EOG RESOURCES INC - FORM 8-K - EX-99.1 - PRESS RELEASE OF EOG RESOURCES, INC.

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EXHIBIT 99.1



EOG Resources, Inc.
News Release
For Further Information Contact:	Investors
	Maire A. Baldwin
	(713) 651-6364
	Kimberly A. Matthews
	(713) 571-4676
	David J. Streit
	(713) 571-4902

	Media
	K Leonard
	(713) 571-3870

EOG Resources Announces Excellent Third Quarter 2014 Results and Raises Crude Oil Production Growth Target for Second Time in 2014


•	Increases 2014 Full-Year Crude Oil and Condensate Production Growth Goal to 31 Percent from 29 Percent


•	Raises 2014 Total Production Growth Target to 16.5 Percent from 14 Percent


•	Reports 29 Percent Increase in U.S. Crude Oil and Condensate Production and 17 Percent Growth in Total Company Production Year-Over-Year


•	Confirms Prolific, Highly Over-Pressured Crude Oil Window on Delaware Basin Wolfcamp Acreage


•	Realizes Strong Drilling Results from Eagle Ford, Emerging Delaware Basin and Rockies Crude Oil Plays

FOR IMMEDIATE RELEASE: Tuesday, November 4, 2014

HOUSTON - EOG Resources, Inc. (EOG) today reported third quarter 2014 net income of $1,103.6 million, or $2.01 per share. This compares to third quarter 2013 net income of $462.5 million, or $0.85 per share.

Adjusted non-GAAP net income for the third quarter 2014 was $720.6 million, or $1.31 per share, and adjusted non-GAAP net income for the same prior year period was $634.3 million, or $1.16 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 third quarter 2014 excluded a previously disclosed non-cash net gain of $469.1 million ($301.0 million after-tax, or $0.55 per share) on the mark-to-market of financial commodity derivative contracts. The net cash outflow related to settlements of financial commodity derivative contracts was $68.0 million ($43.6 million after-tax, or $0.08 per share). During the third quarter 2014, the net gains on asset dispositions were $60.3 million ($38.4 million net of tax, or $0.07 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

Reflecting the ongoing shift in its asset portfolio, crude oil now accounts for 48 percent of EOG’s total production, compared to 42 percent at the end of the third quarter 2013. This highly desirable ratio drove EOG’s strong financial metrics for the first nine months of 2014. Discretionary cash flow increased 18 percent and adjusted EBITDAX advanced 19 percent, versus the first nine months of 2013. In addition, adjusted non-GAAP earnings per share increased 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), adjusted non-GAAP EBITDAX to income before interest expense and income taxes (GAAP) and adjusted non-GAAP net income to GAAP net income.)

Operational Highlights

EOG is increasing its full year 2014 crude oil and condensate production growth target to 31 percent from 29 percent and total production growth target to 16.5 percent from 14 percent, as it continues to improve well productivity in its key domestic crude oil plays.

In the third quarter, EOG’s U.S. crude oil and condensate production increased 29 percent, compared to the same prior year period. Production gains from the South Texas Eagle Ford, North Dakota Bakken and Delaware Basin led EOG’s crude oil production growth. Driven by the Delaware Basin and Eagle Ford, total natural gas liquids (NGLs) production increased 25 percent, and total company natural gas production increased 3 percent, compared to the third quarter 2013. Total company production increased 17 percent.

Delaware Basin

In the Delaware Basin, EOG has confirmed that 90,000 of its 140,000 net acre position in the Wolfcamp is in a highly over-pressured crude oil window, representing a significant enhancement in the play’s reinvestment rate-of-return. EOG drilled two Wolfcamp wells that have a 50 percent crude oil mix. In Lea County, New Mexico, the Diamond SM 36 State #1H began production at 1,340 barrels of oil per day (Bopd) with 195 barrels per day (Bpd) of NGLs and 1.3 million cubic feet per day (MMcfd) of natural gas. On the Texas side of the play in Loving County, the Voyager 15 #3H had a high initial production rate of 1,890 Bopd with 385 Bpd of NGLs and 2.5 MMcfd of natural gas. EOG has 100 and 48 percent working interest, respectively, in these two wells. EOG plans to increase its Delaware Basin Wolfcamp drilling activity on the 50 percent crude oil acreage.

