Edgar Filing: DEVON ENERGY CORP/DE

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2012

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

Commission File Number 001-32318

DEVON ENERGY CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		73-1567067
(State of other jurisdiction of incorporation or organization)		(I.R.S. Employer identification No.)

333 West Sheridan Avenue, Oklahoma City, Oklahoma		73102-5015
(Address of principal executive offices)		(Zip code)

Registrant’s telephone number, including area code: (405) 235-3611

Former name, address and former fiscal year, if changed from last report: Not applicable

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 þ No ¨

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 þ No ¨

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.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ

On October 24, 2012, 405 million shares of common stock were outstanding.

DEVON ENERGY CORPORATION

FORM 10-Q

TABLE OF CONTENTS


Part I Financial Information
Item 1. Consolidated Financial Statements			3
Consolidated Comprehensive Statements of Earnings			3
Consolidated Statements of Cash Flows			4
Consolidated Balance Sheets			5
Consolidated Statements of Stockholders’ Equity			6
Notes to Consolidated Financial Statements			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			22
Item 3. Quantitative and Qualitative Disclosures About Market Risk			32
Item 4. Controls and Procedures			33

Part II Other Information
Item 1. Legal Proceedings			34
Item 1A. Risk Factors			34
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			34
Item 3. Defaults Upon Senior Securities			34
Item 4. Mine Safety Disclosures			34
Item 5. Other Information			34
Item 6. Exhibits			35

Signatures			36

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This report includes forward-looking statements regarding our expectations and plans, as well as future events or conditions. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare our December 31, 2011 reserve reports and other data in our possession or available from third parties. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, such as changes in the supply of and demand for oil, natural gas and NGLs and related products and services; exploration or drilling programs; political or regulatory events; general economic and financial market conditions; and other factors discussed in this report.

All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We assume no duty to update or revise our forward-looking statements based on new information, future events or otherwise.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2012			2011			2012			2011
	(Unaudited)
	(In millions, except per share amounts)
Revenues:
Oil, gas and NGL sales	$	1,738		$	2,111		$	5,270		$	6,171
Oil, gas and NGL derivatives		(295	)		738			515			986
Marketing and midstream revenues		422			653			1,136			1,712

Total revenues		1,865			3,502			6,921			8,869

Expenses and other, net:
Lease operating expenses		513			475			1,540			1,352
Marketing and midstream operating costs and expenses		313			515			847			1,304
Depreciation, depletion and amortization		716			566			2,080			1,622
General and administrative expenses		150			138			494			403
Taxes other than income taxes		104			108			306			336
Interest expense		110			104			296			270
Restructuring costs		—			(3	)		—			(2	)
Asset impairments		1,128			—			1,128			—
Other, net		(8	)		61			46			88

Total expenses and other, net		3,026			1,964			6,737			5,373

Earnings (loss) from continuing operations before income taxes		(1,161	)		1,538			184			3,496
Current income tax expense (benefit)		(41	)		(248	)		8			(301	)
Deferred income tax expense (benefit)		(401	)		746			4			2,184

Earnings (loss) from continuing operations		(719	)		1,040			172			1,613
Earnings (loss) from discontinued operations, net of tax		—			(2	)		(21	)		2,584

Net earnings (loss)	$	(719	)	$	1,038		$	151		$	4,197

Basic net earnings (loss) per share:
Basic earnings (loss) from continuing operations per share	$	(1.80	)	$	2.51		$	0.42		$	3.83
Basic earnings (loss) from discontinued operations per share		—			—			(0.05	)		6.14

Basic net earnings (loss) per share	$	(1.80	)	$	2.51		$	0.37		$	9.97

Diluted net earnings (loss) per share:
Diluted earnings (loss) from continuing operations per share	$	(1.80	)	$	2.50		$	0.42		$	3.82
Diluted earnings (loss) from discontinued operations per share		—			—			(0.05	)		6.11

Diluted net earnings (loss) per share	$	(1.80	)	$	2.50		$	0.37		$	9.93

Comprehensive earnings (loss):
Net earnings (loss)	$	(719	)	$	1,038		$	151		$	4,197
Other comprehensive earnings (loss), net of tax:
Foreign currency translation		311			(615	)		292			(365	)
Pension and postretirement plans		3			6			12			17

Other comprehensive earnings (loss), net of tax		314			(609	)		304			(348	)

Comprehensive earnings (loss)	$	(405	)	$	429		$	455		$	3,849

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months
	Ended September 30,
	2012			2011
	(Unaudited)
	(In millions)
Cash flows from operating activities:
Net earnings	$	151		$	4,197
(Earnings) loss from discontinued operations, net of tax		21			(2,584	)
Adjustments to reconcile earnings from continuing operations to net cash from operating activities:
Depreciation, depletion and amortization		2,080			1,622
Asset impairments		1,128			—
Deferred income tax expense		4			2,184
Unrealized change in fair value of financial instruments		173			(661	)
Other noncash charges		136			185
Net decrease (increase) in working capital		48			(308	)
Decrease (increase) in long-term other assets		(22	)		51
Increase (decrease) in long-term other liabilities		68			(459	)

Cash from operating activities – continuing operations		3,787			4,227
Cash from operating activities – discontinued operations		26			(13	)

Net cash from operating activities		3,813			4,214

Cash flows from investing activities:
Capital expenditures		(6,228	)		(5,515	)
Purchases of short-term investments		(2,969	)		(5,751	)
Redemptions of short-term investments		2,308			4,665
Proceeds from property and equipment divestitures		1,397			13
Other		18			(23	)

Cash from investing activities—continuing operations		(5,474	)		(6,611	)
Cash from investing activities—discontinued operations		58			3,162

Net cash from investing activities		(5,416	)		(3,449	)

Cash flows from financing activities:
Proceeds from borrowings of long-term debt, net of issuance costs		2,465			2,221
Net short-term borrowings (repayments)		(898	)		3,196
Debt repayments		—			(1,760	)
Credit facility borrowings		750			—
Credit facility repayments		(750	)		—
Proceeds from stock option exercises		25			101
Repurchases of common stock		—			(1,987	)
Dividends paid on common stock		(242	)		(209	)
Excess tax benefits related to share-based compensation		5			11

Net cash from financing activities		1,355			1,573

Effect of exchange rate changes on cash		31			(10	)

Net change in cash and cash equivalents		(217	)		2,328

Cash and cash equivalents at beginning of period		5,555			3,290

Cash and cash equivalents at end of period	$	5,338		$	5,618

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	September 30,			December 31,
	2012			2011
	(Unaudited)
	(In millions, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	5,338		$	5,555
Short-term investments		2,164			1,503
Accounts receivable		1,113			1,379
Other current assets		818			868

Total current assets		9,433			9,305

Property and equipment, at cost:
Oil and gas, based on full cost accounting:
Subject to amortization		67,345			61,696
Not subject to amortization		3,827			3,982

Total oil and gas		71,172			65,678
Other		5,643			5,098

Total property and equipment, at cost		76,815			70,776
Less accumulated depreciation, depletion and amortization		(49,669	)		(46,002	)

Property and equipment, net		27,146			24,774

Goodwill		6,114			6,013
Other long-term assets		855			1,025

Total assets	$	43,548		$	41,117

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,485		$	1,471
Revenues and royalties payable		696			678
Short-term debt		2,780			3,811
Other current liabilities		535			778

Total current liabilities		5,496			6,738

Long-term debt		8,455			5,969
Asset retirement obligations		2,009			1,496
Other long-term liabilities		863			721
Deferred income taxes		4,944			4,763
Stockholders’ equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 405 million and 404 million shares in 2012 and 2011, respectively		41			40
Additional paid-in capital		3,644			3,507
Retained earnings		16,217			16,308
Accumulated other comprehensive earnings		1,879			1,575

Total stockholders’ equity		21,781			21,430

Commitments and contingencies (Note 18)
Total liabilities and stockholders’ equity	$	43,548		$	41,117

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY


	Common Stock						Additional Paid-In			Retained			Accumulated Other Comprehensive			Treasury			Total Stockholders’
	Shares			Amount			Capital			Earnings			Earnings			Stock			Equity
	(Unaudited)
	(In millions)
Nine Months Ended September 30, 2012:
Balance as of December 31, 2011		404		$	40		$	3,507		$	16,308		$	1,575		$	—		$	21,430
Net earnings		—			—			—			151			—			—			151
Other comprehensive earnings, net of tax		—			—			—			—			304			—			304
Stock option exercises		1			1			27			—			—			(2	)		26
Common stock repurchased		—			—			—			—			—			(4	)		(4	)
Common stock retired		—			—			(6	)		—			—			6			—
Common stock dividends		—			—			—			(242	)		—			—			(242	)
Share-based compensation		—			—			111			—			—			—			111
Share-based compensation tax benefits		—			—			5			—			—			—			5

Balance as of September 30, 2012		405		$	41		$	3,644		$	16,217		$	1,879		$	—		$	21,781

Nine Months Ended September 30, 2011:
Balance as of December 31, 2010		432		$	43		$	5,601		$	11,882		$	1,760		$	(33	)	$	19,253
Net earnings		—			—			—			4,197			—			—			4,197
Other comprehensive loss, net of tax		—			—			—			—			(348	)		—			(348	)
Stock option exercises		2			—			101			—			—			—			101
Common stock repurchased		—			—			—			—			—			(2,008	)		(2,008	)
Common stock retired		(26	)		(2	)		(1,991	)		—			—			1,993			—
Common stock dividends		—			—			—			(209	)		—			—			(209	)
Share-based compensation		—			—			105			—			—			—			105
Share-based compensation tax benefits		—			—			11			—			—			—			11

Balance as of September 30, 2011		408		$	41		$	3,827		$	15,870		$	1,412		$	(48	)	$	21,102

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

The accompanying unaudited financial statements and notes of Devon Energy Corporation (“Devon”) have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted. The accompanying financial statements and notes should be read in conjunction with the accompanying financial statements and notes included in Devon’s 2011 Annual Report on Form 10-K.

