0.1675

Third Quarter
87.85

 
68.15

 
0.1675

Fourth Quarter
89.52

 
69.30

 
0.1675

2014
 

 
 

 
 

First Quarter
$
99.75

 
$
80.63

 
$
0.1250

Second Quarter
118.89

 
96.01

 
0.1250

Third Quarter
118.81

 
97.45

 
0.1675

Fourth Quarter
103.04

 
81.07

 
0.1675


As of February 3, 2016, there were approximately 2,100 record holders and approximately 339,000 beneficial owners of EOG's common stock.

EOG currently intends to continue to pay quarterly cash dividends on its outstanding shares of common stock in the future. However, the determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other factors, the financial condition, cash flow, level of exploration and development expenditure opportunities and future business prospects of EOG.

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, 2015 - October 31, 2015
 
24,430

 
$
83.69

 
 
6,386,200

November 1, 2015 - November 30, 2015
 
15,850

 
$
85.14

 
 
6,386,200

December 1, 2015 - December 31, 2015
 
25,847

 
$
75.06

 
 
6,386,200

Total
 
66,127

 
$
80.66

 
 
 
 

 
(1)
The 66,127 total shares for the quarter ended December 31, 2015, and the 580,815 total shares for the full year 2015, 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 or restricted stock 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 2015, EOG did not repurchase any shares under the Board-authorized repurchase program.


26



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, 2010 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, 2015)


 
2010
 
2011
 
2012
 
2013
 
2014
 
2015
EOG
$
100.00

 
$
108.48

 
$
133.89

 
$
186.77

 
$
206.01

 
$
159.60

S&P 500
$
100.00

 
$
102.11

 
$
118.45

 
$
156.82

 
$
178.28

 
$
180.78

S&P O&G E&P
$
100.00

 
$
93.57

 
$
96.99

 
$
123.65

 
$
110.55

 
$
72.80


27



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
 
2015
 
2014
 
2013
 
2012
 
2011
 
 
 
 
 
 
 
 
 
 
 
Statement of Income Data:
 
 
 
 
 
 
 
 
 
 
Net Operating Revenues
 
$
8,757,428

 
$
18,035,340

 
$
14,487,118

 
$
11,682,636

 
$
10,126,115

Operating Income (Loss)
 
$
(6,686,079
)
 
$
5,241,823

 
$
3,675,211

 
$
1,479,797

 
$
2,113,309

Net Income (Loss)
 
$
(4,524,515
)
 
$
2,915,487

 
$
2,197,109

 
$
570,279

 
$
1,091,123

Net Income (Loss) Per Share
 
 
 
 
 
 

 
 

 
 

Basic
 
$
(8.29
)
 
$
5.36

 
$
4.07

 
$
1.07

 
$
2.08

Diluted
 
$
(8.29
)
 
$
5.32

 
$
4.02

 
$
1.05

 
$
2.05

Dividends Per Common Share
 
$
0.670

 
$
0.585

 
$
0.375

 
$
0.340

 
$
0.320

Average Number of Common Shares
 
 
 
 
 
 

 
 

 
 

Basic
 
545,697

 
543,443

 
540,341

 
535,155

 
525,470

Diluted
 
545,697

 
548,539

 
546,227

 
541,524

 
532,536


At December 31
 
2015
 
2014
 
2013
 
2012
 
2011
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and Equipment, Net
 
$
24,210,721

 
$
29,172,644

 
$
26,148,836

 
$
23,337,681

 
$
21,288,824

Total Assets
 
26,975,244

 
34,762,687

 
30,574,238

 
27,336,578

 
24,838,797

Total Debt
 
6,660,264

 
5,909,933

 
5,913,221

 
6,312,181

 
5,009,166

Total Stockholders' Equity
 
12,943,035

 
17,712,582

 
15,418,459

 
13,284,764

 
12,640,904


28



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, the United Kingdom 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.  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 by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves.  Maintaining the lowest possible operating cost structure that is consistent with prudent and safe operations is also an important goal in the implementation of EOG's strategy.

