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, 2013

¨	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 22, 2013, 406 million shares of common stock were outstanding.

DEVON ENERGY CORPORATION

FORM 10-Q

TABLE OF CONTENTS


Part I. Financial Information
Item 1. 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			34
Item 4. Controls and Procedures			34

Part II. Other Information
Item 1. Legal Proceedings			36
Item 1A. Risk Factors			36
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			36
Item 3. Defaults Upon Senior Securities			36
Item 4. Mine Safety Disclosures			36
Item 5. Other Information			36
Item 6. Exhibits			37

Signatures			38

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, 2012 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.

PART I. Financial Information

Item 1. Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(Unaudited) (In millions, except per share amounts)
Revenues:
Oil, gas and NGL sales	$	2,341		$	1,738		$	6,367		$	5,270
Oil, gas and NGL derivatives		(141	)		(295	)		(95	)		515
Marketing and midstream revenues		520			422			1,511			1,136

Total revenues		2,720			1,865			7,783			6,921

Expenses and other, net:
Lease operating expenses		600			513			1,684			1,540
Marketing and midstream operating costs and expenses		383			313			1,128			847
Depreciation, depletion and amortization		691			716			2,069			2,080
General and administrative expenses		143			150			460			494
Taxes other than income taxes		115			104			353			306
Interest expense		104			110			322			296
Restructuring costs		4			—			50			—
Asset impairments		7			1,128			1,960			1,128
Other, net		34			(8	)		83			46

Total expenses and other, net		2,081			3,026			8,109			6,737

Earnings (loss) from continuing operations before income taxes		639			(1,161	)		(326	)		184
Current income tax expense (benefit)		(50	)		(41	)		82			8
Deferred income tax expense (benefit)		260			(401	)		(181	)		4

Earnings (loss) from continuing operations		429			(719	)		(227	)		172
Loss from discontinued operations, net of tax		—			—			—			(21	)

Net earnings (loss)	$	429		$	(719	)	$	(227	)	$	151

Basic net earnings (loss) per share:
Basic earnings (loss) from continuing operations per share	$	1.06		$	(1.80	)	$	(0.57	)	$	0.42
Basic loss from discontinued operations per share		—			—			—			(0.05	)

Basic net earnings (loss) per share	$	1.06		$	(1.80	)	$	(0.57	)	$	0.37

Diluted net earnings (loss) per share:
Diluted earnings (loss) from continuing operations per share	$	1.05		$	(1.80	)	$	(0.57	)	$	0.42
Diluted loss from discontinued operations per share		—			—			—			(0.05	)

Diluted net earnings (loss) per share	$	1.05		$	(1.80	)	$	(0.57	)	$	0.37

Comprehensive earnings (loss):
Net earnings (loss)	$	429		$	(719	)	$	(227	)	$	151
Other comprehensive earnings (loss), net of tax:
Foreign currency translation		173			311			(281	)		292
Pension and postretirement plans		3			3			12			12

Other comprehensive earnings (loss), net of tax		176			314			(269	)		304

Comprehensive earnings (loss)	$	605		$	(405	)	$	(496	)	$	455

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended September 30,
	2013			2012
	(Unaudited)
	(In millions)
Cash flows from operating activities:
Net earnings (loss)	$	(227	)	$	151
Loss from discontinued operations, net of tax		—			21
Adjustments to reconcile earnings (loss) from continuing operations to net cash from operating activities:
Depreciation, depletion and amortization		2,069			2,080
Asset impairments		1,960			1,128
Deferred income tax expense (benefit)		(181	)		4
Unrealized change in fair value of financial instruments		212			173
Other noncash charges		206			136
Net change in working capital		(104	)		48
Change in long-term other assets		(28	)		(22	)
Change in long-term other liabilities		92			68

Cash from operating activities – continuing operations		3,999			3,787
Cash from operating activities – discontinued operations		—			26

Net cash from operating activities		3,999			3,813

Cash flows from investing activities:
Capital expenditures		(5,219	)		(6,228	)
Proceeds from property and equipment divestitures		316			1,397
Purchases of short-term investments		(1,076	)		(2,969	)
Redemptions of short-term investments		3,419			2,308
Other		83			18

Cash from investing activities – continuing operations		(2,477	)		(5,474	)
Cash from investing activities – discontinued operations		—			58

Net cash from investing activities		(2,477	)		(5,416	)

Cash flows from financing activities:
Proceeds from borrowings of long-term debt, net of issuance costs		—			2,465
Net short-term debt repayments		(1,577	)		(898	)
Credit facility borrowings		—			750
Credit facility repayments		—			(750	)
Proceeds from stock option exercises		1			25
Dividends paid on common stock		(259	)		(242	)
Excess tax benefits related to share-based compensation		5			5

Net cash from financing activities		(1,830	)		1,355

Effect of exchange rate changes on cash		(9	)		31

Net change in cash and cash equivalents		(317	)		(217	)

Cash and cash equivalents at beginning of period		4,637			5,555

Cash and cash equivalents at end of period	$	4,320		$	5,338

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	September 30,			December 31,
	2013			2012
	(Unaudited)
	(In millions, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	4,320		$	4,637
Short-term investments		—			2,343
Accounts receivable		1,520			1,245
Other current assets		475			746

Total current assets		6,315			8,971

Property and equipment, at cost:
Oil and gas, based on full cost accounting:
Subject to amortization		73,009			69,410
Not subject to amortization		3,319			3,308

Total oil and gas		76,328			72,718
Other		6,050			5,630

Total property and equipment, at cost		82,378			78,348
Less accumulated depreciation, depletion and amortization		(54,416	)		(51,032	)

Property and equipment, net		27,962			27,316

Goodwill		5,954			6,079
Other long-term assets		615			960

Total assets	$	40,846		$	43,326

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,269		$	1,451
Revenues and royalties payable		807			750
Short-term debt		2,112			3,189
Other current liabilities		594			613

Total current liabilities		4,782			6,003

Long-term debt		7,956			8,455
Asset retirement obligations		2,161			1,996
Other long-term liabilities		830			901
Deferred income taxes		4,505			4,693
Stockholders’ equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 406 million shares in 2013 and 2012, respectively		41			41
Additional paid-in capital		3,777			3,688
Retained earnings		15,292			15,778
Accumulated other comprehensive earnings		1,502			1,771

Total stockholders’ equity		20,612			21,278

Commitments and contingencies (Note 17)
Total liabilities and stockholders’ equity	$	40,846		$	43,326

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY


					Additional Paid-In						Accumulated Other						Total
	Common Stock				Additional Paid-In			Retained			Comprehensive			Treasury			Stockholders’
	Shares		Amount		Capital			Earnings			Earnings			Stock			Equity
	(Unaudited)
	(In millions)
Nine Months Ended September 30, 2013
Balance as of December 31, 2012		406	$	41	$	3,688		$	15,778		$	1,771		$	—		$	21,278
Net loss		—		—		—			(227	)		—			—			(227	)
Other comprehensive loss, net of tax		—		—		—			—			(269	)		—			(269	)
Stock option exercises		—		—		1			—			—			—			1
Common stock repurchased		—		—		—			—			—			(9	)		(9	)
Common stock retired		—		—		(9	)		—			—			9			—
Common stock dividends		—		—		—			(259	)		—			—			(259	)
Share-based compensation		—		—		92			—			—			—			92
Share-based compensation tax benefits		—		—		5			—			—			—			5

Balance as of September 30, 2013		406	$	41	$	3,777		$	15,292		$	1,502		$	—		$	20,612

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

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 financial statements and notes included in Devon’s 2012 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 results of operations and cash flows for the three-month and nine-month periods ended September 30, 2013 and 2012 and Devon’s financial position as of September 30, 2013.

