Current Report Filing (8-k)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 OR 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): August 4, 2016

_______________

EOG RESOURCES, INC.

(Exact name of registrant as specified in its charter)



Delaware (State or other jurisdiction of incorporation)	1-9743 (Commission File Number)	47-0684736 (I.R.S. Employer Identification No.)

1111 Bagby, Sky Lobby 2

Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

713-651-7000

(Registrant's telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

EOG RESOURCES, INC.

Item 2.02 Results of Operations and Financial Condition.

On August 4, 2016, EOG Resources, Inc. issued a press release announcing second quarter 2016 financial and operational results and third quarter and full year 2016 forecast and benchmark commodity pricing information (see Item 7.01 below). A copy of this release is attached as Exhibit 99.1 to this filing and is incorporated herein by reference. This information shall not be deemed to be "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended.

Item 7.01 Regulation FD Disclosure.

Accompanying the press release announcing second quarter 2016 financial and operational results attached hereto as Exhibit 99.1 is third quarter and full year 2016 forecast and benchmark commodity pricing information for EOG Resources, Inc., which information is incorporated herein by reference. This information shall not be deemed to be "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

99.1 Press Release of EOG Resources, Inc. dated August 4, 2016 (including the accompanying third quarter and full year 2016 forecast and benchmark commodity pricing information).

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.



		EOG RESOURCES, INC. (Registrant)



Date: August 4, 2016	By:	/s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Executive Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Officer)

EXHIBIT INDEX



Exhibit No.		Description

99.1	-	Press Release of EOG Resources, Inc. dated August 4, 2016 (including the accompanying third quarter and full year 2016 forecast and benchmark commodity pricing information).

EXHIBIT 99.1



EOG Resources, Inc.	P.O. Box 4362, Houston, TX 77210-4362
News Release
For Further Information Contact:	Investors
	Cedric W. Burgher
	(713) 571-4658
	David J. Streit
	(713) 571-4902
	Kimberly M. Ehmer
	(713) 571-4676

	Media
	K Leonard
	(713) 571-3870

EOG Resources Announces Second Quarter 2016 Results; Increases Premium Well Inventory by 34%


•	Increases Net Premium Inventory to 4,300 Locations and Total Net Premium Resource Potential to 3.5 BnBoe


▪	Premium Inventory Well-Level Rates of Return Exceed 30 Percent at $40 Crude Oil Price


•	Beats All U.S. Production and Operating Cost Targets


•	Raises 2016 U.S. Crude Oil Production Guidance


•	Announces $425 Million in Proceeds from Asset Sales


•	Provides Crude Oil Production Growth Outlook through 2020

FOR IMMEDIATE RELEASE: Thursday, August 4, 2016

HOUSTON - EOG Resources, Inc. (EOG) today reported a second quarter 2016 net loss of $292.6 million, or $0.53 per share. This compares to second quarter 2015 net income of $5.3 million, or $0.01 per share.

Adjusted non-GAAP net loss for the second quarter 2016 was $209.7 million, or $0.38 per share, compared to adjusted non-GAAP net income of $153.1 million, or $0.28 per share, for the same prior year period. Adjusted non-GAAP net income (loss) is calculated by matching hedge realizations to settlement months and making certain other adjustments in order to exclude non-recurring items. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Lower commodity prices more than offset significant well productivity improvements and cost reductions, resulting in decreases in adjusted non-GAAP net income, discretionary cash flow and EBITDAX during the second quarter 2016 compared to the second quarter 2015. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Operational Highlights

In the second quarter 2016, EOG increased its inventory of net premium drilling locations from 3,200 to 4,300. Premium inventory is defined by a direct after-tax rate of return hurdle rate of at least 30 percent assuming $40 flat crude oil prices. Total premium net resource potential increased from 2.0 billion barrels of oil equivalent (BnBoe) to 3.5 BnBoe. These additions were the result of advances in completion technology, precision targeting, longer laterals and cost reductions.

U.S. crude oil volumes of 265,400 barrels of oil per day (Bopd) in the second quarter 2016 exceeded the midpoint of the company’s guidance by 2 percent. Compared to the same prior year period, lease and well expenses decreased 23 percent, and transportation costs decreased 13 percent, both on a per-unit basis. Total general and administrative expenses decreased 5 percent compared to the second quarter 2015, excluding expenses related to a voluntary retirement program.

Exploration and development expenditures (excluding property acquisitions) decreased 49 percent, while total crude oil production declined by only 4 percent, in the second quarter 2016 compared to the same period last year. Total natural gas production for the second quarter 2016 decreased 5 percent versus the same prior year period.

“The benefits of EOG’s premium drilling strategy are beginning to show in our operating performance,” said William R. “Bill” Thomas, Chairman and Chief Executive Officer. “We are committed to focusing capital on our premium assets which we are confident will increasingly lead to break-out performance as prices improve. This quarter’s addition of 1.5 BnBoe of additional premium net resource potential further solidifies our ability to deliver premium returns over the long term.”