EOG realized a net loss of $4,525 million during 2015 as compared to net income of $2,915 million for 2014. During 2015, impairments of proved oil and gas properties and other assets totaling $6,326 million, $4,141 million net of tax, were recognized primarily due to the decline in commodity prices. At December 31, 2015, EOG's total estimated net proved reserves were 2,118 million barrels of oil equivalent (MMBoe), a decrease of 379 MMBoe from December 31, 2014.  During 2015, net proved crude oil and condensate and natural gas liquids (NGLs) reserves decreased by 126 million barrels (MMBbl), and net proved natural gas reserves decreased by 1,517 billion cubic feet or 253 MMBoe.

Operations

Several important developments have occurred since January 1, 2015.

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 2015, EOG focused on increasing drilling and completion efficiencies, testing methods to improve the recovery factor of oil-in-place and reducing operating costs through efficiency improvements and service cost reductions. These efficiency gains along with realized lower service costs resulted in lower drilling and completion costs and decreased operating expenses. EOG continues to evaluate certain potential crude oil and liquids-rich natural gas exploration and development prospects. On a volumetric basis, as calculated using the 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 71% of United States production during 2015, consistent with 2014. During 2015, drilling occurred primarily in the Eagle Ford, Delaware Basin and North Dakota Bakken plays, where EOG has built an inventory of uncompleted wells. In addition, EOG continues to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins or tactical acquisitions and to evaluate certain potential crude oil and liquids-rich natural gas exploration and development prospects. In 2015, EOG completed four transactions to acquire certain proved crude oil properties and related assets in the Delaware Basin. The aggregate purchase price of the transactions totaled approximately $400 million. EOG's major producing areas in the United States are in New Mexico, North Dakota, Texas, Utah and Wyoming.

During 2015, due to the decline in commodity prices, proved oil and gas properties and related assets in the United States were written down to their fair value resulting in pretax impairment charges of $6,130 million, $3,945 million net of tax. Impairments were related to legacy natural gas assets and marginal liquids plays.

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) and Modified U(b) Block and the Sercan Area (formerly known as the EMZ 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. EOG completed three net wells in 2015, finishing its SECC Block and Modified U(b) Block drilling program that was initiated in 2014. In 2016, EOG expects to complete one net well and install infrastructure in the Sercan Area.

Other International. As previously reported, during the fourth quarter of 2014, EOG completed the divestiture of substantially all its assets in Canada (see Note 17 to the Consolidated Financial Statements). At the time of the sales, production from the divested assets totaled approximately 7,050 barrels of crude oil per day, 580 barrels of NGLs per day and 43.5 million cubic feet of natural gas per day. Information related to EOG's remaining Canadian operations is presented in the "Other International" segment.


29



In the United Kingdom, EOG continues to make progress in the development of its 100% working interest East Irish Sea Conwy crude oil discovery. Modifications to the nearby third-party owned Douglas platform, which will be used to process Conwy production, began in 2013 and continued throughout 2014 and 2015. First production from the Conwy field is anticipated in March 2016. During 2015, EOG recognized a pretax impairment charge of $186 million for the Conwy project as a result of crude oil price declines.

In 2015, EOG drilled four wells and completed three wells, one of which was drilled in 2014, in the Sichuan Basin, Sichuan Province, China. The successful completions extended the Shaximiao development in the Chuan Zhong Block and provides additional opportunities in the future.

EOG's activity in Argentina is focused on the Vaca Muerta oil shale formation in the Neuquén Province. Management is currently evaluating options for its investment.

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.

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 34% at December 31, 2015 and 25% at December 31, 2014.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity. At December 31, 2015, $400 million aggregate principal amount of its 2.500% Senior Notes due 2016 (the 2016 Notes) and $260 million principal amount of commercial paper borrowings were reclassified as long-term debt based upon EOG's intent and ability to ultimately replace such amount with other long-term debt.