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, 2013, Devon held $43 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, 2013, Devon had the following open oil derivative positions. The first table presents Devon’s oil derivatives that settle against the average of the prompt month NYMEX West Texas Intermediate futures price. The second table presents Devon’s oil derivatives that settle against the Western Canadian Select index.


	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 2013		70,000	$	100.26		72,000	$	90.60	$	111.14		10,000	$	120.00
Q1-Q4 2014		49,000	$	94.77		43,969	$	89.01	$	102.48		42,000	$	116.43
Q1-Q4 2015		500	$	91.00		—	$	—	$	—		22,000	$	115.45

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 2013	Western Canadian Select		40,000	$	(22.47	)

As of September 30, 2013, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The next two tables present Devon’s natural gas derivatives that settle against the AECO 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 2013		987,500	$	4.09		650,000	$	3.61	$	4.28		—	$	—
Q1-Q4 2014		800,000	$	4.42		210,000	$	4.01	$	4.71		500,000	$	5.00
Q1-Q4 2015		—	$	—		—	$	—	$	—		550,000	$	5.09


	Price Swaps
Period	Volume (MMBtu/d)		Weighted Average Price ($/MMBtu)
Q4 2013		28,435	$	3.54


	Basis Swaps
Period	Index		Volume (MMBtu/d)		Weighted Average Differential to Henry Hub ($/MMBtu)
Q4 2013		AECO		62,843	$	(0.44	)
Q1-Q4 2014		AECO		94,781	$	(0.52	)

As of September 30, 2013, Devon had the following open NGL derivative positions. Devon’s NGL derivatives settle against the average of the prompt month OPIS Mont Belvieu, Texas index.


	Price Swaps
Period	Product		Volume (Bbls/d)		Weighted Average Price ($/Bbl)
Q4 2013		Ethane		1,957	$	15.36
Q4 2013		Propane		3,985	$	41.73


	Basis Swaps
Period	Pay		Volume (Bbls/d)		Weighted Average Differential to WTI ($/Bbl)
Q4 2013		Natural Gasoline		1,000	$	(9.58	)
Q1-Q4 2014		Natural Gasoline		329	$	(10.85	)

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Foreign Currency Derivatives

As of September 30, 2013, Devon had the following open foreign currency derivative position:

Forward Contract

Currency

Contract
Type

CAD
Notional

Weighted Average
Fixed Rate Received

Expiration

(In millions)

(CAD-USD)

Canadian Dollar

Sell

1,261

0.969

December 2013

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 oil, gas and NGL derivatives 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 other, net in the accompanying comprehensive statements of earnings.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In millions)
Cash settlements:
Commodity derivatives	$	(7	)	$	243		$	93		$	668
Interest rate derivatives		10			10			24			9
Foreign currency derivatives		(5	)		(38	)		30			(29	)

Total cash settlements		(2	)		215			147			648

Unrealized gains (losses):
Commodity derivatives		(134	)		(538	)		(188	)		(153	)
Interest rate derivatives		(9	)		(9	)		(23	)		(24	)
Foreign currency derivatives		(23	)		12			(1	)		4

Total unrealized gains (losses)		(166	)		(535	)		(212	)		(173	)

Net gains (losses) recognized on comprehensive statements of earnings	$	(168	)	$	(320	)	$	(65	)	$	475

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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


	Balance Sheet Caption	September 30, 2013		December 31, 2012
		(In millions)
Asset derivatives:
Commodity derivatives	Other current assets	$	224	$	379
Commodity derivatives	Other long-term assets		58		22
Interest rate derivatives	Other current assets		—		23
Foreign currency derivatives	Other current assets		—		1

Total asset derivatives		$	282	$	425

Liability derivatives:
Commodity derivatives	Other current liabilities	$	50	$	3
Commodity derivatives	Other long-term liabilities		51		29

Total liability derivatives		$	101	$	32

3. Restructuring Costs

Office Consolidation

In October 2012, Devon announced plans to consolidate its U.S. personnel into a single operations group centrally located at the company’s headquarters in Oklahoma City. As of September 30, 2013, Devon had substantially completed this initiative and incurred $130 million of restructuring costs associated with the office consolidation. The $130 million includes $50 million incurred during the nine months ended September 30, 2013, which largely relates to office space that is subject to non-cancellable operating lease agreements that Devon ceased using.

Divestiture of Offshore Assets

In the fourth quarter of 2009, Devon announced plans to divest its offshore assets. Devon completed this divestiture program in 2012, having incurred $196 million of cumulative restructuring costs associated with the divestitures.

Financial Statement Presentation

The schedule below summarizes restructuring costs presented in the accompanying comprehensive statements of earnings related to the office consolidation. There were no costs related to the offshore divestitures in the nine-month periods ended September 30, 2013 and 2012.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(In millions)
Lease obligations and other	$	4	$	—	$	44	$	—
Asset impairments		—		—		6		—

Restructuring costs	$	4	$	—	$	50	$	—

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The schedule below summarizes Devon’s restructuring liabilities.


	Other Current Liabilities			Other Long-Term Liabilities			Total
	(In millions)
Balance as of December 31, 2012	$	52		$	9		$	61
Lease obligations and other—Office consolidation		18			11			29
Employee severance—Office consolidation		(34	)		—			(34	)
Lease obligations—Offshore		(2	)		(1	)		(3	)

Balance as of September 30, 2013	$	34		$	19		$	53

Balance as of December 31, 2011	$	29		$	16		$	45
Lease obligations—Offshore		(9	)		(3	)		(12	)
Employee severance—Offshore		(7	)		—			(7	)

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

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,
	2013			2012			2013			2012
	(In millions)
Accretion of asset retirement obligations	$	29		$	27		$	86		$	82
Interest rate derivatives		(1	)		(1	)		(1	)		15
Foreign currency derivatives		28			26			(29	)		25
Foreign exchange loss (gain)		(27	)		(28	)		34			(26	)
Interest income		(4	)		(8	)		(16	)		(24	)
Other		9			(24	)		9			(26	)

Other, net	$	34		$	(8	)	$	83		$	46

5. Income Taxes

In the second quarter of 2013, Devon repatriated to the United States $2.0 billion of cash from its foreign subsidiaries. In conjunction with the repatriation, Devon recognized approximately $100 million of current income tax expense. The current expense was entirely offset by the recognition of deferred income tax benefits, which included the reduction of the deferred tax liability previously recognized for unremitted foreign earnings deemed not to be indefinitely reinvested.

As of September 30, 2013, Devon’s unremitted foreign earnings totaled approximately $6.0 billion. Of this amount, approximately $4.8 billion was deemed to be indefinitely reinvested into the development and growth of Devon’s Canadian business. Therefore, Devon has not recognized a deferred tax liability for U.S. income taxes associated with such earnings. If such earnings were to be repatriated to the U.S., Devon may be subject to U.S. income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of such additional taxes that may be payable due to the inter-relationship of the various factors involved in making such an estimate.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Devon has deemed the remaining $1.2 billion of unremitted foreign earnings not to be indefinitely reinvested. Consequently, Devon has recognized a deferred tax liability of approximately $550 million associated with such unremitted earnings as of September 30, 2013.