2016 Capital Plan Update and 2020 Crude Oil Production Outlook

As a result of cost reductions and efficiency improvements, EOG has increased its targeted number of well completions for 2016 from 270 to 350 net wells. Many of the additional well completions are scheduled for late 2016. In addition, due to increased drilling productivity, the company expects to drill 250 net wells, 50 more than in its original 2016 plans. This increase in activity will be accomplished while maintaining 2016 capital expenditure guidance of $2.4 to $2.6 billion, excluding acquisitions.

EOG can achieve significant production growth with balanced cash flow from 2017 through 2020, even in a moderate commodity price environment. Based on EOG’s long-term plan and assuming a flat $50 West Texas Intermediate crude oil price (WTI), EOG would expect 10 percent compound annual crude oil production growth through 2020. Assuming flat $60 WTI, EOG would expect 20 percent compound annual crude oil production growth through 2020.

“EOG’s long-term outlook reflects superior capital efficiency and continued capital discipline, hallmarks of the company since its founding,” Thomas said. “Our premium drilling strategy is the key to

our future success, and it is underpinned by EOG’s industry-leading asset quality, scale, technology, well performance and low-cost structure. Most importantly, EOG’s high-performance culture prioritizes rates of return over other performance metrics.”

South Texas Eagle Ford

The South Texas Eagle Ford, EOG’s largest high-return play, continues to lead the company in activity and production. In the second quarter, EOG increased its Eagle Ford premium inventory by 390 net drilling locations to almost 2,000 total. This large inventory of high-quality locations could be expanded significantly should additional cost reductions or improvements in well productivity be achieved. For example, EOG estimates that a 10 percent reduction in completed well costs or a 10 percent improvement in estimated recoverable reserves per well would more than double EOG’s premium inventory in the Eagle Ford.

In the second quarter, EOG completed 60 wells in the Eagle Ford with an average treated lateral length of 4,800 feet per well and an average 30-day initial production rate per well of 1,705 barrels of oil equivalent per day (Boed), or 1,340 Bopd, 175 barrels per day (Bpd) of natural gas liquids (NGLs) and 1.1 million cubic feet per day (MMcfd) of natural gas.

Delaware Basin

In the second quarter, EOG expanded its premium inventory in all three of its major Delaware Basin formations - the Wolfcamp, the Second Bone Spring and the Leonard. By organically adding more than 500 net premium drilling locations, EOG is well positioned for years of high-return growth in this world-class basin. EOG continues to improve well economics in the Delaware Basin through advances in well and completion designs, including recent breakthroughs that enable higher productivity with longer laterals.

In the Delaware Basin Wolfcamp, EOG completed 16 wells in the second quarter with an average treated lateral length of 6,500 feet per well, a 44 percent increase in lateral length from the prior quarter. The average 30-day initial production rate per well was 2,410 Boed, or 1,610 Bopd, 340 Bpd of NGLs and 2.8 MMcfd of natural gas. In the Delaware Basin Second Bone Spring, EOG completed nine wells in the second quarter with an average treated lateral length of 4,500 feet per well and an average 30-day initial production rate per well of 1,500 Boed, or 1,120 Bopd, 155 Bpd of NGLs and 1.4 MMcfd of natural gas.

Rockies and the Bakken

EOG is continuing to optimize its core Rockies and Bakken plays, adding 200 additional net premium drilling locations to its inventory in the DJ Basin Codell in Wyoming. The Codell is a liquids-rich sandstone formation that now has significant premium potential due to cost reductions and efficiencies along with the application of EOG’s precision targeting and completion technology.

In the DJ Basin Codell in Wyoming, EOG completed the Jubilee 541-3502H well in the second quarter with average 30-day initial production rates of 1,190 Bopd, 130 Bpd of NGLs and 0.5 MMcfd of natural gas.

In the Powder River Basin Turner, EOG completed the Arbalest 73-06H, 272-06H and 66-0607H wells on the same pad during the second quarter with average 30-day initial production rates per well of 1,000 Bopd, 330 Bpd of NGLs and 3.8 MMcfd of natural gas.

In the North Dakota Bakken, EOG completed the Austin 421-2821H, 422-2821H and 423-2821H wells in a three-well pattern in the second quarter with average 30-day initial production rates per well of 1,100 Bopd, 90 Bpd of NGLs and 0.5 MMcfd of natural gas. Also in the North Dakota Bakken, EOG completed the West Clark 103-0136H and 104-0136H wells in a two-well pattern with average 30-day initial production rates per well of 1,210 Bopd, 390 Bpd of NGLs and 1.8 MMcfd of natural gas.

In the Three Forks, EOG completed the West Clark 117-0136H well in the second quarter with average 30-day initial production rates of 1,290 Bopd, 380 Bpd of NGLs and 1.8 MMcfd of natural gas.

Hedging Activity

For the period March 1 through August 31, 2016, EOG had natural gas financial price swap contracts in place for 60,000 million British thermal units (MMBtu) per day at a weighted average price of $2.49 per MMBtu.

For the period September 1 through November 30, 2016, EOG sold natural gas call option contracts for 43,750 MMBtu per day at an average strike price of $3.45 per MMBtu. For the period March 1 through November 30, 2017, EOG sold natural gas call option contracts for 43,750 MMBtu per day at an average strike price of $3.45 per MMBtu. For the period March 1 through November 30, 2018, EOG sold natural gas call option contracts for 12,500 MMBtu per day at an average strike price of $3.32 per MMBtu.

For the period March 1 through November 30, 2017, EOG purchased natural gas put option contracts for 35,000 MMBtu per day at an average strike price of $2.90 per MMBtu. For the period March 1 through November 30, 2018, EOG purchased natural gas put option contracts for 10,000 MMBtu per day at an average strike price of $2.90 per MMBtu.

A comprehensive summary of natural gas derivative contracts is provided in the attached tables.

Capital Structure and Asset Sales

At June 30, 2016, EOG’s total debt outstanding was $7.0 billion with a debt-to-total capitalization ratio of 37 percent. Taking into account cash on the balance sheet of $780 million at the end of the second quarter, EOG’s net debt was $6.2 billion with a net debt-to-total capitalization ratio of 34 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Proceeds from asset sales this year to date total $425 million. This includes proceeds from two transactions that closed in the third quarter 2016. The assets were divested in more than a dozen separate transactions of non-core natural gas and liquids-rich properties. Associated production of the divested assets was 45 MMcfd of natural gas, 3,300 Bopd and 3,700 Bpd of NGLs. Sales of additional non-core assets are in progress and anticipated to close in 2016.

Conference Call August 5, 2016

EOG’s second quarter 2016 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Friday, August 5, 2016. To listen, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview. The webcast will be archived on EOG’s website through August 19, 2016.

EOG Resources, Inc. 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 Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." For additional information about EOG, please visit www.eogresources.com.

This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:


•	the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;


•	the extent to which EOG is successful in its efforts to acquire or discover additional reserves;


•	the extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;


•	the extent to which EOG is successful in its efforts to market its crude oil and condensate, natural gas liquids, natural gas and related commodity production;


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


•	the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG’s ability to retain mineral licenses and leases;

•

the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations; environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;


•	EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;


•	the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;


•	competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services;


•	the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) and services;


•	the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;


•	weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression and transportation facilities;


•	the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;


•	EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;


•	the extent and effect of any hedging activities engaged in by EOG;


•	the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;


•	political conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates;


•	the use of competing energy sources and the development of alternative energy sources;


•	the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;


•	acts of war and terrorism and responses to these acts;


•	physical, electronic and cyber security breaches; and


•	the other factors described under ITEM 1A, Risk Factors, on pages 13 through 21 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015, and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only “proved” reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also “probable” reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as “possible” reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.

###



EOG RESOURCES, INC. Financial Report (Unaudited; in millions, except per share data)

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2016			2015		2016			2015

Net Operating Revenues	$	1,775.7		$	2,469.7	$	3,130.1		$	4,788.2
Net Income (Loss)	$	(292.6	)	$	5.3	$	(764.3	)	$	(164.5	)
Net Income (Loss) Per Share
Basic	$	(0.53	)	$	0.01	$	(1.40	)	$	(0.30	)
Diluted	$	(0.53	)	$	0.01	$	(1.40	)	$	(0.30	)
Average Number of Common Shares
Basic		547.3			545.5		547.0			545.2
Diluted		547.3			549.7		547.0			545.2



Summary Income Statements (Unaudited; in thousands, except per share data)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Net Operating Revenues
Crude Oil and Condensate	$	1,059,690		$	1,452,756		$	1,813,401		$	2,713,000
Natural Gas Liquids		111,643			103,930			186,962			215,920
Natural Gas		155,983			274,038			321,486			561,820
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts		(44,373	)		(48,493	)		(38,938	)		27,715
Gathering, Processing and Marketing		485,256			678,356			819,209			1,248,626
Losses on Asset Dispositions, Net		(15,550	)		(5,564	)		(6,403	)		(3,957	)
Other, Net		23,091			14,678			34,372			25,115
Total		1,775,740			2,469,701			3,130,089			4,788,239
Operating Expenses
Lease and Well		218,393			289,664			459,258			651,145
Transportation Costs		179,471			209,833			369,925			438,145
Gathering and Processing Costs		29,226			34,997			57,750			71,006
Exploration Costs		30,559			43,755			60,388			83,204
Dry Hole Costs		(172	)		(551	)		74			14,119
Impairments		72,714			68,519			144,331			137,955
Marketing Costs		480,046			670,169			820,900			1,308,831
Depreciation, Depletion and Amortization		862,491			909,227			1,791,382			1,822,015
General and Administrative		97,705			82,324			198,236			166,621
Taxes Other Than Income		93,480			122,138			154,159			228,567
Total		2,063,913			2,430,075			4,056,403			4,921,608

