8-K

UNITED STATESSECURITIES 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 6, 2013

_______________

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. EmployerIdentification No.)    

1111 Bagby, Sky Lobby 2Houston, 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 2.02Results of Operations and Financial Condition.

On August 6, 2013, EOG Resources, Inc. issued a press release announcing second quarter 2013 financial and operational results and third quarter and full year 2013 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 7.01Regulation FD Disclosure.

Accompanying the press release announcing second quarter 2013 financial and operational results attached hereto as Exhibit 99.1 is third quarter and full year 2013 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 9.01Financial Statements and Exhibits.

(d)Exhibits

99.1Press Release of EOG Resources, Inc. dated August 6, 2013 (including the accompanying third quarter and full year 2013 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 6, 2013	By:	/s/ TIMOTHY K. DRIGGERSTimothy K. DriggersVice 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 6, 2013 (including the accompanying third quarter and full year 2013 forecast and benchmark commodity pricing information).

EX-99.1

EXHIBIT 99.1

EOG Resources, Inc.
News Release
For Further Information Contact:	Investors
	Maire A. Baldwin
	(713) 651-6EOG (651-6364)
	Kimberly A. Matthews
	(713) 571-4676
	Media
	K Leonard
	(713) 571-3870

EOG Resources Reports Second Quarter 2013 Results; Increases 2013 Crude Oil Production Growth Target and Overall Total Production Estimates

· Delivers 35 Percent Year-Over-Year Total Company Crude Oil Production Growth

· Raises 2013 Full Year Crude Oil Production Target to 35 Percent from 28 Percent

· Increases Total Company Overall Production Growth Target to 7.5 Percent from 4 Percent

· Announces Record South Texas Eagle Ford Oil Well

· Extends Bakken/Three Forks Drilling Inventory and Posts Excellent North Dakota Well Results

· Drives Down Costs in Key Areas of Operations

FOR IMMEDIATE RELEASE: Tuesday, August 6, 2013

HOUSTON – EOG Resources, Inc. (EOG) today reported second quarter 2013 net income of $659.7 million, or $2.42 per share. This compares to second quarter 2012 net income of $395.8 million, or $1.47 per share.

Consistent with some analysts' practice of matching realizations to settlement months and making certain other adjustments in order to exclude one-time items, adjusted non-GAAP net income for the second quarter 2013 was $573.8 million, or $2.10 per share. Adjusted non-GAAP net income for the second quarter 2012 was $312.4 million, or $1.16 per share. The results for the second quarter 2013 included net gains on asset dispositions of $9.4 million, net of tax ($0.04 per share), impairments of $2.0 million, net of tax ($0.01 per share) related to the sale of certain non-core North American assets and a previously disclosed non-cash net gain of $191.5 million ($122.6 million after tax, or $0.45 per share) on the mark-to-market of financial commodity contracts. During the quarter, the net cash inflow related to financial commodity contracts was $68.9 million ($44.1 million after tax, or $0.16 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

EOG reported strong, sustained financial growth for the second quarter 2013. Compared to the second quarter 2012, earnings per share increased 65 percent, discretionary cash flow increased 35 percent and adjusted EBITDAX rose 34 percent. (Please refer to the attached tables for the reconciliation of non-GAAP discretionary cash flow to net cash provided by operating activities (GAAP) and adjusted EBITDAX (non-GAAP) to income before interest expense and income taxes (GAAP).)

"EOG has captured premier positions in key U.S. onshore oil plays – the South Texas Eagle Ford, North Dakota Bakken and Delaware Basin, and we continue to enhance their profitability," said Mark G. Papa, Executive Chairman of the Board. "EOG's financial metrics reflect the superior quality of these assets, as well as our technical acumen in improving well completion design and our ongoing focus on reducing costs."

Operational Highlights

EOG's U.S. crude oil and condensate production increased 37 percent both in the second quarter and the first half of 2013, compared to the same periods in 2012. Total company crude oil and condensate production increased 35 percent in the second quarter over the same prior year period. Total company liquids – crude oil, condensate and natural gas liquids (NGLs) – production rose 30 percent, versus the second quarter 2012.

Based on its exceptional performance during the first half of 2013, EOG is increasing its full year crude oil and condensate production growth target to 35 percent from 28 percent. Total NGL production is expected to increase 14 percent from the previous 10 percent target, while natural gas production is projected to decline 11.5 percent during 2013. Overall, EOG is targeting 7.5 percent total company production growth in 2013. EOG also anticipates certain unit costs will be lower than originally forecast.

 "We have the confidence to raise the bar on EOG's performance expectations because our outstanding assets perform better and better, quarter after quarter," said President and Chief Executive Officer William R. "Bill" Thomas. "EOG expects to achieve these higher goals within our previously stated capex estimate."

At June 30, 2013, EOG's Eagle Ford net production of approximately 173,000 barrels of oil equivalent per day, continued to out-perform the rest of the industry.

Since discovering the prolific Eagle Ford, EOG has more than doubled the initial crude oil production rates from its wells in both the western and eastern parts of the play. Efficiency gains from more effective completions and reduced drilling days are resulting in excellent rates of return.

EOG recorded strong well and economic results from its western Eagle Ford acreage where more than a third of its second quarter drilling activity in the play occurred. In La Salle County, EOG's initial production rates and overall well productivity showed a marked improvement, compared to similar completions in the same area three years ago. The Keller #1H and #2H began production at rates of 1,855 and 2,050 barrels of crude oil per day (Bopd) with 75 and 50 barrels per day (Bpd) of NGLs and 430 and 300 thousand cubic feet per day (Mcfd) of natural gas, respectively. The Smart Unit #1H and #2H had initial rates of 1,495 and 2,030 Bopd with 60 and 75 Bpd of NGLs and 340 and 440 Mcfd of natural gas, respectively. The Dossett Unit #1H and #2H were completed to sales at 1,590 and 2,185 Bopd with 85 and 115 Bpd of NGLs and 490 and 655 Mcfd of natural gas, respectively. In McMullen County, the Naylor Jones B #1H started production at 1,830 Bopd with 240 Bpd of NGLs and 1.4 million cubic feet per day (MMcfd) of natural gas. EOG has 100 percent working interest in these seven wells.

EOG again achieved excellent well results in Gonzales County, the northeastern area of its Eagle Ford acreage. The Burrow Unit #3H, #4H and #5H were completed to sales in May at initial production rates of 2,990, 3,030 and 7,515 Bopd with 385, 370 and 860 Bpd of NGLs and 2.2, 2.1 and 5.0 MMcfd of natural gas, respectively. After 30 days, the Burrow Unit #5H, EOG's best Eagle Ford well to date, had an average production rate of 4,265 Bopd. The Wilde Trust Unit #1H, #2H and #3H began production in early June at rates of 5,475, 6,520 and 5,525 Bopd with 880, 710 and 775 Bpd of NGLs and 5.1, 4.1 and 4.5 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these six Gonzales County wells.

"With wells in our western drilling program following the same trend as those in the east, results from the EOG's Eagle Ford activity continue to outpace our expectations," Papa said.

Improved drilling efficiencies and completion technology also have enhanced well productivity in EOG's Bakken/Three Forks operations. During the second quarter, EOG's North Dakota drilling program focused on the Bakken formation. In the Bakken Core, results from 160-acre spacing between wells continue to be encouraging. In Mountrail County, two Core wells drilled on 160-acre spacing, the Parshall 25-3032H and 22-3032H, were completed to sales at 2,685 and 2,120 Bopd, respectively. EOG has 62 percent working interest in these wells. EOG has 78 percent working interest in the Van Hook 29-1113H and 30-1113H, which began production at 2,390 and 2,295 Bopd, respectively, which were also 160-acre spaced wells.

In the Antelope Extension, EOG's other North Dakota development target this year, the Bear Den 20-1708H was completed in the Bakken formation at 2,455 Bopd. EOG has 91 percent working interest in the well.

Based on the success of its current spacing programs, EOG has increased its drilling inventory in the Bakken/Three Forks from seven to 12 years.

EOG remains active in the Delaware Basin Leonard and Wolfcamp, although the plays are constrained by a lack of natural gas processing infrastructure that is being addressed. In Reeves County, Texas, EOG drilled its best Delaware Basin Wolfcamp well to date. EOG has 100 percent working interest in the Phillips State 56 #301H, which was completed to sales at 870 Bopd with 570 Bpd of NGLs and 3.7 MMcfd of natural gas.

EOG completed and brought to sales a number of highly economic wells in the Leonard formation in Lea County, New Mexico. The Diamond 31 Fed Com #2H, #3H and #4H came online at 1,780, 1,905 and 1,530 Bopd with 215, 165 and 150 Bpd of NGLs and 1,200, 910 and 835 Mcfd of natural gas, respectively. EOG has 91 percent working interest in these wells.

"We expect EOG's three high rate-of-return oil plays, the Eagle Ford, Bakken/Three Forks and Delaware Basin, to provide us with years of drilling inventory, as well as significant growth opportunities," Papa said. "These plays just get bigger and better."

Hedging Activity

In recent weeks, EOG has increased the amount of crude oil hedges in place for the remainder of 2013. For the period August 1 through December 31, 2013, EOG has crude oil financial price swap contracts in place for approximately 121,200 Bpd at a weighted average price of $98.82 per barrel, excluding unexercised options.

For the full year 2014, EOG has crude oil financial price swap contracts in place for approximately 51,000 Bpd at a weighted average price of $96.43 per barrel, excluding unexercised options.

EOG also has hedged some natural gas volumes for 2013 and 2014. For the period September 1 through October 31, 2013, EOG has natural gas financial price swap contracts in place for 200,000 million British thermal units per day (MMBtud) at a weighted average price of $4.72 per million British thermal units (MMBtu), excluding unexercised options. For the period November 1 through December 31, 2013, EOG has hedged 150,000 MMBtud at a weighted average price of $4.79 per MMBtu, excluding unexercised options. For the full year 2014, EOG has natural gas financial price swap contracts in place for 170,000 MMBtud at a weighted average price of $4.54 per MMBtu, excluding unexercised options. (For a comprehensive summary of crude oil and natural gas derivative contracts, please refer to the attached tables.)

Capital Structure

To date, EOG has closed on approximately $580 million of asset sales, exceeding its stated goal for the year. At June 30, 2013, EOG's total debt outstanding was $6,313 million for a debt-to-total capitalization ratio of 31 percent. Taking into account cash on the balance sheet of $1,228 million at the end of the second quarter, EOG's net debt was $5,085 million for a net debt-to-total capitalization ratio of 26 percent. (Please refer to the attached tables for the reconciliation of net debt (non-GAAP) to current and long-term debt (GAAP) and the reconciliation of net debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization ratio (GAAP).)

Conference Call Scheduled for August 7, 2013

EOG's second quarter 2013 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Wednesday, August 7, 2013. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through August 21, 2013.

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, Canada, 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, 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 and extent of changes in prices for, 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 can optimize reserve recovery and economically develop its plays utilizing horizontal and vertical drilling, advanced completion technologies and hydraulic fracturing;

· the extent to which EOG is successful in its efforts to economically develop its acreage in, and to produce reserves and achieve anticipated production levels from, its existing and future crude oil and natural gas exploration and development projects, given the risks and uncertainties and capital expenditure requirements inherent in drilling, completing and operating crude oil and natural gas wells and the potential for interruptions of development and production, whether involuntary or intentional as a result of market or other conditions;

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

· the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation 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 laws and regulations relating to air emissions, waste disposal, hydraulic fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws and regulations with respect to derivatives and hedging activities;

· 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 employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials 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 of production, gathering, processing, 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 16 through 23 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2012 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 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).  As noted above, 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, 2012, 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,
	2013			2012			2013			2012
Net Operating Revenues		$	3,840.2		$	2,909.3		$	7,196.7		$	5,716.0
Net Income		$	659.7		$	395.8		$	1,154.4		$	719.8
Net Income Per Share
Basic		$	2.44		$	1.48		$	4.28		$	2.70
Diluted		$	2.42		$	1.47		$	4.24		$	2.67
Average Number of Common Shares
Basic			270.0			266.9			269.7			266.7
Diluted			272.7			270.0			272.5			270.1

SUMMARY INCOME STATEMENTS(Unaudited; in thousands, except per share data)
	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013			2012
Net Operating Revenues
Crude Oil and Condensate	$	2,012,999	$	1,376,250	$	3,794,832		$	2,686,585
Natural Gas Liquids		178,457		150,023		347,986			348,333
Natural Gas		462,602		359,421		873,481			726,705
Gains on Mark-to-Market Commodity Derivative Contracts		191,490		188,449		86,534			322,657
Gathering, Processing and Marketing		959,413		710,748		1,882,370			1,428,905
Gains on Asset Dispositions, Net		13,153		113,290		177,386			180,758
Other, Net		22,071		11,138		34,110			22,027
Total		3,840,185		2,909,319		7,196,699			5,715,970
Operating Expenses
Lease and Well		268,888		250,756		517,888			512,251
Transportation Costs		224,491		135,393		408,748			267,235
Gathering and Processing Costs		25,897		20,588		50,401			46,180
Exploration Costs		47,323		48,149		91,539			90,956
Dry Hole Costs		35,750		11,081		39,712			11,081
Impairments		37,967		54,217		91,515			187,364
Marketing Costs		965,490		694,118		1,870,139			1,399,586
Depreciation, Depletion and Amortization		910,531		808,765		1,756,919			1,557,508
General and Administrative		80,607		75,727		158,592			151,996
Taxes Other Than Income		151,197		118,186		286,128			239,702
Total		2,748,141		2,216,980		5,271,581			4,463,859
Operating Income		1,092,044		692,339		1,925,118			1,252,111
Other Income (Expense), Net		4,833		4,675		(5,301	)		15,306
Income Before Interest Expense and Income Taxes		1,096,877		697,014		1,919,817			1,267,417
Interest Expense, Net		61,647		50,775		123,568			101,044
Income Before Income Taxes		1,035,230		646,239		1,796,249			1,166,373
Income Tax Provision		375,538		250,461		641,832			446,586
Net Income	$	659,692	$	395,778	$	1,154,417		$	719,787
Dividends Declared per Common Share	$	0.1875	$	0.17	$	0.375		$	0.34

EOG RESOURCES, INC.
OPERATING HIGHLIGHTS
(Unaudited)
	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes (MBbld) (A)
United States		206.5		150.5		192.4		140.7
Canada		6.4		6.4		7.1		7.0
Trinidad		1.4		1.7		1.3		1.9
Other International (B)		0.1		0.1		0.1		0.1
Total		214.4		158.7		200.9		149.7
Average Crude Oil and Condensate Prices ($/Bbl) (C)
United States	$	103.73	$	95.80	$	105.04	$	98.61
Canada		89.66		82.78		87.29		86.33
Trinidad		86.96		88.68		90.36		94.76
Other International (B)		92.28		91.20		93.56		96.49
Composite		103.19		95.20		104.31		98.00
Natural Gas Liquids Volumes (MBbld) (A)
United States		63.7		54.6		61.2		52.4
Canada		1.0		0.9		0.9		0.9
Total		64.7		55.5		62.1		53.3
Average Natural Gas Liquids Prices ($/Bbl) (C)
United States	$	30.19	$	33.54	$	30.87	$	38.12
Canada		39.49		42.89		40.62		46.54
Composite		30.33		33.72		31.02		38.27
Natural Gas Volumes (MMcfd) (A)
United States		928		1,070		931		1,067
Canada		79		96		79		100
Trinidad		346		422		349		396
Other International (B)		8		10		8		10
Total		1,361		1,598		1,367		1,573
Average Natural Gas Prices ($/Mcf) (C)
United States	$	3.73	$	2.09	$	3.41	$	2.28
Canada		3.17		2.21		3.21		2.33
Trinidad		3.82		3.42		3.86		3.21
Other International (B)		6.81		5.64		6.78		5.72
Composite		3.73		2.47		3.53		2.54
Crude Oil Equivalent Volumes (MBoed) (D)
United States		424.8		383.3		408.8		370.9
Canada		20.6		23.4		21.2		24.6
Trinidad		59.0		72.0		59.4		67.9
Other International (B)		1.5		1.8		1.4		1.8
Total		505.9		480.5		490.8		465.2
Total MMBoe (D)		46.0		43.7		88.8		84.7

(A)	Thousand barrels per day or million cubic feet per day, as applicable.
(B)	Other International includes EOG's United Kingdom, China 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 equivalents are determined using the 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,
	2013			2012
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,228,016		$	876,435
Accounts Receivable, Net		1,808,954			1,656,618
Inventories		657,400			683,187
Assets from Price Risk Management Activities		105,667			166,135
Income Taxes Receivable		23,450			29,163
Deferred Income Taxes		157,012			-
Other		260,341			178,346
Total		4,240,840			3,589,884
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)		40,262,580			38,126,298
Other Property, Plant and Equipment		2,846,971			2,740,619
Total Property, Plant and Equipment		43,109,551			40,866,917
Less:  Accumulated Depreciation, Depletion and Amortization		(18,529,163	)		(17,529,236	)
Total Property, Plant and Equipment, Net		24,580,388			23,337,681
Other Assets		255,924			409,013
Total Assets	$	29,077,152		$	27,336,578

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	2,201,940	$	2,078,948
Accrued Taxes Payable		161,608		162,083
Dividends Payable		50,614		45,802
Liabilities from Price Risk Management Activities		5,482		7,617
Deferred Income Taxes		4,310		22,838
Current Portion of Long-Term Debt		406,579		406,579
Other		189,770		200,191
Total		3,020,303		2,924,058
Long-Term Debt		5,906,210		5,905,602
Other Liabilities		795,308		894,758
Deferred Income Taxes		4,970,705		4,327,396
Commitments and Contingencies

Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 272,611,848
Shares Issued at June 30, 2013 and 271,958,495 Shares Issued at December 31, 2012		202,726			202,720
Additional Paid in Capital		2,576,441			2,500,340
Accumulated Other Comprehensive Income		408,257			439,895
Retained Earnings		11,228,011			10,175,631
Common Stock Held in Treasury, 277,274 Shares at June 30, 2013 and
326,264 Shares at December 31, 2012		(30,809	)		(33,822	)
Total Stockholders' Equity		14,384,626			13,284,764
Total Liabilities and Stockholders' Equity	$	29,077,152		$	27,336,578

EOG RESOURCES, INC.
SUMMARY STATEMENTS OF CASH FLOWS
(Unaudited; in thousands)
	Six Months Ended
	June 30,
	2013			2012
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$	1,154,417		$	719,787
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		1,756,919			1,557,508
Impairments		91,515			187,364
Stock-Based Compensation Expenses		57,724			55,466
Deferred Income Taxes		488,632			278,826
Gains on Asset Dispositions, Net		(177,386	)		(180,758	)
Other, Net		8,747			(3,404	)
Dry Hole Costs		39,712			11,081
Mark-to-Market Commodity Derivative Contracts
Total Gains		(86,534	)		(322,657	)
Realized Gains		135,959			306,780
Excess Tax Benefits from Stock-Based Compensation		(21,869	)		(22,115	)
Other, Net		7,759			9,890
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(164,809	)		115,419
Inventories		22,085			(103,576	)
Accounts Payable		141,369			176,355
Accrued Taxes Payable		24,816			14,363
Other Assets		(92,305	)		(102,303	)
Other Liabilities		(51,400	)		(27,355	)
Changes in Components of Working Capital Associated with Investing and
Financing Activities		(19,639	)		(97,453	)
Net Cash Provided by Operating Activities		3,315,712			2,573,218
Investing Cash Flows
Additions to Oil and Gas Properties		(3,250,091	)		(3,748,278	)
Additions to Other Property, Plant and Equipment		(183,516	)		(315,542	)
Proceeds from Sales of Assets		579,941			1,111,517
Changes in Restricted Cash		(52,322	)		-
Changes in Components of Working Capital Associated with Investing Activities		19,358			97,746
Net Cash Used in Investing Activities		(2,886,630	)		(2,854,557	)
Financing Cash Flows
Dividends Paid		(97,006	)		(88,892	)
Excess Tax Benefits from Stock-Based Compensation		21,869			22,115
Treasury Stock Purchased		(21,094	)		(22,663	)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan		20,773			32,986
Repayment of Capital Lease Obligation		(2,866	)		-
Other, Net		281			(293	)
Net Cash Used in Financing Activities		(78,043	)		(56,747	)
Effect of Exchange Rate Changes on Cash		542			2,734
Increase (Decrease) in Cash and Cash Equivalents		351,581			(335,352	)
Cash and Cash Equivalents at Beginning of Period		876,435			615,726
Cash and Cash Equivalents at End of Period	$	1,228,016		$	280,374

EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME (NON-GAAP)

TO NET INCOME (GAAP)

(Unaudited; in thousands, except per share data)

The following chart adjusts the three-month and six-month periods ended June 30, 2013 and 2012 reported Net Income (GAAP) to reflect actual net cash realized from financial commodity price transactions by eliminating the unrealized mark-to-market gains from these transactions, to eliminate the net gains on asset dispositions in North America in 2013 and 2012 and to add back impairment charges related to certain of EOG's North American assets in 2013 and 2012.  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						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Reported Net Income (GAAP)	$	659,692		$	395,778		$	1,154,417		$	719,787
Mark-to-Market (MTM) Commodity Derivative Contracts Impact
Total Gains		(191,490	)		(188,449	)		(86,534	)		(322,657	)
Realized Gains		68,909			173,179			135,959			306,780
Subtotal		(122,581	)		(15,270	)		49,425			(15,877	)
After-Tax MTM Impact		(78,482	)		(9,776	)		31,645			(10,165	)
Less: Net Gains on Asset Dispositions, Net of Tax		(9,382	)		(75,087	)		(124,375	)		(118,298	)
Add: Impairments of Certain North American Assets, Net of Tax		2,003			1,526			2,003			38,575
Adjusted Net Income (Non-GAAP)	$	573,831		$	312,441		$	1,063,690		$	629,899
Net Income Per Share (GAAP)
Basic	$	2.44		$	1.48		$	4.28		$	2.70
Diluted	$	2.42	(a)	$	1.47	(b)	$	4.24		$	2.67
Percentage Increase - [(a) - (b)] / (b)		65	%
Adjusted Net Income Per Share (Non-GAAP)
Basic	$	2.13		$	1.17		$	3.94		$	2.36
Diluted	$	2.10		$	1.16		$	3.90		$	2.33
Average Number of Common Shares
Basic		270,016			266,874			269,665			266,718
Diluted		272,739			269,985			272,473			270,083

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, 2013 and 2012 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,
	2013			2012			2013			2012
Net Cash Provided by Operating Activities (GAAP)	$	1,890,777		$	1,495,613		$	3,315,712		$	2,573,218
Adjustments
Exploration Costs (excluding Stock-Based Compensation Expenses)		40,930			41,890			77,575			78,078
Excess Tax Benefits from Stock-Based Compensation		10,196			5,464			21,869			22,115
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(71,948	)		(205,367	)		164,809			(115,419	)
Inventories		(37,143	)		113,784			(22,085	)		103,576
Accounts Payable		44,696			60,270			(141,369	)		(176,355	)
Accrued Taxes Payable		(15,812	)		(19,526	)		(24,816	)		(14,363	)
Other Assets		45,112			(6,537	)		92,305			102,303
Other Liabilities		(1,533	)		22,296			51,400			27,355
Changes in Components of Working Capital Associated with Investing and
Financing Activities		(37,782	)		(126,222	)		19,639			97,453
Discretionary Cash Flow (Non-GAAP)	$	1,867,493	(a)	$	1,381,665	(b)	$	3,555,039		$	2,697,961
Percentage Increase - [(a) - (b)] / (b)		35	%

 

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 INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES (GAAP)

(Unaudited; in thousands)

The following chart adjusts the three-month and six-month periods ended June 30, 2013 and 2012 reported Income 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 realized from financial commodity derivative transactions by eliminating the unrealized mark-to-market (MTM) gains from these transactions and to eliminate the net gains on asset dispositions primarily in North America in 2013 and 2012.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Income 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						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Income Before Interest Expense and Income Taxes (GAAP)	$	1,096,877		$	697,014		$	1,919,817		$	1,267,417
Adjustments:
Depreciation, Depletion and Amortization		910,531			808,765			1,756,919			1,557,508
Exploration Costs		47,323			48,149			91,539			90,956
Dry Hole Costs		35,750			11,081			39,712			11,081
Impairments		37,967			54,217			91,515			187,364
EBITDAX (Non-GAAP)		2,128,448			1,619,226			3,899,502			3,114,326
Total Gains on MTM Commodity Derivative Contracts		(191,490	)		(188,449	)		(86,534	)		(322,657	)
Realized Gains on MTM Commodity Derivative Contracts		68,909			173,179			135,959			306,780
Net Gains on Asset Dispositions		(13,153	)		(113,290	)		(177,386	)		(180,758	)
Adjusted EBITDAX (Non-GAAP)	$	1,992,714	(a)	$	1,490,666	(b)	$	3,771,541		$	2,917,691
Percentage Increase - [(a) - (b)] / (b)		34	%

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 August 6, 2013, 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)
	2013 (1)
	January 2013 (closed)	101,000	$99.29
	February 1, 2013 through April 30, 2013 (closed)	109,000	99.17
	May 1, 2013 through June 30, 2013 (closed)	101,000	99.29
	July 2013 (closed)	111,000	98.25
	August 1, 2013 through September 30, 2013	126,000	98.80
	October 1, 2013 through December 31, 2013	118,000	98.84
	2014 (2)
	January 1, 2014 through March 31, 2014	103,000	$96.48
	April 1, 2014 through June 30, 2014	93,000	96.47
	July 1, 2014 through December 31, 2014	5,000	95.43

(1)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional three-month and six-month periods.  Options covering a notional volume of 8,000 Bbld are exercisable on September 30, 2013.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 8,000 Bbld at an average price of $98.11 per barrel for each month during the period October 1, 2013 through December 31, 2013.  Options covering a notional volume of 64,000 Bbld are exercisable on December 31, 2013.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 64,000 Bbld at an average price of $99.58 per barrel for each month during the period January 1, 2014 through June 30, 2014.

(2)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month and nine-month periods.  Options covering a notional volume of 10,000 Bbld are exercisable on or about March 31, 2014.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 10,000 Bbld at an average price of $96.60 per barrel for each month during the period April 1, 2014 through December 31, 2014.  Options covering a notional volume of 93,000 Bbld are exercisable on or about June 30, 2014.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 93,000 Bbld at an average price of $96.47 per barrel for each month during the period July 1, 2014 through December 31, 2014.  Options covering a notional volume of 5,000 Bbld are exercisable on December 31, 2014.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 5,000 Bbld at an average price of $95.43 per barrel for each month during the period January 1, 2015 through June 30,2015.

NATURAL GAS DERIVATIVE CONTRACTS
			Weighted
		Volume	Average Price
		(MMBtud)	($/MMBtu)
	2013 (3)
	January 1, 2013 through April 30, 2013 (closed)	150,000	$4.79
	May 1, 2013 through August 31, 2013 (closed)	200,000	4.72
	September 1, 2013 through October 31, 2013	200,000	4.72
	November 1, 2013 through December 31, 2013	150,000	4.79
	2014 (4)
	January 1, 2014 through December 31, 2014	170,000	$4.54

(3)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates.  Such options are exercisable monthly up until the settlement date of each monthly contract.  For the period September 1, 2013 through October 31, 2013, if the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 200,000 MMBtud at an average price of $4.72 per MMBtu for each month during that period.  For the period November 1, 2013 through December 31, 2013, if the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for each month during that period.

(4)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates.  Additionally, in connection with certain natural gas derivative contracts settled in July 2012, counterparties retain an option of entering into derivative contracts at future dates.  All such options are exercisable monthly up until the settlement date of each monthly contract.  If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 320,000 MMBtud at an average price of $4.66 per MMBtu for each month during the period January 1, 2014 through December 31, 2014.

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

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
	June 30,
	2013
Total Stockholders' Equity - (a)	$	14,385
Current and Long-Term Debt - (b)		6,313
Less: Cash		(1,228	)
Net Debt (Non-GAAP) - (c)		5,085
Total Capitalization (GAAP) - (a) + (b)	$	20,698
Total Capitalization (Non-GAAP) - (a) + (c)	$	19,470
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]		31	%
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]		26	%

EOG RESOURCES, INC.
THIRD QUARTER AND FULL YEAR 2013 FORECAST AND BENCHMARK COMMODITY PRICING
	(a)  Third Quarter and Full Year 2013 Forecast
The forecast items for the third quarter and full year 2013 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, Canada 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 and Canada 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 2013									Full Year 2013
Daily Production
Crude Oil and Condensate Volumes (MBbld)
United States			207.0		-		224.0					201.0		-		211.0
Canada			6.2		-		6.8					6.0		-		7.0
Trinidad			1.1		-		1.6					1.0		-		1.6
Other International			0.0		-		0.0					0.0		-		0.0
Total			214.3		-		232.4					208.0		-		219.6
Natural Gas Liquids Volumes (MBbld)
United States			62.0		-		66.0					58.9		-		66.9
Canada			0.6		-		1.1					0.7		-		0.8
Total			62.6		-		67.1					59.6		-		67.7
Natural Gas Volumes (MMcfd)
United States			850		-		900					890		-		910
Canada			69		-		76					70		-		80
Trinidad			340		-		360					348		-		368
Other International			7		-		9					7		-		9
Total			1,266		-		1,345					1,315		-		1,367
Crude Oil Equivalent Volumes (MBoed)
United States			410.7		-		440.0					408.2		-		429.6
Canada			18.3		-		20.6					18.4		-		21.1
Trinidad			57.8		-		61.6					59.0		-		62.9
Other International			1.2		-		1.5					1.2		-		1.5
Total			488.0		-		523.7					486.8		-		515.1
									ESTIMATED RANGES
									(Unaudited)
	3Q 2013									Full Year 2013
Operating Costs
Unit Costs ($/Boe)
Lease and Well		$	6.37		-	$	6.62				$	6.05		-	$	6.25
Transportation Costs		$	4.57		-	$	4.82				$	4.45		-	$	4.85
Depreciation, Depletion and Amortization		$	19.50		-	$	20.00				$	19.60		-	$	20.10
Expenses ($MM)
Exploration, Dry Hole and Impairment		$	130.0		-	$	170.0				$	510.0		-	$	540.0
General and Administrative		$	105.0		-	$	115.0				$	360.0		-	$	390.0
Gathering and Processing		$	25.0		-	$	35.0				$	100.0		-	$	130.0
Capitalized Interest		$	12.0		-	$	15.0				$	40.0		-	$	50.0
Net Interest		$	58.0		-	$	60.0				$	226.0		-	$	246.0
Taxes Other Than Income (% of Wellhead Revenue)			5.9	%	-		6.3	%				5.5	%	-		6.5	%
Income Taxes
Effective Rate			30	%	-		40	%				35	%	-		40	%
Current Taxes ($MM)		$	80		-	$	90				$	305		-	$	325
Capital Expenditures ($MM) - FY 2013 (Excluding Acquisitions)
Exploration and Development, Excluding Facilities											$	5,900		-	$	6,000
Exploration and Development Facilities											$	730		-	$	790
Gathering, Processing and Other											$	415		-	$	445
Pricing - (Refer to Benchmark Commodity Pricing in text)
Crude Oil and Condensate ($/Bbl)
Differentials
United States - (above) below WTI		$	(2.00	)	-	$	(3.50	)			$	(5.40	)	-	$	(7.40	)
Canada - (above) below WTI		$	6.50		-	$	9.00				$	7.00		-	$	9.00
Trinidad - (above) below WTI		$	5.00		-	$	7.00				$	4.00		-	$	6.00
Natural Gas Liquids
Realizations as % of WTI
United States			28	%	-		32	%				28	%	-		32	%
Canada			40	%	-		45	%				39	%	-		43	%
Natural Gas ($/Mcf)
Differentials
United States - (above) below NYMEX Henry Hub		$	0.32		-	$	0.40				$	0.24		-	$	0.50
Canada - (above) below NYMEX Henry Hub		$	0.75		-	$	0.85				$	0.47		-	$	0.77
Realizations
Trinidad		$	2.75		-	$	3.25				$	3.00		-	$	3.50
Other International		$	4.95		-	$	5.45				$	5.35		-	$	6.35

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