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,
	2013			2012			2013			2012
Total income tax expense (benefit) (in millions)	$	210		$	(442	)	$	(99	)	$	12

U.S. statutory income tax rate		35	%		(35	%)		(35	%)		35	%
State income taxes		1	%		(1	%)		(3	%)		(1	%)
Taxation on Canadian operations		(5	%)		(1	%)		9	%		(14	%)
Other		2	%		(1	%)		(1	%)		(13	%)

Effective income tax rate		33	%		(38	%)		(30	%)		7	%

6. Earnings (Loss) 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.


				Common			Earnings (loss)
	Earnings (loss)			Shares			per Share
	(In millions, except per share amounts)
Three Months Ended September 30, 2013:
Earnings from continuing operations	$	429			406
Attributable to participating securities		(4	)		(4	)

Basic earnings per share		425			402		$	1.06
Dilutive effect of potential common shares issuable		—			1

Diluted earnings per share	$	425			403		$	1.05

Three Months Ended September 30, 2012:
Loss from continuing operations	$	(719	)		405
Attributable to participating securities		(1	)		(5	)

Basic earnings per share		(720	)		400		$	(1.80	)
Dilutive effect of potential common shares issuable		—			—

Diluted earnings per share	$	(720	)		400		$	(1.80	)

Nine Months Ended September 30, 2013:
Loss from continuing operations	$	(227	)		406
Attributable to participating securities		(2	)		(4	)

Basic earnings per share		(229	)		402		$	(0.57	)
Dilutive effect of potential common shares issuable		—			—

Diluted earnings per share	$	(229	)		402		$	(0.57	)

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


				Common			Earnings (loss)
	Earnings (loss)			Shares			per Share
	(In millions, except per share amounts)
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

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, 2013, 7.5 million shares and 7.6 million shares, respectively, were excluded from the diluted earnings per share calculations. 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.

7. Other Comprehensive Earnings

Components of other comprehensive earnings consist of the following:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In millions)
Foreign currency translation:
Beginning accumulated foreign currency translation	$	1,542		$	1,783		$	1,996		$	1,802
Change in cumulative translation adjustment		182			325			(294	)		305
Income tax benefit (expense)		(9	)		(14	)		13			(13	)

Ending accumulated foreign currency translation		1,715			2,094			1,715			2,094

Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits		(216	)		(218	)		(225	)		(227	)
Recognition of net actuarial loss and prior service cost in earnings⁽¹⁾		6			6			18			19
Income tax expense		(3	)		(3	)		(6	)		(7	)

Ending accumulated pension and postretirement benefits		(213	)		(215	)		(213	)		(215	)

Accumulated other comprehensive earnings, net of tax	$	1,502		$	1,879		$	1,502		$	1,879

(1)	These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of general and administrative expenses on the accompanying comprehensive statements of earnings (see “Retirement Plans” note for additional details).

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

8. Supplemental Information to Statements of Cash Flows


	Nine Months Ended September 30,
	2013			2012
	(In millions)
Net change in working capital accounts:
Accounts receivable	$	(287	)	$	275
Other current assets		72			(234	)
Accounts payable		127			77
Revenues and royalties payable		56			(34	)
Other current liabilities		(72	)		(36	)

Net change in working capital	$	(104	)	$	48

Interest paid (net of capitalized interest)	$	342		$	260
Income taxes paid (received)	$	(2	)	$	88

9. Short-Term Investments

The components of short-term investments include the following:


	September 30, 2013		December 31, 2012
	(In millions)
Canadian treasury, agency and provincial securities	$	—	$	1,865
U.S. treasuries		—		429
Other		—		49

Short-term investments	$	—	$	2,343

10. Accounts Receivable

The components of accounts receivable include the following:


	September 30, 2013			December 31, 2012
	(In millions)
Oil, gas and NGL sales	$	942		$	752
Joint interest billings		389			270
Marketing and midstream revenues		147			161
Other		53			72

Gross accounts receivable		1,531			1,255
Allowance for doubtful accounts		(11	)		(10	)

Net accounts receivable	$	1,520		$	1,245

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

11. Property and Equipment

Asset Impairments

In the first nine months of 2013 and 2012, Devon recognized asset impairments related to its oil and gas property and equipment and its U.S. midstream assets as presented below.


	Nine Months Ended September 30, 2013				Nine Months Ended September 30, 2012
	Gross		Net of Taxes		Gross		Net of Taxes
	(In millions)
U.S. oil and gas assets	$	1,110	$	707	$	1,106	$	705
Canada oil and gas assets		843		632		—		—
Midstream assets		7		4		22		14

Total asset impairments	$	1,960	$	1,343	$	1,128	$	719

Oil and Gas Impairments

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 oil and gas impairments resulted primarily from declines in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from decreases in the 12-month average trailing prices for oil, bitumen and NGLs, which have reduced proved reserve values.

If estimated future cash flows decline due to price decreases or other factors, Devon could incur additional full cost ceiling impairments related to its oil and gas property and equipment.

Midstream Impairments

In the third quarter of 2013 and 2012, Devon determined that the carrying amounts of certain midstream facilities located in south and east Texas were not recoverable from estimated future cash flows due to declining dry natural gas production. 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 2013, Devon’s Canadian goodwill decreased $99 million entirely due to foreign currency translation. Additionally, Devon’s U.S. goodwill decreased $26 million due to the sale of certain midstream assets.

13. Debt

Commercial Paper

During the second quarter of 2013, Devon repatriated $2.0 billion of foreign earnings to the United States and repaid $2.0 billion of commercial paper borrowings. As of September 30, 2013, Devon had $1.6 billion of outstanding commercial paper at an average rate of 0.27 percent.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Credit Lines

Devon has a $3.0 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). During the third quarter of 2013, the lenders agreed, effective October 24, 2013, to extend the maturity date of the Senior Credit Facility to October 24, 2018. As of September 30, 2013 there were no borrowings under the Senior Credit Facility. The Senior Credit Facility contains 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, 2013, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 22.4 percent.

14. Asset Retirement Obligations

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


	Nine Months Ended September 30,
	2013			2012
	(In millions)
Asset retirement obligations as of beginning of period	$	2,095		$	1,563
Liabilities incurred		88			60
Liabilities settled		(46	)		(57	)
Revision of estimated obligation		104			411
Liabilities assumed by others		(15	)		(18	)
Accretion expense on discounted obligation		86			82
Foreign currency translation adjustment		(44	)		35

Asset retirement obligations as of end of period		2,268			2,076
Less current portion		107			67

Asset retirement obligations, long-term	$	2,161		$	2,009

15. 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						Nine Months Ended						Three Months Ended					Nine Months Ended
	September 30,						September 30,						September 30,					September 30,
	2013			2012			2013			2012			2013		2012			2013			2012
	(In millions)
Service cost	$	9		$	11		$	27		$	32		$	—	$	1		$	—		$	1
Interest cost		13			15			39			45			—		—			1			1
Expected return on plan assets		(16	)		(16	)		(47	)		(48	)		—		—			—			—
Amortization of prior service cost ⁽¹⁾		1			1			3			3			—		—			—			(1	)
Net actuarial loss (gain)⁽¹⁾		5			6			16			18			—		(1	)		(1	)		(1	)

Net periodic benefit cost ⁽²⁾	$	12		$	17		$	38		$	50		$	—	$	—		$	—		$	—

(1)	These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period.