The accompanying unaudited interim financial statements furnished in this report reflect all adjustments that are, in the opinion of management, necessary to a fair statement of Devon’s financial position as of September 30, 2012 and Devon’s results of operations and cash flows for the three-month and nine-month periods ended September 30, 2012 and 2011.

2. Derivative Financial Instruments

Objectives and Strategies

Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility and typically include financial price swaps, basis swaps, costless price collars and call options.

Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon periodically enters into foreign exchange forward contracts to manage its exposure to fluctuations in exchange rates.

Devon does not intend to hold or issue derivative financial instruments for speculative trading purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment.

Counterparty Credit Risk

By using derivative financial instruments, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are acceptable credit risks. It is Devon’s policy to enter into derivative contracts only with investment grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts contain provisions that provide for collateral payments, depending on levels of exposure and the credit rating of the counterparty.

As of September 30, 2012, Devon held $49 million of cash collateral. Such amount represented the estimated fair value of certain derivative positions in excess of Devon’s credit guidelines. The collateral is reported in other current liabilities in the accompanying balance sheet.

Commodity Derivatives

As of September 30, 2012, Devon had the following open oil derivative positions. Devon’s oil derivatives settle against the average of the prompt month NYMEX West Texas Intermediate futures price.


	Price Swaps				Price Collars						Call Options Sold
Period	Volume (Bbls/d)		Weighted Average Price ($/Bbl)		Volume (Bbls/d)		Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)		Volume (Bbls/d)		Weighted Average Price ($/Bbl)
Q4 2012		57,000	$	105.47		77,000	$	89.72	$	122.39		19,500	$	95.00
Q1-Q4 2 013		31,000	$	104.13		45,000	$	91.30	$	116.23		6,000	$	120.00
Q1-Q4 2014		4,000	$	100.49		2,000	$	90.00	$	111.13		6,000	$	120.00

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


	Basis Swaps
Period	Index	Volume (Bbls/d)		Weighted Average Differential to WTI ($/Bbl)
Q4 2012	Western Canadian Select		15,000	$	(17.29	)

As of September 30, 2012, Devon had the following open natural gas derivative positions. Devon’s natural gas derivatives settle against the Inside FERC first of the month Henry Hub index.


	Price Swaps				Price Collars						Call Options Sold
Period	Volume (MMBtu/d)		Weighted Average Price ($/MMBtu)		Volume (MMBtu/d)		Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)		Volume (MMBtu/d)		Weighted Average Price ($/MMBtu)
Q4 2012		654,239	$	3.92		1,323,696	$	3.50	$	4.17		487,500	$	6.00
Q1-Q4 2013		185,000	$	4.37		94,219	$	3.40	$	4.00		—		—
Q1-Q4 2014		240,000	$	4.09		—		—		—		150,000	$	5.00

Interest Rate Derivatives

As of September 30, 2012, Devon had the following open interest rate derivative positions:


Notional	Weighted Average Fixed Rate Received			Variable Rate Paid	Expiration
(In millions)
$ 750		3.88	%	Federal funds rate	July 2013

Foreign Currency Derivatives

As of September 30, 2012, Devon had the following open foreign currency rate derivative positions:

Forward Contract

Currency

Contract
Type

CAD
Notional

Weighted Average
Fixed Rate Received

Expiration

(In millions)

(CAD-USD)

Canadian Dollar

Sell

755

1.02

December 2012

Financial Statement Presentation

The following table presents the cash settlements and unrealized gains and losses on fair value changes included in the accompanying comprehensive statements of earnings associated with derivative financial instruments. Cash settlements and unrealized gains and losses on fair value changes associated with Devon’s commodity derivatives are presented in the “Oil, gas and NGL derivatives” caption in the accompanying comprehensive statements of earnings. Cash settlements and unrealized gains and losses on fair value changes associated with Devon’s interest rate and foreign currency derivatives are presented in the “Other, net” caption in the accompanying comprehensive statements of earnings.


	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012			2011
	(In millions)
Cash settlements:
Commodity derivatives	$	243		$	96	$	668		$	241
Interest rate derivatives		10			52		9			73
Foreign currency derivatives		(38	)		22		(29	)		22

Total cash settlements		215			170		648			336

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(In millions)
Unrealized gains (losses):
Commodity derivatives		(538	)		642			(153	)		745
Interest rate derivatives		(9	)		(55	)		(24	)		(84	)
Foreign currency derivatives		12			—			4			—

Total unrealized gains (losses)		(535	)		587			(173	)		661

Net gain (loss) recognized on comprehensive statements of earnings	$	(320	)	$	757		$	475		$	997

The following table presents the derivative fair values included in the accompanying balance sheets.


	Balance Sheet Caption	September 30, 2012		December 31, 2011
		(In millions)
Asset derivatives:
Commodity derivatives	Other current assets	$	358	$	611
Commodity derivatives	Other long-term assets		75		17
Interest rate derivatives	Other current assets		28		30
Interest rate derivatives	Other long-term assets		—		22
Foreign currency derivatives	Other current assets		4		—

Total asset derivatives		$	465	$	680

Liability derivatives:
Commodity derivatives	Other current liabilities	$	13	$	82
Commodity derivatives	Other long-term liabilities		27		—

Total liability derivatives		$	40	$	82

3. Restructuring Costs

Divestiture of Offshore Assets

In the fourth quarter of 2009, Devon announced plans to divest its offshore assets. As of September 30, 2012, Devon had divested all of its U.S. Offshore and International assets and incurred $202 million of restructuring costs associated with the divestitures.

The schedule below summarizes restructuring costs presented in the accompanying comprehensive statements of earnings. Restructuring costs related to Devon’s discontinued operations totaled $(2) million in the first nine months ended September 30, 2011. These costs primarily related to cash severance and share-based awards and are not included in the schedule below. There were no costs related to discontinued operations in the nine months ended September 30, 2012.


	Three Months Ended September 30,					Nine Months Ended September 30,
	2012		2011			2012		2011
	(In millions)
Lease obligations	$	—	$	(3	)	$	—	$	(5	)
Asset impairments		—		—			—		2
Other		—		—			—		1

Restructuring costs	$	—	$	(3	)	$	—	$	(2	)

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The schedule below summarizes Devon’s restructuring liabilities. Devon’s restructuring liabilities for cash severance related to its discontinued operations totaled $2 million at September 30, 2011 and are not included in the schedule below.


	Other Current Liabilities			Other Long-Term Liabilities			Total
				(In millions)
Balance as of December 31, 2011	$	29		$	16		$	45
Lease obligations settled		(9	)		(3	)		(12	)
Cash severance settled		(7	)		—			(7	)

Balance as of September 30, 2012	$	13		$	13		$	26

Balance as of December 31, 2010	$	31		$	51		$	82
Lease obligations settled		(1	)		(10	)		(11	)
Cash severance settled		(13	)		—			(13	)
Other		2			(6	)		(4	)

Balance as of September 30, 2011	$	19		$	35		$	54

Consolidation of U.S. Operations

In October 2012, Devon announced plans to consolidate its U.S. personnel into a single operations group centrally located at the company’s corporate headquarters in Oklahoma City. As a result, Devon will close its office in Houston and transfer operational responsibilities for assets in South Texas, East Texas and Louisiana to Oklahoma City. Devon expects to relocate a number of employees from Houston to Oklahoma City. This initiative is expected to be substantially complete by the end of the first quarter 2013.

4. Other, net

The components of other, net in the accompanying comprehensive statements of earnings include the following:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(In millions)
Accretion of asset retirement obligations	$	27		$	23		$	82		$	69
Interest rate derivatives		(1	)		3			15			11
Foreign currency derivatives		26			(22	)		25			(22	)
Foreign exchange loss (gain)		(28	)		53			(26	)		39
Interest income		(8	)		(8	)		(24	)		(14	)
Other		(24	)		12			(26	)		5

Other, net	$	(8	)	$	61		$	46		$	88

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

5. Earnings Per Share

The following table reconciles earnings (loss) from continuing operations and common shares outstanding used in the calculations of basic and diluted earnings per share.