Operating Income (Loss)		(288,173	)		39,626			(926,314	)		(133,369	)

Other Income (Expense), Net		(20,996	)		9,380			(25,433	)		(611	)

Income (Loss) Before Interest Expense and Income Taxes		(309,169	)		49,006			(951,747	)		(133,980	)

Interest Expense, Net		71,108			60,484			139,498			113,829

Loss Before Income Taxes		(380,277	)		(11,478	)		(1,091,245	)		(247,809	)

Income Tax Benefit		(87,719	)		(16,746	)		(326,911	)		(83,329	)

Net Income (Loss)	$	(292,558	)	$	5,268		$	(764,334	)	$	(164,480	)

Dividends Declared per Common Share	$	0.1675		$	0.1675		$	0.3350		$	0.3350



EOG RESOURCES, INC. Operating Highlights (Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2016		2015
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes (MBbld) ^(A)
United States		265.4		276.5		265.6		287.5
Trinidad		0.8		0.7		0.8		0.9
Other International ^(B)		1.5		0.3		1.4		0.2
Total		267.7		277.5		267.8		288.6

Average Crude Oil and Condensate Prices ($/Bbl) ^(C)
United States	$	43.87	$	57.47	$	37.36	$	51.91
Trinidad		35.91		49.53		29.83		44.03
Other International ^(B)		—		62.40		—		56.67
Composite		43.65		57.45		37.23		51.89

Natural Gas Liquids Volumes (MBbld) ^(A)
United States		84.3		73.4		81.8		75.4
Other International ^(B)		—		0.1		—		0.1
Total		84.3		73.5		81.8		75.5

Average Natural Gas Liquids Prices ($/Bbl) ^(C)
United States	$	14.56	$	15.55	$	12.54	$	15.83
Other International ^(B)		—		7.81		—		5.80
Composite		14.56		15.54		12.54		15.82

Natural Gas Volumes (MMcfd) ^(A)
United States		820		891		825		898
Trinidad		349		334		355		336
Other International ^(B)		25		32		25		31
Total		1,194		1,257		1,205		1,265

Average Natural Gas Prices ($/Mcf) ^(C)
United States	$	1.18	$	2.11	$	1.22	$	2.19
Trinidad		1.89		3.05		1.88		3.07
Other International ^(B)		3.35		3.49		3.49		3.39
Composite		1.44		2.40		1.47		2.45

Crude Oil Equivalent Volumes (MBoed) ^(D)
United States		486.3		498.3		484.9		512.6
Trinidad		59.0		56.5		59.9		56.8
Other International ^(B)		5.8		5.7		5.6		5.5
Total		551.1		560.5		550.4		574.9

Total MMBoe ^(D)		50.1		51.0		100.2		104.1


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


(B)	Other International includes EOG's United Kingdom, China, Canada and Argentina operations.


(C)	Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments.

(D)

Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids 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.



EOG RESOURCES, INC. Summary Balance Sheets (Unaudited; in thousands, except share data)

	June 30,			December 31,
	2016			2015
ASSETS
Current Assets
Cash and Cash Equivalents	$	779,722		$	718,506
Accounts Receivable, Net		935,592			930,610
Inventories		495,826			598,935
Income Taxes Receivable		4,880			40,704
Deferred Income Taxes		46,712			147,812
Other		187,389			155,677
Total		2,450,121			2,592,244

Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)		51,355,620			50,613,241
Other Property, Plant and Equipment		4,001,132			3,986,610
Total Property, Plant and Equipment		55,356,752			54,599,851
Less: Accumulated Depreciation, Depletion and Amortization		(32,143,873	)		(30,389,130	)
Total Property, Plant and Equipment, Net		23,212,879			24,210,721
Other Assets		167,538			167,505
Total Assets	$	25,830,538		$	26,970,470


LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	1,305,651		$	1,471,953
Accrued Taxes Payable		138,395			93,618
Dividends Payable		91,679			91,546
Liabilities from Price Risk Management Activities		1,315			—
Current Portion of Long-Term Debt		6,579			6,579
Other		168,642			155,591
Total		1,712,261			1,819,287


Long-Term Debt		6,979,286			6,648,911
Other Liabilities		978,513			971,335
Deferred Income Taxes		4,103,777			4,587,902
Commitments and Contingencies

Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 551,004,831 Shares Issued at June 30, 2016 and 550,150,823 Shares Issued at December 31, 2015		205,510			205,502
Additional Paid in Capital		2,982,047			2,923,461
Accumulated Other Comprehensive Loss		(25,264	)		(33,338	)
Retained Earnings		8,923,666			9,870,816
Common Stock Held in Treasury, 375,869 Shares at June 30, 2016 and 292,179 Shares at December 31, 2015		(29,258	)		(23,406	)
Total Stockholders' Equity		12,056,701			12,943,035
Total Liabilities and Stockholders' Equity	$	25,830,538		$	26,970,470



