EOG RESOURCES INC - FORM 8-K - EX-99.1 - EXHIBIT

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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
	David J. Streit
	(713) 571-4902

	Media
	K Leonard
	(713) 571-3870

EOG Resources Announces Outstanding Second Quarter 2014 Results; Increases Common Stock Dividend 34 Percent and Adds Delaware Basin Crude Oil Play


•	Reports 17 Percent Increase in Total Production, Plus 33 Percent Increase in US Crude Oil and Condensate Production Year-Over-Year


•	Raises Common Stock Dividend 34 Percent, Second Increase in 2014


•	Adds Second Bone Spring Sand Crude Oil Play to Portfolio of High Return Assets


•	Realizes Positive Leonard Shale Downspacing Tests


•	Builds on Stellar Eagle Ford and Bakken Success

FOR IMMEDIATE RELEASE: Tuesday, August 5, 2014

HOUSTON - EOG Resources, Inc. (EOG) today reported second quarter 2014 net income of $706.4 million, or $1.29 per share. This compares to second quarter 2013 net income of $659.7 million, or $1.21 per share.

Adjusted non-GAAP net income for the second quarter 2014 was $796.0 million, or $1.45 per share, and adjusted non-GAAP net income for the same prior year period was $573.8 million, or $1.05 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 2014 excluded a previously disclosed non-cash net loss of $229.3 million ($147.0 million after-tax, or $0.27 per share) on the mark-to-market of financial commodity derivative contracts and net gains on asset dispositions of $3.9 million ($1.7 million net of tax, or $0.01 per share). During the second quarter 2014, the net cash outflow related to settlements of financial commodity derivative contracts was

$86.9 million ($55.7 million after-tax, or $0.10 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

For the first half 2014, EOG posted strong financial metrics driven by reinvestment of capital into high rate-of-return drilling opportunities. Discretionary cash flow increased 22 percent and adjusted EBITDAX advanced 24 percent. In addition, adjusted non-GAAP earnings per share increased 46 percent, compared to the first half 2013. (Please refer to the attached tables for the reconciliation of non-GAAP discretionary cash flow to net cash provided by operating activities (GAAP), adjusted non-GAAP EBITDAX to income before interest expense and income taxes (GAAP) and adjusted non-GAAP net income to GAAP net income.)

Dividend Increase

The board of directors increased the cash dividend on the common stock by 34 percent. Effective with the dividend payable October 31, 2014, to holders of record as of October 17, 2014, the board declared a quarterly dividend of $0.1675 per share on the common stock. The indicated annual rate of $0.67 per share represents the 16^th increase in 15 years.

“EOG’s bottom line is a reflection of our top quality drilling operations and return focused capital investments,” said William R. “Bill” Thomas, Chairman and Chief Executive Officer. “Because EOG has demonstrated its ability to sustain crude oil growth and reinvest cash flows in high return assets, we’ve increased the common stock dividend for the second time this year, enhancing long-term value for our stockholders.”

Operational Highlights

In the U.S., crude oil and condensate production increased 33 percent in the second quarter 2014, compared to the same prior year period. Production gains from the South Texas Eagle Ford and North Dakota Bakken led EOG’s U.S. crude oil production growth. Driven by the South Texas Eagle Ford and the Permian Basin, natural gas liquids (NGLs) production increased 22 percent, compared to the second quarter 2013. Natural gas production slightly increased due to EOG’s Trinidad operations and strong associated gas production in the U.S. Overall, total company production increased 17 percent.

Delaware Basin

EOG expanded its inventory of crude oil plays with successful drilling results in the Second Bone Spring Sand, which underlies its extensive Leonard Shale acreage position in Lea and Eddy counties, New Mexico. Through the application of advanced completion techniques, EOG realized robust results from two recent wells. The Mars 3 State #1H, in which EOG has 67 percent working interest, came online at 1,270 barrels of oil per day (Bopd) with 150 barrels per day (Bpd) of NGLs and 1.1 million cubic feet per day (MMcfd) of natural gas. EOG has 100 percent working interest in the Jolly Roger 16 State #1H, which had an initial production rate of 1,450 Bopd with 210 Bpd of NGLs and 1.5 MMcfd of natural gas.