	Earnings (loss)			Common Shares			Earnings (loss) per Share
	(In millions, except per share amounts)
Three Months Ended September 30, 2012:
Loss from continuing operations	$	(719	)		405
Attributable to participating securities		(1	)		(5	)

Basic and diluted loss per share	$	(720	)		400		$	(1.80	)

Three Months Ended September 30, 2011:
Earnings from continuing operations	$	1,040			414
Attributable to participating securities		(11	)		(4	)

Basic earnings per share		1,029			410		$	2.51
Dilutive effect of potential common shares issuable		—			1

Diluted earnings per share	$	1,029			411		$	2.50

Nine Months Ended September 30, 2012:
Earnings from continuing operations	$	172			404
Attributable to participating securities		(2	)		(4	)

Basic earnings per share		170			400		$	0.42
Dilutive effect of potential common shares issuable		—			1

Diluted earnings per share	$	170			401		$	0.42

Nine Months Ended September 30, 2011:
Earnings from continuing operations	$	1,613			421
Attributable to participating securities		(16	)		(4	)

Basic earnings per share		1,597			417		$	3.83
Dilutive effect of potential common shares issuable		—			1

Diluted earnings per share	$	1,597			418		$	3.82

Certain options to purchase shares of Devon’s common stock are excluded from the dilution calculation because the options are antidilutive. During the three-month and nine-month periods ended September 30, 2012, 9.0 million shares and 8.9 million shares, respectively, were excluded from the diluted earnings per share calculations. During the three-month and nine-month periods ended September 30, 2011, 5.3 million shares and 3.1 million shares, respectively, were excluded from the diluted earnings per share calculations.

6. Other Comprehensive Earnings

Components of other comprehensive earnings consist of the following:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(In millions)
Foreign currency translation:
Beginning accumulated foreign currency translation	$	1,783		$	2,243		$	1,802		$	1,993
Change in cumulative translation adjustment		325			(644	)		305			(382	)
Income tax benefit (expense)		(14	)		29			(13	)		17

Ending accumulated foreign currency translation		2,094			1,628			2,094			1,628

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(In millions)
Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits		(218	)		(222	)		(227	)		(233	)
Recognition of net actuarial loss and prior service cost in earnings		6			9			19			26
Income tax expense		(3	)		(3	)		(7	)		(9	)

Ending accumulated pension and postretirement benefits		(215	)		(216	)		(215	)		(216	)

Accumulated other comprehensive earnings, net of tax	$	1,879		$	1,412		$	1,879		$	1,412

7. Supplemental Information to Statements of Cash Flows


	Nine Months Ended September 30,
	2012			2011
	(In millions)
Net change in working capital:
Decrease (increase) in accounts receivable	$	275		$	(118	)
Increase in other current assets		(234	)		(149	)
Increase in accounts payable		77			58
Increase (decrease) in revenues and royalties payable		(34	)		121
Decrease in other current liabilities		(36	)		(220	)

Net decrease (increase) in working capital	$	48		$	(308	)

Supplementary cash flow data – total operations:
Interest paid (net of capitalized interest)	$	260		$	298
Income taxes paid (received)	$	88		$	(113	)

8. Short-Term Investments

The components of short-term investments include the following:


	September 30, 2012		December 31, 2011
	(In millions)
Canadian treasury, agency and provincial securities	$	1,684	$	1,155
U.S. treasuries		480		201
Other		—		147

Short-term investments	$	2,164	$	1,503

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

9. Accounts Receivable

The components of accounts receivable include the following:


	September 30, 2012			December 31, 2011
	(In millions)
Oil, gas and NGL sales	$	713		$	928
Joint interest billings		207			247
Marketing and midstream revenues		137			174
Other		66			39

Gross accounts receivable		1,123			1,388
Allowance for doubtful accounts		(10	)		(9	)

Net accounts receivable	$	1,113		$	1,379

10. Other Current Assets

The components of other current assets include the following:


	September 30, 2012		December 31, 2011
	(In millions)
Derivative financial instruments	$	390	$	641
Inventories		185		102
Income taxes receivable		137		35
Current assets held for sale		—		21
Other		106		69

Other current assets	$	818	$	868

11. Property and Equipment

Sinopec Transaction

In April 2012, Devon closed its joint venture transaction with Sinopec International Petroleum Exploration & Production Corporation. Pursuant to the agreement, Sinopec paid approximately $900 million in cash and received a 33.3% interest in five of Devon’s new ventures exploration plays in the U.S. at closing of the transaction. Additionally, Sinopec is required to fund approximately $1.6 billion of Devon’s share of future exploration, development and drilling costs associated with these plays. Devon recognized the cash proceeds received at closing as a reduction to U.S. oil and gas property and equipment. No gain or loss was recognized.

Sumitomo Transaction

In September 2012, Devon closed its joint venture transaction with Sumitomo Corporation. At closing, Sumitomo paid approximately $400 million in cash and received a 30% interest in the Cline and Midland-Wolfcamp shale plays in Texas. Additionally, Sumitomo is required to fund approximately $1.0 billion of Devon’s share of future exploration, development and drilling costs associated with these plays. Devon recognized the cash proceeds received at closing as a reduction to U.S. oil and gas property and equipment. No gain or loss was recognized.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Asset Impairments

In the third quarter of 2012, Devon recognized asset impairments related to its U.S. oil and gas property and equipment and its U.S. midstream assets as presented below.


	September 30, 2012
	Gross		Net of Taxes
	(In millions)
U.S. oil and gas assets	$	1,106	$	705
Midstream assets		22		14

Total asset impairments	$	1,128	$	719

U.S. Oil and Gas Impairment

Under the full-cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the full cost “ceiling” at the end of each quarter. The ceiling is calculated separately for each country and is based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent per annum, net of related tax effects. Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months.

The U.S. oil and gas impairment resulted primarily from a decline in the U.S. full cost ceiling. The lower ceiling value resulted primarily from decreases in the 12-month average trailing prices for natural gas and NGLs, which have reduced proved reserve values.

Additionally, if natural gas and NGL prices remain depressed, Devon may incur a full cost ceiling impairment related to its oil and gas property and equipment in the fourth quarter of 2012.

Midstream Impairment

Due to declining natural gas production resulting from low natural gas and NGL prices, Devon determined that the carrying amounts of certain of its midstream facilities located in south and east Texas were not recoverable from estimated future cash flows. Consequently, the assets were written down to their estimated fair values, which were determined using discounted cash flow models. The fair value of Devon’s midstream assets is considered a Level 3 fair value measurement.

12. Goodwill

During the first nine months of 2012, Devon’s Canadian goodwill increased $101 million entirely due to foreign currency translation.

13. Accounts Payable

Included in accounts payable at September 30, 2012, are liabilities of $51 million representing the amount by which checks issued, but not presented to Devon’s banks for collection, exceed balances in applicable bank accounts. Changes in these liabilities are reflected in cash flows from financing activities.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

14. Debt

Long-Term Debt

In May 2012, Devon issued $2.5 billion of senior notes that are unsecured and unsubordinated obligations of Devon. Devon used the net proceeds to repay outstanding commercial paper and credit facility borrowings. The schedule below summarizes the key terms of these notes ($ in millions).


1.875% due May 15, 2017	$	750
3.25% due May 15, 2022		1,000
4.75% due May 15, 2042		750
Discount and issuance costs		(35	)

Net proceeds	$	2,465

Commercial Paper

As of September 30, 2012, Devon had $2.8 billion of outstanding commercial paper at an average rate of 0.37 percent.

Credit Lines

Devon previously maintained a $2.19 billion syndicated, unsecured revolving line of credit. As of September 30, 2012, there were no borrowings under this line of credit. Devon terminated this line of credit and established a new $3.0 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) on October 24, 2012. The Senior Credit Facility will mature on October 24, 2017. However, prior to the maturity date, Devon has the option to extend the maturity for up to two additional one-year periods, subject to the approval of the lenders.

The terminated line of credit and the Senior Credit Facility each contain only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65 percent. As of September 30, 2012, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 24.7 percent.

15. Asset Retirement Obligations

The schedule below summarizes changes in Devon’s asset retirement obligations.


	Nine Months Ended September 30,
	2012			2011
	(In millions)
Asset retirement obligations as of beginning of period	$	1,563		$	1,497
Liabilities incurred		60			38
Liabilities settled		(75	)		(56	)
Revision of estimated obligation		411			19
Accretion expense on discounted obligation		82			69
Foreign currency translation adjustment		35			(41	)

Asset retirement obligations as of end of period		2,076			1,526
Less current portion		67			66

Asset retirement obligations, long-term	$	2,009		$	1,460

During the first nine months of 2012, Devon recognized revisions to its asset retirement obligations totaling $411 million. The primary factor contributing to this revision was an overall increase in abandonment cost estimates for certain of its production operations facilities.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

16. Retirement Plans

The following table presents the components of net periodic benefit cost for Devon’s pension and postretirement benefit plans.


	Pension Benefits												Postretirement Benefits
	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011			2012			2011			2012			2011		2012			2011
	(In millions)
Service cost	$	11		$	10		$	32		$	28		$	1		$	—	$	1		$	1
Interest cost		15			15			45			45			—			—		1			1
Expected return on plan assets		(16	)		(11	)		(48	)		(32	)		—			—		—			—
Amortization of prior service cost		1			1			3			3			—			—		(1	)		(1	)
Net actuarial loss		6			8			18			24			(1	)		—		(1	)		—

Net periodic benefit cost	$	17		$	23		$	50		$	68		$	—		$	—	$	—		$	1

17. Stockholders’ Equity

In the second quarter of 2012, Devon’s stockholders adopted the 2012 amendment to the 2009 Long-Term Incentive Plan (“2009 Plan Amendment”), which expires June 2, 2019. The 2009 Plan Amendment increases the number of shares authorized for issuance from 21.5 million shares to 47 million shares. To calculate shares issued under the 2009 Long-Term Incentive Plan subsequent to the 2009 Plan Amendment, options and stock appreciation rights represent one share and other awards represent 2.38 shares.

Dividends

Devon paid common stock dividends of $242 million and $209 million in the first nine months of 2012 and 2011, respectively. The quarterly cash dividend was $0.16 per share in the first quarter of 2011. Devon increased the dividend rate to $0.17 per share in the second quarter of 2011 and further increased the dividend rate to $0.20 per share in the first quarter of 2012.

18. Commitments and Contingencies

Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals. Actual amounts could differ materially from management’s estimates.

Royalty Matters

Numerous natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. The suits allege that the producers and related parties used below-market prices, made improper deductions, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in underpayment of royalties in connection with natural gas and NGLs produced and sold. Devon’s largest exposure for such matters relates to royalties in the states of Oklahoma and New Mexico. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Environmental Matters

Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated uninsured remediation costs. Devon’s monetary exposure for environmental matters is not expected to be material.

Chief Redemption Matters

In 2006, Devon acquired Chief Holdings LLC (“Chief”) from the owners of Chief, including Trevor Rees-Jones, the majority owner of Chief. In 2008, a former owner of Chief filed a petition against Rees-Jones, as the former majority owner of Chief, and Devon, as Chief’s successor pursuant to the 2006 acquisition. The petition claimed, among other things, violations of the Texas Securities Act, fraud and breaches of Rees-Jones’ fiduciary responsibility to the former owner in connection with Chief’s 2004 redemption of the owner’s minority ownership stake in Chief.

On June 20, 2011, a court issued a judgment against Rees-Jones for $196 million, of which $133 million of the judgment was also issued against Devon. Both Rees-Jones and Devon are appealing the judgment. If the appeal is unsuccessful, Devon can and will seek full payment of the judgment and any related interest, costs and expenses from Rees-Jones pursuant to an existing indemnification agreement between Rees-Jones, certain other parties and Devon. Devon does not expect to have any net exposure as a result of the judgment. However, because Devon does not have a legal right of set off with respect to the judgment, Devon has recorded in the accompanying September 30, 2012 and December 31, 2011, balance sheets both a $133 million long-term liability relating to the judgment with an offsetting $133 million long-term receivable relating to its right to be indemnified by Rees-Jones and certain other parties pursuant to the indemnification agreement.

Other Matters

Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon’s knowledge, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.

19. Fair Value Measurements

The following tables provide carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other payables and accrued expenses included in the accompanying balance sheets approximated fair value at September 30, 2012 and December 31, 2011. Therefore, such financial assets and liabilities are not presented in the following tables.


							Fair Value Measurements Using:
	Carrying Amount			Total Fair Value			Level 1 Inputs		Level 2 Inputs			Level 3 Inputs
	(In millions)
September 30, 2012 assets (liabilities):
Cash equivalents	$	4,952		$	4,952		$	527	$	4,425		$	—
Short-term investments	$	2,164		$	2,164		$	480	$	1,684		$	—
Long-term investments	$	64		$	64		$	—	$	—		$	64
Commodity derivatives	$	433		$	433		$	—	$	433		$	—
Commodity derivatives	$	(40	)	$	(40	)	$	—	$	(40	)	$	—
Interest rate derivatives	$	28		$	28		$	—	$	28		$	—
Foreign currency derivatives	$	4		$	4		$	—	$	4		$	—
Debt	$	(11,235	)	$	(13,134	)	$	—	$	(13,130	)	$	(4	)

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


							Fair Value Measurements Using:
	Carrying Amount			Total Fair Value			Level 1 Inputs		Level 2 Inputs			Level 3 Inputs
	(In millions)
December 31, 2011 assets (liabilities):
Cash equivalents	$	5,123		$	5,123		$	929	$	4,194		$	—
Short-term investments	$	1,503		$	1,503		$	201	$	1,302		$	—
Long-term investments	$	84		$	84		$	—	$	—		$	84
Commodity derivatives	$	628		$	628		$	—	$	628		$	—
Commodity derivatives	$	(82	)	$	(82	)	$	—	$	(82	)	$	—
Interest rate derivatives	$	52		$	52		$	—	$	52		$	—
Debt	$	(9,780	)	$	(11,380	)	$	—	$	(11,295	)	$	(85	)

The following methods and assumptions were used to estimate the fair values in the tables above.

Level 1 Fair Value Measurements

Cash equivalents and short-term investments — Amounts consist primarily of U.S. and Canadian treasury securities and money market investments. The fair value approximates the carrying value.

Level 2 Fair Value Measurements

Cash equivalents and short-term investments — Amounts consist primarily of Canadian agency and provincial securities and commercial paper investments. The fair value is based upon data from independent third parties, which approximate the carrying value.

Commodity, interest rate and foreign currency derivatives — The fair values of commodity, interest rate and foreign currency derivatives are estimated using internal discounted cash flow calculations based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.

Debt — Devon’s debt instruments do not actively trade in an established market. The fair values of its fixed-rate debt are estimated based on rates available for debt with similar terms and maturity. The fair values of Devon’s variable-rate commercial paper and credit facility borrowings are the carrying values.

Level 3 Fair Value Measurements

Long-term investments — Devon’s long-term investments presented in the tables above consisted entirely of auction rate securities. Due to auction failures and the lack of an active market for Devon’s auction rate securities, quoted market prices for these securities were not available. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair values of its long-term auction rate securities. These inputs were based on continued receipts of principal at par, the collection of all accrued interest to date, the probability of full repayment of the securities considering the U.S. government guarantees substantially all of the underlying student loans, and the AAA credit rating of the securities. As a result of using these inputs, Devon concluded the estimated fair values of its long-term auction rate securities approximated the par values as of September 30, 2012 and December 31, 2011.

Debt — Devon’s Level 3 debt consisted of a non-interest bearing promissory note. Due to the lack of an active market, quoted marked prices for this note, or similar notes, were not available. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair value of its promissory note. The fair value of this debt is estimated using internal discounted cash flow calculations based upon estimated future payment schedules and a 3.125% interest rate.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Included below is a summary of the changes in Devon’s Level 3 fair value measurements during the first nine months of 2012 and 2011.


	Nine Months Ended September 30,
	2012			2011
	(In millions)
Long-term investments balance at beginning of period	$	84		$	94
Redemptions of principal		(20	)		(10	)

Long-term investments balance at end of period	$	64		$	84


	Nine Months Ended September 30,
	2012			2011
	(In millions)
Debt balance at beginning of period	$	(85	)	$	(144	)
Foreign exchange translation adjustment		(2	)		3
Accretion of promissory note		—			(4	)
Redemptions of principal		83			53

Debt balance at end of period	$	(4	)	$	(92	)

20. Discontinued Operations

In March 2012, Devon received $71 million upon closing the divestiture of its operations in Angola, which completed Devon’s offshore divestiture program that was announced in November 2009. In aggregate, Devon’s U.S. and International offshore divestitures generated total proceeds of $10.1 billion, or approximately $8 billion after-tax, assuming repatriation of a substantial portion of the foreign proceeds under current U.S. tax law.

Revenues related to Devon’s discontinued operations totaled $43 million in the nine months ended September 30, 2011. Devon did not have revenues related to its discontinued operations during the second or third quarter of 2011 or the first nine months of 2012. Earnings (loss) from discontinued operations before income taxes totaled $(16) million in the nine months ended September 30, 2012 and $2.6 billion for the first nine months of 2011, respectively. Devon did not have any earnings in the third quarter of 2012 or 2011. Earnings (loss) from discontinued operations in 2012 and 2011 were primarily due to Devon’s International divestiture transactions.

The following table presents the main classes of assets and liabilities associated with Devon’s discontinued operations at December 31, 2011. Devon did not have assets or liabilities held for sale at September 30, 2012.


	December 31, 2011
	(In millions)
Other current assets	$	21
Property and equipment, net		132

Total assets	$	153

Accounts payable	$	20
Other current liabilities		28

Total liabilities	$	48

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

21. Segment Information

Devon manages its operations through distinct operating segments, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian operating segment is reported as a separate reporting segment primarily due to the significant differences between the U.S. and Canadian regulatory environments. Devon’s segments are all primarily engaged in oil and gas producing activities. Revenues are all from external customers.


	U.S.			Canada			Total
	(In millions)
Three Months Ended September 30, 2012:
Oil, gas and NGL sales	$	1,144		$	594		$	1,738
Oil, gas and NGL derivatives	$	(290	)	$	(5	)	$	(295	)
Marketing and midstream revenues	$	415		$	7		$	422
Depreciation, depletion and amortization	$	478		$	238		$	716
Interest expense	$	94		$	16		$	110
Asset impairments	$	1,128		$	—		$	1,128
Earnings (loss) from continuing operations before income taxes	$	(1,169	)	$	8		$	(1,161	)
Income tax expense (benefit)	$	(438	)	$	(4	)	$	(442	)
Earnings (loss) earnings from continuing operations	$	(731	)	$	12		$	(719	)
Capital expenditures	$	1,598		$	382		$	1,980

Three Months Ended September 30, 2011:
Oil, gas and NGL sales	$	1,406		$	705		$	2,111
Oil, gas and NGL derivatives	$	738		$	—		$	738
Marketing and midstream revenues	$	586		$	67		$	653
Depreciation, depletion and amortization	$	359		$	207		$	566
Interest expense	$	60		$	44		$	104
Earnings from continuing operations before income taxes	$	1,379		$	159		$	1,538
Income tax expense	$	458		$	40		$	498
Earnings from continuing operations	$	921		$	119		$	1,040
Capital expenditures	$	1,556		$	394		$	1,950

Nine Months Ended September 30, 2012:
Oil, gas and NGL sales	$	3,394		$	1,876		$	5,270
Oil, gas and NGL derivatives	$	520		$	(5	)	$	515
Marketing and midstream revenues	$	1,064		$	72		$	1,136
Depreciation, depletion and amortization	$	1,348		$	732		$	2,080
Interest expense	$	249		$	47		$	296
Asset impairments	$	1,128		$	—		$	1,128
Earnings from continuing operations before income taxes	$	91		$	93		$	184
Income tax expense	$	6		$	6		$	12
Earnings from continuing operations	$	85		$	87		$	172
Property and equipment, net	$	18,306		$	8,840		$	27,146
Total assets	$	24,425		$	19,123		$	43,548
Capital expenditures (1)	$	5,129		$	1,565		$	6,694

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


	U.S.		Canada		Total
	(In millions)
Nine Months Ended September 30, 2011:
Oil, gas and NGL sales	$	4,056	$	2,115	$	6,171
Oil, gas and NGL derivatives	$	986	$	—	$	986
Marketing and midstream revenues	$	1,563	$	149	$	1,712
Depreciation, depletion and amortization	$	1,027	$	595	$	1,622
Interest expense	$	137	$	133	$	270
Earnings from continuing operations before income taxes	$	2,965	$	531	$	3,496
Income tax expense	$	1,748	$	135	$	1,883
Earnings from continuing operations	$	1,217	$	396	$	1,613
Property and equipment, net	$	15,639	$	7,531	$	23,170
Total continuing assets (2)	$	21,903	$	17,826	$	39,729
Capital expenditures	$	4,310	$	1,274	$	5,584

(1)	Capital expenditures for the first nine months of 2012 presented above include the $411 million revision to Devon’s asset retirement obligations presented in Note 15. Of the $411 million, $122 million relates to the U.S. and $289 million relates to Canada.

(2)	Amounts in the table above do not include assets held for sale related to Devon’s discontinued operations, which totaled $137 million at September 30, 2011. There were no assets held for sale at September 30, 2012.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis addresses material changes in our results of operations and capital resources and uses for the three-month and nine-month periods ended September 30, 2012, compared to the three-month and nine-month periods ended September 30, 2011, and in our financial condition and liquidity since December 31, 2011 and should be read in conjunction with “Item 1. Consolidated Financial Statements” of this report and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2011 Annual Report on Form 10-K.

Overview of 2012 Results

During the third quarter of 2012, our continuing operations incurred a net loss of $719 million, or $1.80 per diluted share, due to noncash asset impairments and commodity derivative fair value changes. During the first nine months of 2012 our continuing operations generated earnings of $172 million, or $0.42 per diluted share. This compares to net earnings of $1.0 billion, or $2.50 per diluted share, and $1.6 billion, or $3.82 per diluted share for the third quarter and first nine months of 2011, respectively. Key components of our financial performance are summarized below:

•

Total production rose by 3% and 5% during the third quarter and first nine months of 2012, respectively. Our production growth was driven by oil production, which climbed 14% to 143 MBbls per day in the third quarter of 2012 in spite of the scheduled shut-down for facilities maintenance at our Jackfish 1 oil sands project.

•

The combined realized price without hedges for oil, gas and NGLs decreased 20% to $27.85 per Boe and 19% to $28.14 per Boe in the third quarter and first nine months of 2012, respectively.

•

Fair value changes and cash settlements on oil, gas and NGL derivatives resulted in a net loss of $295 million and a net gain of $515 million in the third quarter and first nine months of 2012, respectively, and a net gain of $738 million and $986 million in the third quarter and first nine months of 2011, respectively.

•

Marketing and midstream operating profit decreased 21% to $109 million and 29% to $289 million in the third quarter and first nine months of 2012, respectively.

•

LOE increased 5% and 8% to $8.22 per Boe in the third quarter and first nine months of 2012, respectively.

•

Noncash asset impairments were $1.1 billion in the third quarter of 2012, or $719 million net of income taxes.

•

Operating cash flow decreased 10% to $3.8 billion for the first nine months of 2012.

•

Capital spending, net of divestiture proceeds, totaled approximately $4.8 billion in the first nine months of 2012.

Third Quarter Operational Developments

•

Permian Basin oil production increased 35 percent over the third quarter of 2011. Oil production accounted for nearly 60 percent of our 65,000 Boe per day produced in the Permian during the third quarter. In the Bone Spring and Delaware plays in the Permian Basin, we added 25 new wells to production in the third quarter 2012. Initial 30-day production from these wells averaged 575 Boe per day. Also in the Permian, we brought five Midland-Wolfcamp Shale wells online in the third quarter with initial 30-day production averaging 560 Boe per day.

•

In September, we closed our $1.4 billion joint venture agreement with Sumitomo covering 650,000 net acres in the Permian Basin. Our two new exploration joint ventures in 2012 have delivered almost $4 billion in value.

•

In Canada, net production from our Jackfish projects averaged 44,000 barrels per day in the third quarter. This represents a 24 percent increase in oil production over the year-ago quarter. Construction of our third Jackfish oil sands project is now approximately 45 percent complete, with plant startup expected by year-end 2014.

•

Our third quarter activity in the Mississippian Lime play in Oklahoma was highlighted by the increase in activity to 13 operated rigs. Results from the Mississippian play continue to support our target economics.

•

We brought seven operated Granite Wash wells online in the third quarter. The average 30-day production rate from these wells was 1,065 Boe per day.

•

Our Cana-Woodford Shale production averaged 283 MMcf per day in the third quarter 2012. Third-quarter liquids production increased 64 percent compared to the prior-year quarter to 13,000 barrels per day.

•

Net production in the Barnett Shale totaled 1.4 Bcf per day in the third quarter. Liquids production increased 11 percent compared to the third quarter of 2011 to 51,000 barrels per day.

Results of Operations

Production, Prices and Revenues


	Three Months Ended September 30,							Nine Months Ended September 30,
	FY2012		FY2011		Change⁽¹⁾			FY2012		FY2011		Change⁽¹⁾
Oil (MBbls/d)
U.S.		59		47		+26	%		56		45		+27	%
Canada		84		78		+7	%		88		74		+19	%

Total		143		125		+14	%		144		119		+22	%

Gas (MMcf/d)
U.S.		2,067		2,028		+2	%		2,063		2,007		+3	%
Canada		487		580		-16	%		521		587		-11	%

Total		2,554		2,608		-2	%		2,584		2,594		-0	%

NGLs (MBbls/d)
U.S.		101		91		+11	%		98		89		+10	%
Canada		9		10		-9	%		11		10		+9	%

Total		110		101		+9	%		109		99		+10	%

Combined (MBoe/d)⁽²⁾
U.S.		504		476		+6	%		498		468		+6	%
Canada		174		185		-6	%		186		182		+2	%

Total		678		661		+3	%		684		650		+5	%

(1)	Percentage changes are based on actual figures rather than the rounded figures presented.

(2)	Gas production is converted to Boe at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of gas and oil. NGL production is converted to Boe on a one-to-one basis with oil.


	Three Months Ended September 30,							Nine Months Ended September 30,
	FY2012 ⁽¹⁾		FY2011 ⁽¹⁾		Change			FY2012 ⁽¹⁾		FY2011 ⁽¹⁾		Change
Oil (per Bbl)
U.S.	$	84.84	$	86.30		-2	%	$	90.79	$	91.18		-0	%
Canada	$	58.75	$	61.70		-5	%	$	58.56	$	65.30		-10	%
Total	$	69.53	$	70.89		-2	%	$	71.19	$	75.04		-5	%
Gas (per Mcf)
U.S.	$	2.37	$	3.71		-36	%	$	2.12	$	3.64		-42	%
Canada	$	2.31	$	3.93		-41	%	$	2.26	$	4.01		-44	%
Total	$	2.36	$	3.76		-37	%	$	2.15	$	3.73		-42	%
NGLs (per Bbl)
U.S.	$	25.07	$	40.95		-39	%	$	29.31	$	39.05		-25	%
Canada	$	46.41	$	54.85		-15	%	$	48.92	$	55.92		-13	%
Total	$	26.86	$	42.35		-37	%	$	31.27	$	40.74		-23	%
Combined (per Boe)
U.S.	$	24.64	$	32.11		-23	%	$	24.86	$	31.73		-22	%
Canada	$	37.14	$	41.42		-10	%	$	36.93	$	42.61		-13	%
Total	$	27.85	$	34.72		-20	%	$	28.14	$	34.78		-19	%

(1)	The prices presented exclude any effects due to oil, gas and NGL derivatives.

The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between the three months ended September 30, 2012 and 2011.


	Three Months Ended September 30,
	Oil			Gas			NGLs			Total
	(In millions)
2011 sales	$	816		$	902		$	393		$	2,111
Change due to volumes		114			(19	)		35			130
Change due to prices		(18	)		(329	)		(156	)		(503	)

2012 sales	$	912		$	554		$	272		$	1,738

The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between the nine months ended September 30, 2012 and 2011.


	Nine Months Ended September 30,
	Oil			Gas			NGLs			Total
	(In millions)
2011 sales	$	2,432		$	2,639		$	1,100		$	6,171
Change due to volumes		537			(1	)		111			647
Change due to prices		(152	)		(1,115	)		(281	)		(1,548	)

2012 sales	$	2,817		$	1,523		$	930		$	5,270

Oil Sales

Oil sales increased $114 million and $537 million during the third quarter and first nine months of 2012, respectively, as a result of 14 percent and 22 percent production increases, respectively. The increases were primarily due to continued development of our Permian Basin properties and Jackfish thermal heavy oil projects.

Oil sales decreased $18 million and $152 million during the third quarter and first nine months of 2012, respectively, as a result of 2 percent and 5 percent decreases, respectively, in our realized price without hedges. The largest contributor to the price decreases in each period was the widening differential to the NYMEX West Texas Intermediate index price attributable to our Canadian oil production.

Gas Sales

Gas sales decreased $329 million and $1.1 billion in the third quarter and first nine months of 2012, respectively, as a result of 37 percent and 42 percent decreases, respectively, in our realized price without hedges. These decreases were largely due to the broad deterioration of gas prices in the North American market.

Gas sales decreased $19 million during the third quarter due to a 2 percent decrease in production and decreased $1 million during the first nine months of 2012 as a result of a slight decrease in production. Our gas production has remained somewhat steady as a result of the continued development activities in the liquids-rich gas portions of our Barnett and Cana-Woodford Shales. Production gains from development in these liquids-rich regions were partially offset by natural declines in our operating areas that produce dry gas.

NGL Sales

NGL sales decreased $156 million and $281 million in the third quarter and first nine months of 2012, respectively, as a result of 37 percent and 23 percent decreases, respectively, in our realized price without hedges. The lower prices were largely due to decreases in NGL prices at the Mont Belvieu, Texas hub.

NGL sales increased $35 million and $111 million in the third quarter and first nine months of 2012, respectively, as a result of 9 percent and 10 percent production increases, respectively. The increases in production were primarily due to continued drilling in the liquids-rich gas portions of the Barnett Shale, Cana-Woodford Shale and Granite Wash.

Oil, Gas and NGL Derivatives

The following tables provide financial information associated with our oil, gas and NGL hedges. The first table presents the cash settlements and unrealized gains and losses that are recognized as components of our revenues. The subsequent tables present our oil, gas and NGL prices with, and without, the effects of the cash settlements. The prices do not include the effects of unrealized gains and losses.


	Three Months Ended September 30,						Nine Months Ended September 30,
	FY2012			FY2011			FY2012			FY2011
	(In millions)
Cash settlements:
Gas derivatives	$	156		$	97		$	530		$	262
Oil derivatives		86			(2	)		137			(23	)
NGL derivatives		1			1			1			2

Total cash settlements		243			96			668			241

Unrealized gains (losses) on fair value changes:
Gas derivatives		(207	)		157			(391	)		149
Oil derivatives		(331	)		482			239			592
NGL derivatives		—			3			(1	)		4

Total unrealized gains (losses) on fair value changes		(538	)		642			(153	)		745

Oil, gas and NGL derivatives	$	(295	)	$	738		$	515		$	986


	Three Months Ended September 30, 2012
	Oil (Per Bbl)			Gas (Per Mcf)		NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	69.53		$	2.36	$	26.86	$	27.85
Cash settlements of hedges		6.58			0.66		0.03		3.89

Realized price, including cash settlements	$	76.11		$	3.02	$	26.89	$	31.74


	Three Months Ended September 30, 2011
	Oil (Per Bbl)			Gas (Per Mcf)		NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	70.89		$	3.76	$	42.35	$	34.72
Cash settlements of hedges		(0.13	)		0.40		0.09		1.58

Realized price, including cash settlements	$	70.76		$	4.16	$	42.44	$	36.30


	Nine Months Ended September 30, 2012
	Oil (Per Bbl)			Gas (Per Mcf)		NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	71.19		$	2.15	$	31.27	$	28.14
Cash settlements of hedges		3.47			0.75		0.02		3.56

Realized price, including cash settlements	$	74.66		$	2.90	$	31.29	$	31.70


	Nine Months Ended September 30, 2011
	Oil (Per Bbl)			Gas (Per Mcf)		NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	75.04		$	3.73	$	40.74	$	34.78
Cash settlements of hedges		(0.70	)		0.37		0.07		1.35

Realized price, including cash settlements	$	74.34		$	4.10	$	40.81	$	36.13

Cash settlements presented in the tables above represent realized gains or losses related to various commodity derivatives. A summary of our open commodity derivative positions is included in Note 2 to the financial statements included in “Item 1. Consolidated Financial Statements” of this report.

In addition to cash settlements, we also recognize unrealized changes in the fair values of our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationships between contract prices and the associated forward curves. Including the cash settlements discussed above, our oil, gas and NGL derivatives incurred a net loss of $295 million and generated a net gain of $738 million in the third quarter of 2012 and 2011, respectively. Including the cash settlements discussed above, our oil, gas and NGL derivatives generated a net gain of $515 million and $986 million in the first nine months of 2012 and 2011, respectively.

Marketing and Midstream Revenues and Operating Costs and Expenses


	Three Months Ended September 30,							Nine Months Ended September 30,
	FY2012		FY2011		Change⁽¹⁾			FY2012		FY2011		Change⁽¹⁾
	($ in millions)
Marketing and midstream:
Revenues	$	422	$	653		-35	%	$	1,136	$	1,712		-34	%
Operating Costs and expenses		313		515		-39	%		847		1,304		-35	%

Operating Profit	$	109	$	138		-21	%	$	289	$	408		-29	%

(1)	Percentage changes are based on actual figures rather than the rounded figures presented.

During the third quarter and first nine months of 2012, marketing and midstream operating profit decreased $29 million and $119 million, respectively, primarily due to lower gas and NGL prices.

Lease Operating Expenses (“LOE”)


	Three Months Ended September 30,							Nine Months Ended September 30,
	FY2012		FY2011		Change⁽¹⁾			FY2012		FY2011		Change⁽¹⁾
LOE ($ in millions):
U.S.	$	263	$	236		+11	%	$	774	$	668		+16	%
Canada		250		239		+5	%		766		684		+12	%

Total	$	513	$	475		+8	%	$	1,540	$	1,352		+14	%

LOE per Boe:
U.S.	$	5.65	$	5.38		+5	%	$	5.67	$	5.23		+8	%
Canada	$	15.65	$	14.06		+11	%	$	15.08	$	13.78		+9	%
Total	$	8.22	$	7.81		+5	%	$	8.22	$	7.62		+8	%

(1)	Percentage changes are based on actual figures rather than the rounded figures presented.

LOE increased $0.41 per Boe and $0.60 per Boe during the third quarter and first nine months of 2012, respectively. The largest contributor to the higher unit cost is related to our liquids production growth, particularly at our Jackfish thermal heavy oil projects in Canada and in the Permian Basin in the U.S. Such projects generally require a higher cost to produce per unit than our gas projects. We also experienced upward pressures on costs in certain operating areas, which also contributed to the higher LOE per Boe.

Depreciation, Depletion and Amortization (“DD&A”)


	Three Months Ended September 30,							Nine Months Ended September 30,
	FY2012		FY2011		Change⁽¹⁾			FY2012		FY2011		Change⁽¹⁾
DD&A ($ in millions):
Oil & gas properties	$	642	$	504		+27	%	$	1,870	$	1,431		+31	%
Other properties		74		62		+17	%		210		191		+10	%

Total	$	716	$	566		+26	%	$	2,080	$	1,622		+28	%


	Three Months Ended September 30,							Nine Months Ended September 30,
	FY2012		FY2011		Change⁽¹⁾			FY2012		FY2011		Change⁽¹⁾
DD&A per Boe:
Oil & gas properties	$	10.29	$	8.29		+24	%	$	9.98	$	8.07		+24	%
Other properties		1.17		1.03		+14	%		1.12		1.07		+4	%

Total	$	11.46	$	9.32		+23	%	$	11.10	$	9.14		+21	%

(1)	Percentage changes are based on actual figures rather than the rounded figures presented.

Oil and gas property DD&A increased during the third quarter and first nine months of 2012 largely due to increases in the DD&A rates. The largest contributor to the higher rates were our drilling and development activities subsequent to the end of the third quarter of 2011.

General and Administrative Expenses (“G&A”)


	Three Months Ended September 30,									Nine Months Ended September 30,
	FY2012			FY2011			Change⁽¹⁾			FY2012			FY2011			Change⁽¹⁾
	($ in millions)
Gross G&A	$	281		$	253			+11	%	$	865		$	736			+18	%
Capitalized G&A		(99	)		(85	)		+16	%		(282	)		(247	)		+14	%
Reimbursed G&A		(32	)		(30	)		+7	%		(89	)		(86	)		+3	%

Net G&A	$	150		$	138			+9	%	$	494		$	403			+23	%

Net G&A per Boe	$	2.40		$	2.27			+6	%	$	2.64		$	2.27			+16	%

(1)	Percentage changes are based on actual figures rather than the rounded figures presented.

Net G&A and net G&A per Boe increased during 2012 largely due to higher employee compensation and benefits. Employee costs increased primarily from an expansion of our workforce as part of growing production operations at certain of our key areas, including Jackfish, the Permian and the Cana-Woodford shale.

Taxes Other Than Income Taxes


	Three Months Ended September 30,									Nine Months Ended September 30,
	FY2012			FY2011			Change⁽¹⁾			FY2012			FY2011			Change⁽¹⁾
	($ in millions)
Production	$	60		$	63			-4	%	$	164		$	187			-12	%
Ad valorem and other		44			45			-3	%		142			149			-5	%

Taxes other than income taxes	$	104		$	108			-4	%	$	306		$	336			-9	%

Percentage of oil, gas and NGL revenue:
Production		3.45	%		2.97	%		+16	%		3.12	%		3.03	%		+3	%
Ad valorem and other		2.50	%		2.13	%		+18	%		2.68	%		2.41	%		+12	%

Total		5.95	%		5.10	%		+17	%		5.80	%		5.44	%		+7	%

(1)	Percentage changes are based on actual figures rather than the rounded figures presented.

Taxes other than income taxes as a percentage of our oil, gas and NGL revenues increased in both 2012 periods primarily due to ad valorem and other taxes, which do not change in direct correlation with oil, gas and NGL revenues.

Interest Expense


	Three Months Ended September 30,									Nine Months Ended September 30,
	FY2012			FY2011			Change⁽¹⁾			FY2012			FY2011			Change⁽¹⁾
	($ in millions)
Interest based on debt outstanding	$	117		$	120			-3	%	$	324		$	318			+2	%
Capitalized interest		(9	)		(19	)		-52	%		(38	)		(56	)		-32	%
Other		2			3			-18	%		10			8			+20	%

Interest expense	$	110		$	104			+6	%	$	296		$	270			+10	%

Interest based on debt outstanding remained relatively flat in 2012 as a result of lower weighted average interest rates offset by additional debt borrowings. Borrowings were primarily used to fund capital expenditures in excess of our operating cash flow and divestiture proceeds.

Asset Impairments

In the third quarter of 2012, we recognized asset impairments related to our U.S. oil and gas property and equipment and our U.S. midstream assets as presented below.


	September 30, 2012
	Gross		Net of Taxes
	(In millions)
U.S. oil and gas assets	$	1,106	$	705
Midstream assets		22		14

Total asset impairments	$	1,128	$	719

U.S. Oil and Gas Impairment

Under the full-cost method of accounting, capitalized costs of oil and gas properties are subject to a full cost ceiling test, which is discussed in Note 11 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.

Additionally, if natural gas and NGL prices remain depressed, we may incur a full cost ceiling impairment related to our oil and gas property and equipment in the fourth quarter of 2012.

Midstream Impairment

Due to declining natural gas production resulting from low natural gas and NGL prices, we determined that the carrying amounts of certain of its midstream facilities located in south and east Texas were not recoverable from estimated future cash flows. Consequently, the assets were written down to their estimated fair values, which were determined using discounted cash flow models.

Other, net


	Three Months Ended September 30,						Nine Months Ended September 30,
	FY2012			FY2011			FY2012			FY2011
	(In millions)
Accretion of asset retirement obligations	$	27		$	23		$	82		$	69
Interest rate derivatives		(1	)		3			15			11
Foreign currency derivatives		26			(22	)		25			(22	)
Foreign exchange loss (gain)		(28	)		53			(26	)		39
Interest income		(8	)		(8	)		(24	)		(14	)
Other		(24	)		12			(26	)		5

Other, net	$	(8	)	$	61		$	46		$	88

Income Taxes

The following table presents our total income tax expense (benefit) and a reconciliation of our effective income tax rate to the U.S. statutory income tax rate.


	Three Months Ended September 30,						Nine Months Ended September 30,
	FY2012			FY2011			FY2012			FY2011
Total income tax expense (benefit) (in millions)	$	(442	)	$	498		$	12		$	1,883

U.S. statutory income tax rate		(35	%)		35	%		35	%		35	%
State income taxes		(1	%)		1	%		(1	%)		1	%
Taxation on Canadian operations		(1	%)		(1	%)		(14	%)		(2	%)
Assumed repatriations		—			—			—			21	%
Other		(1	%)		(3	%)		(13	%)		(1	%)

Effective income tax rate		(38	%)		32	%		7	%		54	%

In the table above, the “other” effect is primarily comprised of permanent tax differences for which the dollar amounts do not increase or decrease as our pre-tax earnings do. Generally, such items typically have an insignificant impact on our effective income tax rate. However, these items have a more noticeable impact to our rate for the nine months ended September 30, 2012 because of the relatively low pre-tax earnings for that period.

Earnings (Loss) From Discontinued Operations


	Three Months Ended September 30,					Nine Months Ended September 30,
	FY2012		FY2011			FY2012			FY2011
	(In millions)
Operating earnings (loss)	$	—	$	(4	)	$	—		$	38
Gain (loss) on sale of oil and gas properties		—		—			(16	)		2,546

Earnings (loss) before income taxes		—		(4	)		(16	)		2,584
Income tax expense (benefit)		—		(2	)		5			—

Earnings (loss) from discontinued operations	$	—	$	(2	)	$	(21	)	$	2,584

Earnings decreased in 2012 primarily as a result of the $2.5 billion gain ($2.5 billion after-tax) recognized from the divestiture of our Brazil operations in the second quarter of 2011.

Capital Resources, Uses and Liquidity

Sources and Uses of Cash

The following table presents the major source and use categories of our cash and cash equivalents.


	Nine Months Ended September 30,
	2012			2011
	(In millions)
Operating cash flow – continuing operations	$	3,787		$	4,227
Debt activity, net		1,567			3,657
Divestitures of property and equipment		1,468			3,264
Capital expenditures		(6,228	)		(5,515	)
Short-term investment activity, net		(661	)		(1,086	)
Common stock repurchases and dividends		(242	)		(2,196	)
Other		92			(23	)

Net change in cash and cash equivalents	$	(217	)	$	2,328

Cash and cash equivalents at end of period	$	5,338		$	5,618

Short-term investments at end of period	$	2,164		$	1,231

Operating Cash Flow – Continuing Operations

Net cash provided by operating activities (“operating cash flow”) was our primary source of capital in the first nine months of 2012. Our operating cash flow decreased approximately 10 percent during 2012 primarily due to lower commodity prices and higher expenses, partially offset by additional cash flow from our production growth.

During the first nine months of 2012, our operating cash flow funded approximately 80 percent of our cash payments for capital expenditures, net of divestiture proceeds. Leveraging our liquidity, we used debt to fund the remainder of our cash-based capital expenditures. This cash flow deficit was largely expected as we have allocated approximately 25% of our 2012 capital expenditure budget to exploratory projects and leasehold acquisitions that are not yet generating production revenues.

Debt Activity, Net

During the first nine months of 2012, we increased our debt borrowings by $1.6 billion as a result of issuing $2.5 billion of long-term debt partially offset by the repayment of approximately $0.9 billion of outstanding short-term debt. The additional debt borrowings were primarily used to fund capital expenditures in excess of our operating cash flow.

During the first nine months of 2011, we utilized commercial paper borrowings of $3.2 billion and received $0.5 billion from new debt issuances, net of debt maturities, to fund capital expenditures and common share repurchases.

Divestitures of Property and Equipment

During the third quarter of 2012, we closed our joint venture transaction with Sumitomo Corporation. At closing, Sumitomo paid approximately $400 million and received a 30% interest in the Cline and Midland-Wolfcamp shale plays in Texas. Additionally, Sumitomo is funding approximately $1.0 billion of our share of future exploration, development and drilling costs associated with these plays. Also during the third quarter of 2012, we sold our West Johnson County Plant in north Texas for approximately $90 million.

During the second quarter of 2012, we closed our joint venture transaction with Sinopec. Sinopec paid approximately $900 million in cash and received a 33.3% interest in five of our new ventures exploration plays in the U.S. Sinopec is also funding approximately $1.6 billion of our share of future exploration, development and drilling costs associated with these plays.

In the first quarter of 2012, we received $71 million from the divestiture of our Angola operations.

During the second quarter of 2011, we completed the divestiture of our operations in Brazil, generating $3.3 billion in net proceeds.

Capital Expenditures

The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior periods.


	Nine Months Ended September 30,
	2012		2011
	(In millions)
U.S.	$	4,401	$	3,665
Canada		1,157		1,224

Total oil and gas		5,558		4,889
Midstream		341		244
Other		329		382

Total continuing operations	$	6,228	$	5,515

Our capital expenditures consist of amounts related to our oil and gas exploration and development operations, our midstream operations and other corporate activities. The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties, which totaled $5.6 billion and $4.9 billion in the first nine months of 2012 and 2011, respectively. The 14% growth in exploration and development capital spending in the first nine months of 2012 was primarily due to increased new ventures exploratory activity and unproved leasehold acquisitions.

Capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas gathering systems and oil transportation facilities. Our midstream capital expenditures are largely impacted by oil and gas drilling activities.

Short-term Investment Activity, Net

During the first nine months of 2012 and 2011, we had net short-term investment purchases totaling $0.7 billion and $1.1 billion, respectively. The 2012 purchases were primarily related to the investment of a portion of our joint venture proceeds into marketable securities. The 2011 purchases were primarily related to the investment of a portion of the International offshore divestiture proceeds into marketable securities.

Common Stock Repurchases and Dividends

In connection with our offshore divestitures noted above, we conducted a $3.5 billion share repurchase program, which we completed in the fourth quarter of 2011. Since the third quarter of 2011, we have increased our quarterly dividend rate 18%.

The following table summarizes our repurchases and our common stock dividends (amounts and shares in millions) during the first nine months of 2012 and 2011.


	2012						2011
	Amount		Shares		Per Share		Amount		Shares		Per Share
Repurchases	$	—		—	$	—	$	1,987		25.6	$	77.61
Dividends	$	242		N/A	$	0.20	$	209		N/A	$	0.17

Liquidity

Historically, our primary sources of capital and liquidity have been our operating cash flow and cash on hand. Additionally, we maintain revolving lines of credit and a commercial paper program, which can be accessed as needed to supplement operating cash flow and cash balances. Other available sources of capital and liquidity include debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC. We estimate the combination of these sources of capital will be adequate to fund future capital expenditures, debt repayments and other contractual commitments. The following sections discuss changes to our liquidity subsequent to filing our 2011 Annual Report on Form 10-K.

Operating Cash Flow

Our operating cash flow is sensitive to many variables, the most volatile of which are the prices of the oil, gas and NGLs we produce. We expect operating cash flow to continue to be our primary source of liquidity. To mitigate some of the risk inherent in prices, we have utilized various derivative financial instruments to set minimum and maximum prices on our 2012 production. The key terms to our open oil, gas and NGL derivative financial instruments as of September 30, 2012 are presented in Note 2 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.

Credit Availability

As of October 24, 2012, we had $2.9 billion of available capacity under our syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) and $3.2 billion of commercial paper borrowings outstanding. Our Senior Credit Facility matures on October 24, 2017. However, prior to the maturity date, we have the option to extend the maturity for up to two additional one-year periods, subject to the approval of the lenders.

The Senior Credit Facility contains only one material financial covenant. This covenant requires us to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65 percent. As of September 30, 2012, we were in compliance with this covenant with a debt-to-capitalization ratio of 24.7 percent.

Although we ended the third quarter of 2012 with approximately $7.5 billion of cash and short-term investments, the vast majority of this amount consists of proceeds from our International offshore divestitures that are held by certain of our foreign subsidiaries. We do not currently expect to repatriate such amounts to the U.S. If we were to repatriate a portion or all of the cash and short-term investments held by these foreign subsidiaries, we would be required to accrue and pay current income taxes in accordance with current U.S. tax law. With these proceeds remaining outside of the U.S., we expect to continue using commercial paper and credit facility borrowings in the U.S. to supplement our U.S. operating cash flow. We do not expect near-term increases in such borrowings will have a material effect on our overall liquidity or financial condition.

Capital Expenditures

We previously disclosed that we expected our 2012 capital expenditures to range from $6.2 billion to $6.8 billion. During 2012, we expanded our new ventures exploration activities, targeting oil and liquids-rich opportunities. As a result, we increased our total estimated 2012 capital expenditures by approximately $1.7 billion.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

We have commodity derivatives that pertain to a portion of our production for the last three months of 2012, as well as 2013 and 2014. The key terms to our open oil, gas and NGL derivative financial instruments as of September 30, 2012 are presented in Note 2 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.

The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At September 30, 2012, a 10 percent change in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by the following amounts:


	10% Increase			10% Decrease
	(In millions)
Gain/(loss):
Oil derivatives	$	(310	)	$	317
Gas derivatives	$	(131	)	$	124

Interest Rate Risk

At September 30, 2012, we had total debt outstanding of $11.2 billion. Our long-term debt of $8.4 billion bears fixed interest rates averaging 5.4 percent. The remaining $2.8 billion of commercial paper borrowings bears interest at fixed rates which averaged 0.37 percent. Such borrowings typically have maturity rates between 1 and 90 days.

As of September 30, 2012, we had open interest rate swap positions that are presented in Note 2 to the financial statements under “Item 1. Consolidated Financial Statements” of this report. The fair values of our interest rate swaps are largely determined by estimates of the forward curves of the Federal Funds rate. A 10 percent change in these forward curves would not have materially impacted our balance sheet at September 30, 2012.

Foreign Currency Risk

Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. A 10 percent unfavorable change in the Canadian-to-U.S. dollar exchange rate would not materially impact our September 30, 2012 balance sheet.

Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, one of these foreign subsidiaries holds Canadian-dollar cash and engages in short-term intercompany loans with Canadian subsidiaries that are sometimes based in Canadian dollars. Additionally, at September 30, 2012, we held foreign currency exchange forward contracts to hedge exposures to fluctuations in exchange rates on the Canadian-dollar cash and intercompany loans. The increase or decrease in the value of the forward contracts is offset by the increase or decrease to the U.S. dollar equivalent of the Canadian-dollar cash. The value of the intercompany loans increases or decreases from the remeasurement of the loans into the U.S. dollar functional currency. Based on the amount of the intercompany loans as of September 30, 2012, a 10 percent change in the foreign currency exchange rates would not have materially impacted our balance sheet.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that material information relating to Devon, including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to other members of senior management and the Board of Directors.

Based on their evaluation, our principal executive and principal financial officers have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of September 30, 2012, to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. Other Information

Item 1. Legal Proceedings

There have been no material changes to the information included in Item 3. “Legal Proceedings” in our 2011 Annual Report on Form 10-K.

Item 1A. Risk Factors

There have been no material changes to the information included in Item 1A. “Risk Factors” in our 2011 Annual Report on Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information regarding purchases of our common stock that were made by us during the third quarter of 2012.


Period	Total Number of Shares Purchased (1)		Average Price Paid per Share
July 1 – July 31		2,962	$	57.71
August 1 – August 31		32,165	$	59.16
September 1 – September 30		33,566	$	59.41

Total		68,693	$	59.22

(1)	Share repurchases represent shares received by us from employees and directors for the payment of personal income tax withholding on restricted stock vesting and stock option exercises.

Under the Devon Canada Corporation Savings Plan (the “Canadian Plan”), eligible Canadian employees may purchase shares of our common stock through an investment in the Canadian Plan, which is administered by an independent trustee, Sun Life Assurance Company of Canada. Eligible Canadian employees purchased approximately 6,200 shares of our common stock in the third quarter of 2012, at then-prevailing stock prices, that they held through their ownership in the Canadian Plan. We acquired the shares sold under the Canadian Plan through open-market purchases. These shares and any interest in the Canadian Plan were offered and sold in reliance on the exemptions for offers and sales of securities made outside of the U.S., including under Regulation S for offers and sales of securities to employees pursuant to an employee benefit plan established and administered in accordance with the law of a country other than the U.S.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

None.

Item 6. Exhibits

(a) Exhibits required by Item 601 of Regulation S-K are as follows:


Exhibit Number		Description

31.1		Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB		XBRL Taxonomy Extension Labels Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

SIGNATURES

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

INDEX TO EXHIBITS


Exhibit Number		Description

31.1		Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB		XBRL Taxonomy Extension Labels Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

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