(2)	Net periodic benefit cost is a component of general and administrative expenses on the accompanying comprehensive statements of earnings.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

16. Stockholders’ Equity

Dividends

Devon paid common stock dividends of $259 million and $242 million in the first nine months of 2013 and 2012, respectively. The quarterly cash dividend was $0.20 per share in the first nine months of 2012 and in the first quarter of 2013. Devon increased the dividend rate to $0.22 per share in the second quarter of 2013.

17. 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 New Mexico. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.

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. Devon did not have a legal right of set off with respect to the judgment. Therefore, Devon had recorded 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.

The plaintiffs and Rees-Jones have settled all claims related to the 2004 redemption. Under the terms of the settlement, Rees-Jones and Devon received full releases for all of the plaintiffs’ claims with Rees-Jones funding all settlement payments. Consequently, Devon reversed the previously recorded liability and asset in the first quarter of 2013.

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.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

18. 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 current payables and accrued expenses included in the accompanying balance sheets approximated fair value at September 30, 2013 and December 31, 2012. Therefore, such financial assets and liabilities are not presented in the following tables.


							Fair Value Measurements Using:
	Carrying			Total Fair			Level 1		Level 2			Level 3
	Amount			Value			Inputs		Inputs			Inputs
	(In millions)
September 30, 2013 assets (liabilities):
Cash equivalents	$	3,592		$	3,592		$	13	$	3,579		$	—
Long-term investments	$	62		$	62		$	—	$	—		$	62
Commodity derivatives	$	282		$	282		$	—	$	282		$	—
Commodity derivatives	$	(101	)	$	(101	)	$	—	$	(101	)	$	—
Debt	$	(10,068	)	$	(10,926	)	$	—	$	(10,926	)	$	—
December 31, 2012 assets (liabilities):
Cash equivalents	$	4,149		$	4,149		$	32	$	4,117		$	—
Short-term investments	$	2,343		$	2,343		$	429	$	1,914		$	—
Long-term investments	$	64		$	64		$	—	$	—		$	64
Commodity derivatives	$	401		$	401		$	—	$	401		$	—
Commodity derivatives	$	(32	)	$	(32	)	$	—	$	(32	)	$	—
Interest rate derivatives	$	23		$	23		$	—	$	23		$	—
Foreign currency derivatives	$	1		$	1		$	—	$	1		$	—
Debt	$	(11,644	)	$	(13,435	)	$	—	$	(13,435	)	$	—

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 approximates 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 value of Devon’s variable-rate commercial paper is the carrying value.

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 an inactive 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-

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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, 2013 and December 31, 2012.

Included below is a summary of the changes in Devon’s Level 3 fair value measurements during the first nine months of 2013 and 2012.


	Nine Months Ended September 30,
	2013			2012
	(In millions)
Long-term investments balance at beginning of period	$	64		$	84
Redemptions of principal		(2	)		(20	)

Long-term investments balance at end of period	$	62		$	64

19. 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, 2013:
Oil, gas and NGL sales	$	1,573		$	768		$	2,341
Oil, gas and NGL derivatives	$	(153	)	$	12		$	(141	)
Marketing and midstream revenues	$	509		$	11		$	520
Depreciation, depletion and amortization	$	492		$	199		$	691
Interest expense	$	94		$	10		$	104
Asset impairments	$	7		$	—		$	7
Earnings from continuing operations before income taxes	$	410		$	229		$	639
Income tax expense	$	160		$	50		$	210
Earnings from continuing operations	$	250		$	179		$	429
Capital expenditures	$	1,256		$	437		$	1,693

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 benefit	$	(438	)	$	(4	)	$	(442	)
Earnings (loss) from continuing operations	$	(731	)	$	12		$	(719	)
Capital expenditures	$	1,586		$	382		$	1,968

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


	U.S.			Canada			Total
	(In millions)
Nine Months Ended September 30, 2013:
Oil, gas and NGL sales	$	4,377		$	1,990		$	6,367
Oil, gas and NGL derivatives	$	(82	)	$	(13	)	$	(95	)
Marketing and midstream revenues	$	1,436		$	75		$	1,511
Depreciation, depletion and amortization	$	1,426		$	643		$	2,069
Interest expense	$	284		$	38		$	322
Asset impairments	$	1,117		$	843		$	1,960
Earnings (loss) from continuing operations before income taxes	$	208		$	(534	)	$	(326	)
Income tax expense (benefit)	$	59		$	(158	)	$	(99	)
Earnings (loss) from continuing operations	$	149		$	(376	)	$	(227	)
Property and equipment, net	$	19,462		$	8,500		$	27,962
Total assets	$	24,668		$	16,178		$	40,846
Capital expenditures	$	3,650		$	1,377		$	5,027

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	$	5,007		$	1,276		$	6,283

20. Subsequent Event

On October 21, 2013, Devon, Crosstex Energy, Inc. and Crosstex Energy, L.P. (collectively “Crosstex”) announced plans to combine substantially all of Devon’s U.S. midstream assets with Crosstex’s assets to form a new midstream business. The new business will consist of a master limited partnership and a general partner entity (the “Master Limited Partnership” and the “General Partner”), which will both be publicly traded entities.

In exchange for a controlling interest in both the General Partner and the Master Limited Partnership, Devon will contribute its equity interest in a newly formed Devon subsidiary (“Devon Holdings”) and $100 million in cash. Devon Holdings will own Devon’s midstream assets in the Barnett Shale in North Texas and the Cana and Arkoma Woodford Shales in Oklahoma, as well as Devon’s interest in Gulf Coast Fractionators in Mt. Belvieu, Texas. The Master Limited Partnership and the General Partner will each own 50% of Devon Holdings. The completion of these transactions is subject to Crosstex Energy, Inc. shareholder approval.

Upon closing of the transactions, the pro forma ownership of the General Partner will be approximately:

•

70% - Devon Energy Corporation

•

30% - Current Crosstex Energy, Inc. public stockholders

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Upon closing of the transactions, the pro forma ownership of the Master Limited Partnership will be approximately:

•

53% - Devon Energy Corporation

•

40% - Current Crosstex Energy, L.P. public unitholders

•

7% - the General Partner

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, 2013, compared to the three-month and nine-month periods ended September 30, 2012, and in our financial condition and liquidity since December 31, 2012. For information regarding our critical accounting policies and estimates, see our 2012 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Overview of 2013 Results

Key components of our financial performance are summarized below, which exclude amounts from our discontinued operations.