On January 14, 2016, EOG closed its sale of $750 million aggregate principal amount of its 4.15% Senior Notes due 2026 and $250 million aggregate principal amount of its 5.10% Senior Notes due 2036 (collectively, the New Notes). Interest on the New Notes is payable semi-annually in arrears on January 15 and July 15 of each year, beginning July 15, 2016. Proceeds from the issuance of the New Notes totaled approximately $991 million and were used to repay the $400 million aggregate principal amount of the 2016 Notes when such notes came due on February 1, 2016 and for general corporate purposes, including the repayment of outstanding commercial paper borrowings and funding of future capital expenditures.

On July 21, 2015, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (2015 Agreement) with domestic and foreign lenders (Banks). The 2015 Agreement replaced EOG's $2.0 billion senior unsecured revolving credit agreement which was canceled by EOG upon the closing of the 2015 Agreement. The 2015 Agreement has a scheduled maturity date of July 21, 2020, and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods, subject to certain terms and conditions. The 2015 Agreement commits the Banks to provide advances up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions.

On June 1, 2015, EOG repaid upon maturity the $500 million aggregate principal amount of its 2.95% Senior Notes due 2015.

On March 17, 2015, EOG closed its sale of $500 million aggregate principal amount of its 3.15% Senior Notes due 2025 and $500 million aggregate principal amount of its 3.90% Senior Notes due 2035 (together, the Notes). Interest on the Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2015. Net proceeds from the Notes offering of approximately $990 million were used for general corporate purposes.

During 2015, EOG funded $5.2 billion in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), repaid at maturity $500 million aggregate principal amount of long-term debt, paid $367 million in dividends to common stockholders and purchased $49 million of treasury stock in connection with stock compensation plans, primarily by utilizing net cash provided from its operating activities, net proceeds from the sale of the Notes, commercial paper borrowings, net proceeds of $193 million from the sale of assets and $26 million of excess tax benefits from stock compensation.

Total anticipated 2016 capital expenditures are estimated to range from approximately $2.4 billion to $2.6 billion, excluding acquisitions. The majority of 2016 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 the 2015 Agreement and equity and debt offerings.

30



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

Results of Operations

The following review of operations for each of the three years in the period ended December 31, 2015, should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning on page F-1.

Net Operating Revenues

During 2015, net operating revenues decreased $9,278 million, or 51%, to $8,757 million from $18,035 million in 2014. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, decreased $6,188 million, or 49%, to $6,404 million in 2015 from $12,592 million in 2014. Revenues from the sales of crude oil and condensate and NGLs in 2015 were approximately 83% of total wellhead revenues compared to 85% in 2014. During 2015, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $62 million compared to net gains of $834 million in 2014. Gathering, processing and marketing revenues decreased $1,793 million during 2015, to $2,253 million from $4,046 million in 2014. Net losses on asset dispositions totaled $9 million in 2015 compared to net gains on asset dispositions of $508 million in 2014.


31



Wellhead volume and price statistics for the years ended December 31, 2015, 2014 and 2013 were as follows:
Year Ended December 31
 
2015
 
2014
 
2013
 
 
 
 
 
 
 
Crude Oil and Condensate Volumes (MBbld) (1)
 
 
 
 
 
 
United States
 
283.3

 
282.0

 
212.1

Trinidad
 
0.9

 
1.0

 
1.2

Other International (2)
 
0.2

 
5.9

 
7.1

Total
 
284.4

 
288.9

 
220.4

Average Crude Oil and Condensate Prices ($/Bbl) (3)
 
 
 
 

 
 

United States
 
$
47.55

 
$
92.73

 
$
103.81

Trinidad
 
39.51

 
84.63

 
90.30

Other International (2)
 
57.32

 
86.75

 
87.08

Composite
 
47.53

 
92.58

 
103.20

Natural Gas Liquids Volumes (MBbld) (1)
 
 
 
 
 
 

United States
 
76.9

 
79.7

 
64.3

Other International (2)
 
0.1

 
0.6

 
0.9

Total
 
77.0

 
80.3

 
65.2

Average Natural Gas Liquids Prices ($/Bbl) (3)
 
 
 
 

 
 

United States
 
$
14.50

 
$
31.84

 
$
32.46

Other International (2)
 