EOG RESOURCES, INC. Summary Statements of Cash Flows (Unaudited; in thousands)
	Six Months Ended
	June 30,
	2016			2015
Cash Flows from Operating Activities
Reconciliation of Net Loss to Net Cash Provided by Operating Activities:
Net Loss	$	(764,334	)	$	(164,480	)
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		1,791,382			1,822,015
Impairments		144,331			137,955
Stock-Based Compensation Expenses		59,471			61,650
Deferred Income Taxes		(384,294	)		(154,803	)
Losses on Asset Dispositions, Net		6,403			3,957
Other, Net		29,991			6,787
Dry Hole Costs		74			14,119
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses		38,938			(27,715	)
Net Cash Received from Settlements of Commodity Derivative Contracts		2,852			561,142
Excess Tax Benefits from Stock-Based Compensation		(11,811	)		(16,393	)
Other, Net		5,008			6,346
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(22,572	)		298,183
Inventories		95,813			37,609
Accounts Payable		(203,358	)		(999,644	)
Accrued Taxes Payable		93,320			64,124
Other Assets		(33,589	)		76,114
Other Liabilities		1,565			(48,848	)
Changes in Components of Working Capital Associated with Investing and Financing Activities		(54,453	)		169,802
Net Cash Provided by Operating Activities		794,737			1,847,920

Investing Cash Flows
Additions to Oil and Gas Properties		(1,143,549	)		(2,611,848	)
Additions to Other Property, Plant and Equipment		(44,584	)		(201,597	)
Proceeds from Sales of Assets		252,529			116,166
Changes in Components of Working Capital Associated with Investing Activities		54,477			(169,903	)
Net Cash Used in Investing Activities		(881,127	)		(2,867,182	)

Financing Cash Flows
Net Commercial Paper Repayments		(259,718	)		—
Long-Term Debt Borrowings		991,097			990,225
Long-Term Debt Repayments		(400,000	)		(500,000	)
Dividends Paid		(184,036	)		(183,130	)
Excess Tax Benefits from Stock-Based Compensation		11,811			16,393
Treasury Stock Purchased		(28,755	)		(26,362	)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan		10,624			14,484
Debt Issuance Costs		(1,602	)		(1,585	)
Repayment of Capital Lease Obligation		(3,150	)		(3,053	)
Other, Net		(24	)		101
Net Cash Provided by Financing Activities		136,247			307,073

Effect of Exchange Rate Changes on Cash		11,359			(7,629	)

Increase (Decrease) in Cash and Cash Equivalents		61,216			(719,818	)
Cash and Cash Equivalents at Beginning of Period		718,506			2,087,213
Cash and Cash Equivalents at End of Period	$	779,722		$	1,367,395



EOG RESOURCES, INC. Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP) to Net Income (Loss) (GAAP) (Unaudited; in thousands, except per share data)


The following chart adjusts the three-month and six-month periods ended June 30, 2016 and 2015 reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net losses on asset dispositions in 2015 and 2016, to eliminate the impact of the Texas margin tax rate reduction in 2015, to add back severance costs associated with EOG's North American operations in 2015, to eliminate the impact of the Trinidad tax settlement in 2016 and to add back certain voluntary retirement expense in 2016. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

		Three Months Ended												Three Months Ended
		June 30, 2016												June 30, 2015

		Before Tax			Income Tax Impact			After Tax			Diluted Earnings per Share			Before Tax			Income Tax Impact			After Tax			Diluted Earnings per Share
Reported Net Income (Loss) (GAAP)	$	(380,277	)	$	87,719		$	(292,558	)	$	(0.53	)	$	(11,478	)	$	16,746		$	5,268		$	0.01
Adjustments:
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts		44,373			(15,819	)		28,554			0.05			48,493			(17,288	)		31,205			0.06
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		(14,835	)		5,289			(9,546	)		(0.01	)		193,435			(68,960	)		124,475			0.23
Add: Net Losses on Asset Dispositions		15,550			(7,378	)		8,172			0.01			5,564			570			6,134			0.01
Less: Texas Margin Tax Rate Reduction		—			—			—			—			—			(19,500	)		(19,500	)		(0.04	)
Add: Severance Costs		—			—			—			—			8,505			(3,032	)		5,473			0.01
Add: Trinidad Tax Settlement		—			43,000			43,000			0.08			—			—			—			—
Add: Voluntary Retirement Expense		19,663			(7,010	)		12,653			0.02			—			—			—			—
Adjustments to Net Income (Loss)		64,751			18,082			82,833			0.15			255,997			(108,210	)		147,787			0.27

Adjusted Net Income (Loss) (Non-GAAP)	$	(315,526	)	$	105,801		$	(209,725	)	$	(0.38	)	$	244,519		$	(91,464	)	$	153,055		$	0.28

Average Number of Common Shares (GAAP)
Basic											547,335												545,504
Diluted											547,335												549,683

Average Number of Common Shares (Non-GAAP)
Basic											547,335												545,504
Diluted											547,335												549,683



		Six Months Ended												Six Months Ended
		June 30, 2016												June 30, 2015

		Before Tax			Income Tax Impact			After Tax			Diluted Earnings per Share			Before Tax			Income Tax Impact			After Tax			Diluted Earnings per Share
Reported Net Income (Loss) (GAAP)	$	(1,091,245	)	$	326,911		$	(764,334	)	$	(1.40	)	$	(247,809	)	$	83,329		$	(164,480	)	$	(0.30	)
Adjustments:
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts		38,938			(13,881	)		25,057			0.05			(27,715	)		9,880			(17,835	)		(0.03	)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		2,852			(1,017	)		1,835			—			561,142			(200,047	)		361,095			0.66
Add: Net Losses on Asset Dispositions		6,403			(4,168	)		2,235			—			3,957			1,166			5,123			0.01
Less: Texas Margin Tax Rate Reduction		—			—			—			—			—			(19,500	)		(19,500	)		(0.04	)
Add: Severance Costs		—			—			—			—			8,505			(3,032	)		5,473			0.01
Add: Trinidad Tax Settlement		—			43,000			43,000			0.08			—			—			—			—
Add: Voluntary Retirement Expense		42,054			(14,992	)		27,062			0.05			—			—			—			—
Adjustments to Net Income (Loss)		90,247			8,942			99,189			0.18			545,889			(211,533	)		334,356			0.61

Adjusted Net Income (Loss) (Non-GAAP)	$	(1,000,998	)	$	335,853		$	(665,145	)	$	(1.22	)	$	298,080		$	(128,204	)	$	169,876		$	0.31

Average Number of Common Shares (GAAP)
Basic											547,029												545,245
Diluted											547,029												545,245

Average Number of Common Shares (Non-GAAP)
Basic											547,029												545,245
Diluted											547,029												549,505



EOG RESOURCES, INC. Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) to Net Cash Provided by Operating Activities (GAAP) (Unaudited; in thousands)

The following chart reconciles the three-month and six-month periods ended June 30, 2016 and 2015 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG management uses this information for comparative purposes within the industry.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015

Net Cash Provided by Operating Activities (GAAP)	$	503,146		$	887,373		$	794,737		$	1,847,920

Adjustments:
Exploration Costs (excluding Stock-Based Compensation Expenses)		25,527			37,870			48,884			69,967
Excess Tax Benefits from Stock-Based Compensation		11,811			7,535			11,811			16,393
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		154,970			54,917			22,572			(298,183	)
Inventories		(38,235	)		(99,781	)		(95,813	)		(37,609	)
Accounts Payable		(86,269	)		321,769			203,358			999,644
Accrued Taxes Payable		(90,860	)		(62,019	)		(93,320	)		(64,124	)
Other Assets		37,535			(16,938	)		33,589			(76,114	)
Other Liabilities		6,427			16,993			(1,565	)		48,848
Changes in Components of Working Capital Associated with Investing and Financing Activities		56,681			90,190			54,453			(169,802	)

Discretionary Cash Flow (Non-GAAP)	$	580,733		$	1,237,909		$	978,706		$	2,336,940

Discretionary Cash Flow (Non-GAAP) - Percentage Decrease		-53	%					-58	%



EOG RESOURCES, INC. Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) (Non-GAAP) to Net Income (Loss) (GAAP) (Unaudited; in thousands)

The following chart adjusts the three-month and six-month periods ended June 30, 2016 and 2015 reported Net Income (Loss) (GAAP) to Earnings Before Net Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net losses on asset dispositions. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (Loss) (GAAP) to add back Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015

Net Income (Loss) (GAAP)	$	(292,558	)	$	5,268		$	(764,334	)	$	(164,480	)

Adjustments:
Interest Expense, Net		71,108			60,484			139,498			113,829
Income Tax Benefit		(87,719	)		(16,746	)		(326,911	)		(83,329	)
Depreciation, Depletion and Amortization		862,491			909,227			1,791,382			1,822,015
Exploration Costs		30,559			43,755			60,388			83,204
Dry Hole Costs		(172	)		(551	)		74			14,119
Impairments		72,714			68,519			144,331			137,955
EBITDAX (Non-GAAP)		656,423			1,069,956			1,044,428			1,923,313
Total (Gains) Losses on MTM Commodity Derivative Contracts		44,373			48,493			38,938			(27,715	)
Net Cash Received from (Payments for)Settlements of Commodity Derivative Contracts		(14,835	)		193,435			2,852			561,142
Losses on Asset Dispositions, Net		15,550			5,564			6,403			3,957

Adjusted EBITDAX (Non-GAAP)	$	701,511		$	1,317,448		$	1,092,621		$	2,460,697

Adjusted EBITDAX (Non-GAAP) - Percentage Decrease		-47	%					-56	%



EOG RESOURCES, INC. Quantitative Reconciliation of Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as Used in the Calculation of the Net Debt-to-Total Capitalization Ratio (Non-GAAP) to Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) (Unaudited; in millions, except ratio data)

The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry.

