Edgar Filing: EOG RESOURCES INC

10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2015

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 1-9743

EOG RESOURCES, INC.

(Exact name of registrant as specified in its charter)



Delaware		47-0684736
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1111 Bagby, Sky Lobby 2, Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

713-651-7000

(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer ý Accelerated filer o Non-accelerated filer o Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No ý

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.



Title of each class		Number of shares
Common Stock, par value $0.01 per share		549,707,193 (as of October 29, 2015)

EOG RESOURCES, INC.

TABLE OF CONTENTS



PART I.	FINANCIAL INFORMATION		Page No.

	ITEM 1.	Financial Statements (Unaudited)

		Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) - Three Months Ended September 30, 2015 and 2014 and Nine Months Ended September 30, 2015 and 2014	3

		Consolidated Balance Sheets - September 30, 2015 and December 31, 2014	4

		Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2015 and 2014	5

		Notes to Consolidated Financial Statements	6

	ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	19

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	35

	ITEM 4.	Controls and Procedures	35

PART II.	OTHER INFORMATION

	ITEM 1.	Legal Proceedings	36

	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36

	ITEM 4.	Mine Safety Disclosures	36

	ITEM 6.	Exhibits	37

SIGNATURES			38

EXHIBIT INDEX			39

-2-

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

(In Thousands, Except Per Share Data)

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Net Operating Revenues
Crude Oil and Condensate	$	1,181,092		$	2,671,502		$	3,894,092		$	7,687,579
Natural Gas Liquids	95,217			258,927			311,137			753,135
Natural Gas	281,837			443,108			843,657			1,508,892
Gains on Mark-to-Market Commodity Derivative Contracts	29,239			469,125			56,954			84,119
Gathering, Processing and Marketing	572,217			1,196,933			1,820,843			3,240,139
Gains (Losses) on Asset Dispositions, Net	(1,185		)	60,346			(5,142		)	75,700
Other, Net	14,011			18,675			39,126			40,279
Total	2,172,428			5,118,616			6,960,667			13,389,843
Operating Expenses
Lease and Well	283,221			368,340			934,366			1,035,632
Transportation Costs	203,594			246,067			641,739			729,883
Gathering and Processing Costs	35,497			41,621			106,503			108,015
Exploration Costs	31,344			48,955			114,548			139,221
Dry Hole Costs	198			16,359			14,317			30,265
Impairments	6,307,420			55,542			6,445,375			207,938
Marketing Costs	615,303			1,213,652			1,924,134			3,263,471
Depreciation, Depletion and Amortization	722,172			1,040,018			2,544,187			2,983,111
General and Administrative	90,959			96,931			257,580			270,725
Taxes Other Than Income	105,677			204,969			334,244			606,411
Total	8,395,385			3,332,454			13,316,993			9,374,672
Operating Income (Loss)	(6,222,957		)	1,786,162			(6,356,326		)	4,015,171
Other Income (Expense), Net	8,607			(21,338		)	7,996			(16,726		)
Income (Loss) Before Interest Expense and Income Taxes	(6,214,350		)	1,764,824			(6,348,330		)	3,998,445
Interest Expense, Net	60,571			49,704			174,400			151,723
Income (Loss) Before Income Taxes	(6,274,921		)	1,715,120			(6,522,730		)	3,846,722
Income Tax Provision (Benefit)	(2,199,182		)	611,502			(2,282,511		)	1,375,823
Net Income (Loss)	$	(4,075,739	)	$	1,103,618		$	(4,240,219	)	$	2,470,899
Net Income (Loss) Per Share
Basic	$	(7.47	)	$	2.03		$	(7.77	)	$	4.55
Diluted	$	(7.47	)	$	2.01		$	(7.77	)	$	4.51
Dividends Declared per Common Share	$	0.1675		$	0.1675		$	0.5025		$	0.4175
Average Number of Common Shares
Basic	545,920			543,984			545,466			543,086
Diluted	545,920			549,518			545,466			548,401
Comprehensive Income (Loss)
Net Income (Loss)	$	(4,075,739	)	$	1,103,618		$	(4,240,219	)	$	2,470,899
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments	(7,004		)	(38,886		)	(11,767		)	(27,438		)
Other, Net of Tax	28			23			(156		)	(671		)
Other Comprehensive Loss	(6,976		)	(38,863		)	(11,923		)	(28,109		)
Comprehensive Income (Loss)	$	(4,082,715	)	$	1,064,755		$	(4,252,142	)	$	2,442,790

The accompanying notes are an integral part of these consolidated financial statements.

-3-

EOG RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Data)

(Unaudited)



	September 30, 2015			December 31, 2014
ASSETS
Current Assets
Cash and Cash Equivalents	$	742,689		$	2,087,213
Accounts Receivable, Net	1,123,111			1,779,311
Inventories	660,252			706,597
Assets from Price Risk Management Activities	71,503			465,128
Income Taxes Receivable	53,667			71,621
Deferred Income Taxes	40,619			19,618
Other	133,117			286,533
Total	2,824,958			5,416,021
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	50,025,191			46,503,532
Other Property, Plant and Equipment	3,890,934			3,750,958
Total Property, Plant and Equipment	53,916,125			50,254,490
Less: Accumulated Depreciation, Depletion and Amortization	(29,640,793		)	(21,081,846		)
Total Property, Plant and Equipment, Net	24,275,332			29,172,644
Other Assets	176,957			174,022
Total Assets	$	27,277,247		$	34,762,687
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	1,561,574		$	2,860,548
Accrued Taxes Payable	174,897			140,098
Dividends Payable	91,377			91,594
Deferred Income Taxes	—			110,743
Short-Term Borrowings and Current Portion of Long-Term Debt	36,279			6,579
Other	182,834			174,746
Total	2,046,961			3,384,308

Long-Term Debt	6,393,931			5,903,354
Other Liabilities	970,288			939,497
Deferred Income Taxes	4,581,844			6,822,946
Commitments and Contingencies (Note 8)

Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 550,052,879 Shares Issued at September 30, 2015 and 549,028,374 Shares Issued at December 31, 2014	205,503			205,492
Additional Paid in Capital	2,897,439			2,837,150
Accumulated Other Comprehensive Loss	(34,979		)	(23,056		)
Retained Earnings	10,247,349			14,763,098
Common Stock Held in Treasury, 383,870 Shares at September 30, 2015 and 733,517 Shares at December 31, 2014	(31,089		)	(70,102		)
Total Stockholders' Equity	13,284,223			17,712,582
Total Liabilities and Stockholders' Equity	$	27,277,247		$	34,762,687

The accompanying notes are an integral part of these consolidated financial statements.

-4-

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)



	Nine Months Ended September 30,
	2015			2014
Cash Flows from Operating Activities
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities:
Net Income (Loss)	$	(4,240,219	)	$	2,470,899
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	2,544,187			2,983,111
Impairments	6,445,375			207,938
Stock-Based Compensation Expenses	101,926			103,636
Deferred Income Taxes	(2,377,030		)	974,522
(Gains) Losses on Asset Dispositions, Net	5,142			(75,700		)
Other, Net	3,735			17,188
Dry Hole Costs	14,317			30,265
Mark-to-Market Commodity Derivative Contracts
Total Gains	(56,954		)	(84,119		)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts	661,021			(188,937		)
Excess Tax Benefits from Stock-Based Compensation	(24,219		)	(87,827		)
Other, Net	8,904			8,701
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	448,311			(341,043		)
Inventories	27,007			(119,166		)
Accounts Payable	(1,310,211		)	566,753
Accrued Taxes Payable	77,575			176,412
Other Assets	146,965			(61,966		)
Other Liabilities	(15,683		)	66,618
Changes in Components of Working Capital Associated with Investing and Financing Activities	519,203			(108,568		)
Net Cash Provided by Operating Activities	2,979,352			6,538,717
Investing Cash Flows
Additions to Oil and Gas Properties	(3,918,065		)	(5,653,035		)
Additions to Other Property, Plant and Equipment	(252,295		)	(587,178		)
Proceeds from Sales of Assets	144,285			91,335
Changes in Restricted Cash	—			(91,238		)
Changes in Components of Working Capital Associated with Investing Activities	(519,323		)	108,999
Net Cash Used in Investing Activities	(4,545,398		)	(6,131,117		)
Financing Cash Flows
Net Commercial Paper Borrowings	29,700			—
Long-Term Debt Borrowings	990,225			496,220
Long-Term Debt Repayments	(500,000		)	(500,000		)
Settlement of Foreign Currency Swap	—			(31,573		)
Dividends Paid	(274,577		)	(187,670		)
Excess Tax Benefits from Stock-Based Compensation	24,219			87,827
Treasury Stock Purchased	(43,419		)	(114,824		)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	14,967			11,740
Debt Issuance Costs	(5,933		)	(895		)
Repayment of Capital Lease Obligation	(4,599		)	(4,457		)
Other, Net	120			(431		)
Net Cash Provided by (Used in) Financing Activities	230,703			(244,063		)
Effect of Exchange Rate Changes on Cash	(9,181		)	(601		)
Increase (Decrease) in Cash and Cash Equivalents	(1,344,524		)	162,936
Cash and Cash Equivalents at Beginning of Period	2,087,213			1,318,209
Cash and Cash Equivalents at End of Period	$	742,689		$	1,481,145

The accompanying notes are an integral part of these consolidated financial statements.