While EOG estimates the play may be prospective over the majority of its 73,000 net Leonard acres, evaluation and confirmation is ongoing. Across the Second Bone Spring Sand, EOG’s production mix is estimated to be approximately 70 percent crude oil with average estimated gross reserves per well of 500 thousand barrels of oil equivalent. Plans are to drill several more wells in the Second Bone Spring Sand in 2014 and increase activity in 2015.

In the West Texas and southeast New Mexico Leonard Shale play, EOG continues to enhance completions and test well spacing both within and across zones to maximize recovery of the hydrocarbons in place.

Over the last 12 months, EOG has systematically tightened spacing from 660 to 300 feet between wells to test production interference between Leonard ‘A’ wells. In Lea County, EOG completed a 500-foot spacing test by drilling the Dragon 36 State #05H, #06H, #07H and #08H. The wells were turned to production at initial rates of 1,100, 1,500, 1,270 and 1,360 Bopd, respectively. EOG has 100 percent working interest in these Leonard ‘A’ zone wells that had associated NGL production of 200, 195, 235 and 235 Bpd and 1.1, 1.1, 1.3 and 1.3 MMcfd of natural gas, respectively.

The most recent successful pilot in Loving County is a three-well pattern, also in the Leonard ‘A’ zone. The Gemini #1H, #2H and #3H were drilled 300 feet apart and turned to production at initial rates of 1,120, 1,530 and 1,290 Bopd, respectively. These Leonard ‘A’ zone wells, in which EOG has 48 percent, 100 percent and 48 percent working interest, respectively, had associated NGL production of 185, 220 and 200 Bpd and 1.0, 1.2 and 1.1 MMcfd of natural gas, respectively.

In addition, EOG has completed two strong Leonard ‘B’ zone wells, one drilled as part of a two-well pattern offsetting an ‘A’ zone well. In Lea County, the Falcon 25 Fed #2H began sales from the ‘B’ zone at 920 Bopd with 120 Bpd of NGLs and 660 thousand cubic feet per day (Mcfd) of natural gas. In Loving County, the Mercury State #2H also was completed in the ‘B’ zone, flowing 1,630 Bopd with 230 Bpd of NGLs and 1.3 MMcfd of natural gas. Offsetting the Mercury State #2H by 250 feet, the Mercury State #1H was completed in the ‘A’ zone at 1,700 Bopd with 360 Bpd of NGLs and 2.0 MMcfd of natural gas. EOG has 100 percent working interest in these three wells. Positive initial results from the Falcon 25 Fed #2H and the Mercury State #2H wells support additional downspacing tests of the Leonard ‘B’ zone.

Using early production results from the tightly spaced Gemini ‘A’ zone wells and the Mercury State wells drilled across zones ‘A’ and ‘B’, EOG is evaluating various downspacing options that could significantly increase the number of drilling locations across its Leonard acreage.

“The Second Bone Spring Sand is yet another example of how EOG organically increases its high return crude oil inventory. Its potential, combined with downspacing results from the Leonard Shale play, positions EOG for steady long-term exploration and development activity in the Delaware Basin. We have

the momentum to unlock additional high rate-of-return growth from EOG’s oil-rich acreage for years to come,” Thomas said.

In Reeves County, Texas, EOG reported a number of successful wells from its 134,000 net acre position in the Delaware Basin Wolfcamp play. The State Apache 57 #1103H, #1104H, #1105H and #1107H were completed at initial rates ranging from 590 to 1,600 Bopd with 200 to 460 Bpd of NGLs and 1.3 to 3.0 MMcfd of natural gas. Also in Reeves County, the State Harrison Ranch 56 #302H and #303H began sales at 660 and 665 Bopd with 275 and 450 Bpd of NGLs and 1.8 and 2.9 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these six wells. EOG continues to test various well spacing patterns and zones on its Delaware Basin Wolfcamp acreage.

Eagle Ford

EOG’s South Texas Eagle Ford crude oil play again contributed significantly to total company second quarter crude oil production growth. Associated NGL and natural gas production also contributed to total company growth. Maintaining a robust drilling and completion program across its Eagle Ford acreage, EOG is further improving individual well results by modifying completion techniques and reducing drilling days.

In Karnes County, the McCoy Unit #1H and #2H began production at 5,290 and 5,415 Bopd with 475 and 415 Bpd of NGLs and 2.7 and 2.4 MMcfd of natural gas, respectively. EOG has 90 percent working interest in these wells. The Wolf Unit #6H, #7H, #8H and #9H, in which EOG has 100 percent working interest, began sales at rates ranging from 3,160 to 3,600 Bopd with 310 to 390 Bpd of NGLs and 1.8 to 2.3 MMcfd of natural gas.