4.61

 
40.73

 
39.45

Composite
 
14.49

 
31.91

 
32.55

Natural Gas Volumes (MMcfd) (1)
 
 
 
 
 
 

United States
 
886

 
920

 
908

Trinidad
 
349

 
363

 
355

Other International (2)
 
30

 
70

 
84

Total
 
1,265

 
1,353

 
1,347

Average Natural Gas Prices ($/Mcf) (3)
 
 
 
 

 
 

United States
 
$
1.97

 
$
3.93

 
$
3.32

Trinidad
 
2.89

 
3.65

 
3.68

Other International (2)
 
5.05

 
4.40

 
3.39

Composite
 
2.30

 
3.88

 
3.42

Crude Oil Equivalent Volumes (MBoed) (4)
 
 
 
 
 
 

United States
 
507.9

 
515.0

 
427.9

Trinidad
 
59.1

 
61.5

 
60.4

Other International (2)
 
5.2

 
18.2

 
21.8

Total
 
572.2

 
594.7

 
510.1

 
 
 
 
 
 
 
Total MMBoe (4)
 
208.9

 
217.1

 
186.2

 
(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.
(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)
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.

32



2015 compared to 2014. Wellhead crude oil and condensate revenues in 2015 decreased $4,807 million, or 49%, to $4,935 million from $9,742 million in 2014, due to a lower composite average wellhead crude oil and condensate price ($4,677 million) and a decrease of 5 MBbld, or 2%, in wellhead crude oil and condensate deliveries ($131 million). The decrease in deliveries primarily reflects decreased production in the North Dakota Bakken, the Fort Worth Barnett Shale area and Other International, partially offset by increased production in the Permian Basin and Eagle Ford. The decrease in Other International is due to the sale of the Canadian assets. EOG's composite wellhead crude oil and condensate price for 2015 decreased 49% to $47.53 per barrel compared to $92.58 per barrel in 2014.

NGL revenues in 2015 decreased $526 million, or 56%, to $408 million from $934 million in 2014, due to a lower composite average price ($490 million) and a decrease of 3 MBbld, or 4%, in NGL deliveries ($36 million). EOG's composite NGL price in 2015 decreased 55% to $14.49 per barrel compared to $31.91 per barrel in 2014.

Wellhead natural gas revenues in 2015 decreased $855 million, or 45%, to $1,061 million from $1,916 million in 2014, primarily due to a lower composite wellhead natural gas price ($730 million) and a decrease in wellhead natural gas deliveries ($125 million). EOG's composite average wellhead natural gas price decreased 41% to $2.30 per Mcf in 2015 compared to $3.88 per Mcf in 2014. Natural gas deliveries in 2015 decreased 7% to 1,265 MMcfd as compared to 1,353 MMcfd in 2014. The decrease in production was due to decreased production in Other International (40 MMcfd), the United States (34 MMcfd) and Trinidad (14 MMcfd). In the United States, decreased production was due primarily to lower production in the Upper Gulf Coast, Fort Worth Barnett Shale and South Texas areas, partially offset by increased production of associated gas in the Eagle Ford and Permian Basin. The decline in Other International primarily reflects the sale of the Canadian assets.

During 2015, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $62 million, which included net cash received from settlements of crude oil and natural gas financial derivative contracts of $730 million. During 2014, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $834 million, which included net cash received from settlements of crude oil and natural gas financial derivative contracts of $34 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 are utilized in order to balance firm transportation capacity with production in certain areas and to utilize excess capacity at EOG-owned facilities. Marketing costs represent the costs of purchasing third-party crude oil and natural gas 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 2015 declined $53 million compared to 2014, primarily due to lower margins on crude oil and natural gas marketing activities and losses on sand sales.

2014 compared to 2013.  Wellhead crude oil and condensate revenues in 2014 increased $1,441 million, or 17%, to $9,742 million from $8,301 million in 2013, due to an increase of 68.5 MBbld, or 31%, in wellhead crude oil and condensate deliveries ($2,558 million), partially offset by a lower composite average wellhead crude oil and condensate price ($1,117 million).  The increase in deliveries primarily reflects increased production in the Eagle Ford, the North Dakota Bakken and the Permian Basin.  EOG's composite wellhead crude oil and condensate price for 2014 decreased 10% to $92.58 per barrel compared to $103.20 per barrel in 2013.