Near the Texas/New Mexico border in Loving County, Texas, EOG completed its third well in the Second Bone Spring Sand this year. The State Magellan #2H, in which EOG has 100 percent working interest, began initial production at 1,825 Bopd with 295 Bpd of NGLs and 2.2 MMcfd of natural gas. Drilled 20 miles southwest of EOG’s existing production, the well confirms the prospectivity of the Second Bone Spring Sand over a greater amount of acreage. These results, together with recent mapping and geological studies, indicate EOG has at least 90,000 net acres of Second Bone Spring Sand potential across its acreage.

Also in Loving County, Texas, EOG has been drilling Leonard Shale wells. The State Pathfinder #1H and #3H, which were completed in the Leonard ‘A’ zone as 450-foot spacing tests, had a combined rate of 2,340 Bopd with 470 Bpd of NGLs and 2.6 MMcfd of natural gas. EOG has 100 percent working interest in these wells. EOG is continuing to test various spacing patterns between and across producing zones in the Leonard Shale where it holds an expanded 80,000 net acre position.

South Texas Eagle Ford

Through drilling and completion improvements, EOG again realized outstanding capital efficiencies and strong well results in its single largest growth engine, the Eagle Ford. In Gonzales County, the Neuse Unit #1H was turned to sales at an initial peak rate of 4,170 Bopd with 160 Bpd of NGLs and 935 thousand cubic feet per day (Mcfd) of natural gas. The Boothe Unit #12H, #13H, #14H and #15H came online at rates ranging from 2,640 to 3,445 Bopd with 490 to 580 Bpd of NGLs and 2.8 to 3.4 MMcfd of natural gas. EOG has 100 percent working interest in these five Eagle Ford wells.

In Karnes County, the Colleen Unit #1H had an initial production rate of 3,660 Bopd with 360 Bpd of NGLs and 2.1 MMcfd of natural gas. The Maverick Unit #2H came online at an initial rate of 3,680 Bopd with 365 Bpd of NGLs and 2.1 MMcfd of natural gas. The Lake Unit #4H, #6H and #8H began production from two different pads at a combined rate of 6,460 Bopd with 735 Bpd of NGLs and 4.3 MMcfd of natural gas. EOG has 100 percent working interest in these five Eagle Ford wells.

West of Gonzales and Karnes, in LaSalle and McMullen counties, among the wells turned to sales, 31 had initial production rates exceeding 1,200 Bopd including the Corner S Ranch #11H, #12H, #13H, #14H, #15H and #16H. The wells, in which EOG has 100 percent working interest, had a combined rate exceeding 8,400 Bopd, 325 Bpd of NGLs and 1.9 MMcfd of natural gas.

North Dakota Bakken

EOG’s Bakken drilling activity for the year has concentrated on its Parshall Core and Antelope Extension acreage. In the Core, EOG continues to test various spacing patterns to determine a development program that maximizes the field’s resource potential. While preliminary results from 700-foot spaced wells are encouraging, EOG will continue to analyze production data. EOG is simultaneously testing well patterns of less than 700 feet. In the Antelope Extension area, EOG has pursued development drilling in the Bakken and tested various Three Forks intervals to determine the prospectivity of the formation across its acreage. Additionally, EOG has reduced its overall Bakken drilling costs by integrating self-sourced sand and identifying drilling efficiencies, as well as refining completion techniques in both areas.

In the Core area, the Parshall 44-1004H, 45-1004H and 46-1004H, in which EOG has 69 percent working interest, were turned to production at initial rates of 2,710, 2,005 and 2,105 Bopd with 875, 665 and 860 Mcfd of rich natural gas, respectively. The Parshall 47-2226H, 48-2226H and 49-2226H began production at a cumulative rate of 5,105 Bopd with 2.3 MMcfd of rich natural gas. EOG has 70 percent working interest in these three Core wells.

In the Antelope Extension area, EOG had successful drilling results from the first, second and third Three Forks benches. The first well drilled in the third interval of the Three Forks was the Mandaree 134-05H, in which EOG has 70 percent working interest. It came online at 1,410 Bopd with 2.2 MMcfd of rich natural gas. In the second interval, the Mandaree 135-05H, in which EOG has 69 percent working interest, had an initial rate of 1,620 Bopd with 2.5 MMcfd of rich natural gas. EOG has 42 percent working interest in the Mandaree 17-05H, which began producing at 1,745 Bopd with 2.8 MMcfd of rich natural gas from the first bench. EOG is continuing to test and drill Three Forks wells in all three intervals across its Antelope acreage.