	Three Months Ended September 30,								Nine Months Ended September 30,
	2013		2012			Change			2013			2012		Change
	($ in millions, except per share amounts)
Net earnings (loss)	$	429	$	(719	)		+160	%	$	(227	)	$	172		-232	%
Adjusted earnings⁽¹⁾	$	526	$	355			+48	%	$	1,287		$	1,005		+28	%
Earnings (loss) per share	$	1.05	$	(1.80	)		+159	%	$	(0.57	)	$	0.42		-234	%
Adjusted earnings per share⁽¹⁾	$	1.29	$	0.88			+47	%	$	3.16		$	2.48		+27	%
Production (MBoe/d)		690.8		678.2			+2	%		691.8			683.5		+1	%
Realized price per Boe	$	36.84	$	27.85			+32	%	$	33.71		$	28.14		+20	%
Operating margin per Boe ⁽²⁾	$	23.74	$	19.44			+22	%	$	21.31		$	19.17		+11	%
Operating cash flow	$	1,601	$	1,361			+18	%	$	3,999		$	3,787		+6	%
Adjusted operating cash flow⁽¹⁾	$	1,583	$	1,281			+24	%	$	4,137		$	3,693		+12	%
Capitalized costs	$	1,693	$	1,968			-14	%	$	5,027		$	6,283		-20	%
Shareholder distributions	$	89	$	80			+10	%	$	259		$	242		+7	%

(1)

Adjusted earnings, adjusted earnings per share and adjusted operating cash flow are financial measures not prepared in accordance with accounting principles generally accepted in the U.S. (GAAP). For a description of adjusted earnings, adjusted earnings per share and adjusted operating cash flow as well as reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 2.

(2)

Computed as revenues from commodity sales, commodity derivatives settlements, and marketing and midstream operations, less expenses for lease operations, marketing and midstream operations, general and administration, taxes other than income taxes and interest, with the result divided by total production.

During the three-month and nine-month periods ended September 30, 2013, our adjusted earnings, adjusted earnings per share and operating margin per Boe all increased compared to the 2012 periods. The improved 2013 results were driven primarily by increases in gas prices, oil volumes and oil realizations. These factors also contributed to higher adjusted operating cash flow, which when combined with a reduction in capitalized costs, caused our cash flow deficit to narrow considerably in 2013.

During the first nine months of 2013, we recognized noncash asset impairments totaling $2.0 billion ($1.3 billion after tax).

Results of Operations

Production, Prices and Revenues


	Three Months Ended September 30,							Nine Months Ended September 30,
	2013		2012		Change			2013		2012		Change
Oil (MBbls/d)
U.S.		81.4		58.9		+38	%		75.1		56.6		+33	%
Canada		37.9		39.3		-4	%		39.4		40.7		-3	%

Total		119.3		98.2		+21	%		114.5		97.3		+18	%

Bitumen (MBbls/d)
Canada		45.6		44.3		+3	%		51.0		47.1		+8	%

Gas (MMcf/d)
U.S.		1,934.8		2,067.1		-6	%		1,957.6		2,063.0		-5	%
Canada		448.0		487.2		-8	%		457.9		520.8		-12	%

Total		2,382.8		2,554.3		-7	%		2,415.5		2,583.8		-7	%

NGLs (MBbls/d)
U.S.		118.7		100.8		+18	%		113.8		97.7		+17	%
Canada		10.0		9.2		+8	%		9.9		10.8		-9	%

Total		128.7		110.0		+17	%		123.7		108.5		+14	%

Combined (MBoe/d)
U.S.		522.6		504.2		+4	%		515.2		498.1		+3	%
Canada		168.2		174.0		-3	%		176.6		185.4		-5	%

Total		690.8		678.2		+2	%		691.8		683.5		+1	%


	Three Months Ended September 30,							Nine Months Ended September 30,
	2013 ⁽¹⁾		2012 ⁽¹⁾		Change			2013 ⁽¹⁾		2012 ⁽¹⁾		Change
Oil (per Bbl)
U.S.	$	101.40	$	84.84		+20	%	$	93.94	$	90.79		+3	%
Canada	$	87.25	$	67.53		+29	%	$	72.07	$	69.34		+4	%
Total	$	96.90	$	77.91		+24	%	$	86.41	$	81.82		+6	%
Bitumen (per Bbl)
Canada	$	73.74	$	50.94		+45	%	$	50.93	$	49.26		+3	%
Gas (per Mcf)
U.S.	$	3.08	$	2.37		+30	%	$	3.13	$	2.12		+47	%
Canada	$	2.67	$	2.31		+16	%	$	3.05	$	2.26		+35	%
Total	$	3.00	$	2.36		+27	%	$	3.11	$	2.15		+45	%
NGLs (per Bbl)
U.S.	$	24.36	$	25.07		-3	%	$	25.12	$	29.31		-14	%
Canada	$	48.48	$	46.41		+4	%	$	46.54	$	48.92		-5	%
Total	$	26.23	$	26.86		-2	%	$	26.83	$	31.27		-14	%
Combined (per Boe)
U.S.	$	32.72	$	24.64		+33	%	$	31.12	$	24.86		+25	%
Canada	$	49.65	$	37.14		+34	%	$	41.29	$	36.93		+12	%
Total	$	36.84	$	27.85		+32	%	$	33.71	$	28.14		+20	%

(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, 2013 and 2012.


	Three Months Ended September 30,
	Oil		Bitumen		Gas			NGLs			Total
	(In millions)
2012 sales	$	705	$	207	$	554		$	272		$	1,738
Change due to volumes		151		6		(37	)		46			166
Change due to prices		208		96		141			(8	)		437

2013 sales	$	1,064	$	309	$	658		$	310		$	2,341

Upstream sales increased $166 million in the third quarter of 2013 due to a 16 percent increase in our liquids production, partially offset by a 7 percent decline in our gas production. As a result of continued development of our oil properties, primarily in the Permian Basin, oil sales increased $151 million. Bitumen sales increased $6 million due to development of our Jackfish thermal heavy oil projects in Canada. Additionally, our NGL sales increased $46 million primarily as a result of continued drilling in the liquids-rich gas portions of the Cana-Woodford and Barnett Shales, as well as the Permian Basin. These increases were partially offset by decreases in our dry gas production, which resulted in a $37 million decline in sales.

Production information for our key properties is summarized below:

•

Permian Basin production increased 26 percent compared to the third quarter of 2012 and 7 percent compared to the second quarter of 2013. Oil production accounted for 60 percent of our 82,000 Boe per day produced in the Permian Basin during the third quarter of 2013. The year-over-year increase in total production was driven by a 29 percent increase in oil production.

•

Barnett Shale production decreased 3 percent compared to the third quarter of 2012 and 1 percent compared to the second quarter of 2013. Although total production decreased in both periods, liquids production increased 15 percent compared to the third quarter of 2012 and 4 percent compared to the second quarter of 2013. Liquids production accounted for 26 percent of our 1.4 Bcfe per day produced in the Barnett Shale during the third quarter of 2013.

•

Cana-Woodford Shale production increased 21 percent compared to the third quarter of 2012 and 6 percent compared to the second quarter of 2013. Liquids production accounted for 37 percent of our 342 MMcfe per day produced in Cana during the third quarter of 2013. The year-over-year increase in total production was driven by a 58 percent increase in liquids production.

•

Jackfish production increased 3 percent compared to the third quarter of 2012 and decreased 14 percent compared to the second quarter of 2013. Jackfish production for the third quarter of 2013 was impacted by both a higher royalty rate and a turnaround conducted at Jackfish 2. In June 2013, our Jackfish 1 project reached payout status. Consequently, our Jackfish 1 production is burdened with a higher Canadian provincial government royalty rate that decreases our production net of royalties. Bitumen production accounted for all of our 46,000 Boe per day produced at Jackfish during the third quarter of 2013.

•

Granite Wash production increased 14 percent compared to the third quarter of 2012 and decreased 3 percent compared to the second quarter of 2013. Liquids production accounted for 52 percent of our 21,000 Boe per day produced in the Granite Wash during the third quarter of 2013.