Northeast of Karnes in DeWitt County, the Justiss Unit #11H, #12H and #13H had initial production rates of 4,000, 3,900 and 4,130 Bopd with 690, 650 and 750 Bpd of NGLs and 4.0, 3.8 and 4.3 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these three wells.

In Gonzales County, EOG recorded a number of wells with robust initial production including the Boothe Unit #11H and #16H, which had rates of 4,570 and 3,245 Bopd with 580 and 500 Bpd of NGLs and 3.4 and 2.9 MMcfd of natural gas, respectively. The Zimmerman Unit #14H began sales at 3,800 Bopd with 350 Bpd of NGLs and 2.0 MMcfd of natural gas. EOG has 100 percent working interest in these three wells.

Southwest of Gonzales in LaSalle County, the Naylor Jones Unit 127 #1H, #2H and #3H had initial production rates ranging from 2,200 to 2,500 Bopd with 220 to 250 Bpd of NGLs and 1.3 to 1.5 MMcfd of natural gas. EOG has 100 percent, 100 percent and 75 percent working interest in these wells, respectively.

North Dakota Bakken

In the North Dakota Bakken, EOG is concentrating activity on its Core acreage in Mountrail County. Well productivity is improving markedly due to continued refinements in completion designs. Three Core wells, the Wayzetta 43-0311H, 44-0311H and 45-0311H, were completed during the second quarter at 1,505, 2,410 and 2,690 Bopd, respectively. EOG has 75 percent working interest in these wells. EOG continues to drill and evaluate production data from various spacing patterns in order to maximize the value of this asset. In addition, EOG plans to drill several Three Forks wells to test various benches of this play on both its Core and Antelope Extension acreage during the remainder of 2014.

Wyoming

In the Wyoming DJ Basin, EOG is simultaneously developing the stacked Codell and Niobrara formations from multi-well pad locations in Laramie County, Wyoming. During the second quarter, the Jubilee 586-1705H, the second well completed from a multi-well pad, began production from the Codell at an initial rate of 1,145 Bopd with 445 Mcfd of rich natural gas. EOG has 75 percent working interest in the well. A number of wells are targeted to begin production in August through year-end. EOG plans to test well spacing patterns and various completion techniques in both the Codell and Niobrara formations. EOG has increased its acreage position in the Codell by 13,000 net acres to 85,000 net acres.

In the Wyoming Powder River Basin, EOG is maintaining a steady drilling program with denser pad drilling operations. In the Parkman play, the Mary’s Draw 404-21H and 468-34H, which were drilled from the same pad, had initial production rates of 1,045 and 980 Bopd with 305 and 330 Mcfd of rich natural gas, respectively. EOG has 99 percent and 100 percent working interest in the wells, respectively.

“To summarize our position, EOG is extending its lead as the largest crude oil producer in the onshore U.S. Lower 48. We continue to grow the size and quality of our drilling inventory by generating excellent new plays internally and increasing the drilling potential of our existing plays,” Thomas said. “EOG is leading its peers in terms of barrels per day of crude oil growth, while our forecast ROE and ROCE metrics exceed the average of all upstream energy sectors, including the majors.”

Crude Oil and Natural Gas Hedging Activity

For the period August 1 through December 31, 2014, EOG has crude oil financial price swap contracts in place for 194,000 Bopd at a weighted average price of $96.19 per barrel. For the calendar year 2015, EOG has no crude oil financial derivative contracts in place, excluding unexercised options.

For the period September 1 through December 31, 2014, EOG has natural gas financial price swap contracts in place for 330,000 million British thermal units per day (MMBtud) at a weighted average price of $4.55 per million British thermal units (MMBtu), excluding unexercised options.

For the period January 1 through December 31, 2015, EOG has natural gas financial price swap contracts in place for 175,000 MMBtud at a weighted average price of $4.51 per MMBtu, excluding

unexercised options. (For a comprehensive summary of crude oil and natural gas derivative contracts, please refer to the attached tables.)