“At EOG, we are never satisfied with the status quo. We are constantly identifying efficiencies in our drilling practices and making breakthroughs in completion methodology that raise the bar on EOG’s ongoing outstanding performance,” said Chairman and Chief Executive Officer William R. “Bill” Thomas.

Wyoming DJ and Powder River Basins

In the DJ Basin, EOG is simultaneously developing the stacked Codell and Niobrara formations from multi-well pad locations in Laramie County, Wyoming. During the third quarter, a seven-well pattern of three Codell and four Niobrara wells was brought to production with a combined initial rate exceeding 7,800 Bopd with 5.4 MMcfd of rich natural gas. The wells, in which EOG has 75 percent working interest, were drilled with 710-foot spacing between laterals averaging 9,400 feet. Initial production and drilling results from the Codell and Niobrara are encouraging.

In Campbell and Converse counties, Wyoming, EOG is actively developing its acreage in the Powder River Basin with a single drilling rig program. EOG completed one well from the Parkman formation and two from the Turner during the third quarter. The Mary’s Draw 412-1527H began sales at an initial rate of 1,190 Bopd with 270 Mcfd of rich natural gas from the Parkman formation. The Mary’s Draw 24-13H and 25-13H had a combined crude oil rate of 1,880 Bopd with 3.1 MMcfd of rich natural gas from the Turner. EOG has 100 percent working interest in these three wells.

“We have added a number of new plays to EOG’s portfolio this year, while continuing to improve well productivity in our existing assets. We expect the Eagle Ford, EOG’s cornerstone, to drive our production growth for many years,” Thomas said. “It’s important to note that despite the recent pullback in crude oil prices, because of our premier acreage positions and

zealous approach to improving completion methods, EOG is positioned to realize ongoing excellent returns in our top plays and continue to be an industry leader in domestic organic production growth.”

Crude Oil and Natural Gas Hedging Activity

For the period November 1 through December 31, 2014, EOG has crude oil financial price swap contracts in place for 192,000 Bopd at a weighted average price of $96.15 per barrel. For the period January 1 through December 31, 2015, EOG has crude oil financial price swap contracts in place for an average of 28,350 Bopd at a weighted average price of $91.00 per barrel, excluding unexercised options.

For December 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 September 30, 2014, EOG’s total debt outstanding was $5,910 million for a debt-to-total capitalization ratio of 25 percent. Taking into account cash on the balance sheet of $1.5 billion at September 30, 2014, EOG’s net debt was $4,429 million for a net debt-to-total capitalization ratio of 20 percent, down from 23 percent at December 31, 2013. (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 committed to enhancing long-term shareholder value. We have increased the dividend twice in 2014 because our excellent financial and operational performance drives outstanding returns quarter after quarter,” Thomas said.

Conference Call November 5, 2014

EOG’s third quarter 2014 results conference call will be available via live audio webcast at 7 a.m. Central time (8 a.m. Eastern time) on Wednesday, November 5, 2014. To listen, log on to www.eogresources.com. The webcast will be archived on EOG’s website through November 19, 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				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013

Net Operating Revenues	$	5,118.6	$	3,541.4	$	13,389.8	$	10,738.1
Net Income	$	1,103.6	$	462.5	$	2,470.9	$	1,616.9
Net Income Per Share
Basic	$	2.03	$	0.85	$	4.55	$	3.00
Diluted	$	2.01	$	0.85	$	4.51	$	2.96
Average Number of Common Shares
Basic		544.0		540.9		543.1		539.9
Diluted		549.5		547.2		548.4		545.7



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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Net Operating Revenues
Crude Oil and Condensate	$	2,671,502		$	2,337,742		$	7,687,579		$	6,132,574
Natural Gas Liquids		258,927			208,190			753,135			556,176
Natural Gas		443,108			396,123			1,508,892			1,269,604
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts		469,125			(293,387	)		84,119			(206,853	)
Gathering, Processing and Marketing		1,196,933			872,699			3,240,139			2,755,069
Gains on Asset Dispositions, Net		60,346			8,183			75,700			185,569
Other, Net		18,675			11,846			40,279			45,956
Total		5,118,616			3,541,396			13,389,843			10,738,095
Operating Expenses
Lease and Well		368,340			299,169			1,035,632			817,057
Transportation Costs		246,067			219,790			729,883			628,538
Gathering and Processing Costs		41,621			31,121			108,015			81,522
Exploration Costs		48,955			39,429			139,221			130,968
Dry Hole Costs		16,359			19,548			30,265			59,260
Impairments		55,542			85,917			207,938			177,432
Marketing Costs		1,213,652			876,761			3,263,471			2,746,900
Depreciation, Depletion and Amortization		1,040,018			928,800			2,983,111			2,685,719
General and Administrative		96,931			98,654			270,725			257,246
Taxes Other Than Income		204,969			172,438			606,411			458,566
Total		3,332,454			2,771,627			9,374,672			8,043,208

Operating Income		1,786,162			769,769			4,015,171			2,694,887

Other Income (Expense), Net		(21,338	)		11,168			(16,726	)		5,867

Income Before Interest Expense and Income Taxes		1,764,824			780,937			3,998,445			2,700,754

Interest Expense, Net		49,704			59,382			151,723			182,950

Income Before Income Taxes		1,715,120			721,555			3,846,722			2,517,804

Income Tax Provision		611,502			259,057			1,375,823			900,889

Net Income	$	1,103,618		$	462,498		$	2,470,899		$	1,616,915

Dividends Declared per Common Share	$	0.1675		$	0.0938		$	0.4175		$	0.2813



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



EOG RESOURCES, INC. OPERATING HIGHLIGHTS (Unaudited)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes (MBbld) ^(A)
United States		293.2		227.6		275.5		204.3
Canada		5.3		6.1		6.0		6.7
Trinidad		0.9		1.2		1.0		1.3
Other International ^(B)		0.1		0.1		0.1		0.1
Total		299.5		235.0		282.6		212.4

Average Crude Oil and Condensate Prices ($/Bbl) ^(C)
United States	$	97.33	$	108.56	$	100.10	$	106.36
Canada		87.64		97.90		90.74		90.53
Trinidad		87.87		94.96		90.84		91.80
Other International ^(B)		94.31		81.30		90.68		88.90
Composite		97.13		108.20		99.87		105.76

Natural Gas Liquids Volumes (MBbld) ^(A)
United States		85.8		68.2		78.4		63.5
Canada		0.6		0.9		0.7		0.9
Total		86.4		69.1		79.1		64.4

Average Natural Gas Liquids Prices ($/Bbl) ^(C)
United States	$	32.61	$	32.75	$	34.83	$	31.55
Canada		40.38		32.24		43.01		37.83
Composite		32.67		32.74		34.90		31.64

Natural Gas Volumes (MMcfd) ^(A)
United States		941		899		920		920
Canada		63		76		65		78
Trinidad		356		352		374		350
Other International ^(B)		9		7		9		8
Total		1,369		1,334		1,368		1,356

Average Natural Gas Prices ($/Mcf) ^(C)
United States	$	3.48	$	3.19	$	4.17	$	3.33
Canada		4.05		2.61		4.49		3.01
Trinidad		3.50		3.41		3.61		3.71
Other International ^(B)		5.00		6.12		5.03		6.58
Composite		3.52		3.23		4.04		3.43

Crude Oil Equivalent Volumes (MBoed) ^(D)
United States		536.1		445.7		507.3		421.2
Canada		16.4		19.7		17.5		20.7
Trinidad		60.1		59.8		63.4		59.5
Other International ^(B)		1.5		1.2		1.5		1.4
Total		614.1		526.4		589.7		502.8

Total MMBoe ^(D)		56.5		48.4		161.0		137.3


(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)

	September 30,			December 31,
	2014			2013
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,481,145		$	1,318,209
Accounts Receivable, Net		2,009,091			1,658,853
Inventories		672,899			563,268
Assets from Price Risk Management Activities		132,931			8,260
Income Taxes Receivable		17,978			4,797
Deferred Income Taxes		238,258			244,606
Other		332,414			274,022
Total		4,884,716			4,072,015

Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)		47,912,930			42,821,803
Other Property, Plant and Equipment		3,571,545			2,967,085
Total Property, Plant and Equipment		51,484,475			45,788,888
Less: Accumulated Depreciation, Depletion and Amortization		(22,267,642	)		(19,640,052	)
Total Property, Plant and Equipment, Net		29,216,833			26,148,836
Other Assets		399,334			353,387
Total Assets	$	34,500,883		$	30,574,238

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	2,775,342		$	2,254,418
Accrued Taxes Payable		257,948			159,365
Dividends Payable		91,094			50,795
Liabilities from Price Risk Management Activities		—			127,542
Deferred Income Taxes		2,444			—
Current Portion of Long-Term Debt		6,579			6,579
Other		245,339			263,017
Total		3,378,746			2,861,716


Long-Term Debt		5,903,232			5,906,642
Other Liabilities		1,084,461			865,067
Deferred Income Taxes		6,414,546			5,522,354
Commitments and Contingencies

Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 548,601,616 Shares Issued at September 30, 2014 and 546,378,440 Shares Issued at December 31, 2013		205,488			202,732
Additional Paid in Capital		2,785,716			2,646,879
Accumulated Other Comprehensive Income		387,725			415,834
Retained Earnings		14,410,707			12,168,277
Common Stock Held in Treasury, 701,786 Shares at September 30, 2014 and 206,830 Shares at December 31, 2013		(69,738	)		(15,263	)
Total Stockholders' Equity		17,719,898			15,418,459
Total Liabilities and Stockholders’ Equity	$	34,500,883		$	30,574,238

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



EOG RESOURCES, INC. SUMMARY STATEMENTS OF CASH FLOWS (Unaudited; in thousands)
	Nine Months Ended
	September 30,
	2014			2013
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$	2,470,899		$	1,616,915
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		2,983,111			2,685,719
Impairments		207,938			177,432
Stock-Based Compensation Expenses		103,636			103,171
Deferred Income Taxes		974,522			657,686
Gains on Asset Dispositions, Net		(75,700	)		(185,569	)
Other, Net		17,188			460
Dry Hole Costs		30,265			59,260
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses		(84,119	)		206,853
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		(188,937	)		115,323
Excess Tax Benefits from Stock-Based Compensation		(87,827	)		(50,230	)
Other, Net		8,701			16,222
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(341,043	)		(213,746	)
Inventories		(119,166	)		61,147
Accounts Payable		566,753			145,199
Accrued Taxes Payable		176,412			73,197
Other Assets		(61,966	)		(78,799	)
Other Liabilities		66,618			10,889
Changes in Components of Working Capital Associated with Investing and Financing Activities		(108,568	)		(72,945	)
Net Cash Provided by Operating Activities		6,538,717			5,328,184

Investing Cash Flows
Additions to Oil and Gas Properties		(5,653,035	)		(5,084,335	)
Additions to Other Property, Plant and Equipment		(587,178	)		(271,136	)
Proceeds from Sales of Assets		91,335			587,273
Changes in Restricted Cash		(91,238	)		(68,061	)
Changes in Components of Working Capital Associated with Investing Activities		108,999			72,916
Net Cash Used in Investing Activities		(6,131,117	)		(4,763,343	)

Financing Cash Flows
Long-Term Debt Borrowings		496,220			—
Long-Term Debt Repayments		(500,000	)		—
Settlement of Foreign Currency Swap		(31,573	)		—
Dividends Paid		(187,670	)		(147,731	)
Excess Tax Benefits from Stock-Based Compensation		87,827			50,230
Treasury Stock Purchased		(114,824	)		(55,562	)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan		11,740			30,080
Debt Issuance Costs		(895	)		—
Repayment of Capital Lease Obligation		(4,457	)		(4,318	)
Other, Net		(431	)		29
Net Cash Used in Financing Activities		(244,063	)		(127,272	)

Effect of Exchange Rate Changes on Cash		(601	)		4,813

Increase in Cash and Cash Equivalents		162,936			442,382
Cash and Cash Equivalents at Beginning of Period		1,318,209			876,435
Cash and Cash Equivalents at End of Period	$	1,481,145		$	1,318,817



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 nine-month periods ended September 30, 2014 and 2013 reported Net Income (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net 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						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013

Reported Net Income (GAAP)	$	1,103,618		$	462,498		$	2,470,899		$	1,616,915

Commodity Derivative Contracts Impact
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts		(469,125	)		293,387			(84,119	)		206,853
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		(68,037	)		(20,636	)		(188,937	)		115,323
Subtotal		(537,162	)		272,751			(273,056	)		322,176

After-Tax Impact		(344,616	)		174,628			(175,179	)		206,273

Less: Net Gains on Asset Dispositions, Net of Tax		(38,386	)		(5,241	)		(47,426	)		(129,616	)
Add: Impairments of Certain North American Assets, Net of Tax		—			2,422			36,058			4,425

Adjusted Net Income (Non-GAAP)	$	720,616		$	634,307		$	2,284,352		$	1,697,997

Net Income Per Share (GAAP)
Basic	$	2.03		$	0.85		$	4.55		$	3.00
Diluted	$	2.01		$	0.85		$	4.51		$	2.96

Adjusted Net Income Per Share (Non-GAAP)
Basic	$	1.32		$	1.17		$	4.21		$	3.15
Diluted	$	1.31		$	1.16		$	4.17		$	3.11

Adjusted Net Income Per Diluted Share (Non-GAAP) - Percentage Increase		13	%					34	%

Average Number of Common Shares (GAAP)
Basic		543,984			540,941			543,086			539,869
Diluted		549,518			547,152			548,401			545,712

Note: All share and per-share amounts shown have been restated to reflect the 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 nine-month periods ended September 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						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013

Net Cash Provided by Operating Activities (GAAP)	$	2,336,469		$	2,012,472		$	6,538,717		$	5,328,184

Adjustments:
Exploration Costs (excluding Stock-Based Compensation Expenses)		42,220			32,755			119,003			110,330
Excess Tax Benefits from Stock-Based Compensation		24,068			28,361			87,827			50,230
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		91,707			48,937			341,043			213,746
Inventories		9,410			(39,062	)		119,166			(61,147	)
Accounts Payable		(219,214	)		(3,830	)		(566,753	)		(145,199	)
Accrued Taxes Payable		(60,744	)		(48,381	)		(176,412	)		(73,197	)
Other Assets		(79,487	)		(13,506	)		61,966			78,799
Other Liabilities		(9,517	)		(62,289	)		(66,618	)		(10,889	)
Changes in Components of Working Capital Associated with Investing and Financing Activities		76,924			53,306			108,568			72,945

Discretionary Cash Flow (Non-GAAP)	$	2,211,836		$	2,008,763		$	6,566,507		$	5,563,802

Discretionary Cash Flow (Non-GAAP) - Percentage Increase		10	%					18	%



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 nine-month periods ended September 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 received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net 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						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013

Income Before Interest Expense and Income Taxes (GAAP)	$	1,764,824		$	780,937		$	3,998,445		$	2,700,754

Adjustments:
Depreciation, Depletion and Amortization		1,040,018			928,800			2,983,111			2,685,719
Exploration Costs		48,955			39,429			139,221			130,968
Dry Hole Costs		16,359			19,548			30,265			59,260
Impairments		55,542			85,917			207,938			177,432
EBITDAX (Non-GAAP)		2,925,698			1,854,631			7,358,980			5,754,133
Total (Gains) Losses on MTM Commodity Derivative Contracts		(469,125	)		293,387			(84,119	)		206,853
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		(68,037	)		(20,636	)		(188,937	)		115,323
Gains on Asset Dispositions, Net		(60,346	)		(8,183	)		(75,700	)		(185,569	)

Adjusted EBITDAX (Non-GAAP)	$	2,328,190		$	2,119,199		$	7,010,224		$	5,890,740

Adjusted EBITDAX (Non-GAAP) - Percentage Increase		10	%					19	%



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
	September 30,			December 31,
	2014			2013

Total Stockholders' Equity - (a)	$	17,720		$	15,418

Current and Long-Term Debt (GAAP) - (b)		5,910			5,913
Less: Cash		(1,481	)		(1,318	)
Net Debt (Non-GAAP) - (c)		4,429			4,595

Total Capitalization (GAAP) - (a) + (b)	$	23,630		$	21,331

Total Capitalization (Non-GAAP) - (a) + (c)	$	22,149		$	20,013

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]		25	%		28%

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]		20	%		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 November 4, 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 1, 2014 through August 31, 2014 (closed)		202,000	96.34
September 1, 2014 through October 31, 2014 (closed)		192,000	96.15
November 1, 2014 through December 31, 2014		192,000	96.15

2015 ⁽¹⁾
January 1, 2015 through June 30, 2015		47,000	$	91.22
July 1, 2015 through December 31, 2015		10,000	89.98

(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. Options covering a notional volume of 37,000 Bbld are exercisable on June 30, 2015. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 37,000 Bbld at an average price of $91.56 per barrel for each month during the period July 1, 2015 through December 31, 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 1, 2014 through November 30, 2014 (closed)		330,000	4.55
December 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. For December 2014, 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.

(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. FOURTH QUARTER AND FULL YEAR 2014 FORECAST AND BENCHMARK COMMODITY PRICING

	(a) Fourth Quarter and Full Year 2014 Forecast

The forecast items for the fourth 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)
		4Q 2014			Full Year 2014
Daily Production
Crude Oil and Condensate Volumes (MBbld)
United States		293.0	-	300.0	279.9	-	281.6
Canada		6.5	-	7.5	6.2	-	6.4
Trinidad		0.5	-	0.7	0.8	-	1.0
Other International		0.0	-	0.0	0.0	-	0.1
Total		300.0	-	308.2	286.9	-	289.1

Natural Gas Liquids Volumes (MBbld)
United States		81.0	-	87.0	79.1	-	80.6
Canada		0.4	-	0.6	0.6	-	0.7
Total		81.4	-	87.6	79.7	-	81.3

Natural Gas Volumes (MMcfd)
United States		905	-	925	916	-	921
Canada		60	-	66	63	-	65
Trinidad		324	-	372	362	-	374
Other International		8	-	10	8	-	9
Total		1,297	-	1,373	1,349	-	1,369

Crude Oil Equivalent Volumes (MBoed)
United States		524.8	-	541.2	511.7	-	515.8
Canada		16.9	-	19.1	17.4	-	17.9
Trinidad		54.5	-	62.7	61.1	-	63.3
Other International		1.3	-	1.7	1.4	-	1.6
Total		597.5	-	624.7	591.6	-	598.6



	ESTIMATED RANGES (Unaudited)
	4Q 2014							Full Year 2014
Operating Costs
Unit Costs ($/Boe)
Lease and Well	$	6.50		-	$	6.80		$	6.45		-	$	6.53
Transportation Costs	$	4.55		-	$	4.75		$	4.54		-	$	4.59
Depreciation, Depletion and Amortization	$	18.10		-	$	18.70		$	18.43		-	$	18.58

Expenses ($MM)
Exploration, Dry Hole and Impairment	$	155		-	$	175		$	476		-	$	496
General and Administrative	$	102		-	$	112		$	373		-	$	383
Gathering and Processing	$	34		-	$	40		$	142		-	$	148
Capitalized Interest	$	14		-	$	16		$	57		-	$	59
Net Interest	$	48		-	$	52		$	200		-	$	204

Taxes Other Than Income (% of Wellhead Revenue)		6.1	%	-		6.5	%		6.0	%	-		6.4	%

Income Taxes
Effective Rate		32	%	-		37	%		34	%	-		37	%
Current Taxes ($MM)	$	115		-	$	130		$	515		-	$	535

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	$	0.50		-	$	1.50		$	(0.09	)	-	$	0.25
Canada - (above) below WTI	$	9.50		-	$	10.50		$	9.21		-	$	9.90
Trinidad - (above) below WTI	$	9.75		-	$	10.75		$	7.97		-	$	8.75

Natural Gas Liquids
Realizations as % of WTI
United States		30	%	-		35	%		33	%	-		35	%
Canada		32	%	-		38	%		40	%	-		43	%

Natural Gas ($/Mcf)
Differentials
United States - (above) below NYMEX Henry Hub	$	0.30		-	$	0.70		$	0.32		-	$	0.43
Canada - (above) below NYMEX Henry Hub	$	0.00		-	$	0.30		$	0.00		-	$	0.09

Realizations
Trinidad	$	3.10		-	$	3.50		$	3.50		-	$	3.58
Other International	$	4.45		-	$	5.45		$	4.87		-	$	5.12

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 - PRESS RELEASE OF EOG RESOURCES, INC. - November 4, 2014

Attached files

EOG RESOURCES INC Reports