NGL revenues in 2014 increased $160 million, or 21%, to $934 million from $774 million in 2013, due to an increase of 15 MBbld, or 23%, in NGL deliveries ($179 million), partially offset by a lower composite average price ($19 million).  The increase in deliveries primarily reflects increased volumes in the Eagle Ford and the Permian Basin.  EOG's composite NGL price in 2014 decreased 2% to $31.91 per barrel compared to $32.55 per barrel in 2013.

Wellhead natural gas revenues in 2014 increased $235 million, or 14%, to $1,916 million from $1,681 million in 2013, primarily due to a higher composite wellhead natural gas price.  EOG's composite average wellhead natural gas price increased 13% to $3.88 per Mcf in 2014 compared to $3.42 per Mcf in 2013.  Natural gas deliveries in 2014 increased less than 1% to 1,353 MMcfd as compared to 1,347 MMcfd in 2013. Increased production in the United States (12 MMcfd) and Trinidad (8 MMcfd) was offset by lower production in Canada (15 MMcfd). In the United States, increased production of associated natural gas in the Eagle Ford and Permian Basin areas was partially offset by lower production in the Upper Gulf Coast and Fort Worth Basin Barnett Shale areas.


33



During 2014, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $834 million, which included net cash received from settlements of crude oil and natural gas financial derivative contracts of $34 million. During 2013, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $166 million, which included net cash received from settlements of crude oil and natural gas financial derivative contracts of $116 million.

Gathering, processing and marketing revenues less marketing costs in 2014 declined $75 million compared to 2013, primarily due to lower margins on crude oil marketing activities.

Operating and Other Expenses

2015 compared to 2014.  During 2015, operating expenses of $15,444 million were $2,650 million higher than the $12,794 million incurred during 2014.  Operating expenses for 2015 included impairments of proved properties, other property, plant and equipment and other assets of $6,326 million primarily due to commodity price declines. The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2015 and 2014:
 
2015
 
2014
 
 
 
 
Lease and Well
$
5.66

 
$
6.53

Transportation Costs
4.07

 
4.48

Depreciation, Depletion and Amortization (DD&A) -
 
 
 
Oil and Gas Properties
15.27

 
17.90

Other Property, Plant and Equipment
0.59

 
0.53

General and Administrative (G&A)
1.75

 
1.85

Net Interest Expense
1.14

 
0.93

Total (1)
$
28.48

 
$
32.22

 
(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 2015 compared to 2014 are set forth below.  See "Net Operating Revenues" 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 $1,182 million in 2015 decreased $234 million from $1,416 million in 2014 primarily due to lower operating and maintenance costs in the United States ($125 million), lower lease and well expenses in Other International ($99 million) primarily due to the sale of the Canadian assets and lower workover expenditures in the United States ($21 million), partially offset by increased lease and well administrative expenses in the United States ($12 million).

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, costs associated with crude-by-rail operations, 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.


34



Transportation costs of $849 million in 2015 decreased $123 million from $972 million in 2014 primarily due to decreased transportation costs in the Rocky Mountain area ($81 million) and the Eagle Ford ($48 million) primarily due to an increase in the use of pipelines to transport crude oil production, partially offset by increased transportation costs related to higher production from the Permian Basin ($19 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 2015 decreased $683 million to $3,314 million from $3,997 million in 2014.  DD&A expenses associated with oil and gas properties in 2015 were $691 million lower than in 2014 primarily due to lower unit rates in the United States ($513 million) and Trinidad ($28 million), a decrease in production in the United States ($44 million) and lower DD&A expense in Other International ($104 million) primarily due to the sale of the Canadian assets.  Unit rates in the United States decreased primarily due to impairments of proved oil and gas properties (see Note 14 to the Consolidated Financial Statements), upward reserve revisions and reserves added at lower costs as a result of increased efficiencies.