•

Mississippian-Woodford Trend production increased 65 percent compared to the second quarter of 2013 to 9,000 Boe per day. Oil production accounted for 61 percent of our total production in the Mississippian-Woodford Trend during the third quarter of 2013.

•

Rocky Mountain production decreased 5 percent compared to the third quarter of 2012. Although total production was down, oil production increased 34 percent compared to the third quarter of 2012. Liquids production accounted for 33 percent of our 326 MMcfe per day produced in the Rocky Mountains during the third quarter of 2013.

•

Gulf Coast/East Texas production decreased 13 percent compared to the third quarter of 2012. Liquids production accounted for 27 percent of our 317 MMcfe per day produced in Gulf Coast/East Texas during the third quarter of 2013.

•

Lloydminster production decreased 11 percent compared to the third quarter of 2012. Oil production accounted for 94 percent of our 29,000 Boe per day produced at Lloydminster during the third quarter of 2013.

Upstream sales increased $437 million in the third quarter of 2013 primarily due to a 32 percent increase in our realized price without hedges. Oil and bitumen sales were the most significantly impacted with a combined $304 million increase due to prices and realizations. Gas sales increased $141 million largely due to higher North American regional index prices upon which our gas sales are based. NGL sales decreased $8 million as a result of a 2 percent decline in our realized price without hedges. The largest contributors to the higher liquids prices were an increase in the average NYMEX West Texas Intermediate index price and tighter bitumen and heavy oil differentials partially offset by lower NGL prices at the Mont Belvieu, Texas index.

The volume and price changes in the preceding tables caused the following changes to our oil, gas and NGL sales between the nine months ended September 30, 2013 and 2012.


	Nine Months Ended September 30,
	Oil		Bitumen		Gas			NGLs			Total
	(In millions)
2012 sales	$	2,181	$	636	$	1,523		$	930		$	5,270
Change due to volumes		376		50		(104	)		126			448
Change due to prices		143		23		633			(150	)		649

2013 sales	$	2,700	$	709	$	2,052		$	906		$	6,367

Upstream sales increased $448 million in the first nine months of 2013 due to a 14 percent increase in our liquids production, partially offset by a 7 percent decline in our gas production. As a result of continued development of our oil properties, primarily in the Permian Basin, oil sales increased $376 million. Bitumen sales increased $50 million due to development of our Jackfish thermal heavy oil projects in Canada. Additionally, our NGL sales increased $126 million primarily as a result of continued drilling in the liquids-rich gas portions of the Cana-Woodford and Barnett Shales, as well as the Permian Basin. These increases were partially offset by decreases in our dry gas production, which resulted in a $104 million decline in sales.

Upstream sales increased $649 million during the first nine months of 2013 due to a 20 percent increase in our realized price without hedges. Our gas sales increased $633 million due to prices. The change in our gas price was largely due to higher North American regional index prices upon which our gas sales are based. Our liquids sales had a slight increase of $16 million due to higher oil and bitumen sales partially offset by lower NGL sales. The largest contributors to the higher liquids prices were an increase in the average NYMEX West Texas Intermediate index price and tighter bitumen and heavy oil differentials partially offset by lower NGL prices at the Mont Belvieu, Texas index.

Oil, Gas and NGL 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. The following tables provide financial information associated with our commodity derivatives. 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, bitumen, 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,
	2013			2012			2013			2012
	(In millions)
Cash settlements:
Gas derivatives	$	53		$	156		$	89		$	530
Oil derivatives		(60	)		86			1			137
NGL derivatives		—			1			3			1

Total cash settlements		(7	)		243			93			668

Unrealized gains (losses) on fair value changes:
Gas derivatives		(18	)		(207	)		34			(391	)
Oil derivatives		(113	)		(331	)		(217	)		239
NGL derivatives		(3	)		—			(5	)		(1	)

Total unrealized losses on fair value changes		(134	)		(538	)		(188	)		(153	)

Oil, gas and NGL derivatives	$	(141	)	$	(295	)	$	(95	)	$	515


	Three Months Ended September 30, 2013
	Oil (Per Bbl)			Bitumen (Per Bbl)		Gas (Per Mcf)		NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	96.90		$	73.74	$	3.00	$	26.23	$	36.84
Cash settlements of hedges⁽¹⁾		(5.51	)		—		0.24		0.02		(0.12	)

Realized price, including cash settlements	$	91.39		$	73.74	$	3.24	$	26.25	$	36.72


	Three Months Ended September 30, 2012
	Oil (Per Bbl)			Bitumen (Per Bbl)		Gas (Per Mcf)		NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	77.91		$	50.94	$	2.36	$	26.86	$	27.85
Cash settlements of hedges		9.54			—		0.66		0.03		3.89

Realized price, including cash settlements	$	87.45		$	50.94	$	3.02	$	26.89	$	31.74


	Nine Months Ended September 30, 2013
	Oil (Per Bbl)			Bitumen (Per Bbl)		Gas (Per Mcf)		NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	86.41		$	50.93	$	3.11	$	26.83	$	33.71
Cash settlements of hedges⁽¹⁾		0.04			—		0.14		0.08		0.50

Realized price, including cash settlements	$	86.45		$	50.93	$	3.25	$	26.91	$	34.21


	Nine Months Ended September 30, 2012
	Oil (Per Bbl)			Bitumen (Per Bbl)		Gas (Per Mcf)		NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	81.82		$	49.26	$	2.15	$	31.27	$	28.14
Cash settlements of hedges		5.14			—		0.75		0.02		3.56

Realized price, including cash settlements	$	86.96		$	49.26	$	2.90	$	31.29	$	31.70

(1)	Cash settlements of oil hedges include settlements from our Western Canadian Select basis swaps presented in Note 2 to the financial statements included in “Item 1. Consolidated Financial Statements” of this report.

Cash settlements presented in the tables above represent realized gains or losses related to various commodity derivatives. In addition to cash settlements, we also recognize unrealized changes in the fair values of our commodity derivatives in each reporting period. The changes in fair value result from new positions and settlements that occur during each period, as well as the relationships between contract prices and the associated forward curves. Including the cash settlements discussed above, our commodity derivatives incurred a net loss of $141 million and $295 million in the third quarter of 2013 and 2012, respectively. Including the cash settlements discussed above, our commodity derivatives incurred a net loss of $95 million and generated a net gain of $515 million in the first nine months of 2013 and 2012, respectively.

Marketing and Midstream Revenues and Operating Costs and Expenses


	Three Months Ended September 30,							Nine Months Ended September 30,
	2013		2012		Change			2013		2012		Change
	($ in millions)
Revenues	$	520	$	422		+23	%	$	1,511	$	1,136		+33	%
Operating costs and expenses		383		313		+22	%		1,128		847		+33	%

Operating profit	$	137	$	109		+25	%	$	383	$	289		+32	%

During the third quarter and first nine months of 2013, marketing and midstream operating profit increased $28 million and $94 million, respectively, primarily due to higher NGL production and natural gas prices, as well as higher utilization at the fractionator facility in Mont Belvieu, Texas.

Lease Operating Expenses (“LOE”)


	Three Months Ended September 30,							Nine Months Ended September 30,
	2013		2012		Change			2013		2012		Change
LOE ($ in millions):
U.S.	$	333	$	263		+27	%	$	928	$	774		+20	%
Canada		267		250		+7	%		756		766		-1	%

Total	$	600	$	513		+17	%	$	1,684	$	1,540		+9	%

LOE per Boe:
U.S.	$	6.91	$	5.65		+22	%	$	6.60	$	5.67		+16	%
Canada	$	17.32	$	15.65		+11	%	$	15.70	$	15.08		+4	%
Total	$	9.45	$	8.22		+15	%	$	8.92	$	8.22		+8	%

LOE increased $1.23 per Boe and $0.70 per Boe during the third quarter and first nine months of 2013, respectively. The largest contributor to the higher unit cost is related to our liquids production growth, particularly in the Permian Basin and Mississippian in the U.S. Such projects generally require a higher cost to produce per unit than our gas projects. Additionally, we conducted a turnaround at Jackfish 2 in the third quarter of 2013, contributing to higher absolute and unit costs for the quarter. We 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,
	2013		2012		Change			2013		2012		Change
DD&A ($ in millions):
Oil & gas properties	$	611	$	642		-5	%	$	1,833	$	1,870		-2	%
Other properties		80		74		+8	%		236		210		+12	%

Total	$	691	$	716		-3	%	$	2,069	$	2,080		-1	%

DD&A per Boe:
Oil & gas properties	$	9.62	$	10.29		-6	%	$	9.70	$	9.98		-3	%
Other properties		1.25		1.17		+6	%		1.25		1.12		+11	%

Total	$	10.87	$	11.46		-5	%	$	10.95	$	11.10		-1	%

DD&A from our oil and gas properties decreased in both 2013 periods largely as a result of the asset impairment charges recognized in 2012 and 2013. DD&A from our other properties increased in both 2013 periods largely from the construction of our new headquarters in Oklahoma City and natural gas pipeline development in the Cana-Woodford Shale.

General and Administrative Expenses (“G&A”)


	Three Months Ended September 30,									Nine Months Ended September 30,
	2013			2012			Change			2013			2012			Change
	($ in millions)
Gross G&A	$	266		$	281			-5	%	$	836		$	865			-3	%
Capitalized G&A		(88	)		(99	)		-11	%		(271	)		(282	)		-4	%
Reimbursed G&A		(35	)		(32	)		+11	%		(105	)		(89	)		+18	%

Net G&A	$	143		$	150			-5	%	$	460		$	494			-7	%

Net G&A per Boe	$	2.25		$	2.40			-6	%	$	2.44		$	2.64			-8	%

Net G&A and net G&A per Boe decreased in both 2013 periods largely due to lower administrative expenses, as well as higher reimbursements due to increased well counts and reimbursement rates.

Taxes Other Than Income Taxes


	Three Months Ended September 30,									Nine Months Ended September 30,
	2013			2012			Change			2013			2012			Change
	($ in millions)
Production	$	70		$	60			+16	%	$	201		$	164			+22	%
Ad valorem and other		45			44			+4	%		152			142			+7	%

Taxes other than income taxes	$	115		$	104			+11	%	$	353		$	306			+15	%

Percentage of oil, gas and NGL revenue:
Production		2.96	%		3.45	%		-14	%		3.15	%		3.12	%		+1	%
Ad valorem and other		1.93	%		2.50	%		-23	%		2.39	%		2.68	%		-11	%

Total		4.89	%		5.95	%		-18	%		5.54	%		5.80	%		-4	%

Taxes other than income taxes as a percentage of oil, gas and NGL revenue decreased during the third quarter of 2013 and first nine months of 2013 primarily due to ad valorem and other taxes that do not change in direct correlation with oil, gas and NGL revenues as well as higher Canadian revenues with no associated production taxes.

Interest Expense


	Three Months Ended September 30,									Nine Months Ended September 30,
	2013			2012			Change			2013			2012			Change
	($ in millions)
Interest based on debt outstanding	$	116		$	117			-1	%	$	350		$	324			+8	%
Capitalized interest		(15	)		(9	)		+67	%		(38	)		(38	)		+0	%
Other		3			2			+38	%		10			10			-2	%

Interest expense	$	104		$	110			-6	%	$	322		$	296			+9	%

Interest expense decreased in the third quarter of 2013 primarily due to higher capitalized interest. Interest expense increased in the first nine months of 2013 primarily due to higher average debt borrowings, partially offset by lower weighted average interest rates. Borrowings were primarily used to fund capital expenditures in excess of our operating cash flow.

Restructuring Costs


	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(In millions)
Lease obligations and other	$	4	$	—	$	44	$	—
Asset impairments		—		—		6		—

Restructuring costs	$	4	$	—	$	50	$	—

In the nine months ended September 30, 2013, we incurred $50 million of restructuring costs associated with the consolidation of our U.S. personnel into one location in Oklahoma City. This amount includes $25 million related to office space that is subject to non-cancellable operating lease agreements that we ceased using as a part of the office consolidation. We also recognized $6 million of asset impairment charges for leasehold improvements and furniture associated with the office consolidation.

Asset Impairments


	Nine Months Ended September 30, 2013				Nine Months Ended September 30, 2012
	Gross		Net of Taxes		Gross		Net of Taxes
	(In millions)
U.S. oil and gas assets	$	1,110	$	707	$	1,106	$	705
Canada oil and gas assets		843		632		—		—
Midstream assets		7		4		22		14

Total asset impairments	$	1,960	$	1,343	$	1,128	$	719

Oil and Gas Impairments

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

If estimated future cash flows decline due to price decreases or other factors, Devon could incur additional full cost ceiling impairments related to its oil and gas property and equipment.

Midstream Impairments

In the third quarter of 2013 and 2012, we determined that the carrying amounts of certain of our midstream facilities located in south and east Texas were not recoverable from estimated future cash flows due to declining dry natural gas production. Consequently, the assets were written down to their estimated fair values, which were determined using discounted cash flow models.

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,
	2013			2012			2013			2012
Total income tax expense (benefit) (in millions)	$	210		$	(442	)	$	(99	)	$	12

U.S. statutory income tax rate		35	%		(35	%)		(35	%)		35	%
State income taxes		1	%		(1	%)		(3	%)		(1	%)
Taxation on Canadian operations		(5	%)		(1	%)		9	%		(14	%)
Other		2	%		(1	%)		(1	%)		(13	%)

Effective income tax rate		33	%		(38	%)		(30	%)		7	%

In the second quarter of 2013, we repatriated to the United States $2.0 billion of cash from our foreign subsidiaries. In conjunction with the repatriation, we recognized approximately $100 million of current income tax expense. The current expense was entirely offset by the recognition of deferred income tax benefits, which included the reduction of the deferred tax liability previously recognized for unremitted foreign earnings deemed not to be indefinitely reinvested.

Capital Resources, Uses and Liquidity

Sources and Uses of Cash

The following table presents the major changes in our cash and short-term investments.


	Nine Months Ended September 30,
	2013			2012
	(In millions)
Operating cash flow – continuing operations	$	3,999		$	3,787
Capital expenditures		(5,219	)		(6,228	)
Debt activity, net		(1,577	)		1,567
Shareholder distributions		(259	)		(242	)
Divestitures of property and equipment		316			1,468
Other		80			92

Net change in cash and short-term investments	$	(2,660	)	$	444

Cash and short-term investments at end of period	$	4,320		$	7,502

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 2013. Our operating cash flow increased 6 percent during 2013 primarily due to higher commodity prices and production growth, partially offset by higher expenses.