-5-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

General. The consolidated financial statements of EOG Resources, Inc., together with its subsidiaries (collectively, EOG), included herein have been prepared by management without audit pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC). Accordingly, they reflect all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the financial results for the interim periods presented. Certain information and notes normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) have been condensed or omitted pursuant to such rules and regulations. However, management believes that the disclosures included either on the face of the financial statements or in these notes are sufficient to make the interim information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in EOG's Annual Report on Form 10-K for the year ended December 31, 2014, filed on February 18, 2015 (EOG's 2014 Annual Report).

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The operating results for the three and nine months ended September 30, 2015, are not necessarily indicative of the results to be expected for the full year.

Recently Issued Accounting Standards. In July 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2015-11, "Accounting for Inventory" (ASU 2015-11), which requires entities to measure most inventory at lower of cost or net realizable value. ASU 2015-11 defines net realizable value as "the estimated selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal and transportation." ASU 2015-11 is effective prospectively for interim and annual periods beginning after December 15, 2016. EOG is reviewing the requirements of the new standard and does not believe that the adoption of ASU 2015-11 will have a material impact on its consolidated financial statements and related disclosures.

In April 2015, the FASB issued ASU 2015-03, "Interest - Computation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" (ASU 2015-03), which changes the presentation of debt issuance costs in financial statements. Under ASU 2015-03, an entity will present debt issuance costs in the balance sheet as a direct reduction from the related debt liability rather than as an asset. Amortization of such costs will be presented as a component of interest expense. ASU 2015-03 is effective for interim and annual reporting periods beginning after December 15, 2015. Early adoption is permitted. Because ASU 2015-03 does not address debt issuance costs related to line-of-credit arrangements, in August 2015, the FASB issued ASU 2015-15 "Interest - Computation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements" (ASU 2015-15). ASU 2015-15 provides that, in the absence of authoritative guidance in ASU 2015-03, the SEC would not object to an entity deferring and presenting debt issuance costs related to a line-of-credit arrangement as an asset and subsequently amortizing the deferred debt issuance costs over the term of the line-of-credit arrangement. EOG does not expect the adoption of ASU 2015-03 and ASU 2015-15 to have a material impact on its consolidated financial statements and related disclosures.

In May 2014, the FASB issued ASU 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09), which will require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will supersede most current guidance related to revenue recognition when it becomes effective. The new standard also will require expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. The FASB originally intended ASU 2014-09 to be effective for interim and annual reporting periods beginning after December 15, 2016 and permits adoption through the use of either the full retrospective approach or a modified retrospective approach. In July 2015, the FASB issued an update which delays by one year the effective date of ASU 2014-09 and allows for early adoption as of the original effective date. EOG has not determined which transition method it will use and is continuing to analyze ASU 2014-09 to determine what impact the new standard will have on its consolidated financial statements and related disclosures.

-6-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

2. Stock-Based Compensation

As more fully discussed in Note 7 to the Consolidated Financial Statements included in EOG's 2014 Annual Report, EOG maintains various stock-based compensation plans. Stock-based compensation expense is included on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) based upon the job function of the employees receiving the grants as follows (in millions):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Lease and Well	$	10.3	$	9.7	$	32.9	$	30.4
Gathering and Processing Costs	0.4		0.4		1.0		0.9
Exploration Costs	6.0		6.7		19.3		20.2
General and Administrative	23.6		21.7		48.8		52.1
Total	$	40.3	$	38.5	$	102.0	$	103.6

The Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) provides for grants of stock options, stock-settled stock appreciation rights (SAR), restricted stock and restricted stock units, performance units and performance stock and other stock-based awards. At September 30, 2015, approximately 24.6 million common shares remained available for grant under the 2008 Plan. EOG's policy is to issue shares related to the 2008 Plan from either previously authorized unissued shares or treasury shares to the extent treasury shares are available.

Stock Options and Stock-Settled Stock Appreciation Rights and Employee Stock Purchase Plan. The fair value of stock option grants and SAR grants is estimated using the Hull-White II binomial option pricing model. The fair value of Employee Stock Purchase Plan (ESPP) grants is estimated using the Black-Scholes-Merton model. Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $20.0 million and $21.2 million during the three months ended September 30, 2015 and 2014, respectively, and $43.3 million and $44.9 million during the nine months ended September 30, 2015 and 2014, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants during the nine-month periods ended September 30, 2015 and 2014 are as follows:



	Stock Options/SARs						ESPP
	Nine Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Weighted Average Fair Value of Grants	$	21.87		$	30.77		$	21.40		$	21.27
Expected Volatility	38.04		%	35.25		%	32.54		%	25.12		%
Risk-Free Interest Rate	0.83		%	0.95		%	0.12		%	0.08		%
Dividend Yield	0.85		%	0.60		%	0.72		%	0.50		%
Expected Life	5.3 years			5.2 years			0.5 years			0.5 years

Expected volatility is based on an equal weighting of historical volatility and implied volatility from traded options in EOG's common stock. The risk-free interest rate is based upon United States Treasury yields in effect at the time of grant. The expected life is based upon historical experience and contractual terms of stock option, SAR and ESPP grants.

-7-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth stock option and SAR transactions for the nine-month periods ended September 30, 2015 and 2014 (stock options and SARs in thousands):



	Nine Months Ended September 30, 2015				Nine Months Ended September 30, 2014
	Number of Stock Options/SARs		Weighted Average Grant Price		Number of Stock Options/SARs		Weighted Average Grant Price
Outstanding at January 1	10,493		$	64.96	10,452		$	54.43
Granted	2,029		69.95		2,122		101.65
Exercised ⁽¹⁾	(1,291	)	47.25		(1,351	)	44.52
Forfeited	(203	)	80.12		(226	)	62.95
Outstanding at September 30 ⁽²⁾	11,028		$	67.67	10,997		$	64.58
Vested or Expected to Vest ⁽³⁾	10,653		$	67.22	10,568		$	63.92
Exercisable at September 30 ⁽⁴⁾	6,121		$	57.34	5,573		$	49.23


(1)	The total intrinsic value of stock options/SARs exercised for the nine months ended September 30, 2015 and 2014 was $52.4 million and $78.0 million, respectively. The intrinsic value is based upon the difference between the market price of EOG's common stock on the date of exercise and the grant price of the stock options/SARs.


(2)	The total intrinsic value of stock options/SARs outstanding at September 30, 2015 and 2014 was $136.9 million and $384.9 million, respectively. At September 30, 2015 and 2014, the weighted average remaining contractual life was 4.4 years and 4.6 years, respectively.


(3)	The total intrinsic value of stock options/SARs vested or expected to vest at September 30, 2015 and 2014 was $135.7 million and $376.6 million, respectively. At September 30, 2015 and 2014, the weighted average remaining contractual life was 4.3 years and 4.5 years, respectively.


(4)	The total intrinsic value of stock options/SARs exercisable at September 30, 2015 and 2014 was $121.6 million and $277.5 million, respectively. At September 30, 2015 and 2014, the weighted average remaining contractual life was 3.1 years and 3.3 years, respectively.

At September 30, 2015, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $112.2 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 3.0 years.

Restricted Stock and Restricted Stock Units. Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them. Stock-based compensation expense related to restricted stock and restricted stock units totaled $16.2 million and $13.9 million for the three months ended September 30, 2015 and 2014, respectively, and $53.9 million and $53.4 million for the nine months ended September 30, 2015 and 2014, respectively.

-8-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth restricted stock and restricted stock unit transactions for the nine-month periods ended September 30, 2015 and 2014 (shares and units in thousands):



	Nine Months Ended September 30, 2015				Nine Months Ended September 30, 2014
	Number of Shares and Units		Weighted Average Grant Date Fair Value		Number of Shares and Units		Weighted Average Grant Date Fair Value
Outstanding at January 1	5,394		$	64.39	7,358		$	49.54
Granted	1,036		77.90		1,024		99.00
Released ⁽¹⁾	(1,250	)	51.02		(2,540	)	37.92
Forfeited	(152	)	74.83		(220	)	59.36
Outstanding at September 30 ⁽²⁾	5,028		$	70.18	5,622		$	63.41


(1)	The total intrinsic value of restricted stock and restricted stock units released for the nine months ended September 30, 2015 and 2014 was $102.5 million and $270.0 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date the restricted stock and restricted stock units are released.


(2)	The total intrinsic value of restricted stock and restricted stock units outstanding at September 30, 2015 and 2014 was $366.0 million and $556.7 million, respectively.

At September 30, 2015, unrecognized compensation expense related to restricted stock and restricted stock units totaled $194.5 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.7 years.

Performance Units and Performance Stock. EOG grants performance units and/or performance stock to its executive officers. The fair value of the performance units and performance stock is estimated using a Monte Carlo simulation. Stock-based compensation expense related to performance unit and performance stock grants totaled $4.1 million and $3.4 million for the three months ended September 30, 2015 and 2014, respectively, and $4.8 million and $5.3 million for the nine months ended September 30, 2015 and 2014, respectively.

Weighted average fair values and valuation assumptions used to value performance unit and performance stock grants during the nine-month periods ended September 30, 2015 and 2014 are as follows:



	Nine Months Ended September 30,
	2015			2014
Weighted Average Fair Value of Grants	$	80.64		$	119.27
Expected Volatility	29.35		%	32.18		%
Risk-Free Interest Rate	1.07		%	1.18		%

Expected volatility is based on the term-matched historical volatility over the simulated term, which is calculated as the time between the grant date and the end of the performance period. The risk-free interest rate is based on a 3.26 year zero-coupon risk-free interest rate derived from the Treasury Constant Maturities yield curve on the grant date.