G&A expenses of $367 million in 2015 were $35 million lower than 2014 primarily due to lower employee-related expenses.

Net interest expense of $237 million in 2015 was $36 million higher than 2014 primarily due to interest incurred on the Notes issued in March 2015 ($28 million), as well as a decrease in capitalized interest ($15 million). This was partially offset by the reduction of interest on debt repaid in June 2015 and during 2014 ($11 million).

Exploration costs of $149 million in 2015 decreased $35 million from $184 million in 2014 primarily due to decreased geological and geophysical expenditures in the United States ($19 million) and lower exploration administrative expenses in Other International ($10 million) primarily due to the sale of the Canadian assets.

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.  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 bids as the basis for determining fair value.

Impairments of $6,614 million in 2015 increased $5,870 million from $744 million in 2014 primarily due to increased impairments of proved properties and other assets in the United States ($5,959 million), primarily due to commodity price declines; and increased amortization of unproved property costs in the United States ($112 million), which was caused by higher amortization rates being applied to undeveloped leasehold costs in response to the significant decrease in commodity prices and an increase in EOG's estimates of undeveloped properties not expected to be developed before lease expiration; partially offset by decreased impairments of proved properties in the United Kingdom ($156 million) and Argentina ($43 million). Proved property and other asset impairments in the United States were primarily related to legacy natural gas assets and marginal liquids plays. EOG recorded impairments of proved properties; other property, plant and equipment; and other assets of $6,326 million and $575 million in 2015 and 2014, respectively.

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 2015 decreased $336 million to $422 million (6.6% of wellhead revenues) from $758 million (6.0% of wellhead revenues) in 2014. The decrease in taxes other than income was primarily due to decreases in severance/production taxes ($307 million), primarily as a result of decreased wellhead revenues and lower ad valorem/property taxes ($17 million), both in the United States.


35



Other income, net, was $2 million in 2015 compared to other expense, net, of $45 million in 2014. The increase of $47 million was primarily due to a decrease in net foreign currency transaction losses and decreased deferred compensation expense.

EOG recognized an income tax benefit of $2,397 million in 2015 compared to an income tax expense of $2,080 million in 2014 primarily due to impairments recognized in the United States in 2015. The net effective tax rate for 2015 decreased to 35% from 42% in the prior year primarily due to the effects of recording valuation allowances in the United Kingdom and deferred tax in the United States related to undistributed foreign earnings in 2014.

2014 compared to 2013.  During 2014, operating expenses of $12,794 million were $1,982 million higher than the $10,812 million incurred during 2013.  The following table presents the costs per Boe for the years ended December 31, 2014 and 2013:
 
2014
 
2013
 
 
 
 
Lease and Well
$
6.53

 
$
5.94

Transportation Costs
4.48

 
4.58

DD&A -
 
 
 

Oil and Gas Properties
17.90

 
18.79

Other Property, Plant and Equipment
0.53

 
0.55

G&A
1.85

 
1.87

Net Interest Expense
0.93

 
1.26

Total (1)
$
32.22

 
$
32.99

 
(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 2014 compared to 2013 are set forth below.  See "Net Operating Revenues" above for a discussion of production volumes.

Lease and well expenses of $1,416 million in 2014 increased $310 million from $1,106 million in 2013 primarily due to higher operating and maintenance costs ($209 million), increased workover expenditures ($69 million) and increased lease and well administrative expenses ($32 million), all in the United States.

Transportation costs of $972 million in 2014 increased $119 million from $853 million in 2013 primarily due to increased transportation costs related to production from the Eagle Ford ($99 million) and the Rocky Mountain area ($15 million).

DD&A expenses in 2014 increased $396 million to $3,997 million from $3,601 million in 2013.  DD&A expenses associated with oil and gas properties in 2014 were $384 million higher than in 2013 primarily due to increased production in the United States ($630 million), partially offset by lower unit rates in the United States ($191 million) and Canada ($37 million) and a decrease in production in Canada ($31 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 $402 million in 2014 were $54 million higher than 2013 primarily due to higher costs associated with supporting expanding operations.

Net interest expense of $201 million in 2014 was $34 million lower than 2013 primarily due to repayment of the $400 million aggregate principal amount of the 6.125% Senior Notes due 2013, the Subsidiary Debt and the Floating Rate Notes ($31 million), as well as an increase in capitalized interest across the company ($8 million). This was partially offset by interest expense on the Notes issued in March 2014 ($10 million).

Gathering and processing costs increased $38 million to $146 million in 2014 compared to $108 million in 2013 primarily due to increased activities in the Eagle Ford.

Exploration costs of $184 million in 2014 increased $23 million from $161 million in 2013 primarily due to increased geological and geophysical expenditures in the United States.

36



Impairments of $744 million in 2014 increased $457 million from $287 million in 2013 primarily due to increased impairments of proved properties in the United Kingdom ($351 million), the United States ($145 million) and Argentina ($39 million); and increased amortization of unproved property costs in the United States ($54 million); partially offset by decreased impairments of proved properties in Canada ($67 million) and Trinidad ($14 million); and lower impairments of other assets in the United States ($46 million). EOG recorded impairments of proved properties; other property, plant and equipment; and other assets of $575 million and $172 million in 2014 and 2013, respectively. The 2014 and 2013 amounts include impairments of $503 million and $7 million, respectively, related to certain assets as a result of declining commodity prices and using accepted bids for determining fair value.

Taxes other than income in 2014 increased $134 million to $758 million (6.0% of wellhead revenues) from $624 million (5.8% of wellhead revenues) in 2013.  The increase in taxes other than income was primarily due to increases in severance/production taxes ($112 million) primarily as a result of increased wellhead revenues and higher ad valorem/property taxes ($34 million) in the United States, partially offset by an increase in credits available to EOG in 2014 for Texas high-cost gas severance tax rate reductions ($11 million).

Other expense, net, was $45 million in 2014 compared to $3 million in 2013. The increase of $42 million was primarily due to net foreign currency transaction losses.

Income tax provision of $2,080 million in 2014 increased $840 million from $1,240 million in 2013 due primarily to higher pretax income.  The net effective tax rate for 2014 increased to 42% from 36% in the prior year. The net effective tax rate for 2014 exceeded the United States statutory tax rate (35%) due primarily to valuation allowances in the United Kingdom and deferred tax in the United States related to EOG's undistributed foreign earnings. EOG no longer asserts that foreign earnings will remain permanently reinvested abroad and therefore recorded deferred tax of $250 million on the accumulated balance of such earnings in the fourth quarter of 2014.

Capital Resources and Liquidity

Cash Flow

The primary sources of cash for EOG during the three-year period ended December 31, 2015, were funds generated from operations, net proceeds from issuances of long-term debt, proceeds from asset sales, excess tax benefits from stock-based compensation and net commercial paper borrowings and borrowings under other uncommitted credit facilities.  The primary uses of cash were funds used in operations; exploration and development expenditures; other property, plant and equipment expenditures; repayments of debt; dividend payments to stockholders; and purchases of treasury stock in connection with stock compensation plans.

2015 compared to 2014.  Net cash provided by operating activities of $3,595 million in 2015 decreased $5,054 million from $8,649 million in 2014 primarily reflecting a decrease in wellhead revenues ($6,188 million), unfavorable changes in working capital and other assets and liabilities ($591 million) and an increase in net cash paid for interest expense ($25 million), partially offset by a decrease in cash operating expenses ($741 million), a favorable change in the net cash received from the settlement of financial commodity derivative contracts ($696 million) and a decrease in net cash paid for income taxes ($302 million).

Net cash used in investing activities of $5,320 million in 2015 decreased by $2,194 million from $7,514 million in 2014 primarily due to a decrease in additions to oil and gas properties ($2,795 million); and a decrease in additions to other property, plant and equipment ($439 million); partially offset by unfavorable changes in working capital associated with investing activities ($603 million); a decrease in proceeds from sales of as