	At			At
	June 30,			December 31,
	2016			2015

Total Stockholders' Equity - (a)	$	12,057		$	12,943

Current and Long-Term Debt (GAAP) - (b)		6,986			6,655
Less: Cash		(780	)		(719	)
Net Debt (Non-GAAP) - (c)		6,206			5,936

Total Capitalization (GAAP) - (a) + (b)	$	19,043		$	19,598

Total Capitalization (Non-GAAP) - (a) + (c)	$	18,263		$	18,879

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]		37	%		34	%

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]		34	%		31	%



EOG RESOURCES, INC. Natural Gas Financial Commodity Derivative Contracts

Presented below is a comprehensive summary of EOG's natural gas derivative contracts at August 4, 2016, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method.

Natural Gas Option Contracts
	Call Options Sold			Put Options Purchased
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)		Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2016
September 1, 2016 through November 30, 2016	43,750	$	3.45	—	$	—

2017
March 1, 2017 through November 30, 2017	43,750	$	3.45	35,000	$	2.90

2018
March 1, 2018 through November 30, 2018	12,500	$	3.32	10,000	$	2.90



Definitions
MMBtud		Million British thermal units per day
$/MMBtu		Dollars per million British thermal units

EOG RESOURCES, INC.

Direct After-Tax Rate of Return (ATROR)

The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated proved reserves ("net" to EOG’s interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements.

Direct ATROR

Based on Cash Flow and Time Value of Money

- Estimated future commodity prices and operating costs

- Costs incurred to drill, complete and equip a well, including facilities

Excludes Indirect Capital

- Gathering and Processing and other Midstream

- Land, Seismic, Geological and Geophysical

Payback ~12 Months on 100% Direct ATROR Wells

First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured

Return on Equity / Return on Capital Employed

Based on GAAP Accrual Accounting

Includes All Indirect Capital and Growth Capital for Infrastructure

- Eagle Ford, Bakken, Permian Facilities

- Gathering and Processing

Includes Legacy Gas Capital and Capital from Mature Wells



EOG RESOURCES, INC. Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term (GAAP) and Total Capitalization (GAAP), Respectively (Unaudited; in millions, except ratio data)

The following chart reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.
	2015				2014				2013				2012
Return on Capital Employed (ROCE) (Non-GAAP)

Net Interest Expense (GAAP)	$	237			$	201			$	235
Tax Benefit Imputed (based on 35%)	(83		)		(70		)		(82		)
After-Tax Net Interest Expense (Non-GAAP) - (a)	$	154			$	131			$	153

Net Income (Loss) (GAAP) - (b)	$	(4,525	)		$	2,915			$	2,197
Adjustments to Net Income (Loss), Net of Tax (See Accompanying Schedules)	4,559			(a)	(199		)	(b)	49			(c)
Adjusted Net Income (Non-GAAP) - (c)	$	34			$	2,716			$	2,246

Total Stockholders' Equity - (d)	$	12,943			$	17,713			$	15,418			$	13,285

Average Total Stockholders' Equity * - (e)	$	15,328			$	16,566			$	14,352

Current and Long-Term Debt (GAAP) - (f)	$	6,660			$	5,910			$	5,913			$	6,312
Less: Cash	(719		)		(2,087		)		(1,318		)		(876		)
Net Debt (Non-GAAP) - (g)	$	5,941			$	3,823			$	4,595			$	5,436

Total Capitalization (GAAP) - (d) + (f)	$	19,603			$	23,623			$	21,331			$	19,597

Total Capitalization (Non-GAAP) - (d) + (g)	$	18,884			$	21,536			$	20,013			$	18,721

Average Total Capitalization (Non-GAAP) * - (h)	$	20,210			$	20,775			$	19,367

ROCE (GAAP Net Income) - [(a) + (b)] / (h)	-21.6		%		14.7		%		12.1		%

ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h)	0.9		%		13.7		%		12.4		%

Return on Equity (ROE) (Non-GAAP)

ROE (GAAP Net Income) - (b) / (e)	-29.5		%		17.6		%		15.3		%

ROE (Non-GAAP Adjusted Net Income) - (c) / (e)	0.2		%		16.4		%		15.6		%

* Average for the current and immediately preceding year

Adjustments to Net Income (Loss) (GAAP)



(a) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2015:
	Year Ended December 31, 2015
	Before Tax			Income Tax Impact			After Tax
Adjustments:
Add: Mark-to-Market Commodity Derivative Contracts Impact	$	668		$	(238	)	$	430
Add: Impairments of Certain Assets	6,308			(2,183		)	4,125
Less: Texas Margin Tax Rate Reduction	(20		)	—			(20		)
Add: Legal Settlement - Early Leasehold Termination	19			(6		)	13
Add: Severance Costs	9			(3		)	6
Add: Net Losses on Asset Dispositions	9			(4		)	5
Total	$	6,993		$	(2,434	)	$	4,559