-9-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth performance unit and performance stock transactions for the nine-month periods ended September 30, 2015 and 2014 (shares and units in thousands):



	Nine Months Ended September 30, 2015			Nine Months Ended September 30, 2014
	Number of Shares and Units	Weighted Average Grant Date Fair Value		Number of Shares and Units	Weighted Average Grant Date Fair Value
Outstanding at January 1	333	$	90.17	261	$	82.18
Granted	72	80.64		72	119.27
Released	—	—		—	—
Forfeited	—	—		—	—
Outstanding at September 30 ⁽¹⁾	405	$	88.48	333	$	90.17


(1)	The total intrinsic value of performance units and performance stock outstanding at September 30, 2015 and 2014 was $29.5 million and $33.0 million, respectively.

At September 30, 2015, unrecognized compensation expense related to performance units and performance stock totaled $6.4 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 3.5 years.

3. Net Income (Loss) Per Share

The following table sets forth the computation of Net Income (Loss) Per Share for the three-month and nine-month periods ended September 30, 2015 and 2014 (in thousands, except per share data):



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014
Numerator for Basic and Diluted Earnings Per Share -
Net Income (Loss)	$	(4,075,739	)	$	1,103,618	$	(4,240,219	)	$	2,470,899
Denominator for Basic Earnings Per Share -
Weighted Average Shares	545,920			543,984		545,466			543,086
Potential Dilutive Common Shares -
Stock Options/SARs	—			2,760		—			2,644
Restricted Stock/Units and Performance Units/Stock	—			2,774		—			2,671
Denominator for Diluted Earnings Per Share -
Adjusted Diluted Weighted Average Shares	545,920			549,518		545,466			548,401
Net Income (Loss) Per Share
Basic	$	(7.47	)	$	2.03	$	(7.77	)	$	4.55
Diluted	$	(7.47	)	$	2.01	$	(7.77	)	$	4.51

The diluted earnings per share calculation excludes stock options, SARs, restricted stock and units and performance units and stock that were anti-dilutive. Shares underlying the excluded stock options and SARs totaled 9.8 million and 0.2 million shares for the three months ended September 30, 2015 and 2014, respectively, and 10.0 million and 0.2 million shares for the nine months ended September 30, 2015 and 2014, respectively. For both the three months and nine months ended September 30, 2015, 5.4 million shares of restricted stock and restricted stock units and performance units and performance stock were excluded.

-10-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

4. Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the nine-month periods ended September 30, 2015 and 2014 (in thousands):



	Nine Months Ended September 30,
	2015		2014
Interest ⁽¹⁾	$	152,590	$	143,615
Income Taxes, Net of Refunds Received	$	69,281	$	330,476


(1)	Net of capitalized interest of $33 million and $43 million for the nine months ended September 30, 2015 and 2014, respectively.

EOG's accrued capital expenditures at September 30, 2015 and 2014 were $437 million and $960 million, respectively.

5. Segment Information

As more fully discussed in Note 13, during the fourth quarter of 2014, EOG completed the sale of substantially all of its Canadian operations. As a result, information related to EOG's remaining Canadian operations have been included in the Other International segment and prior year amounts have been reclassified to conform to current year presentation. Selected financial information by reportable segment is presented below for the three-month and nine-month periods ended September 30, 2015 and 2014 (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Net Operating Revenues
United States	$	2,040,881		$	4,924,226		$	6,622,781		$	12,748,128
Trinidad	98,493			123,154			290,758			398,140
Other International ⁽¹⁾	33,054			71,236			47,128			243,575
Total	$	2,172,428		$	5,118,616		$	6,960,667		$	13,389,843
Operating Income (Loss)
United States	$	(6,110,284	)	$	1,767,044		$	(6,271,908	)	$	3,900,263
Trinidad	46,230			61,328			139,116			209,785
Other International ⁽¹⁾	(158,903		)	(42,210		)	(223,534		)	(94,877		)
Total	(6,222,957		)	1,786,162			(6,356,326		)	4,015,171
Reconciling Items
Other Income (Expense), Net	8,607			(21,338		)	7,996			(16,726		)
Interest Expense, Net	60,571			49,704			174,400			151,723
Income (Loss) Before Income Taxes	$	(6,274,921	)	$	1,715,120		$	(6,522,730	)	$	3,846,722

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

-11-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Total assets by reportable segment are presented below at September 30, 2015 and December 31, 2014 (in thousands):



	At September 30, 2015		At December 31, 2014
Total Assets
United States	$	25,550,746	$	32,871,398
Trinidad	879,643		865,674
Other International ⁽¹⁾	846,858		1,025,615
Total	$	27,277,247	$	34,762,687

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

6. Asset Retirement Obligations

The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the nine-month periods ended September 30, 2015 and 2014 (in thousands):



	Nine Months Ended September 30,
	2015			2014
Carrying Amount at Beginning of Period	$	752,718		$	761,898
Liabilities Incurred	38,095			91,822
Liabilities Settled ⁽¹⁾	(12,929		)	(44,805		)
Accretion	23,810			33,833
Revisions	(13,576		)	68,785
Foreign Currency Translations	(4,361		)	(4,178		)
Carrying Amount at End of Period	$	783,757		$	907,355

Current Portion	$	11,592		$	12,528
Noncurrent Portion	$	772,165		$	894,827


(1)	Includes settlements related to asset sales.

The current and noncurrent portions of EOG's asset retirement obligations are included in Current Liabilities - Other and Other Liabilities, respectively, on the Consolidated Balance Sheets.

-12-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

7. Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the nine-month period ended September 30, 2015, are presented below (in thousands):



	Nine Months Ended September 30, 2015
Balance at January 1	$	17,253
Additions Pending the Determination of Proved Reserves	23,936
Reclassifications to Proved Properties	(26,499		)
Costs Charged to Expense	(6,178		)	(1)
Balance at September 30	$	8,512


(1)	Includes capitalized exploratory well costs charged to dry hole costs.

At September 30, 2015, all capitalized exploratory well costs had been capitalized for periods of less than one year.

8. Commitments and Contingencies

There are currently various suits and claims pending against EOG that have arisen in the ordinary course of EOG's business, including contract disputes, personal injury and property damage claims and title disputes. While the ultimate outcome and impact on EOG cannot be predicted, management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material adverse effect on EOG's consolidated financial position, results of operations or cash flow. EOG records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

9. Pension and Postretirement Benefits

EOG has defined contribution pension plans in place for most of its employees in the United States, Trinidad and the United Kingdom, and defined benefit pension plans covering certain of its employees in Trinidad. For the nine months ended September 30, 2015 and 2014, EOG's total costs recognized for these pension plans were $27.0 million and $29.6 million, respectively. In connection with the divestiture of substantially all of its Canadian assets in the fourth quarter of 2014, EOG has elected to terminate the Canadian non-contributory defined benefit pension plan. EOG also has postretirement medical and dental plans in place for eligible employees in the United States and Trinidad, the costs of which are not material.

10. Long-Term Debt

During the nine months ended September 30, 2015 and 2014, EOG utilized commercial paper and short-term borrowings under uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes. At September 30, 2015 and 2014, EOG had $30 million and zero, respectively, of outstanding short-term borrowings from commercial paper and no outstanding borrowings from uncommitted credit facilities. The average borrowings outstanding under the commercial paper program were $7 million and $16 million during the nine months ended September 30, 2015 and 2014, respectively. The average borrowings outstanding under the uncommitted credit facilities were zero and $0.1 million during the nine months ended September 30, 2015 and 2014, respectively. The weighted average interest rates for commercial paper borrowings during the nine months ended September 30, 2015 and 2014 were 0.45% and 0.25%, respectively, and 0.70% for uncommitted credit facility borrowings during the nine months ended September 30, 2014.

At September 30, 2015, the $400 million aggregate principal amount of 2.500% Senior Notes due 2016 were classified as long-term debt based upon EOG's intent and ability to ultimately replace such amount with other long-term debt.

On June 1, 2015, EOG repaid upon maturity the $500 million aggregate principal amount of its 2.95% Senior Notes due 2015.

-13-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

payable semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2015. Net proceeds from the Notes offering of approximately $990 million were used for general corporate purposes.

On July 21, 2015, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (2015 Agreement) with domestic and foreign lenders. The 2015 Agreement replaces EOG's $2.0 billion senior unsecured Revolving Credit Agreement, dated as of October 11, 2011, which had a scheduled maturity date of October 11, 2016 (2011 Agreement). There were no borrowings or letters of credit outstanding under the 2011 Agreement as of the closing of the 2015 Agreement and the termination of the 2011 Agreement. The 2015 Agreement has a scheduled maturity date of July 21, 2020, and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods subject to certain terms and conditions. Advances under the 2015 Agreement will accrue interest based, at EOG's option, on either the London InterBank Offered Rate plus an applicable margin (Eurodollar rate) or the base rate (as defined in the 2015 Agreement) plus an applicable margin. Consistent with the terms of the 2011 Agreement, the 2015 Agreement contains representations, warranties, covenants and events of default that are customary for investment-grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a debt-to-total capitalization ratio of no greater than 65%. At September 30, 2015, there were no borrowings or letters of credit outstanding under the 2015 Agreement. The Eurodollar rate and applicable base rate, had there been any amounts borrowed under the 2015 Agreement, would have been 1.09% and 3.25%, respectively.

11. Fair Value Measurements

As more fully discussed in Note 13 to the Consolidated Financial Statements included in EOG's 2014 Annual Report, certain of EOG's financial and nonfinancial assets and liabilities are reported at fair value on the Consolidated Balance Sheets. The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at September 30, 2015 and December 31, 2014 (in millions):



	Fair Value Measurements Using:
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
At September 30, 2015
Financial Assets
Natural Gas Options/Swaptions	$	—	$	31	$	—	$	31
Crude Oil Swaps/Put Options	—		40		—		40

At December 31, 2014
Financial Assets
Natural Gas Options/Swaptions	$	—	$	100	$	—	$	100
Crude Oil Swaps	—		121		—		121
Crude Oil Options/Swaptions	—		244		—		244

The estimated fair value of crude oil and natural gas derivative contracts (including options/swaptions) was based upon forward commodity price curves based on quoted market prices. Commodity derivative contracts were valued by utilizing an independent third-party derivative valuation provider who uses various types of valuation models, as applicable.

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of EOG's asset retirement obligations is presented in Note 6.

-14-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Due to the decline in commodity prices, proved oil and gas properties, other property, plant and equipment and other assets with a carrying amount of $8,857 million were written down to their fair value of $2,627 million, resulting in pretax impairment charges of $6,230 million, $4,061 million net of tax, for the nine months ended September 30, 2015. Impairments included domestic legacy natural gas assets and marginal liquids plays and the Conwy crude oil project in the East Irish Sea. Significant Level 3 inputs associated with the calculation of discounted cash flows used in the impairment analysis include EOG's estimate of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data.

Fair Value of Debt. At September 30, 2015 and December 31, 2014, EOG had outstanding $6,390 million and $5,890 million, respectively, aggregate principal amount of senior notes, which had estimated fair values of approximately $6,673 million and $6,242 million, respectively. The estimated fair value of the senior notes was based upon quoted market prices and, where such prices were not available, other observable (Level 2) inputs regarding interest rates available to EOG at the end of each respective period.

12. Risk Management Activities

Commodity Price Risk. As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's 2014 Annual Report, EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis swap contracts, as a means to manage this price risk. EOG has not designated any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for financial commodity derivative contracts using the mark-to-market accounting method.

Commodity Derivative Contracts. Presented below is a comprehensive summary of EOG's crude oil price swap contracts at September 30, 2015, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).



Crude Oil Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2015
January 1, 2015 through June 30, 2015 (closed)	47,000	$	91.22
July 1, 2015 through September 30, 2015 (closed)	10,000	89.98
October 1, 2015 through December 31, 2015	10,000	89.98

-15-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

EOG has purchased put options which establish a floor price for the sale of certain notional volumes of crude oil as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the average NYMEX West Texas Intermediate crude oil price for the contract month (Index Price), in the event the Index Price is below the put option strike price. If the Index Price is above the put option strike price, EOG is only required to pay the put option premium. Below is a summary of EOG's put option contracts at September 30, 2015, with notional volumes expressed in Bbld and prices and premiums expressed in $/Bbl.



Crude Oil Put Option Contracts
	Volume (Bbld)	Average Premium ($/Bbl)		Strike Price ($/Bbl)
2015
September 2015 (closed)	82,500	$	1.75	$	45.00
October 1, 2015 through November 30, 2015	82,500	1.75		45.00

Presented below is a comprehensive summary of EOG's natural gas price swap contracts at September 30, 2015, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).



Natural Gas Price Swap Contracts
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2015 ⁽¹⁾
January 1, 2015 through February 28, 2015 (closed)	235,000	$	4.47
March 2015 (closed)	225,000	4.48
April 2015 (closed)	195,000	4.49
May 2015 (closed)	235,000	4.13
June 1, 2015 through July 31, 2015 (closed)	275,000	3.98
August 1, 2015 through October 31, 2015 (closed)	175,000	4.51
November 1, 2015 through December 31, 2015	175,000	4.51

(1)

EOG has entered into natural gas price swap contracts which give counterparties the option of entering into price swap 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 price swap contracts will increase by 175,000 MMBtud at an average price of $4.51 per MMBtu for each month during the period November 1, 2015 through December 31, 2015.

-16-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth the amounts and classification of EOG's outstanding derivative financial instruments at September 30, 2015 and December 31, 2014. Certain amounts may be presented on a net basis on the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions):



		Fair Value at
Description	Location on Balance Sheet	September 30, 2015		December 31, 2014

Asset Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Assets from Price Risk Management Activities ⁽¹⁾	$	71	$	465

Liability Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Liabilities from Price Risk Management Activities ⁽²⁾	$	—	$	—


(1)	The current portion of Assets from Price Risk Management Activities consists of gross assets of $80 million, partially offset by gross liabilities of $9 million at September 30, 2015, and gross assets of $477 million, partially offset by gross liabilities of $12 million at December 31, 2014.


(2)	The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $9 million, offset by gross assets of $9 million at September 30, 2015, and gross liabilities of $12 million, offset by gross assets of $12 million at December 31, 2014.

Credit Risk. Notional contract amounts are used to express the magnitude of commodity price swap agreements. The amounts potentially subject to credit risk, in the event of nonperformance by the counterparties, are equal to the fair value of such contracts (see Note 11). EOG evaluates its exposure to significant counterparties on an ongoing basis, including those arising from physical and financial transactions. In some instances, EOG renegotiates payment terms and/or requires collateral, parent guarantees or letters of credit to minimize credit risk.

All of EOG's outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (ISDAs) with counterparties. The ISDAs may contain provisions that require EOG, if it is the party in a net liability position, to post collateral when the amount of the net liability exceeds the threshold level specified for EOG's then-current credit ratings. In addition, the ISDAs may also provide that as a result of certain circumstances, including certain events that cause EOG's credit ratings to become materially weaker than its then-current ratings, the counterparty may require all outstanding derivatives under the ISDAs to be settled immediately. See Note 11 for the aggregate fair value of all derivative instruments that were in a net asset position at September 30, 2015 and December 31, 2014. EOG held collateral of $30 million and $278 million at September 30, 2015 and December 31, 2014, respectively, and had no collateral posted at September 30, 2015 or December 31, 2014.

-17-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Concluded)

(Unaudited)

13. Acquisitions and Divestitures

During the third quarter of 2015, EOG completed three transactions to acquire certain proved crude oil properties and related assets in the Delaware Basin. The aggregate purchase price of the transactions totaled approximately $368 million.

During the first nine months of 2015, EOG received proceeds of approximately $144 million primarily from sales of gathering and processing assets. During the first nine months of 2014, EOG received proceeds of approximately $91 million from sales of producing properties and acreage primarily in the Mid-Continent area, the Upper Gulf Coast region, Canada and the Rocky Mountain area.

During the fourth quarter of 2014, EOG received proceeds of approximately $400 million from the divestiture of all its assets in Manitoba and the majority of its assets in Alberta (collectively, the Canadian Sales). The Canadian Sales that closed on or about December 1, 2014, occurred in two separate transactions, an asset sale and the sale of the stock of certain of EOG's Canadian subsidiaries. As these two transactions represented a substantially complete liquidation of EOG's Canadian operations, approximately $383 million of cumulative translation adjustments previously recorded on the Consolidated Balance Sheets was reclassified to the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). The Canadian Sales also resulted in the release of approximately $150 million of restricted cash related to future abandonment liabilities.

-18-

PART I. FINANCIAL INFORMATION

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EOG RESOURCES, INC.

Overview

EOG Resources, Inc., together with its subsidiaries (collectively, EOG), is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, Canada, the United Kingdom and China. EOG operates under a consistent business strategy that focuses predominantly on maximizing the rate of return on investment of capital by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves, controlling operating and capital costs and maximizing reserve recoveries. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to deliver long-term production growth while maintaining a strong balance sheet. Maintaining the lowest possible operating cost structure that is consistent with prudent and safe operations is also an important goal in the implementation of EOG's strategy.

United States. EOG's efforts to identify plays with large reserve potential have proven to be successful. EOG continues to drill numerous wells in large acreage plays, which in the aggregate have contributed substantially to, and are expected to continue to contribute substantially to, EOG's crude oil and liquids-rich natural gas production. EOG has placed an emphasis on applying its horizontal drilling and completion expertise to unconventional crude oil and liquids-rich reservoirs. On a volumetric basis, as calculated using the ratio of 1.0 barrel of crude oil and condensate or natural gas liquids (NGL) to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGL production accounted for approximately 71% of total United States production during the first nine months of 2015 as compared to 70% for the same comparable period in 2014. In 2015, EOG is focused on increasing drilling and completion efficiencies, testing methods to improve the recovery factor of oil-in-place and reducing operating costs through efficiency improvements and service cost reductions. Through the first nine months of 2015, drilling continued to occur primarily in the Eagle Ford, Delaware Basin and North Dakota Bakken plays, where EOG has built an inventory of uncompleted wells. In addition, EOG continues to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins or tactical acquisitions and to evaluate certain potential crude oil and liquids-rich natural gas exploration and development prospects. During the third quarter of 2015, EOG completed three transactions to acquire certain proved crude oil properties and related assets in the Delaware Basin. The aggregate purchase price of the transactions totaled approximately $368 million. Based on its 2015 drilling plan, which has been influenced by the current low commodity price environment, EOG expects its 2015 crude oil and condensate and NGL production to be relatively flat compared to 2014. EOG's major producing areas in the United States are in New Mexico, North Dakota, Texas, Utah and Wyoming.

During the third quarter of 2015, due to the decline in commodity prices, proved oil and gas properties and related assets were written down to their fair value resulting in pretax impairment charges of $6,081 million, $3,913 million net of tax. Impairments were related to legacy natural gas assets and marginal liquids plays.

Canada. As previously reported, during the fourth quarter of 2014, EOG completed the divestiture of substantially all its assets in Canada (see Note 13 to the Consolidated Financial Statements). At the time of the sales, production from the divested assets totaled approximately 7,050 barrels of crude oil per day, 580 barrels of NGLs per day and 43.5 million cubic feet of natural gas per day. Net proved reserves divested were estimated to be 7.7 million barrels of oil, 0.8 million barrels of NGLs and 78.7 billion cubic feet of natural gas. Information related to EOG's remaining Canadian operations is presented in the "Other International" segment.

International. In Trinidad, EOG continues to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium (SECC) Block, Modified U(a) Block, Block 4(a), Modified U(b) Block and the EMZ Area have been developed and are producing natural gas, which is sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary. Crude oil and condensate from these fields are sold to the Petroleum Company of Trinidad and Tobago Limited. In the third quarter of 2015, EOG completed its three net well drilling program in Trinidad.

In the United Kingdom, EOG continues to make progress in the development of its 100% working interest East Irish Sea Conwy crude oil discovery. Modifications to the nearby third-party-owned Douglas platform, which will be used to process Conwy production, continued throughout the first nine months of 2015. In the third quarter of 2015, EOG recorded pretax impairment charges of $138 million for the Conwy project, primarily related to the continued decline in crude oil prices. First production from the Conwy field is anticipated by the end of 2015.

-19-

During the first nine months of 2015, in the Sichuan Basin, Sichuan Province, China, EOG drilled and completed a well. The successful completion extended the Shaxzimiao development in the Chuanzhong Block and provides additional opportunity for 2016.

EOG's activity in Argentina is focused on the Vaca Muerta oil shale formation in the Neuquén Province. Management is currently evaluating options for this investment.

EOG continues to evaluate other select crude oil and natural gas opportunities outside the United States primarily by pursuing exploitation opportunities in countries where indigenous crude oil and natural gas reserves have been identified.

The declines in commodity prices are expected to negatively impact the amount of EOG's year-end 2015 reserves to be calculated under the United States Securities and Exchange Commission rules which require companies to use a trailing 12-month average price to determine the year-end reported reserve quantities. Such prices have decreased in 2015 by approximately 45% for crude oil and condensate and 40% for natural gas compared to the prices used in estimating the reserves disclosed in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2014. EOG is unable to predict the amount of future reserve revisions at this time.

Capital Structure. One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 33% and 25% at September 30, 2015 and December 31, 2014, respectively. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity. At September 30, 2015, the $400 million aggregate principal amount of EOG's 2.500% Senior Notes due 2016 was classified as long-term debt based upon its intent and ability to ultimately replace such amount with other long-term debt.

On July 21, 2015, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (2015 Agreement) with domestic and foreign lenders (Banks). The 2015 Agreement replaces EOG's $2.0 billion senior unsecured revolving credit agreement which was cancelled by EOG upon the closing of the 2015 Agreement. The 2015 Agreement has a scheduled maturity date of July 21, 2020, and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods, subject to certain terms and conditions. The 2015 Agreement commits the Banks to provide advances up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions.

On June 1, 2015, EOG repaid upon maturity the $500 million aggregate principal amount of its 2.95% Senior Notes due 2015.

On March 17, 2015, EOG closed its sale of the $500 million aggregate principal amount of its 3.15% Senior Notes due 2025 and the $500 million aggregate principal amount of its 3.90% Senior Notes due 2035 (together, the Notes). Interest on the Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2015. Net proceeds from the Notes offering of approximately $990 million were used for general corporate purposes.

Total anticipated 2015 capital expenditures are estimated to range from approximately $4.7 billion to $4.9 billion, excluding acquisitions. The majority of 2015 expenditures have been, and will continue to be, focused on United States crude oil drilling activities. The 2015 capital expenditure program has been structured to maintain EOG's strategy of capital discipline by funding its exploration, development and exploitation activities primarily from available internally generated cash flows and cash on hand. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program and other uncommitted credit facilities, bank borrowings, borrowings under the 2015 Agreement and equity and debt offerings.

When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer incremental exploration and/or production opportunities. Management continues to believe EOG has one of the strongest prospect inventories in EOG's history.

-20-

Results of Operations

The following review of operations for the three months ended September 30, 2015 and 2014 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included in this Quarterly Report on Form 10-Q.

Three Months Ended September 30, 2015 vs. Three Months Ended September 30, 2014

Net Operating Revenues. During the third quarter of 2015, net operating revenues decreased $2,947 million, or 58%, to $2,172 million from $5,119 million for the same period of 2014. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, for the third quarter of 2015 decreased $1,816 million, or 54%, to $1,558 million from $3,374 million for the same period of 2014. During the third quarter of 2015, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $29 million compared to net gains of $469 million for the same period of 2014. Gathering, processing and marketing revenues, which are revenues generated from sales of third-party crude oil and condensate, NGLs and natural gas as well as fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand, for the third quarter of 2015 decreased $625 million, or 52%, to $572 million from $1,197 million for the same period of 2014.

-21-

Wellhead volume and price statistics for the three-month periods ended September 30, 2015 and 2014 were as follows:



	Three Months Ended September 30,
	2015			2014
Crude Oil and Condensate Volumes (MBbld) ⁽¹⁾
United States	278.3			293.2
Trinidad	1.0			0.9
Other International ⁽²⁾	0.2			5.4
Total	279.5			299.5
Average Crude Oil and Condensate Prices ($/Bbl) ⁽³⁾
United States	$	45.93		$	97.33
Trinidad	38.56			87.87
Other International ⁽²⁾	61.80			87.72
Composite	45.91			97.13
Natural Gas Liquids Volumes (MBbld) ⁽¹⁾
United States	77.7			85.8
Other International ⁽²⁾	0.1			0.6
Total	77.8			86.4
Average Natural Gas Liquids Prices ($/Bbl) ⁽³⁾
United States	$	13.25		$	32.61
Other International ⁽²⁾	8.05			40.38
Composite	13.24			32.67
Natural Gas Volumes (MMcfd) ⁽¹⁾
United States	889			941
Trinidad	355			356
Other International ⁽²⁾	30			72
Total	1,274			1,369
Average Natural Gas Prices ($/Mcf) ⁽³⁾
United States	$	2.04		$	3.48
Trinidad	2.90			3.50
Other International ⁽²⁾	7.18		(5)	4.16
Composite	2.40			3.52
Crude Oil Equivalent Volumes (MBoed) ⁽⁴⁾
United States	504.2			536.1
Trinidad	60.2			60.1
Other International ⁽²⁾	5.2			17.9
Total	569.6			614.1

Total MMBoe ⁽⁴⁾	52.4			56.5


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


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


(3)	Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Consolidated Financial Statements).

(4)

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


(5)	Includes revenue adjustment of $3.62 per Mcf related to a price adjustment for natural gas sales made in China during the period June 2012 through March 2015.

-22-

Wellhead crude oil and condensate revenues for the third quarter of 2015 decreased $1,491 million, or 56%, to $1,181 million from $2,672 million for the same period of 2014. The decline was primarily due to a lower composite wellhead crude oil and condensate price ($1,318 million) and a decrease of 20 MBbld, or 7%, in wellhead crude oil and condensate production ($173 million). Decreased production in the Rocky Mountain area, the Eagle Ford, Other International and the Fort Worth Basin Barnett Shale area was partially offset by increased production in the Permian Basin. The decrease in Other International was primarily due to the divestiture of substantially all of EOG's Canadian operations in the fourth quarter of 2014. EOG's composite wellhead crude oil and condensate price for the third quarter of 2015 decreased 53% to $45.91 per barrel compared to $97.13 per barrel for the same period of 2014.

NGL revenues for the third quarter of 2015 decreased $164 million, or 63%, to $95 million from $259 million for the same period of 2014 due to a lower composite average price ($140 million), and a decrease of 9 MBbld, or 10%, in NGL deliveries ($24 million) primarily in the Fort Worth Basin Barnett Shale area. EOG's composite NGL price for the third quarter of 2015 decreased 59% to $13.24 per barrel compared to $32.67 per barrel for the same period of 2014.

Wellhead natural gas revenues for the third quarter of 2015 decreased $161 million, or 36%, to $282 million from $443 million for the same period of 2014. The decrease was due to a lower composite wellhead natural gas price ($130 million) and a decrease in natural gas deliveries ($31 million). Natural gas deliveries for the third quarter of 2015 decreased 95 MMcfd, or 7%, compared to the same period of 2014 due primarily to lower production in the United States (52 MMcfd) and in Other International (42 MMcfd). The decrease in the United States was due primarily to decreased production in the Upper Gulf Coast, Fort Worth Basin Barnett Shale and South Texas areas, partially offset by increased production of associated natural gas from the Permian Basin and Eagle Ford. EOG's composite wellhead natural gas price for the third quarter of 2015 decreased 32% to $2.40 per Mcf compared to $3.52 per Mcf for the same period of 2014.

During the third quarter of 2015, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $29 million compared to net gains of $469 million for the same period of 2014. During the third quarter of 2015, net cash received from settlements of crude oil and natural gas financial derivative contracts was $100 million and net cash payments for settlements of crude oil and natural gas financial derivative contracts were $68 million for the same period of 2014.

Gathering, processing and marketing revenues primarily relate to the sale of third-party crude oil and natural gas. Purchases and sales of third-party crude oil and natural gas are utilized in order to balance firm transportation capacity with production in certain areas and to utilize excess capacity at EOG-owned facilities. Gathering, processing and marketing revenues also include fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. Marketing costs represent the costs of purchasing third-party crude oil and natural gas and the associated transportation costs as well as costs associated with EOG-owned sand sold to third parties.

Gathering, processing and marketing revenues less marketing costs for the third quarter of 2015 decreased $26 million as compared to the same period of 2014. The decrease primarily reflects lower margins on crude oil marketing activities.

-23-

Operating and Other Expenses. For the third quarter of 2015, operating expenses of $8,395 million were $5,063 million higher than the $3,332 million incurred during the third quarter of 2014. Third quarter 2015 operating expenses included impairments of proved properties, other property, plant and equipment and other assets of $6,225 million related to commodity price declines. The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended September 30, 2015 and 2014:



	Three Months Ended September 30,
	2015		2014
Lease and Well	$	5.40	$	6.53
Transportation Costs	3.88		4.36
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties	13.16		17.91
Other Property, Plant and Equipment	0.61		0.53
General and Administrative (G&A)	1.73		1.72
Interest Expense, Net	1.15		0.88
Total ⁽¹⁾	$	25.93	$	31.93


(1)	Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A and interest expense, net, for the three months ended September 30, 2015, compared to the same period of 2014 are set forth below. See "Net Operating Revenues" above for a discussion of production volumes.

Lease and well expenses include expenses for EOG-operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property. Lease and well expenses can be divided into the following categories: costs to operate and maintain crude oil and natural gas wells, the cost of workovers and lease and well administrative expenses. Operating and maintenance costs include, among other things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. Workovers are operations to restore or maintain production from existing wells.

Each of these categories of costs individually fluctuates from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating and maintenance costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.

Lease and well expenses of $283 million for the third quarter of 2015 decreased $85 million from $368 million for the same prior year period primarily due to lower lease and well expenses in Canada ($27 million) due to the divestiture of substantially all of EOG's operations in Canada during the fourth quarter of 2014, decreased operating and maintenance costs in the United States ($53 million) and decreased workover expenditures in the United States ($8 million).

Transportation costs represent costs associated with the delivery of hydrocarbon products from the lease to a downstream point of sale. Transportation costs include transportation fees, costs associated with crude-by-rail operations, the cost of compression (the cost of compressing natural gas to meet pipeline pressure requirements), dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees and fuel costs.

Transportation costs of $204 million for the third quarter of 2015 decreased $42 million from $246 million for the same prior year period primarily due to decreased transportation costs in the Rocky Mountain area ($26 million) and the Eagle Ford ($10 million) as a result of an increase in the use of pipelines to transport crude oil production and decreased transportation costs related to lower production from the Fort Worth Basin Barnett Shale area ($7 million).

-24-

DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual DD&A group calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or acquisition of new wells, disposition of existing wells and reserve revisions (upward or downward) primarily related to well performance, economic factors and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from period to period. DD&A of the cost of other property, plant and equipment is generally calculated using the straight-line depreciation method over the useful lives of the assets.

DD&A expenses for the third quarter of 2015 decreased $318 million to $722 million from $1,040 million for the same prior year period. DD&A expenses associated with oil and gas properties for the third quarter of 2015 were $320 million lower than the same prior year period. The decrease primarily reflects decreased rates in the United States ($231 million) and Trinidad ($9 million), decreased production in the United States ($52 million) and lower DD&A expenses in Canada ($29 million) due to the divestiture of substantially all of EOG's operations in Canada during the fourth quarter of 2014. Unit rates in the United States decreased primarily due to impairments of proved properties. See Note 11 to the Consolidated Financial Statements.

Exploration costs of $31 million for the third quarter of 2015 decreased $18 million from $49 million for the same prior year period primarily due to decreased geological and geophysical costs in the United States ($11 million) and lower exploration costs in Canada ($2 million) due to the divestiture of substantially all of EOG's operations in Canada during the fourth quarter of 2014.

Interest expense, net, of $61 million for the third quarter of 2015 increased $11 million compared to the same prior year period primarily due to increased debt outstanding ($5 million) and decreased capitalized interest ($5 million).

Gathering and processing costs represent operating and maintenance expenses and administrative expenses associated with operating EOG's gathering and processing assets.

Gathering and processing costs decreased $7 million to $35 million for the third quarter of 2015 compared to $42 million for the same prior year period. The decrease primarily reflects decreased operating expenses in the Eagle Ford ($11 million), partially offset by increased activities in the Permian Basin ($6 million).

Impairments include amortization of unproved oil and gas property costs, as well as impairments of proved oil and gas properties; other property, plant and equipment; and other assets. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. When circumstances indicate that a proved property may be impaired, EOG compares expected undiscounted future cash flows at a DD&A group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated by using the Income Approach described in the Fair Value Measurement Topic of the Financial Accounting Standards Board's Accounting Standards Codification. In certain instances, EOG utilizes accepted bids as the basis for determining fair value.

Impairments of $6,307 million for the third quarter of 2015 were $6,252 million higher than impairments for the same prior year period primarily due to increased impairments of proved properties and related assets in the United States ($6,072 million) and in the United Kingdom ($142 million), primarily with respect to the Conwy project, and increased amortization of unproved property costs in the United States ($25 million), which was caused by higher amortization rates being applied to undeveloped leasehold costs in response to the significant decrease in commodity prices and an increase in EOG's estimates of undeveloped properties not expected to be developed before lease expiration. Proved property and related asset impairments in the United States were related to legacy natural gas assets and marginal liquids plays. EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $6,225 million and $10 million for the third quarter of 2015 and 2014, respectively.

Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are generally determined based on wellhead revenues, and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.

Taxes other than income for the third quarter of 2015 decreased $99 million to $106 million (6.8% of wellhead revenues) compared to $205 million (6.1% of wellhead revenues) for the same prior year period. The decrease in taxes other than income was primarily due to decreases in severance/production taxes ($93 million), primarily as a result of decreased wellhead revenues, and in ad valorem/property taxes ($9 million), both in the United States, partially offset by a decrease in credits available to EOG in the third quarter of 2015 for Texas high-cost gas severance tax rate reductions ($6 million).

Other income (expense), net for the third quarter of 2015 increased $30 million compared to the same prior year period primarily due to a decrease in foreign currency exchange losses.

-25-

EOG recognized an income tax benefit of $2,199 million for the third quarter of 2015 compared to an income tax expense of $612 million in the third quarter of 2014 primarily due to 2015 impairments in the United States. The effective tax rate for the third quarter of 2015 was 35% compared to the prior year rate of 36%.

Nine Months Ended September 30, 2015 vs. Nine Months Ended September 30, 2014

Net Operating Revenues. During the first nine months of 2015, net operating revenues decreased $6,429 million, or 48%, to $6,961 million from $13,390 million for the same period of 2014. Total wellhead revenues for the first nine months of 2015 decreased $4,901 million, or 49%, to $5,049 million from $9,950 million for the same period of 2014. During the first nine months of 2015, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $57 million compared to net gains of $84 million for the same period of 2014. Gathering, processing and marketing revenues for the first nine months of 2015 decreased $1,419 million, or 44%, to $1,821 million from $3,240 million for the same period of 2014.

-26-

Wellhead volume and price statistics for the nine-month periods ended September 30, 2015 and 2014 were as follows:



	Nine Months Ended September 30,
	2015			2014
Crude Oil and Condensate Volumes (MBbld)
United States	284.4			275.5
Trinidad	0.9			1.0
Other International	0.2			6.1
Total	285.5			282.6
Average Crude Oil and Condensate Prices ($/Bbl) ⁽¹⁾
United States	$	49.94		$	100.10
Trinidad	41.98			90.84
Other International	58.44			90.74
Composite	49.92			99.87
Natural Gas Liquids Volumes (MBbld)
United States	76.2			78.4
Other International	0.1			0.7
Total	76.3			79.1
Average Natural Gas Liquids Prices ($/Bbl)
United States	$	14.94		$	34.83
Other International	6.05			43.01
Composite	14.93			34.90
Natural Gas Volumes (MMcfd)
United States	895			920
Trinidad	342			374
Other International	31			74
Total	1,268			1,368
Average Natural Gas Prices ($/Mcf) ⁽¹⁾
United States	$	2.14		$	4.17
Trinidad	3.01			3.61
Other International	4.63		(2)	4.56
Composite	2.44			4.04
Crude Oil Equivalent Volumes (MBoed)
United States	509.8			507.3
Trinidad	57.9			63.4
Other International	5.4			19.0
Total	573.1			589.7
Total MMBoe	156.5			161.0

(1) Excludes the impact of financial commodity derivative instruments.


(2)	Includes revenue adjustment of $1.19 per Mcf related to a price adjustment for natural gas sales made in China during the period June 2012 through March 2015.

-27-

Wellhead crude oil and condensate revenues for the first nine months of 2015 decreased $3,794 million, or 49%, to $3,894 million from $7,688 million for the same period of 2014 due primarily to a lower composite wellhead crude oil and condensate price. EOG's composite wellhead crude oil and condensate price for the first nine months of 2015 decreased 50% to $49.92 per barrel compared to $99.87 per barrel for the same period of 2014.

NGL revenues for the first nine months of 2015 decreased $442 million, or 59%, to $311 million from $753 million for the same period of 2014 due primarily to a lower composite average price. EOG's composite NGL price for the first nine months of 2015 decreased 57% to $14.93 per barrel compared to $34.90 per barrel for the same period of 2014.

Wellhead natural gas revenues for the first nine months of 2015 decreased $665 million, or 44%, to $844 million from $1,509 million for the same period of 2014 primarily due to a lower composite wellhead natural gas price ($555 million) and a decrease of 100 MMcfd, or 7%, in natural gas deliveries ($110 million) primarily due to lower production in Other International (43 MMcfd) as a result of the divestiture of substantially all of EOG's Canadian operations in the fourth quarter of 2014, in Trinidad (32 MMcfd) and in the United States (25 MMcfd). EOG's composite wellhead natural gas price for the first nine months of 2015 decreased 40% to $2.44 per Mcf compared to $4.04 per Mcf for the same period of 2014.

During the first nine months of 2015, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $57 million compared to net gains of $84 million for the same period of 2014. During the first nine months of 2015, net cash received from settlements of crude oil and natural gas financial derivative contracts was $661 million and net cash payments for settlements of crude oil and natural gas financial derivative contracts were $189 million for the same period of 2014.

Gathering, processing and marketing revenues less marketing costs for the first nine months of 2015 declined $80 million as compared to the same period of 2014 primarily due to lower margins on crude oil and natural gas marketing activities and losses on sand sales.

Operating and Other Expenses. For the first nine months of 2015, operating expenses of $13,317 million were $3,942 million higher than the $9,375 million incurred during the same period of 2014. Operating expenses for the first nine months of 2015 included impairments of proved properties, other property, plant and equipment and other assets of $6,230 million related to commodity price declines. The following table presents the costs per Boe for the nine-month periods ended September 30, 2015 and 2014:



	Nine Months Ended September 30,
	2015		2014
Lease and Well	$	5.97	$	6.44
Transportation Costs	4.10		4.54
DD&A -
Oil and Gas Properties	15.64		18.02
Other Property, Plant and Equipment	0.61		0.53
G&A	1.65		1.68
Interest Expense, Net	1.11		0.94
Total ⁽¹⁾	$	29.08	$	32.15


(1)	Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and interest expense, net, for the nine months ended September 30, 2015, compared to the same period of 2014 are set forth below. See "Net Operating Revenues" above for a discussion of production volumes.

Lease and well expenses of $934 million for the first nine months of 2015 decreased $102 million from $1,036 million for the same prior year period primarily due to lower lease and well expenses in Canada ($77 million) due to the divestiture of substantially all of EOG's operations in Canada during the fourth quarter of 2014, decreased operating and maintenance costs in the United States ($35 million) and decreased workover expenditures in the United States ($8 million), partially offset by increased lease and well administrative expenses in the United States ($21 million) primarily due to increased employee-related costs.

-28-

Transportation costs of $642 million for the first nine months of 2015 decreased $88 million from $730 million for the same prior year period primarily due to decreased transportation costs in the Rocky Mountain area ($65 million) and the Eagle Ford ($35 million) primarily due to an increase in the use of pipelines to transport crude oil production, partially offset by increased transportation costs related to higher production from the Permian Basin ($17 million).

DD&A expenses for the first nine months of 2015 decreased $439 million to $2,544 million from $2,983 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first nine months of 2015 were $449 million lower than the same prior year period. The decrease primarily reflects decreased rates in the United States ($335 million) and Trinidad ($23 million), lower DD&A expenses in Canada ($100 million) due to the divestiture of substantially all of EOG's operations in Canada during the fourth quarter of 2014 and lower volumes in Trinidad ($12 million), partially offset by higher volumes in the United States ($18 million). Unit rates in the United States decreased primarily due to impairments of proved properties (see Note 11 to the Consolidated Financial Statements), upward reserve revisions and reserves added at lower costs as a result of increased efficiencies.

Exploration costs of $115 million for the first nine months of 2015 decreased $24 million from $139 million for the same prior year period primarily due to decreased geological and geophysical costs in the United States ($16 million) and lower exploration costs in Canada ($9 million) due to the divestiture of substantially all of EOG's operations in Canada during the fourth quarter of 2014, partially offset by increased exploration administrative expenses ($4 million) in the United States.

G&A expenses of $258 million for the first nine months of 2015 decreased $13 million from $271 million for the same prior year period primarily due to decreased employee-related costs ($5 million) and decreased professional service fees ($4 million).

Interest expense, net, of $174 million for the first nine months of 2015 increased $23 million compared to the same prior year period primarily due to increased debt outstanding ($15 million) and decreased capitalized interest ($10 million).

Impairments of $6,445 million for the first nine months of 2015 were $6,237 million higher than impairments for the same prior year period primarily due to increased impairments of proved properties and related assets in the United States ($6,007 million) and in the United Kingdom ($142 million), primarily with respect to the Conwy project, and increased amortization of unproved property costs in the United States ($84 million), which was caused by higher amortization rates being applied to undeveloped leasehold costs in response to the significant decrease in commodity prices and an increase in EOG's estimates of undeveloped properties not expected to be developed before lease expiration. Proved property and related asset impairments in the United States were related to legacy natural gas assets and marginal liquids plays. EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $6,230 million and $84 million for the first nine months of 2015 and 2014, respectively.

Taxes other than income for the first nine months of 2015 decreased $272 million to $334 million (6.6% of wellhead revenues) from $606 million (6.1% of wellhead revenues) for the same prior year period. The decrease in taxes other than income was primarily due to decreased severance/production taxes in the United States ($247 million) primarily as a result of decreased wellhead revenues, decreased ad valorem/property taxes in the United States ($8 million), an increase in credits available to EOG in 2015 for Texas high-cost gas severance tax rate reductions ($7 million) and decreased severance/production taxes in Trinidad ($5 million).

Other income (expense), net for the first nine months of 2015 increased $25 million compared to the same prior year period. The increase was primarily due to decreased deferred compensation expense ($10 million) and a decrease in foreign currency exchange losses ($5 million).

EOG recognized an income tax benefit of $2,283 million for the first nine months of 2015 compared to an income tax expense of $1,376 million for the same period in 2014 primarily due to certain 2015 impairments in the United States. The net effective tax rate for the first nine months of 2015 was 35% compared to the prior year rate of 36%.

-29-

Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the nine months ended September 30, 2015, were funds generated from operations, net proceeds from the issuance of the Notes and proceeds from asset sales. The primary uses of cash were funds used in operations; exploration and development expenditures; repayments of debt; other property, plant and equipment expenditures; dividend payments to stockholders; and purchases of treasury stock in connection with stock compensation plans. During the first nine months of 2015, EOG's cash balance decreased $1,344 million to $743 million from $2,087 million at December 31, 2014.

Net cash provided by operating activities of $2,979 million for the first nine months of 2015 decreased $3,559 million compared to the same period of 2014 primarily due to a decrease in wellhead revenues ($4,901 million), unfavorable changes in working capital and other assets and liabilities ($202 million) and an increase in net cash paid for interest expense ($9 million), partially offset by a favorable change in net cash flow from the settlement of financial commodity derivative contracts ($850 million), a decrease in cash operating expenses ($492 million) and a decrease in net cash paid for income taxes ($261 million).

Net cash used in investing activities of $4,545 million for the first nine months of 2015 decreased by $1,586 million compared to the same period of 2014 due primarily to a decrease in additions to oil and gas properties ($1,735 million); a decrease in additions to other property, plant and equipment ($335 million); a decrease in restricted cash ($91 million); and an increase in proceeds from sales of assets ($53 million); partially offset by unfavorable changes in working capital associated with investing activities ($628 million).

Net cash provided by financing activities of $231 million for the first nine months of 2015 included net proceeds from the issuance of the Notes ($990 million), net commercial paper borrowings ($30 million), excess tax benefits from stock-based compensation ($24 million) and proceeds from stock options exercised and employee stock purchase plan activity ($15 million). Cash used in financing activities for the first nine months of 2015 included repayments of long-term debt ($500 million), cash dividend payments ($275 million) and purchases of treasury stock in connection with stock compensation plans ($43 million). Net cash used in financing activities of $244 million for the first nine months of 2014 included repayments of long-term debt ($500 million), cash dividend payments ($188 million), purchases of treasury stock in connection with stock compensation plans ($115 million) and the settlement of a foreign currency swap ($32 million). Cash provided by financing activities for the first nine months of 2014 included net proceeds from the issuances of long-term debt ($496 million), excess tax benefits from stock-based compensation ($88 million) and proceeds from stock options exercised and employee stock purchase plan activity ($12 million).

Total Expenditures. For the year 2015, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $4.7 billion to $4.9 billion, excluding acquisitions. The table below sets out components of total expenditures for the nine-month periods ended September 30, 2015 and 2014 (in millions):



	Nine Months Ended September 30,
	2015		2014
Expenditure Category
Capital
Drilling and Facilities	$	3,384	$	5,191
Leasehold Acquisitions	111		321
Property Acquisitions	376		73
Capitalized Interest	33		43
Subtotal	3,904		5,628
Exploration Costs	115		139
Dry Hole Costs	14		30
Exploration and Development Expenditures	4,033		5,797
Asset Retirement Costs	26		170
Total Exploration and Development Expenditures	4,059		5,967
Other Property, Plant and Equipment	253		587
Total Expenditures	$	4,312	$	6,554

-30-

Exploration and development expenditures of $4,033 million for the first nine months of 2015 were $1,764 million lower than the same period of 2014 primarily due to decreased drilling and facilities expenditures in the United States ($1,768 million), Canada ($64 million) and the United Kingdom ($28 million); decreased leasehold acquisitions ($210 million) and decreased geological and geophysical expenditures ($16 million); partially offset by increased property acquisitions in the United States ($303 million) and increased drilling and facilities expenditures in Trinidad ($55 million). Exploration and development expenditures for the first nine months of 2015 of $4,033 million consist of $3,339 million in development, $376 million in property acquisitions, $285 million in exploration and $33 million in capitalized interest. Exploration and development expenditures for the first nine months of 2014 of $5,797 million consist of $5,121 million in development, $560 million in exploration, $73 million in property acquisitions and $43 million in capitalized interest.

The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other related economic factors. EOG has significant flexibility with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to its operations, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.

Commodity Derivative Transactions. As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2014, filed on February 18, 2015, EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis swap contracts, as a means to manage this price risk. EOG has not designated any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). The related cash flow impact is reflected in Cash Flows from Operating Activities.

Commodity Derivative Contracts. The total fair value of EOG's crude oil and natural gas price swap contracts was reflected on the Consolidated Balance Sheets at September 30, 2015, as a net asset of $71 million. Presented below is a comprehensive summary of EOG's crude oil price swap contracts at November 5, 2015, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).



Crude Oil Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2015
January 1, 2015 through June 30, 2015 (closed)	47,000	$	91.22
July 1, 2015 through October 31, 2015 (closed)	10,000	89.98
November 1, 2015 through December 31, 2015	10,000	89.98

-31-

EOG has purchased put options which establish a floor price for the sale of certain notional volumes of crude oil specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the average NYMEX West Texas Intermediate crude oil price for the contract month (Index Price), in the event the Index Price is below the put option strike price. If the Index Price is above the put option strike price, EOG is only required to pay the put option premium. Below is a summary of EOG's put option contracts at November 5, 2015, with notional volumes expressed in Bbld and prices and premiums expressed in $/Bbl.



Crude Oil Put Option Contracts
	Volume (Bbld)	Average Premium ($/Bbl)		Strike Price ($/Bbl)
2015
September 1, 2015 through October 31, 2015 (closed)	82,500	$	1.75	$	45.00
November 2015	82,500	1.75		45.00

Presented below is a comprehensive summary of EOG's natural gas price swap contracts at November 5, 2015, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).



Natural Gas Price Swap Contracts
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2015 ⁽¹⁾
January 1, 2015 through February 28, 2015 (closed)	235,000	$	4.47
March 2015 (closed)	225,000	4.48
April 2015 (closed)	195,000	4.49
May 2015 (closed)	235,000	4.13
June 1, 2015 through July 31, 2015 (closed)	275,000	3.98
August 1, 2015 through November 30, 2015 (closed)	175,000	4.51
December 2015	175,000	4.51

(1)

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Information Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q 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, extent and duration 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

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•	the other factors described under ITEM 1A, Risk Factors, on pages 13 through 20 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014, 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.

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PART I. FINANCIAL INFORMATION

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

EOG RESOURCES, INC.

EOG's exposure to commodity price risk, interest rate risk and foreign currency exchange rate risk is discussed in (i) the "Derivative Transactions," "Financing," "Foreign Currency Exchange Rate Risk" and "Outlook" sections of "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity" on pages 39 through 41 of EOG's Annual Report on Form 10-K for the year ended December 31, 2014, filed on February 18, 2015 (EOG's 2014 Annual Report); and (ii) Note 12, "Risk Management Activities," to EOG's Consolidated Financial Statements on pages F-26 through F-28 of EOG's 2014 Annual Report. There have been no material changes in this information. For additional information regarding EOG's financial commodity derivative contracts and physical commodity contracts, see (i) Note 12, "Risk Management Activities," to EOG's Consolidated Financial Statements in this Quarterly Report on Form 10-Q; (ii) "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Net Operating Revenues" in this Quarterly Report on Form 10-Q; and (iii) "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Commodity Derivative Transactions" in this Quarterly Report on Form 10-Q.

ITEM 4. CONTROLS AND PROCEDURES

EOG RESOURCES, INC.

Disclosure Controls and Procedures. EOG's management, with the participation of EOG's principal executive officer and principal financial officer, evaluated the effectiveness of EOG's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of the end of the period covered by this Quarterly Report on Form 10-Q (Evaluation Date). Based on this evaluation, EOG's principal executive officer and principal financial officer have concluded that EOG's disclosure controls and procedures were effective as of the Evaluation Date in ensuring that information that is required to be disclosed in the reports EOG files or furnishes under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms and (ii) accumulated and communicated to EOG's management, as appropriate, to allow timely decisions regarding required disclosure.

Internal Control Over Financial Reporting. There were no changes in EOG's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act) that occurred during the quarterly period covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting.

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PART II. OTHER INFORMATION

EOG RESOURCES, INC.

ITEM 1. LEGAL PROCEEDINGS

See Part I, Item 1, Note 8 to Consolidated Financial Statements, which is incorporated herein by reference.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth, for the periods indicated, EOG's share repurchase activity:



Period	Total Number of Shares Purchased ⁽¹⁾	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under The Plans or Programs ⁽²⁾
Period	Total Number of Shares Purchased ⁽¹⁾	Average Price Paid Per Share

July 1, 2015 - July 31, 2015	21,067	$	82.30	—	6,386,200
August 1, 2015 - August 31, 2015	20,929	75.98		—	6,386,200
September 1, 2015 - September 30, 2015	185,620	73.85		—	6,386,200
Total	227,616	74.82		—

(1)

Represents shares that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or stock-settled stock appreciation rights or the vesting of restricted stock or restricted stock unit grants or (ii) in payment of the exercise price of employee stock options. These shares do not count against the 10 million aggregate share repurchase authorization by EOG's Board of Directors (Board) discussed below.


(2)	In September 2001, the Board authorized the repurchase of up to 10 million shares of EOG's common stock. During the third quarter of 2015, EOG did not repurchase any shares under the Board-authorized repurchase program.

ITEM 4. MINE SAFETY DISCLOSURES

The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this Quarterly Report on Form 10-Q.

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ITEM 6. EXHIBITS



Exhibit No.		Description

3.1	-	Bylaws, as amended and restated effective as of September 22, 2015 (incorporated by reference to Exhibit 3.1 to EOG's Current Report on Form 8-K, filed September 28, 2015).

10.1	-	Revolving Credit Agreement, dated as of July 21, 2015, among EOG, JPMorgan Chase Bank, N.A., as Administrative Agent, the financial institutions as bank parties thereto, and the other parties thereto (incorporated by reference to Exhibit 10.1 to EOG’s Current Report on Form 8-K, filed July 24, 2015).

* 31.1	-	Section 302 Certification of Periodic Report of Principal Executive Officer.

* 31.2	-	Section 302 Certification of Periodic Report of Principal Financial Officer.

* 32.1	-	Section 906 Certification of Periodic Report of Principal Executive Officer.

* 32.2	-	Section 906 Certification of Periodic Report of Principal Financial Officer.

* 95	-	Mine Safety Disclosure Exhibit.

* **101.INS	-	XBRL Instance Document.

* **101.SCH	-	XBRL Schema Document.

* **101.CAL	-	XBRL Calculation Linkbase Document.

* **101.DEF	-	XBRL Definition Linkbase Document.

* **101.LAB	-	XBRL Label Linkbase Document.

* **101.PRE	-	XBRL Presentation Linkbase Document.

* Exhibits filed herewith

** Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) - Three Months Ended September 30, 2015 and 2014 and Nine Months Ended September 30, 2015 and 2014, (ii) the Consolidated Balance Sheets - September 30, 2015 and December 31, 2014, (iii) the Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2015 and 2014 and (iv) the Notes to Consolidated Financial Statements.

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SIGNATURES

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



			EOG RESOURCES, INC.
			(Registrant)



Date:	November 5, 2015	By:	/s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Officer)

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EXHIBIT INDEX



Exhibit No.		Description

3.1	-	Bylaws, as amended and restated effective as of September 22, 2015 (incorporated by reference to Exhibit 3.1 to EOG's Current Report on Form 8-K, filed September 28, 2015).

10.1	-	Revolving Credit Agreement, dated as of July 21, 2015, among EOG, JPMorgan Chase Bank, N.A., as Administrative Agent, the financial institutions as bank parties thereto, and the other parties thereto (incorporated by reference to Exhibit 10.1 to EOG’s Current Report on Form 8-K, filed July 24, 2015).

* 31.1	-	Section 302 Certification of Periodic Report of Principal Executive Officer.

* 31.2	-	Section 302 Certification of Periodic Report of Principal Financial Officer.

* 32.1	-	Section 906 Certification of Periodic Report of Principal Executive Officer.

* 32.2	-	Section 906 Certification of Periodic Report of Principal Financial Officer.

* 95	-	Mine Safety Disclosure Exhibit.

* **101.INS	-	XBRL Instance Document.

* **101.SCH	-	XBRL Schema Document.

* **101.CAL	-	XBRL Calculation Linkbase Document.

* **101.DEF	-	XBRL Definition Linkbase Document.

* **101.LAB	-	XBRL Label Linkbase Document.

* **101.PRE	-	XBRL Presentation Linkbase Document.

* Exhibits filed herewith

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