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 First Quarter 2016 Results and Successful Enhanced Oil Recovery Project

• Completes First Economic Enhanced Oil Recovery Test in U.S. Horizontal Shale Reservoir

▪ Concludes Four Pilot Projects in the Eagle Ford

▪ Adds New Reserve Potential at Single Digit Per Barrel Costs

▪ Generates High Net Present Value

▪ Delivers Rates of Return on Investment Exceeding 30 Percent at $40 Oil Price

▪ Extends EOG’s Horizontal Technology Gains

• Announces Successful South Texas Austin Chalk Exploratory Results

• Reports Strong Quarterly Operating Results, Exceeds U.S. Oil Production and Cost Reduction Targets

FOR IMMEDIATE RELEASE: Thursday, May 5, 2016

HOUSTON - EOG Resources, Inc. (EOG) today reported a first quarter 2016 net loss of $471.8 million, or $0.86 per share. This compares to a first quarter 2015 net loss of $169.7 million, or $0.31 per share.

Adjusted non-GAAP net loss for the first quarter 2016 was $455.4 million, or $0.83 per share, compared to adjusted non-GAAP net income of $16.8 million, or $0.03 per share, for the same prior year period. Adjusted non-GAAP net income (loss) is calculated by matching realizations to settlement months and making certain other adjustments in order to exclude one-time items. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)

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

Operational Highlights

In the first quarter 2016, EOG implemented its previously announced strategy to focus capital in areas which generate premium rates of return. This move significantly improved average well performance and contributed to EOG’s strong production in the first quarter 2016. U.S. crude oil volumes exceeded the high end of the company’s forecast in the first quarter 2016.

In addition, EOG continued to reduce costs across its operations. During the first quarter of 2016, lease and well expenses decreased 29 percent and transportation costs decreased 12 percent compared to the same prior year period, both on a per-unit basis. Total general and administrative expenses decreased 7 percent compared to the first quarter 2015, excluding expenses related to a voluntary retirement program.

EOG’s East Irish Sea Conwy project in the United Kingdom achieved first production in March 2016.

EOG also continued to improve capital efficiency. For the first quarter 2016, exploration and development expenditures (excluding property acquisitions) decreased 61 percent, while total crude oil and condensate production declined by only 10 percent, compared to the first quarter 2015. Total natural gas production for the first quarter 2016 decreased 3 percent versus the prior year period.

“Our premium drilling strategy is extending EOG’s performance leadership in the upstream industry,” said William R. “Bill” Thomas, Chairman and Chief Executive Officer. “Excellent well performance and cost reductions drove tremendous capital efficiency gains and gave EOG a great start on another successful year. EOG is steadily approaching its goal of becoming one of the lowest cost global oil producers through its sustainable advantages in asset quality, technology, cost reductions and operational execution.”

Enhanced Oil Recovery (EOR)

EOG confirmed success of its internally developed EOR process in the Eagle Ford following more than three years of testing in four successful pilot projects with 15 producing wells. These four pilot projects, located across the field, demonstrated consistent reservoir responses from a group of mature producing wells. The pilots generated significant increases in crude oil production with relatively low capital cost. One additional EOR pilot project that encompasses 32 producing wells is planned for 2016.

EOG anticipates many benefits from the application of this new technology, including high incremental net present value and rates of return on investment, low finding and operating costs, reduced severance tax rates, lower production decline rates and increased reservoir recoveries. EOG’s Eagle Ford shale acreage position possesses unique geologic properties ideally suited for the company’s proprietary

EOR techniques. These methods require very strong geologic containment that may not exist in most horizontal oil plays.

“Today’s introduction of EOG’s enhanced oil recovery potential for the Eagle Ford shale is another technical breakthrough to further enhance the value of EOG’s Eagle Ford assets,” Thomas said. “Our proprietary EOR capabilities and first-mover advantages uniquely position the company to create substantial incremental shareholder value through this long-life project.”