Cash Flow and Capital Structure

At June 30, 2014, EOG’s total debt outstanding was $5,910 million for a debt-to-total capitalization ratio of 26 percent. Taking into account cash on the balance sheet of $1.2 billion at June 30, EOG’s net debt was $4,680 million for a net debt-to-total capitalization ratio of 22 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).)

EOG is targeting 29 percent total company crude oil production growth in 2014. Total company production is expected to rise 14 percent, an increase from the previous 12 percent estimate. Capital expenditures are anticipated to range from $8.1 billion to $8.3 billion for 2014, unchanged from prior estimates.

Conference Call August 6, 2014

EOG’s second quarter 2014 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Wednesday, August 6, 2014. To listen, log on to www.eogresources.com. The webcast will be archived on EOG’s website through August 20, 2014.

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 is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and optimize 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, 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 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 17 through 26 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013 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, 2013, 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,
	2014		2013		2014		2013

Net Operating Revenues	$	4,187.6	$	3,840.2	$	8,271.2	$	7,196.7
Net Income	$	706.4	$	659.7	$	1,367.3	$	1,154.4
Net Income Per Share
Basic	$	1.30	$	1.22	$	2.52	$	2.14
Diluted	$	1.29	$	1.21	$	2.49	$	2.12
Average Number of Common Shares
Basic		543.1		540.0		542.7		539.3
Diluted		548.7		545.5		548.0		544.9



SUMMARY INCOME STATEMENTS (Unaudited; in thousands, except per share data)

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2014			2013		2014			2013
Net Operating Revenues
Crude Oil and Condensate	$	2,618,975		$	2,012,999	$	5,016,077		$	3,794,832
Natural Gas Liquids		247,973			178,457		494,208			347,986
Natural Gas		509,091			462,602		1,065,784			873,481
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts		(229,270	)		191,490		(385,006	)		86,534
Gathering, Processing and Marketing		1,027,795			959,413		2,043,206			1,882,370
Gains on Asset Dispositions, Net		3,856			13,153		15,354			177,386
Other, Net		9,136			22,071		21,604			34,110
Total		4,187,556			3,840,185		8,271,227			7,196,699
Operating Expenses
Lease and Well		346,458			268,888		667,292			517,888
Transportation Costs		240,579			224,491		483,816			408,748
Gathering and Processing Costs		32,470			25,897		66,394			50,401
Exploration Costs		42,208			47,323		90,266			91,539
Dry Hole Costs		5,558			35,750		13,906			39,712
Impairments		39,035			37,967		152,396			91,515
Marketing Costs		1,043,515			965,490		2,049,819			1,870,139
Depreciation, Depletion and Amortization		996,602			910,531		1,943,093			1,756,919
General and Administrative		90,932			80,607		173,794			158,592
Taxes Other Than Income		205,469			151,197		401,442			286,128
Total		3,042,826			2,748,141		6,042,218			5,271,581

Operating Income		1,144,730			1,092,044		2,229,009			1,925,118

Other Income (Expense), Net		7,950			4,833		4,612			(5,301	)

Income Before Interest Expense and Income Taxes		1,152,680			1,096,877		2,233,621			1,919,817

Interest Expense, Net		51,867			61,647		102,019			123,568

Income Before Income Taxes		1,100,813			1,035,230		2,131,602			1,796,249

Income Tax Provision		394,460			375,538		764,321			641,832

Net Income	$	706,353		$	659,692	$	1,367,281		$	1,154,417

Dividends Declared per Common Share	$	0.1250		$	0.0938	$	0.2500		$	0.1875



Note: All share and per-share amounts shown have been restated to reflect the announced 2-for-1 stock split effective March 31, 2014.



EOG RESOURCES, INC. OPERATING HIGHLIGHTS (Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes (MBbld) ^(A)
United States		274.6		206.5		266.4		192.4
Canada		5.6		6.4		6.4		7.1
Trinidad		1.0		1.4		1.0		1.3
Other International ^(B)		0.1		0.1		0.1		0.1
Total		281.3		214.4		273.9		200.9

Average Crude Oil and Condensate Prices ($/Bbl) ^(C)
United States	$	102.66	$	103.73	$	101.66	$	105.04
Canada		94.66		89.66		92.05		87.29
Trinidad		94.25		86.96		92.09		90.36
Other International ^(B)		91.27		92.28		89.10		93.56
Composite		102.47		103.19		101.40		104.31

Natural Gas Liquids Volumes (MBbld) ^(A)
United States		78.5		63.7		74.7		61.2
Canada		0.7		1.0		0.7		0.9
Total		79.2		64.7		75.4		62.1

Average Natural Gas Liquids Prices ($/Bbl) ^(C)
United States	$	34.35	$	30.19	$	36.12	$	30.87
Canada		40.90		39.49		44.15		40.62
Composite		34.41		30.33		36.20		31.02

Natural Gas Volumes (MMcfd) ^(A)
United States		925		928		910		931
Canada		67		79		65		79
Trinidad		380		346		384		349
Other International ^(B)		11		8		9		8
Total		1,383		1,361		1,368		1,367

Average Natural Gas Prices ($/Mcf) ^(C)
United States	$	4.14	$	3.73	$	4.54	$	3.41
Canada		4.72		3.17		4.71		3.21
Trinidad		3.69		3.82		3.66		3.86
Other International ^(B)		4.39		6.81		5.04		6.78
Composite		4.04		3.73		4.31		3.53

Crude Oil Equivalent Volumes (MBoed) ^(D)
United States		507.2		424.8		492.7		408.8
Canada		17.4		20.6		18.1		21.2
Trinidad		64.5		59.0		65.0		59.4
Other International ^(B)		1.9		1.5		1.5		1.4
Total		591.0		505.9		577.3		490.8

Total MMBoe ^(D)		53.8		46.0		104.5		88.8


(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,
	2014			2013
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,230,140		$	1,318,209
Accounts Receivable, Net		1,902,248			1,658,853
Inventories		667,108			563,268
Assets from Price Risk Management Activities		-			8,260
Income Taxes Receivable		24,527			4,797
Deferred Income Taxes		485,507			244,606
Other		415,215			274,022
Total		4,724,745			4,072,015

Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)		46,270,734			42,821,803
Other Property, Plant and Equipment		3,374,278			2,967,085
Total Property, Plant and Equipment		49,645,012			45,788,888
Less: Accumulated Depreciation, Depletion and Amortization		(21,449,581	)		(19,640,052	)
Total Property, Plant and Equipment, Net		28,195,431			26,148,836
Other Assets		382,258			353,387
Total Assets	$	33,302,434		$	30,574,238

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	2,661,473		$	2,254,418
Accrued Taxes Payable		228,569			159,365
Dividends Payable		67,865			50,795
Liabilities from Price Risk Management Activities		338,318			127,542
Current Portion of Long-Term Debt		6,579			6,579
Other		234,683			263,017
Total		3,537,487			2,861,716


Long-Term Debt		5,903,099			5,906,642
Other Liabilities		991,450			865,067
Deferred Income Taxes		6,162,010			5,522,354
Commitments and Contingencies

Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 547,951,875 Shares Issued at June 30, 2014 and 546,378,440 Shares Issued at December 31, 2013		205,482			202,732
Additional Paid in Capital		2,728,482			2,646,879
Accumulated Other Comprehensive Income		426,588			415,834
Retained Earnings		13,398,901			12,168,277
Common Stock Held in Treasury, 515,079 Shares at June 30, 2014 and 206,830 Shares at December 31, 2013		(51,065	)		(15,263	)
Total Stockholders' Equity		16,708,388			15,418,459
Total Liabilities and Stockholders’ Equity	$	33,302,434		$	30,574,238

Note: All share amounts shown have been restated to reflect the announced 2-for-1 stock split effective March 31, 2014.



EOG RESOURCES, INC. SUMMARY STATEMENTS OF CASH FLOWS (Unaudited; in thousands)
	Six Months Ended
	June 30,
	2014			2013
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$	1,367,281		$	1,154,417
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		1,943,093			1,756,919
Impairments		152,396			91,515
Stock-Based Compensation Expenses		65,144			57,724
Deferred Income Taxes		479,109			488,632
Gains on Asset Dispositions, Net		(15,354	)		(177,386	)
Other, Net		984			8,747
Dry Hole Costs		13,906			39,712
Mark-to-Market Commodity Derivative Contracts
Total Losses (Gains)		385,006			(86,534	)
Net Cash (Payments for) Received from Settlements of Commodity Derivative Contracts		(120,900	)		135,959
Excess Tax Benefits from Stock-Based Compensation		(63,759	)		(21,869	)
Other, Net		7,223			7,759
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(249,336	)		(164,809	)
Inventories		(109,756	)		22,085
Accounts Payable		347,539			141,369
Accrued Taxes Payable		115,668			24,816
Other Assets		(141,453	)		(92,305	)
Other Liabilities		57,101			(51,400	)
Changes in Components of Working Capital Associated with Investing and Financing Activities		(31,644	)		(19,639	)
Net Cash Provided by Operating Activities		4,202,248			3,315,712

Investing Cash Flows
Additions to Oil and Gas Properties		(3,724,486	)		(3,250,091	)
Additions to Other Property, Plant and Equipment		(402,972	)		(183,516	)
Proceeds from Sales of Assets		74,512			579,941
Changes in Restricted Cash		(91,238	)		(52,322	)
Changes in Components of Working Capital Associated with Investing Activities		31,620			19,358
Net Cash Used in Investing Activities		(4,112,564	)		(2,886,630	)

Financing Cash Flows
Long-Term Debt Borrowings		496,220			-
Long-Term Debt Repayments		(500,000	)		-
Settlement of Foreign Currency Swap		(31,573	)		-
Dividends Paid		(119,684	)		(97,006	)
Excess Tax Benefits from Stock-Based Compensation		63,759			21,869
Treasury Stock Purchased		(89,524	)		(21,094	)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan		10,433			20,773
Debt Issuance Costs		(895	)		-
Repayment of Capital Lease Obligation		(2,958	)		(2,866	)
Other, Net		24			281
Net Cash Used in Financing Activities		(174,198	)		(78,043	)

Effect of Exchange Rate Changes on Cash		(3,555	)		542

(Decrease) Increase in Cash and Cash Equivalents		(88,069	)		351,581
Cash and Cash Equivalents at Beginning of Period		1,318,209			876,435
Cash and Cash Equivalents at End of Period	$	1,230,140		$	1,228,016



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, 2014 and 2013 reported Net Income (GAAP) to reflect actual net cash (payments for) received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market losses (gains) from these transactions, to eliminate the net gains on asset dispositions in North America in 2014 and 2013 and to add back impairment charges related to certain of EOG's non-core North American assets in 2014 and 2013. 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,
	2014			2013			2014			2013

Reported Net Income (GAAP)	$	706,353		$	659,692		$	1,367,281		$	1,154,417

Mark-to-Market (MTM) Commodity Derivative Contracts Impact
Total Losses (Gains)		229,270			(191,490	)		385,006			(86,534	)
Net Cash (Payments for) Received from Settlements of Commodity Derivative Contracts		(86,867	)		68,909			(120,900	)		135,959
Subtotal		142,403			(122,581	)		264,106			49,425

After-Tax MTM Impact		91,359			(78,482	)		169,437			31,645

Less: Net Gains on Asset Dispositions, Net of Tax		(1,663	)		(9,382	)		(9,040	)		(124,375	)
Add: Impairments of Certain North American Assets, Net of Tax		-			2,003			36,058			2,003

Adjusted Net Income (Non-GAAP)	$	796,049		$	573,831		$	1,563,736		$	1,063,690

Net Income Per Share (GAAP)
Basic	$	1.30		$	1.22		$	2.52		$	2.14
Diluted	$	1.29		$	1.21		$	2.49		$	2.12

Adjusted Net Income Per Share (Non-GAAP)
Basic	$	1.47		$	1.06		$	2.88		$	1.97
Diluted	$	1.45		$	1.05		$	2.85		$	1.95

Adjusted Net Income Per Diluted Share (Non-GAAP) - Percentage Increase		38%						46%

Average Number of Common Shares (GAAP)
Basic		543,099			540,033			542,675			539,330
Diluted		548,676			545,477			548,046			544,946

Note: All share and per-share amounts shown have been restated to reflect the announced 2-for-1 stock split effective March 31, 2014.



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, 2014 and 2013 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,
	2014			2013			2014			2013

Net Cash Provided by Operating Activities (GAAP)	$	1,934,575		$	1,890,777		$	4,202,248		$	3,315,712

Adjustments:
Exploration Costs (excluding Stock-Based Compensation Expenses)		36,659			40,930			76,783			77,575
Excess Tax Benefits from Stock-Based Compensation		36,337			10,196			63,759			21,869
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		105,019			(71,948	)		249,336			164,809
Inventories		40,808			(37,143	)		109,756			(22,085	)
Accounts Payable		14,271			44,696			(347,539	)		(141,369	)
Accrued Taxes Payable		24,133			(15,812	)		(115,668	)		(24,816	)
Other Assets		128,917			45,112			141,453			92,305
Other Liabilities		(86,270	)		(1,533	)		(57,101	)		51,400
Changes in Components of Working Capital Associated with Investing and Financing Activities		(36,639	)		(37,782	)		31,644			19,639

Discretionary Cash Flow (Non-GAAP)	$	2,197,810		$	1,867,493		$	4,354,671		$	3,555,039

Discretionary Cash Flow (Non-GAAP) - Percentage Increase		18%						22%



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, 2014 and 2013 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 (payments for) received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) losses (gains) from these transactions and to eliminate the net gains on asset dispositions in North America in 2014 and 2013. 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,
	2014			2013			2014			2013

Income Before Interest Expense and Income Taxes (GAAP)	$	1,152,680		$	1,096,877		$	2,233,621		$	1,919,817

Adjustments:
Depreciation, Depletion and Amortization		996,602			910,531			1,943,093			1,756,919
Exploration Costs		42,208			47,323			90,266			91,539
Dry Hole Costs		5,558			35,750			13,906			39,712
Impairments		39,035			37,967			152,396			91,515
EBITDAX (Non-GAAP)		2,236,083			2,128,448			4,433,282			3,899,502
Total Losses (Gains) on MTM Commodity Derivative Contracts		229,270			(191,490	)		385,006			(86,534	)
Net Cash (Payments for) Received from Settlements of Commodity Derivative Contracts		(86,867	)		68,909			(120,900	)		135,959
Net Gains on Asset Dispositions		(3,856	)		(13,153	)		(15,354	)		(177,386	)

Adjusted EBITDAX (Non-GAAP)	$	2,374,630		$	1,992,714		$	4,682,034		$	3,771,541

Adjusted EBITDAX (Non-GAAP) - Percentage Increase		19%						24%



EOG RESOURCES, INC. QUANTITATIVE RECONCILIATION OF NET DEBT (NON-GAAP) AND TOTAL CAPITALIZATION (NON-GAAP) AS USED IN THE CALCULATION OF THE NET DEBT-TO-TOTAL CAPITALIZATION RATIO (NON-GAAP) TO CURRENT AND LONG-TERM DEBT (GAAP) AND TOTAL CAPITALIZATION (GAAP) (Unaudited; in millions, except ratio data)

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

	At			At
	June 30,			December 31,
	2014			2013

Total Stockholders' Equity - (a)	$	16,708		$	15,418

Current and Long-Term Debt (GAAP) - (b)		5,910			5,913
Less: Cash		(1,230	)		(1,318	)
Net Debt (Non-GAAP) - (c)		4,680			4,595

Total Capitalization (GAAP) - (a) + (b)	$	22,618		$	21,331

Total Capitalization (Non-GAAP) - (a) + (c)	$	21,388		$	20,013

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]		26%			28%

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]		22%			23%



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 5, 2014, 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)
2014
January 2014 (closed)		156,000	$	96.30
February 2014 (closed)		171,000	96.35
March 1, 2014 through June 30, 2014 (closed)		181,000	96.55
July 2014 (closed)		202,000	96.34
August 2014		202,000	96.34
September 1, 2014 through December 31, 2014		192,000	96.15

2015 ⁽¹⁾		—	$	—

(1)	EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month periods. Options covering a notional volume of 69,000 Bbld are exercisable on or about December 31, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 69,000 Bbld at an average price of $95.20 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)
2014 ⁽²⁾
January 2014 (closed)		230,000	$	4.51
February 2014 (closed)		710,000	4.57
March 2014 (closed)		810,000	4.60
April 2014 (closed)		465,000	4.52
May 2014 (closed)		685,000	4.55
June 2014 (closed)		515,000	4.52
July 2014 (closed)		340,000	4.55
August 2014 (closed)		330,000	4.55
September 1, 2014 through December 31, 2014		330,000	4.55

2015 ⁽³⁾
January 1, 2015 through December 31, 2015		175,000	$	4.51

(2)	EOG has entered into natural gas derivative contracts which give counterparties the 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 480,000 MMBtud at an average price of $4.63 per MMBtu for each month during the period September 1, 2014 through December 31, 2014.

(3)	EOG has entered into natural gas derivative contracts which give counterparties the 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 175,000 MMBtud at an average price of $4.51 per MMBtu for each month during the period January 1, 2015 through December 31, 2015.



$/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. THIRD QUARTER AND FULL YEAR 2014 FORECAST AND BENCHMARK COMMODITY PRICING

	(a) Third Quarter and Full Year 2014 Forecast

The forecast items for the third quarter and full year 2014 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 2014			Full Year 2014
Daily Production
Crude Oil and Condensate Volumes (MBbld)
United States		278.0	-	292.0	268.0	-	288.0
Canada		4.5	-	5.5	5.5	-	6.5
Trinidad		0.6	-	0.8	0.7	-	1.0
Other International		0.0	-	0.0	0.0	-	0.0
Total		283.1	-	298.3	274.2	-	295.5

Natural Gas Liquids Volumes (MBbld)
United States		75.5	-	79.5	73.8	-	78.3
Canada		0.4	-	0.6	0.5	-	0.7
Total		75.9	-	80.1	74.3	-	79.0

Natural Gas Volumes (MMcfd)
United States		877	-	901	886	-	905
Canada		58	-	62	61	-	64
Trinidad		327	-	345	358	-	372
Other International		8	-	10	8	-	10
Total		1,270	-	1,318	1,313	-	1,351

Crude Oil Equivalent Volumes (MBoed)
United States		499.7	-	521.7	489.5	-	517.1
Canada		14.6	-	16.4	16.2	-	17.9
Trinidad		55.1	-	58.3	60.4	-	63.0
Other International		1.3	-	1.7	1.3	-	1.7
Total		570.7	-	598.1	567.4	-	599.7



	ESTIMATED RANGES (Unaudited)
	3Q 2014					Full Year 2014
Operating Costs
Unit Costs ($/Boe)
Lease and Well	$	6.40	-	$	6.70	$	6.40	-	$	6.60
Transportation Costs	$	4.79	-	$	4.98	$	4.66	-	$	4.86
Depreciation, Depletion and Amortization	$	18.35	-	$	19.05	$	18.30	-	$	19.00

Expenses ($MM)
Exploration, Dry Hole and Impairment	$	130	-	$	150	$	500	-	$	550
General and Administrative	$	101	-	$	112	$	380	-	$	390
Gathering and Processing	$	38	-	$	44	$	130	-	$	150
Capitalized Interest	$	14	-	$	16	$	55	-	$	65
Net Interest	$	48	-	$	52	$	194	-	$	214

Taxes Other Than Income (% of Wellhead Revenue)		6.1%	-		6.5%		6.0%	-		6.5%

Income Taxes
Effective Rate		35%	-		40%		35%	-		40%
Current Taxes ($MM)	$	120	-	$	135	$	540	-	$	560

Capital Expenditures ($MM) - FY 2014 (Excluding Acquisitions)
Exploration and Development, Excluding Facilities						$	6,450	-	$	6,550
Exploration and Development Facilities						$	880	-	$	920
Gathering, Processing and Other						$	770	-	$	810

Pricing - (Refer to Benchmark Commodity Pricing in text)
Crude Oil and Condensate ($/Bbl)
Differentials
United States - (above) below WTI	$	0.70	-	$	1.70	$	0.01	-	$	0.51
Canada - (above) below WTI	$	10.50	-	$	12.50	$	8.00	-	$	12.00
Trinidad - (above) below WTI	$	9.00	-	$	11.00	$	7.20	-	$	11.40

Natural Gas Liquids
Realizations as % of WTI
United States		30%	-		37%		32%	-		37%
Canada		32%	-		38%		38%	-		43%

Natural Gas ($/Mcf)
Differentials
United States - (above) below NYMEX Henry Hub	$	0.30	-	$	0.70	$	0.15	-	$	0.50
Canada - (above) below NYMEX Henry Hub	$	0.10	-	$	0.50	$	0.00	-	$	0.25

Realizations
Trinidad	$	2.85	-	$	3.35	$	3.20	-	$	3.55
Other International	$	3.75	-	$	5.75	$	3.80	-	$	5.90

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

EOG RESOURCES INC - FORM 8-K - EX-99.1 - EXHIBIT - August 5, 2014

Attached files

EOG RESOURCES INC Reports