(b) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2014:
	Year Ended December 31, 2014
	Before Tax			Income Tax Impact			After Tax
Adjustments:
Less: Mark-to-Market Commodity Derivative Contracts Impact	$	(800	)	$	285		$	(515	)
Add: Impairments of Certain Assets	824			(271		)	553
Less: Net Gains on Asset Dispositions	(508		)	21			(487		)
Add: Tax Expense Related to the Repatriation of Accumulated Foreign Earnings in Future Years	250			—			250
Total	$	(234	)	$	35		$	(199	)



(c) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2013:
	Year Ended December 31, 2013
	Before Tax			Income Tax Impact			After Tax
Adjustments:
Add: Mark-to-Market Commodity Derivative Contracts Impact	$	283		$	(101	)	$	182
Add: Impairments of Certain Assets	7			(3		)	4
Less: Net Gains on Asset Dispositions	(198		)	61			(137		)
Total	$	92		$	(43	)	$	49



EOG RESOURCES, INC. Third Quarter and Full Year 2016 Forecast and Benchmark Commodity Pricing

(a) Third Quarter and Full Year 2016 Forecast

The forecast items for the third quarter and full year 2016 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast.

(b) Benchmark Commodity Pricing

EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month.

EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month.

	Estimated Ranges (Unaudited)
	3Q 2016			Full Year 2016
Daily Production
Crude Oil and Condensate Volumes (MBbld)
United States	264.0	-	272.0	266.0	-	270.0
Trinidad	0.4	-	0.8	0.6	-	0.8
Other International	4.0	-	8.0	3.0	-	5.0
Total	268.4	-	280.8	269.6	-	275.8

Natural Gas Liquids Volumes (MBbld)
Total	75.0	-	79.0	76.0	-	80.0

Natural Gas Volumes (MMcfd)
United States	740	-	760	775	-	795
Trinidad	325	-	355	330	-	355
Other International	20	-	24	22	-	24
Total	1,085	-	1,139	1,127	-	1,174

Crude Oil Equivalent Volumes (MBoed)
United States	462.3	-	477.7	471.2	-	482.5
Trinidad	54.6	-	60.0	55.6	-	60.0
Other International	7.3	-	12.0	6.7	-	9.0
Total	524.2	-	549.7	533.5	-	551.5



		Estimated Ranges (Unaudited)
		3Q 2016							Full Year 2016
Operating Costs
Unit Costs ($/Boe)
Lease and Well		$	4.50		-	$	5.00		$	4.50		-	$	5.00
Transportation Costs		$	3.75		-	$	4.25		$	3.70		-	$	4.00
Depreciation, Depletion and Amortization		$	17.45		-	$	17.85		$	17.65		-	$	18.00

Expenses ($MM)
Exploration, Dry Hole and Impairment		$	105		-	$	125		$	415		-	$	460
General and Administrative		$	85		-	$	95		$	320		-	$	340
Gathering and Processing		$	28		-	$	32		$	112		-	$	122
Capitalized Interest		$	6		-	$	8		$	30		-	$	33
Net Interest		$	69		-	$	71		$	277		-	$	283

Taxes Other Than Income (% of Wellhead Revenue)			6.3	%	-		6.7	%		6.4	%	-		6.6	%

Income Taxes
Effective Rate			28	%	-		33	%		28	%	-		33	%
Current Taxes ($MM)		$	(15	)	-	$	0		$	50		-	$	70

Capital Expenditures (Excluding Acquisitions, $MM)
Exploration and Development, Excluding Facilities									$	1,925		-	$	2,025
Exploration and Development Facilities									$	350		-	$	400
Gathering, Processing and Other									$	125		-	$	175

Pricing - (Refer to Benchmark Commodity Pricing in text)
Crude Oil and Condensate ($/Bbl)
Differentials
United States - above (below) WTI		$	(3.00	)	-	$	(1.00	)	$	(2.65	)	-	$	(1.65	)
Trinidad - above (below) WTI		$	(10.50	)	-	$	(9.50	)	$	(10.80	)	-	$	(10.30	)
Other International - above (below) WTI		$	(5.00	)	-	$	(3.00	)	$	(5.15	)	-	$	(4.15	)

Natural Gas Liquids
Realizations as % of WTI			30	%	-		34	%		31	%	-		33	%

Natural Gas ($/Mcf)
Differentials
United States - above (below) NYMEX Henry Hub		$	(1.15	)	-	$	(0.50	)	$	(0.90	)	-	$	(0.70	)

Realizations
Trinidad		$	1.70		-	$	2.30		$	1.85		-	$	2.20
Other International		$	3.00		-	$	4.25		$	3.30		-	$	3.80

Definitions
$/Bbl	U.S. Dollars per barrel
$/Boe	U.S. Dollars per barrel of oil equivalent
$/Mcf	U.S. Dollars per thousand cubic feet
$MM	U.S. Dollars in millions
MBbld	Thousand barrels per day
MBoed	Thousand barrels of oil equivalent per day
MMcfd	Million cubic feet per day
NYMEX	New York Mercantile Exchange
WTI	West Texas Intermediate