South Texas Austin Chalk

EOG expanded its inventory of high rate of return crude oil plays with successful drilling results in the South Texas Austin Chalk, which sits on top of the South Texas Eagle Ford shale. The initial test well, the Leonard AC Unit 101H, came online with average 30-day initial production rates of 2,100 barrels of oil per day (Bopd) with 295 barrels per day (Bpd) of natural gas liquids (NGLs) and 1.9 million cubic feet per day (MMcfd) of natural gas. A second Austin Chalk well, the Denali Unit 101H, was brought online in April 2016, with average 20-day initial production rates of 2,265 Bopd with 415 Bpd of NGLs and 2.7 MMcfd of natural gas. EOG intends to drill seven additional Austin Chalk wells in 2016 to further delineate the formation’s potential.

“EOG continues to demonstrate its organic growth capabilities by discovering a new geologic concept in an existing play,” Thomas said. “Although the industry has known about the Austin Chalk for many years, it took a new approach to turn it into a high rate of return play which competes with EOG’s top-tier assets. We expect the Austin Chalk to make a meaningful contribution to our future success.”

South Texas Eagle Ford

EOG continued to achieve strong well performance and capital efficiencies in the Eagle Ford during the first quarter 2016. In Gonzales County, EOG completed the Stills Unit 2H with average 30-day initial production rates of 2,775 Bopd, 345 Bpd of NGLs and 2.2 MMcfd of natural gas and the Neets Unit 9H with average 30-day initial production rates of 2,355 Bopd, 255 Bpd of NGLs and 1.7 MMcfd of natural gas. Also in Gonzales County, EOG completed the Fleetwood Unit 5H-8H wells in a four-well pattern with average 30-day initial production rates per well of 2,330 Bopd, 320 Bpd of NGLs and 2.1 MMcfd of natural gas. In Lavaca County, EOG completed the Boedeker 18H with average 30-day initial production rates of 2,305 Bopd, 220 Bpd of NGLs and 1.4 MMcfd of natural gas.

Delaware Basin

EOG’s advancements in precision targeting and completions technology continue to drive superior well results and rates of return in the Delaware Basin. In the Delaware Basin Wolfcamp in Lea County,

N.M., EOG completed the Rattlesnake 21 Fed Com #701H and #702H with average 20-day initial production rates of 2,670 and 2,870 Bopd, 450 and 480 Bpd of NGLs and 3.7 and 4.0 MMcfd of natural gas, respectively. Also in the Delaware Basin Wolfcamp in Lea County, N.M., EOG completed the Lomas Rojas 26 State Com #701H - #704H in a four-well pattern with average 30-day initial production rates per well of 1,910 Bopd, 300 Bpd of NGLs and 2.4 MMcfd of natural gas.

EOG continues to improve well and completion designs in the Delaware Basin, which led to increased well productivity in the first quarter 2016.

Hedging Activity

For the period April 12 through April 30, 2016, EOG had crude oil financial price swap contracts in place for 90,000 Bopd at a weighted average price of $42.30 per barrel. For the period May 1 through June 30, 2016, EOG has crude oil financial price swap contracts in place for 128,000 Bopd at a weighted average price of $42.56 per barrel.

For the period March 1 through May 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 June 1 through August 31, 2016, EOG has natural gas financial price swap contracts in place for 60,000 MMBtu per day at a weighted average price of $2.49 per MMBtu.

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

Capital Structure

At March 31, 2016, EOG’s total debt outstanding was $7.0 billion with a debt-to-total capitalization ratio of 36 percent. Taking into account cash on the balance sheet of $668 million at the end of the first quarter, EOG’s net debt was $6.3 billion with a net debt-to-total capitalization ratio of 34 percent. A reconciliation of non-GAAP measures to GAAP measures is provided in the attached tables.

Conference Call May 6, 2016

EOG’s first 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, May 6, 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 May 20, 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."

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
	March 31,
	2016				2015
Net Operating Revenues	$	1,354.3			$	2,318.5
Net Loss	$	(471.8	)		$	(169.7	)
Net Loss Per Share
Basic	$	(0.86	)		$	(0.31	)
Diluted	$	(0.86	)		$	(0.31	)
Average Number of Common Shares
Basic		546.7				545.0
Diluted		546.7				545.0

Summary Income Statements (Unaudited; in thousands, except per share data)
	Three Months Ended
	March 31,
	2016				2015
Net Operating Revenues
Crude Oil and Condensate	$	753,711			$	1,260,244
Natural Gas Liquids		75,319				111,990
Natural Gas		165,503				287,782
Gains on Mark-to-Market Commodity Derivative Contracts		5,435				76,208
Gathering, Processing and Marketing		333,953				570,270
Gains on Asset Dispositions, Net		9,147				1,607
Other, Net		11,281				10,437
Total		1,354,349				2,318,538
Operating Expenses
Lease and Well		240,865				361,481
Transportation Costs		190,454				228,312
Gathering and Processing Costs		28,524				36,009
Exploration Costs		29,829				39,449
Dry Hole Costs		246				14,670
Impairments		71,617				69,436
Marketing Costs		340,854				638,662
Depreciation, Depletion and Amortization		928,891				912,788
General and Administrative		100,531				84,297
Taxes Other Than Income		60,679				106,429
Total		1,992,490				2,491,533
Operating Loss		(638,141	)			(172,995	)
Other Expense, Net		(4,437	)			(9,991	)
Loss Before Interest Expense and Income Taxes		(642,578	)			(182,986	)
Interest Expense, Net		68,390				53,345
Loss Before Income Taxes		(710,968	)			(236,331	)
Income Tax Benefit		(239,192	)			(66,583	)
Net Loss	$	(471,776	)		$	(169,748	)
Dividends Declared per Common Share	$	0.1675			$	0.1675

EOG RESOURCES, INC. Operating Highlights (Unaudited)
	Three Months Ended
	March 31,
	2016				2015
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes (MBbld) (A)
United States		265.8				298.6
Trinidad		0.7				1.0
Other International (B)		1.4				0.1
Total		267.9				299.7
Average Crude Oil and Condensate Prices ($/Bbl) (C)
United States	$	30.87			$	46.71
Trinidad		22.78				39.78
Other International (B)		32.33				43.06
Composite		30.85				46.68
Natural Gas Liquids Volumes (MBbld) (A)
United States		79.4				77.4
Other International (B)		—				0.1
Total		79.4				77.5
Average Natural Gas Liquids Prices ($/Bbl) (C)
United States	$	10.41			$	16.10
Other International (B)		—				2.46
Composite		10.41				16.08
Natural Gas Volumes (MMcfd) (A)
United States		829				905
Trinidad		361				337
Other International (B)		25				31
Total		1,215				1,273
Average Natural Gas Prices ($/Mcf) (C)
United States	$	1.27			$	2.27
Trinidad		1.88				3.09
Other International (B)		3.63				3.28
Composite		1.50				2.51
Crude Oil Equivalent Volumes (MBoed) (D)
United States		483.6				527.1
Trinidad		60.8				57.1
Other International (B)		5.5				5.3
Total		549.9				589.5
Total MMBoe (D)		50.0				53.1

(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)
	March 31,				December 31,
	2016				2015
ASSETS
Current Assets
Cash and Cash Equivalents	$	668,481			$	718,506
Accounts Receivable, Net		780,625				930,610
Inventories		538,926				598,935
Assets from Price Risk Management Activities		4,070				—
Income Taxes Receivable		39,045				40,704
Deferred Income Taxes		177,057				147,812
Other		157,608				155,677
Total		2,365,812				2,592,244
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)		51,159,332				50,613,241
Other Property, Plant and Equipment		4,004,310				3,986,610
Total Property, Plant and Equipment		55,163,642				54,599,851
Less: Accumulated Depreciation, Depletion and Amortization		(31,362,209	)			(30,389,130	)
Total Property, Plant and Equipment, Net		23,801,433				24,210,721
Other Assets		171,178				167,505
Total Assets	$	26,338,423			$	26,970,470
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	1,182,025			$	1,471,953
Accrued Taxes Payable		93,077				93,618
Dividends Payable		91,569				91,546
Current Portion of Long-Term Debt		6,579				6,579
Other		174,722				155,591
Total		1,547,972				1,819,287
Long-Term Debt		6,979,029				6,648,911
Other Liabilities		985,713				971,335
Deferred Income Taxes		4,420,221				4,587,902
Commitments and Contingencies
Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 550,576,063 Shares Issued at March 31, 2016 and 550,150,823 Shares Issued at December 31, 2015		205,506				205,502
Additional Paid in Capital		2,951,861				2,923,461
Accumulated Other Comprehensive Loss		(31,131	)			(33,338	)
Retained Earnings		9,308,463				9,870,816
Common Stock Held in Treasury, 383,609 Shares at March 31, 2016 and 292,179 Shares at December 31, 2015		(29,211	)			(23,406	)
Total Stockholders' Equity		12,405,488				12,943,035
Total Liabilities and Stockholders' Equity	$	26,338,423			$	26,970,470

EOG RESOURCES, INC. Summary Statements of Cash Flows (Unaudited; in thousands)
	Three Months Ended
	March 31,
	2016				2015
Cash Flows from Operating Activities
Reconciliation of Net Loss to Net Cash Provided by Operating Activities:
Net Loss	$	(471,776	)		$	(169,748	)
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		928,891				912,788
Impairments		71,617				69,436
Stock-Based Compensation Expenses		32,380				33,052
Deferred Income Taxes		(196,696	)			(97,241	)
Gains on Asset Dispositions, Net		(9,147	)			(1,607	)
Other, Net		5,442				12,469
Dry Hole Costs		246				14,670
Mark-to-Market Commodity Derivative Contracts
Total Gains		(5,435	)			(76,208	)
Net Cash Received from Settlements of Commodity Derivative Contracts		17,687				367,707
Excess Tax Benefits from Stock-Based Compensation		—				(8,858	)
Other, Net		1,407				1,616
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		132,398				353,100
Inventories		57,578				(62,172	)
Accounts Payable		(289,627	)			(677,875	)
Accrued Taxes Payable		2,460				2,105
Other Assets		3,946				59,176
Other Liabilities		7,992				(31,855	)
Changes in Components of Working Capital Associated with Investing and Financing Activities		2,228				259,992
Net Cash Provided by Operating Activities		291,591				960,547
Investing Cash Flows
Additions to Oil and Gas Properties		(547,399	)			(1,428,733	)
Additions to Other Property, Plant and Equipment		(25,792	)			(116,866	)
Proceeds from Sales of Assets		6,667				1,118
Changes in Components of Working Capital Associated with Investing Activities		(2,228	)			(259,741	)
Net Cash Used in Investing Activities		(568,752	)			(1,804,222	)
Financing Cash Flows
Net Commercial Paper Repayments		(259,718	)			—
Long-Term Debt Borrowings		991,097				990,225
Long-Term Debt Repayments		(400,000	)			—
Dividends Paid		(92,170	)			(91,661	)
Excess Tax Benefits from Stock-Based Compensation		—				8,858
Treasury Stock Purchased		(12,672	)			(15,459	)
Proceeds from Stock Options Exercised		2,688				3,984
Debt Issuance Costs		(1,592	)			(1,603	)
Repayment of Capital Lease Obligation		(1,569	)			(1,521	)
Other, Net		—				(251	)
Net Cash Provided by Financing Activities		226,064				892,572
Effect of Exchange Rate Changes on Cash		1,072				(8,691	)
(Decrease) Increase in Cash and Cash Equivalents		(50,025	)			40,206
Cash and Cash Equivalents at Beginning of Period		718,506				2,087,213
Cash and Cash Equivalents at End of Period	$	668,481			$	2,127,419

EOG RESOURCES, INC. Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP) to Net Loss (GAAP) (Unaudited; in thousands, except per share data)
The following chart adjusts the three-month periods ended March 31, 2016 and 2015 reported Net Loss (GAAP) to reflect actual net cash received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market gains from these transactions, to eliminate the net gains on asset dispositions in 2015 and 2016 and to add back certain voluntary retirement expenses 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 realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for comparative purposes within the industry.
	Three Months Ended
	March 31,
	2016				2015
Reported Net Loss (GAAP)	$	(471,776	)		$	(169,748	)
Commodity Derivative Contracts Impact
Gains on Mark-to-Market Commodity Derivative Contracts		(5,435	)			(76,208	)
Net Cash Received from Settlements of Commodity Derivative Contracts		17,687				367,707
Pre-tax MTM Impact		12,252				291,499
After-Tax MTM Impact		7,884				187,580
Less: Net Gains on Asset Dispositions, Net of Tax (Pre-tax $9,147 and $1,607, respectively)		(5,937	)			(1,011	)
Add: Voluntary Retirements Expense, Net of Tax (Pre-tax $22,391)		14,409				—
Adjusted Net Income (Loss) (Non-GAAP)	$	(455,420	)		$	16,821
Net Loss Per Share (GAAP)
Basic	$	(0.86	)		$	(0.31	)
Diluted	$	(0.86	)		$	(0.31	)
Adjusted Net Income (Loss) Per Share (Non-GAAP)
Basic	$	(0.83	)		$	0.03
Diluted	$	(0.83	)		$	0.03
Adjusted Net Income (Loss) Per Diluted Share (Non-GAAP) - Percentage Decrease		-2,867	%
Average Number of Common Shares (GAAP)
Basic		546,715				544,998
Diluted		546,715				544,998
Average Number of Common Shares (Non-GAAP)
Basic		546,715				544,998
Diluted		546,715				549,401

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 periods ended March 31, 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
	March 31,
	2016				2015
Net Cash Provided by Operating Activities (GAAP)	$	291,591			$	960,547
Adjustments:
Exploration Costs (excluding Stock-Based Compensation Expenses)		23,357				32,097
Excess Tax Benefits from Stock-Based Compensation		—				8,858
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(132,398	)			(353,100	)
Inventories		(57,578	)			62,172
Accounts Payable		289,627				677,875
Accrued Taxes Payable		(2,460	)			(2,105	)
Other Assets		(3,946	)			(59,176	)
Other Liabilities		(7,992	)			31,855
Changes in Components of Working Capital Associated with Investing and Financing Activities		(2,228	)			(259,992	)
Discretionary Cash Flow (Non-GAAP)	$	397,973			$	1,099,031
Discretionary Cash Flow (Non-GAAP) - Percentage Decrease		-64	%

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 Loss Before Interest Expense and Income Taxes (GAAP) (Unaudited; in thousands)
The following chart adjusts the three-month periods ended March 31, 2016 and 2015 reported Loss Before Interest Expense and Income Taxes (GAAP) to Earnings Before 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 settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) gains from these transactions and to eliminate the net gains on asset dispositions. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Loss Before Interest Expense and Income Taxes (GAAP) to add back Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for comparative purposes within the industry.
	Three Months Ended
	March 31,
	2016				2015
Loss Before Interest Expense and Income Taxes (GAAP)	$	(642,578	)		$	(182,986	)
Adjustments:
Depreciation, Depletion and Amortization		928,891				912,788
Exploration Costs		29,829				39,449
Dry Hole Costs		246				14,670
Impairments		71,617				69,436
EBITDAX (Non-GAAP)		388,005				853,357
Total Gains on MTM Commodity Derivative Contracts		(5,435	)			(76,208	)
Net Cash Received from Settlements of Commodity Derivative Contracts		17,687				367,707
Gains on Asset Dispositions, Net		(9,147	)			(1,607	)
Adjusted EBITDAX (Non-GAAP)	$	391,110			$	1,143,249
Adjusted EBITDAX (Non-GAAP) - Percentage Decrease		-66	%

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
	March 31,				December 31,
	2016				2015
Total Stockholders' Equity - (a)	$	12,405			$	12,943
Current and Long-Term Debt (GAAP) - (b)		6,986				6,655
Less: Cash		(668	)			(719	)
Net Debt (Non-GAAP) - (c)		6,318				5,936
Total Capitalization (GAAP) - (a) + (b)	$	19,391			$	19,598
Total Capitalization (Non-GAAP) - (a) + (c)	$	18,723			$	18,879
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]		36	%			34	%
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]		34	%			31	%

EOG RESOURCES, INC. Crude Oil and Natural Gas Financial Commodity Derivative Contracts
Presented below is a comprehensive summary of EOG's crude oil and natural gas derivative contracts at May 5, 2016, with notional volumes expressed in Bbld and MMBtud and prices expressed in $/Bbl and $/MMBtu. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method.
Crude Oil Derivative Contracts
							Weighted
				Volume			Average Price
				(Bbld)			($/Bbl)
2016
April 12, 2016 through April 30, 2016 (closed)				90,000			$	42.30
May 1, 2016 through June 30, 2016				128,000			42.56

Natural Gas Derivative Contracts
							Weighted
				Volume			Average Price
				(MMBtud)			($/MMBtu)
2016
March 1, 2016 through May 31, 2016 (closed)				60,000			$	2.49
June 1, 2016 through August 31, 2016				60,000			2.49

$/Bbl		Dollars per barrel
$/MMBtu		Dollars per million British thermal units
Bbld		Barrels per day
MMBtu		Million British thermal units
MMBtud		Million British thermal units per day

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 comparative purposes within 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
Add: After-Tax Mark-to-Market Commodity Derivative Contracts Impact	430				(515		)		182
Add: Impairments of Certain Assets, Net of Tax	4,125				553				4
Less: Texas Margin Tax Rate Reduction	(20		)		—				—
Add: Legal Settlement - Early Leasehold Termination, Net of Tax	13				—				—
Add: Severance Costs, Net of Tax	6				—				—
Less: Net (Gains) Losses on Asset Dispositions, Net of Tax	5				(487		)		(137		)
Add: Tax Expense Related to the Repatriation of Accumulated Foreign Earnings in Future Years	—				250				—
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

EOG RESOURCES, INC. Second Quarter and Full Year 2016 Forecast and Benchmark Commodity Pricing
(a) Second Quarter and Full Year 2016 Forecast
The forecast items for the second 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)
						2Q 2016								Full Year 2016
Daily Production
Crude Oil and Condensate Volumes (MBbld)
United States						255.0		-		265.0				256.0		-		271.0
Trinidad						0.3		-		0.5				0.4		-		0.6
Other International						4.0		-		8.0				4.0		-		8.0
Total						259.3		-		273.5				260.4		-		279.6
Natural Gas Liquids Volumes (MBbld)
Total						71.0		-		79.0				72.0		-		80.0
Natural Gas Volumes (MMcfd)
United States						785		-		805				770		-		800
Trinidad						290		-		340				290		-		320
Other International						20		-		26				20		-		25
Total						1,095		-		1,171				1,080		-		1,145
Crude Oil Equivalent Volumes (MBoed)
United States						456.8		-		478.2				456.3		-		484.3
Trinidad						48.6		-		57.2				48.7		-		53.9
Other International						7.3		-		12.3				7.3		-		12.2
Total						512.7		-		547.7				512.3		-		550.4

					Estimated Ranges (Unaudited)
					2Q 2016								Full Year 2016
Operating Costs
Unit Costs ($/Boe)
Lease and Well					$	5.00		-	$	5.50			$	5.00		-	$	5.80
Transportation Costs					$	3.70		-	$	4.30			$	3.80		-	$	4.30
Depreciation, Depletion and Amortization					$	17.60		-	$	18.00			$	17.90		-	$	18.40
Expenses ($MM)
Exploration, Dry Hole and Impairment					$	110		-	$	130			$	425		-	$	475
General and Administrative					$	80		-	$	90			$	325		-	$	355
Gathering and Processing					$	30		-	$	35			$	115		-	$	135
Capitalized Interest					$	7		-	$	9			$	28		-	$	32
Net Interest					$	69		-	$	71			$	275		-	$	285
Taxes Other Than Income (% of Wellhead Revenue)						6.8	%	-		7.3	%			6.3	%	-		6.8	%
Income Taxes
Effective Rate						32	%	-		37	%			32	%	-		37	%
Current Taxes ($MM)					$	(50	)	-	$	(35	)		$	(180	)	-	$	(160	)
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					$	(3.50	)	-	$	(1.50	)		$	(3.75	)	-	$	(1.75	)
Trinidad - above (below) WTI					$	(10.75	)	-	$	(9.75	)		$	(13.00	)	-	$	(10.00	)
Other International - above (below) WTI					$	(8.00	)	-	$	(6.00	)		$	(5.25	)	-	$	(3.25	)
Natural Gas Liquids
Realizations as % of WTI						29	%	-		33	%			29	%	-		33	%
Natural Gas ($/Mcf)
Differentials
United States - above (below) NYMEX Henry Hub					$	(1.20	)	-	$	(0.50	)		$	(1.20	)	-	$	(0.50	)
Realizations
Trinidad					$	1.70		-	$	2.30			$	1.75		-	$	2.35
Other International					$	3.00		-	$	4.25			$	3.30		-	$	3.90
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