During the first nine months of 2013 and 2012, our operating cash flow funded approximately 80 percent and 60 percent, respectively, of our cash payments for capital expenditures. Leveraging our liquidity, we used cash balances, short-term debt and divestiture proceeds to fund the remainder of our cash-based capital expenditures.

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,
	2013		2012
	(In millions)
Development	$	3,640	$	3,777
Exploration		693		1,568

Subtotal		4,333		5,345
Capitalized G&A and interest		301		308

Total oil and gas		4,634		5,653
Midstream		555		341
Corporate and other		30		234

Total capital expenditures	$	5,219	$	6,228

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 $4.6 billion and $5.7 billion in the first nine months of 2013 and 2012, respectively. The 19 percent decline in exploration and development capital spending in the first nine months of 2013 was primarily due to a decline in new venture acreage acquisitions and utilization of the drilling carries in 2013 from our Sinopec and Sumitomo joint venture arrangements.

Capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas gathering systems and oil pipelines. Our midstream capital expenditures are largely impacted by oil and gas drilling activities. The higher 2013 midstream expenditures primarily relate to expansions of our plants in the Barnett and Cana-Woodford Shales and the Access Pipeline in Canada.

Debt Activity, Net

During the first nine months of 2013, we repatriated $2.0 billion of foreign earnings to the U.S. and repaid outstanding commercial paper borrowings. The repayment resulted in a net repayment of $1.6 billion for the first nine months of 2013. During the first nine months of 2012, we received $2.5 billion from the issuance of long-term debt, the proceeds of which were primarily used to repay outstanding commercial paper and credit facility borrowings. We also utilized short-term borrowings of $967 million to fund capital expenditures in excess of our operating cash flow.

Shareholder distributions

The following table summarizes our common stock dividends (amounts in millions) during the first nine months of 2013 and 2012. In the second quarter of 2013, we increased our quarterly dividend to $0.22 per share.


	Nine Months Ended September 30,
	2013				2012
	Amount		Per Share		Amount		Per Share
Dividends	$	259	$	0.64	$	242	$	0.60

Divestitures of Property and Equipment

During the third quarter of 2013, we sold our controlling interest in certain of our midstream assets and operations located in Wyoming for $148 million, as well as other minor oil and gas assets.

During the second and third quarters of 2012, we closed our joint venture transactions with Sinopec and Sumitomo, respectively. Sinopec paid approximately $900 million in cash and received a 33.3 percent 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 exploration, development and drilling costs associated with these plays. Sumitomo paid approximately $400 million and received a 30 percent 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. At September 30, 2013, Sinopec’s and Sumitomo’s remaining commitment to fund our share of future costs associated with these plays was approximately $1.7 billion.

Liquidity

Historically, our primary sources of capital and liquidity have been our operating cash flow, asset divestiture proceeds 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 2012 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 a portion of our 2013 production. The key terms to our open oil, gas and NGL derivative financial instruments as of September 30, 2013 are presented in Note 2 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.

Credit Availability

As of September 30, 2013, we had $2.9 billion of available capacity under our syndicated, unsecured revolving line of credit (the “Senior Credit Facility”), net of letters of credit outstanding. During the third quarter of 2013, the lenders agreed, effective October 24, 2013, to extend the maturity of the Senior Credit Facility to October 24, 2018. We also have access to $5.0 billion of short-term credit under our commercial paper program. At September 30, 2013, we had $1.6 billion of commercial paper borrowings outstanding.

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, 2013, we were in compliance with this covenant with a debt-to-capitalization ratio of 22.4 percent.

At September 30, 2013, we held approximately $4.3 billion of cash. Included in this total was $4.1 billion of cash held by our foreign subsidiaries. While we are using a portion of our foreign cash to invest in the development and growth of our Canadian business, we did repatriate $2.0 billion to the U.S. in the second quarter of 2013 at a reduced income tax rate. Additionally, as we have progressed through 2013, we have gained additional clarity on our tax attributes and now expect to repatriate an additional $2 billion to the U.S. in a tax-efficient manner around year-end 2013.

Non-GAAP Measures

We make reference to “adjusted earnings,” “adjusted earnings per share” and “adjusted cash flow” in “Overview of 2013 Results” in this Item 2 that are not required by or presented in accordance with GAAP. These non-GAAP measures should not be considered as alternatives to GAAP measures. Adjusted earnings represents net earnings excluding certain non-cash or non-recurring items that are typically excluded by securities analysts in their published estimates of our financial results. Adjusted cash flow represents cash flow from operating activities excluding certain balance sheet changes and non-recurring items that are typically excluded by securities analysts in their published estimates of our financial results. We believe these non-GAAP measures facilitate comparisons of our performance to earnings and cash flow estimates published by securities analysts. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers. The amounts below exclude any amounts from our discontinued operations.

Adjusted Earnings and Adjusted Earnings Per Share

Below are reconciliations of our adjusted earnings and earnings per share to their comparable GAAP measures.


	Three Months Ended September 30,					Nine Months Ended September 30,
	2013		2012			2013			2012
	(In millions, except per share amounts)
Net earnings (loss) (GAAP)	$	429	$	(719	)	$	(227	)	$	172
Adjustments (net of taxes):
Asset impairments		4		719			1,343			719
Oil, gas and NGL derivatives		84		349			121			99
Restructuring costs		3		—			32			—
Interest rate and other financial instruments		6		6			18			15

Adjusted earnings (Non-GAAP)	$	526	$	355		$	1,287		$	1,005

Earnings (loss) per share (GAAP)	$	1.05	$	(1.80	)	$	(0.57	)	$	0.42
Adjustments (net of taxes):
Asset impairments		0.01		1.79			3.32			1.79
Oil, gas and NGL derivatives		0.21		0.87			0.29			0.24
Restructuring costs		0.01		—			0.08			—
Interest rate and other financial instruments		0.01		0.02			0.04			0.03

Adjusted earnings per share (Non-GAAP)	$	1.29	$	0.88		$	3.16		$	2.48

Adjusted Cash Flow

Below is a reconciliation of our adjusted operating cash flow to its comparable GAAP measure.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013		2012
	(In millions)
Operating cash flow (GAAP)	$	1,601		$	1,361		$	3,999	$	3,787
Adjustments (net of taxes):
Changes in assets and liabilities		(18	)		(80	)		40		(94	)

Operating cash flow before balance sheet changes (Non-GAAP)		1,583			1,281			4,039		3,693

Current taxes on cash repatriation		—			—			98		—

Adjusted operating cash flow (Non-GAAP)	$	1,583		$	1,281		$	4,137	$	3,693

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 2013, as well as 2014 and 2015. The key terms to our open oil, gas and NGL derivative financial instruments as of September 30, 2013 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, 2013, 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):
Gas derivatives	$	(214	)	$	208
Oil derivatives	$	(411	)	$	372
NGL derivatives	$	(2	)	$	2

Interest Rate Risk

At September 30, 2013, we had total debt outstanding of $10.1 billion. Of this amount, $8.5 billion bears fixed interest rates averaging 5.4 percent. The remaining $1.6 billion of commercial paper borrowings bears interest rates that averaged 0.27 percent.

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, 2013 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 based in Canadian dollars. The value of the Canadian-dollar cash and intercompany loans increases or decreases from the remeasurement of the cash and loans into the U.S. dollar functional currency. Additionally, at September 30, 2013, 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 and intercompany loans. