FORM 10-Q

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

Title of each class		Number of shares
Common Stock, par value $0.01 per share		270,880,999 as of October 31, 2012

PART I.	FINANCIAL INFORMATION		Page No.
	ITEM 1.	Financial Statements (Unaudited)
		Consolidated Statements of Income and Comprehensive Income - Three Months Ended September 30, 2012 and 2011 and Nine Months Ended September 30, 2012 and 2011	3
		Consolidated Balance Sheets - September 30, 2012 and December 31, 2011	4
		Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2012 and 2011	5
		Notes to Consolidated Financial Statements	6
	ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	20
	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	37
	ITEM 4.	Controls and Procedures	37
PART II.	OTHER INFORMATION
	ITEM 1.	Legal Proceedings	38
	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
	ITEM 4.	Mine Safety Disclosures	38
	ITEM 6.	Exhibits	39
SIGNATURES			40
EXHIBIT INDEX			41

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2012				2011				2012				2011
Net Operating Revenues
Crude Oil and Condensate		$	1,512,168			$	953,154			$	4,198,753			$	2,649,034
Natural Gas Liquids			170,351				206,572				518,684				539,104
Natural Gas			426,728				576,803				1,153,433				1,760,715
Gains on Mark-to-Market Commodity Derivative Contracts			4,671				357,664				327,328				480,539
Gathering, Processing and Marketing			764,385				578,022				2,193,290				1,461,303
Gains on Asset Dispositions, Net			67,376				207,468				248,134				442,981
Other, Net			9,176				6,061				31,203				19,424
Total			2,954,855				2,885,744				8,670,825				7,353,100
Operating Expenses
Lease and Well			253,452				248,926				765,703				680,710
Transportation Costs			164,407				108,678				431,642				308,276
Gathering and Processing Costs			26,223				18,532				72,403				55,444
Exploration Costs			45,953				48,469				136,909				140,616
Dry Hole Costs			1,924				22,604				13,005				47,231
Impairments			62,875				83,431				250,239				531,413
Marketing Costs			755,457				572,604				2,155,043				1,427,450
Depreciation, Depletion and Amortization			825,851				651,684				2,383,359				1,822,854
General and Administrative			92,870				82,260				244,866				219,703
Taxes Other Than Income			120,096				98,526				359,798				308,669
Total			2,349,108				1,935,714				6,812,967				5,542,366
Operating Income			605,747				950,030				1,857,858				1,810,734
Other Income, Net			7,596				1,377				22,902				11,205
Income Before Interest Expense and Income Taxes			613,343				951,407				1,880,760				1,821,939
Interest Expense, Net			53,154				52,186				154,198				153,772
Income Before Income Taxes			560,189				899,221				1,726,562				1,668,167
Income Tax Provision			204,698				358,343				651,284				697,742
Net Income		$	355,491			$	540,878			$	1,075,278			$	970,425
Net Income Per Share
Basic		$	1.33			$	2.03			$	4.03			$	3.71
Diluted		$	1.31			$	2.01			$	3.98			$	3.66
Dividends Declared per Common Share		$	0.17			$	0.16			$	0.51			$	0.48
Average Number of Common Shares
Basic			267,941				266,053				267,136				261,664
Diluted			270,982				269,292				270,328				265,245
Comprehensive Income
Net Income		$	355,491			$	540,878			$	1,075,278			$	970,425
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments			50,426				(119,338	)			48,262				(63,823	)
Foreign Currency Swap			1,708				646				2,338				462
Income Tax Related to Foreign Currency Swap			(646	)			(166	)			(597	)			(114	)
Interest Rate Swap			(318	)			(2,503	)			(682	)			(6,612	)
Income Tax Related to Interest Rate Swap			114				901				245				2,378
Other			29				28				87				86
Other Comprehensive Income (Loss)			51,313				(120,432	)			49,653				(67,623	)
Comprehensive Income		$	406,804			$	420,446			$	1,124,931			$	902,802

		September 30,				December 31,
		2012				2011
ASSETS
Current Assets
Cash and Cash Equivalents		$	1,112,623			$	615,726
Accounts Receivable, Net			1,579,841				1,451,227
Inventories			657,880				590,594
Assets from Price Risk Management Activities			248,698				450,730
Income Taxes Receivable			54,049				26,609
Deferred Income Taxes			120,967				-
Other			226,104				119,052
Total			4,000,162				3,253,938
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)			37,021,216				33,664,435
Other Property, Plant and Equipment			2,609,467				2,149,989
Total Property, Plant and Equipment			39,630,683				35,814,424
Less:  Accumulated Depreciation, Depletion and Amortization			(15,944,233	)			(14,525,600	)
Total Property, Plant and Equipment, Net			23,686,450				21,288,824
Other Assets			345,879				296,035
Total Assets		$	28,032,491			$	24,838,797
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable		$	2,151,093			$	2,033,615
Accrued Taxes Payable			168,691				147,105
Dividends Payable			45,653				42,578
Deferred Income Taxes			2,793				135,989
Other			210,153				163,032
Total			2,578,383				2,522,319
Long-Term Debt			6,305,277				5,009,166
Other Liabilities			842,173				799,189
Deferred Income Taxes			4,513,188				3,867,219
Commitments and Contingencies (Note 8)
Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 271,323,486 Shares Issued at September 30, 2012 and 269,323,084 Shares Issued at December 31, 2011			202,713				202,693
Additional Paid in Capital			2,459,531				2,272,052
Accumulated Other Comprehensive Income			451,399				401,746
Retained Earnings			10,726,811				9,789,345
Common Stock Held in Treasury, 473,624 Shares at September 30, 2012 and 303,633 Shares at December 31, 2011			(46,984	)			(24,932	)
Total Stockholders' Equity			13,793,470				12,640,904
Total Liabilities and Stockholders' Equity		$	28,032,491			$	24,838,797

		Nine Months Ended
		September 30,
		2012				2011
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income		$	1,075,278			$	970,425
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization			2,383,359				1,822,854
Impairments			250,239				531,413
Stock-Based Compensation Expenses			101,337				95,057
Deferred Income Taxes			385,878				499,279
Gains on Asset Dispositions, Net			(248,134	)			(442,981	)
Other, Net			(10,266	)			2,270
Dry Hole Costs			13,005				47,231
Mark-to-Market Commodity Derivative Contracts
Total Gains			(327,328	)			(480,539	)
Realized Gains			555,946				83,765
Excess Tax Benefits from Stock-Based Compensation			(49,426	)			-
Other, Net			12,675				21,052
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable			(112,174	)			(128,965	)
Inventories			(154,766	)			(167,611	)
Accounts Payable			83,682				245,385
Accrued Taxes Payable			42,791				101,239
Other Assets			(120,085	)			(28,600	)
Other Liabilities			39,871				37,022
Changes in Components of Working Capital Associated with Investing and    Financing Activities			87,708				133,227
Net Cash Provided by Operating Activities			4,009,590				3,341,523
Investing Cash Flows
Additions to Oil and Gas Properties			(5,326,884	)			(4,665,535	)
Additions to Other Property, Plant and Equipment			(477,351	)			(502,112	)
Proceeds from Sales of Assets			1,213,550				1,294,627
Changes in Components of Working Capital Associated with Investing Activities			(87,654	)			(133,512	)
Net Cash Used in Investing Activities			(4,678,339	)			(4,006,532	)
Financing Cash Flows
Common Stock Sold			-				1,388,270
Long-Term Debt Borrowings			1,234,138				-
Dividends Paid			(134,412	)			(124,133	)
Excess Tax Benefits from Stock-Based Compensation			49,426				-
Treasury Stock Purchased			(44,799	)			(21,357	)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan			59,714				26,887
Debt Issuance Costs			(1,771	)			-
Repayment of Capital Lease Obligation			(1,407	)			-
Other, Net			(54	)			285
Net Cash Provided by Financing Activities			1,160,835				1,269,952
Effect of Exchange Rate Changes on Cash			4,811				(7,068	)
Increase in Cash and Cash Equivalents			496,897				597,875
Cash and Cash Equivalents at Beginning of Period			615,726				788,853
Cash and Cash Equivalents at End of Period		$	1,112,623			$	1,386,728

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2012				2011				2012				2011
Lease and Well		$	9.9			$	9.5			$	26.4			$	24.4
Gathering and Processing Costs			0.3				0.2				0.8				0.6
Exploration Costs			7.4				7.8				20.3				19.4
General and Administrative			28.3				24.1				53.8				50.6
Total		$	45.9			$	41.6			$	101.3			$	95.0

		Stock Options/SARs								ESPP
		Nine Months Ended								Nine Months Ended
		September 30,								September 30,
		2012				2011				2012				2011
Weighted Average Fair Value of Grants		$	37.94			$	29.87			$	25.17			$	22.35
Expected Volatility			39.68	%			40.92	%			41.04	%			29.68	%
Risk-Free Interest Rate			0.45	%			0.58	%			0.11	%			0.18	%
Dividend Yield			0.6	%			0.7	%			0.6	%			0.7	%
Expected Life		5.6 yrs				5.6 yrs				0.5 yrs				0.5 yrs

		Nine Months Ended								Nine Months Ended
		September 30, 2012								September 30, 2011
						Weighted								Weighted
		Number of				Average				Number of				Average
		Stock				Grant				Stock				Grant
		Options/SARs				Price				Options/SARs				Price
Outstanding at January 1			8,374			$	70.01				8,445			$	64.49
Granted			1,223				111.91				1,470				85.25
Exercised (1)			(2,044	)			53.52				(1,150	)			48.41
Forfeited			(124	)			89.95				(133	)			87.75
Outstanding at September 30 (2)			7,429			$	81.11				8,632			$	69.80
Vested or Expected to Vest (3)			7,184			$	80.57				8,387			$	69.29
Exercisable at September 30 (4)			4,315			$	69.87				5,382			$	59.25

		Nine Months Ended								Nine Months Ended
		September 30, 2012								September 30, 2011
						Weighted								Weighted
		Number of				Average				Number of				Average
		Shares and				Grant Date				Shares and				Grant Date
		Units				Fair Value				Units				Fair Value
Outstanding at January 1			4,240			$	82.93				4,009			$	79.13
Granted			757				112.13				917				90.93
Released (1)			(977	)			72.97				(410	)			65.77
Forfeited			(106	)			88.36				(202	)			82.51
Outstanding at September 30 (2)			3,914			$	90.91				4,314			$	82.75

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2012				2011				2012				2011
Numerator for Basic and Diluted Earnings Per Share -
Net Income		$	355,491			$	540,878			$	1,075,278			$	970,425
Denominator for Basic Earnings Per Share -
Weighted Average Shares			267,941				266,053				267,136				261,664
Potential Dilutive Common Shares -
Stock Options/SARs			1,343				1,479				1,517				1,759
Restricted Stock/Units and Performance Units/Stock			1,698				1,760				1,675				1,822
Denominator for Diluted Earnings Per Share -
Adjusted Diluted Weighted Average Shares			270,982				269,292				270,328				265,245
Net Income Per Share
Basic		$	1.33			$	2.03			$	4.03			$	3.71
Diluted		$	1.31			$	2.01			$	3.98			$	3.66

		Nine Months Ended
		September 30,
		2012				2011
Interest (1)		$	132,264			$	111,111
Income Taxes, Net of Refunds Received		$	257,046			$	148,937

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2012				2011				2012				2011
Net Operating Revenues
United States		$	2,702,046			$	2,640,739			$	7,953,839			$	6,549,392
Canada			79,500				103,842				264,059				360,380
Trinidad			167,402				134,542				434,746				421,884
Other International (1)			5,907				6,621				18,181				21,444
Total		$	2,954,855			$	2,885,744			$	8,670,825			$	7,353,100
Operating Income (Loss)
United States		$	545,982			$	923,810			$	1,711,860			$	1,938,349
Canada			(40,477	)			(36,596	)			(93,113	)			(356,012	)
Trinidad			114,709				96,304				284,869				279,413
Other International (1)			(14,467	)			(33,488	)			(45,758	)			(51,016	)
Total			605,747				950,030				1,857,858				1,810,734
Reconciling Items
Other Income, Net			7,596				1,377				22,902				11,205
Interest Expense, Net			53,154				52,186				154,198				153,772
Income Before Income Taxes		$	560,189			$	899,221			$	1,726,562			$	1,668,167

		At				At
		September 30,				December 31,
		2012				2011
Total Assets
United States		$	24,313,164			$	21,313,158
Canada			2,104,831				2,131,949
Trinidad			1,126,274				1,085,664
Other International (1)			488,222				308,026
Total		$	28,032,491			$	24,838,797

		Nine Months Ended
		September 30,
		2012				2011
Carrying Amount at Beginning of Period		$	587,084			$	498,288
Liabilities Incurred			47,320				45,754
Liabilities Settled (1)			(56,150	)			(58,084	)
Accretion			22,714				20,125
Revisions			12,709				61,668
Foreign Currency Translations			5,140				(3,688	)
Carrying Amount at End of Period		$	618,817			$	564,063
Current Portion		$	27,615			$	30,306
Noncurrent Portion		$	591,202			$	533,757

EOG's net changes in capitalized exploratory well costs for the nine-month period ended September 30, 2012 are presented below (in thousands):

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EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

The following table provides an aging of capitalized exploratory well costs at September 30, 2012 (in thousands, except well count):

 

(1)

Consists of costs related to an outside operated, offshore Central North Sea natural gas project in the United Kingdom (U.K.) ($21 million) and a shale project in the Horn River Basin area of British Columbia, Canada (B.C.) ($6 million).  In the Central North Sea Columbus project, a revised field development plan was submitted to the U.K. Department of Energy and Climate Change during the third quarter of 2012.  In the B.C. shale project, EOG drilled seven wells in the first nine months of 2012 to retain land and further evaluate the project.

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.

EOG has defined contribution pension plans in place for most of its employees in the United States, Canada, Trinidad and the United Kingdom, and defined benefit pension plans covering certain of its employees in Canada and Trinidad.  For the nine months ended September 30, 2012 and 2011, EOG's total costs recognized for these pension plans were $27.1 million and $20.6 million, respectively.  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.

Long-Term Debt.  During the nine months ended September 30, 2012, EOG utilized commercial paper and short-term borrowings from uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes.  EOG had no outstanding borrowings from commercial paper issuances or uncommitted credit facilities at September 30, 2012.  The average of the borrowings outstanding under the commercial paper program and uncommitted credit facilities was $315 million and $55 thousand, respectively, during the nine months ended September 30, 2012.  The weighted average interest rates for commercial paper and uncommitted credit facility borrowings for the nine months ended September 30, 2012 were 0.45% and 0.70%, respectively.

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EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

 

On September 10, 2012, EOG closed its sale of $1.25 billion aggregate principal amount of its 2.625% Senior Notes due 2023 (Notes).  Interest on the Notes is payable semi-annually in arrears on March 15 and September 15 of each year, beginning March 15, 2013.  Net proceeds from the Notes offering of approximately $1,234 million were used for general corporate purposes, including repayment of outstanding commercial paper borrowings and funding of capital expenditures.

EOG currently has a $2.0 billion unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders.  The Agreement matures on October 11, 2016 and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods, subject to, among certain other terms and conditions, the consent of the banks holding greater than 50% of the commitments then outstanding under the Agreement.  At September 30, 2012, there were no borrowings or letters of credit outstanding under the Agreement.  Advances under the Agreement accrue interest based, at EOG's option, on either the London InterBank Offered Rate (LIBOR) plus an applicable margin (Eurodollar rate), or the base rate (as defined in the Agreement) plus an applicable margin.  At September 30, 2012, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 1.09% and 3.25%, respectively.

Capital Lease.  During the third quarter of 2012, EOG began leasing certain newly constructed crude oil storage tanks located in the Eagle Ford Shale.  The lease has an initial term of 10 years and EOG has an option to extend the lease for an additional 5-year period.  It was determined that the lease qualifies as a capital lease for accounting purposes and, as a result, EOG has recognized a capital lease asset and a related liability of $66 million.  The capital lease asset is included in Other Property, Plant and Equipment on the Consolidated Balance Sheets.  The related liability is included in Long-Term Debt ($59 million) and Current Liabilities – Other ($7 million) on the Consolidated Balance Sheets.  Total aggregate minimum lease payments are approximately $76 million over the initial term of the lease.

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EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's 2011 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, 2012 and December 31, 2011 (in millions):

The estimated fair value of crude oil and natural gas derivative contracts (including options/swaptions) and the interest rate swap contract was based upon forward commodity price and interest rate curves based on quoted market prices.  The estimated fair value of the foreign currency rate swap was based upon forward currency rates. Swaps were valued using market prices and discount rates from an independent third-party provider of financial market data.  The Black 76 Model is utilized in valuing options.

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on 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.

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EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

Proved oil and gas properties and other property, plant and equipment with a carrying amount of $197 million were written down to their fair value of $87 million, resulting in a pretax impairment charge of $110 million for the nine months ended September 30, 2012.  Included in the $110 million pretax impairment charge is a $60 million impairment of proved oil and gas properties and other property, plant and equipment, for which EOG utilized an accepted offer from a third-party as the basis for determining fair value.  Significant Level 3 assumptions 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, 2012 and December 31, 2011, EOG had outstanding $6,290 million and $5,040 million, respectively, aggregate principal amount of debt, which had estimated fair values of approximately $7,048 million and $5,657 million, respectively.  The estimated fair value of debt 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.

Commodity Price Risk.  As more fully discussed in Note 11 to the Consolidated Financial Statements included in EOG's 2011 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, collar, option and basis swap contracts, as a means to manage this price risk.  In addition to financial transactions, from time to time EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions.  These physical commodity contracts qualify for the normal purchases and normal sales exception and, therefore, are not subject to hedge accounting or mark-to-market accounting.  The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.

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EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

Commodity Derivative Contracts.  Presented below is a comprehensive summary of EOG's crude oil derivative contracts at September 30, 2012, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).

 

(1)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for an additional six-month period.  Options covering a notional volume of 25,000 Bbld are exercisable on December 31, 2012.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 25,000 Bbld at an average price of $106.27 per barrel for the period January 1, 2013 through June 30, 2013.  Options covering a notional volume of 59,000 Bbld are exercisable on June 28, 2013.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 59,000 Bbld at an average price of $100.45 per barrel for the period July 1, 2013 through December 31, 2013.  Options covering a notional volume of 15,000 Bbld are exercisable on December 31, 2013.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 15,000 Bbld at an average price of $103.54 per barrel for the period from January 1, 2014 through June 30, 2014.

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EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

Presented below is a comprehensive summary of EOG's natural gas derivative contracts at September 30, 2012, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

(1)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates.  Such options are exercisable monthly up until the settlement date of each monthly contract.  If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 425,000 MMBtud at an average price of $5.44 per MMBtu for the period from November 1, 2012 through December 31, 2012.

(2)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates.  Such options are exercisable monthly up until the settlement date of each monthly contract.  If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for each month of 2013.

(3)

In July 2012, EOG settled its natural gas derivative contracts for the period January 1, 2014 through December 31, 2014 and received proceeds of $36.6 million.  In connection with these contracts, the counterparties retain an option of entering into derivative contracts at future dates. Such options are exercisable monthly up until the settlement date of each monthly contract.  If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for each month of 2014.

Foreign Currency Exchange Rate Derivative.  EOG is party to a foreign currency aggregate swap with multiple banks to eliminate any exchange rate impacts that may result from the $150 million principal amount of notes issued by one of EOG's Canadian subsidiaries.  EOG accounts for the foreign currency swap using the hedge accounting method.  Changes in the fair value of the foreign currency swap do not impact Net Income.  The after-tax net impact from the foreign currency swap resulted in increases in Other Comprehensive Income (OCI) of $1.1 million and $0.5 million for the three months ended September 30, 2012 and 2011, respectively, and increases in OCI of $1.7 million and $0.3 million for the nine months ended September 30, 2012 and 2011, respectively.

Interest Rate Derivative.  EOG is a party to an interest rate swap with a counterparty bank.  The interest rate swap was entered into in order to mitigate EOG's exposure to volatility in interest rates related to EOG's $350 million principal amount of Floating Rate Senior Notes due 2014.  The interest rate swap has a notional amount of $350 million.  EOG accounts for the interest rate swap using the hedge accounting method.  Changes in the fair value of the interest rate swap do not impact Net Income.  The after-tax net impact from the interest rate swap resulted in reductions in OCI of $0.2 million and $1.6 million for the three months ended September 30, 2012 and 2011, respectively, and reductions in OCI of $0.4 million and $4.2 million for the nine months ended September 30, 2012 and 2011, respectively.

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EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Concluded)
(Unaudited)

The following table sets forth the amounts, on a gross basis, and classification of EOG's outstanding financial derivative instruments at September 30, 2012 and December 31, 2011.  Certain amounts may be presented on a net basis in the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions):

 

Credit Risk.  Notional contract amounts are used to express the magnitude of commodity price, foreign currency and interest rate 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 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 rating 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 are in a net liability position at September 30, 2012 and December 31, 2011.  EOG had no collateral posted at either September 30, 2012 or December 31, 2011 and held no collateral at September 30, 2012.  EOG held $67 million of collateral at December 31, 2011.

13.  Divestitures

During the first nine months of 2012, EOG received proceeds of approximately $1,214 million from the sales of producing properties and acreage primarily in the Rocky Mountain area, the Upper Gulf Coast area and Canada.

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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, Canada, Trinidad, the United Kingdom and China.  EOG operates under a consistent business and operational strategy that focuses predominantly on maximizing the rate of return on investment of capital by 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.  EOG implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves.  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 and Canada.  EOG's efforts to identify plays with large reserve potential have proven a successful supplement to its base development and exploitation program in the United States and Canada.  EOG continues to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's crude oil and natural gas liquids production.  EOG has placed an emphasis on applying its horizontal drilling and completion expertise gained from its natural gas resource plays to unconventional crude oil and liquids-rich reservoirs.  In 2012, EOG continues to focus its efforts on developing its existing North American crude oil and liquids-rich acreage.  In addition, EOG continues to evaluate certain potential liquids-rich exploration and development prospects.  For the first nine months of 2012, crude oil and condensate and natural gas liquids production accounted for approximately 45% of total company production as compared to approximately 35% for the comparable period in 2011.  In North America, crude oil and condensate and natural gas liquids production accounted for approximately 52% of total North American production during the first nine months of 2012 as compared to approximately 40% for the comparable period in 2011.  This liquids growth primarily reflects increased production from the Eagle Ford Shale near San Antonio, Texas, the North Dakota Bakken, and the Permian Basin.  Based on current trends, EOG expects its 2012 crude oil and condensate and natural gas liquids production to continue to increase both in total and as a percentage of total company production as compared to 2011.

EOG delivers its crude oil to various markets in the United States, including sales points on the Gulf Coast where sales are based upon a Light Louisiana Sweet (LLS) crude oil index.  As part of its diversification strategy for its crude-by-rail shipments, in April 2012, EOG completed the construction of a crude oil unloading facility in St. James, Louisiana, where sales are based upon the LLS crude oil index.  This facility, which received the first unit train of EOG crude oil in April 2012, has a capacity of approximately 100 thousand barrels per day (MBbld).  With the addition of the St. James facility, EOG's crude-by-rail system has access to both the Gulf Coast market and the Cushing, Oklahoma, market.  At the beginning of July 2012, EOG also began shipping a portion of its Eagle Ford Shale crude oil production to Gulf Coast sales points on the newly completed Enterprise Products Partners L.P. crude oil pipeline.  In addition, EOG began supplying sand for a majority of its completion operations in several plays, primarily in Texas, from Wisconsin sand mines in 2012.

EOG's wholly-owned Canadian subsidiary, EOG Resources Canada Inc. (EOGRC), holds a 30% interest in both the planned liquefied natural gas export terminal to be located at Bish Cove, near the Port of Kitimat, north of Vancouver, British Columbia (Kitimat LNG Terminal) and the proposed Pacific Trail Pipelines (PTP) which is intended to link Western Canada's natural gas producing regions to the Kitimat LNG Terminal.  An affiliate of Apache Corporation is the operator of both the PTP and the Kitimat LNG Terminal.  Marketing efforts continue in order to support a final investment decision.

EOG's major producing areas in the United States and Canada are in Louisiana, New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.

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International.  In Trinidad, EOG continued to deliver natural gas under existing supply contracts.  Several fields in the South East Coast Consortium Block, Modified U(a) Block and Modified U(b) Block, as well as the Pelican Field, have been developed and are producing natural gas and crude oil and condensate.  Production from the Block 4(a) Toucan Field and the EMZ Area that began in the first quarter of 2012 is supplying natural gas under a contract with the National Gas Company of Trinidad and Tobago.

In the United Kingdom, EOG continues to make progress in field development for its East Irish Sea Conwy/Corfe crude oil discovery and its Central North Sea Columbus natural gas discovery.  The field development plan for the Conwy/Corfe project was approved by the U.K. Department of Energy and Climate Change (DECC) in March 2012.  The production platform was installed during the second quarter of 2012 and the pipelines are scheduled to be installed in the fourth quarter of 2012.  EOG expects to begin processing facility installation in the first half of 2013.  The Conwy development drilling program is expected to commence during the first quarter of 2013, with initial production expected in the second half of 2013.  In the Central North Sea Columbus project, a revised field development plan was submitted to the DECC in the third quarter of 2012 with approval expected in the first quarter of 2013.  The project participants are currently negotiating commercial agreements.

EOG's activity in Argentina is focused on the Vaca Muerta oil shale formation in the Neuquén Basin in Neuquén Province.  During the first half of 2012, EOG participated in the drilling and completion of a vertical well in the Bajo del Toro Block.  In the first quarter of 2012, EOG drilled a well to monitor future well completions in the Aguada del Chivato Block.  During the first half of 2012, EOG drilled and completed a horizontal well in this block.  Both the horizontal and vertical wells that were completed are under evaluation.

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 31% and 28% at September 30, 2012 and December 31, 2011, respectively.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

On September 10, 2012, EOG closed its sale of $1,250 million aggregate principal amount of 2.625% Senior Notes due 2023 (Notes).  Interest on the Notes is payable semiannually in arrears on March 15 and September 15 of each year, beginning March 15, 2013.  Net proceeds from the offering of approximately $1,234 million were used for general corporate purposes including the repayment of outstanding commercial paper borrowings and funding of capital expenditures.

EOG's total 2012 capital expenditures are estimated to total approximately $7.6 billion, excluding non-cash items.  The majority of 2012 expenditures are focused on United States and Canada crude oil and liquids-rich gas drilling activity and, to a much lesser extent, natural gas drilling activity in the Haynesville, Marcellus and British Columbia Horn River Basin plays to hold acreage.  EOG expects capital expenditures to be greater than cash flow from operating activities for 2012.  In the first nine months of 2012, to cover the anticipated shortfall, EOG sold the Notes and received proceeds of $1,214 million from the sales of producing properties and acreage primarily in the Rocky Mountain area, Upper Gulf Coast area and Canada.  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 its revolving credit facility 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.

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Results of Operations

The following review of operations for the three and nine months ended September 30, 2012 and 2011 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, 2012 vs. Three Months Ended September 30, 2011

Net Operating Revenues.  During the third quarter of 2012, net operating revenues increased $69 million, or 2%, to $2,955 million from $2,886 million for the same period of 2011.  Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, natural gas liquids and natural gas, for the third quarter of 2012 increased $372 million, or 21%, to $2,109 million from $1,737 million for the same period of 2011.  During the third quarter of 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $5 million compared to net gains of $358 million for the same period of 2011.  Gathering, processing and marketing revenues, which are revenues generated from sales of third-party crude oil and condensate, natural gas liquids and natural gas as well as fees associated with gathering third-party natural gas, for the third quarter of 2012 increased $186 million, or 32%, to $764 million from $578 million for the same period of 2011.  Gains on asset dispositions, net, of $67 million for the third quarter of 2012 primarily consist of gains on asset dispositions in the Rocky Mountain area.

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Wellhead volume and price statistics for the three-month periods ended September 30, 2012 and 2011 were as follows:

 

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

(2)	Other International includes EOG's 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.

(4)

Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas.  Crude oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas.  MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

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Wellhead crude oil and condensate revenues for the third quarter of 2012 increased $559 million, or 59%, to $1,512 million from $953 million for the same period of 2011, due to an increase of 50 MBbld, or 42%, in wellhead crude oil and condensate deliveries ($409 million) and a higher composite average wellhead crude oil and condensate price ($150 million).  The increase in deliveries primarily reflects increased production in the Eagle Ford Shale and North Dakota Bakken.  EOG's composite average wellhead crude oil and condensate price for the third quarter of 2012 increased 11% to $97.13 per barrel compared to $87.49 per barrel for the same period of 2011.

Natural gas liquids revenues for the third quarter of 2012 decreased $37 million, or 18%, to $170 million from $207 million for the same period of 2011, due to a lower composite average natural gas liquids price ($109 million), partially offset by an increase of 15 MBbld, or 34%, in natural gas liquids deliveries ($72 million).  The increase in deliveries primarily reflects increased volumes in the Eagle Ford Shale, Permian Basin and Fort Worth Basin Barnett Shale.  EOG's composite average natural gas liquids price for the third quarter of 2012 decreased 39% to $31.11 per barrel compared to $51.02 per barrel for the same period of 2011.

Wellhead natural gas revenues for the third quarter of 2012 decreased $150 million, or 26%, to $427 million from $577 million for the same period of 2011.  The decrease was due to a lower composite average wellhead natural gas price ($123 million) and a decrease in natural gas deliveries ($27 million).  EOG's composite average wellhead natural gas price for the third quarter of 2012 decreased 22% to $3.07 per thousand cubic feet (Mcf) compared to $3.95 per Mcf for the same period of 2011.

Natural gas deliveries for the third quarter of 2012 decreased 75 MMcfd, or 5%, to 1,512 MMcfd from 1,587 MMcfd for the same period of 2011.  The decrease was primarily due to lower production in the United States (100 MMcfd) and Canada (29 MMcfd), partially offset by increased production in Trinidad (57 MMcfd).  The decrease in the United States was attributable to asset sales and decreased production.  The decrease in Canada was primarily due to decreased production in Alberta and the Horn River Basin area.  The increase in Trinidad was primarily attributable to an increase in contractual deliveries.

During the third quarter of 2012, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $5 million compared to net gains of $358 million for the same period of 2011.  During the third quarter of 2012, the net cash inflow related to settled crude oil and natural gas derivative contracts was $249 million compared to the net cash inflow of $52 million for the same period of 2011.

Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, natural gas liquids and natural gas as well as fees associated with gathering third-party natural gas.  For the three months and nine months ended September 30, 2012 and 2011, gathering, processing and marketing revenues were primarily related to sales 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.  Marketing costs represent the costs of purchasing third-party crude oil and natural gas and the associated transportation costs.

During the third quarter of 2012, gathering, processing and marketing revenues and marketing costs increased, compared to the same period of 2011, primarily as a result of increased crude oil marketing activities.  Gathering, processing and marketing revenues less marketing costs for the third quarter of 2012 totaled $9 million compared to $5 million for the same period of 2011.

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Operating and Other Expenses.  For the third quarter of 2012, operating expenses of $2,349 million were $413 million higher than the $1,936 million incurred in the third quarter of 2011.  The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended September 30, 2012 and 2011: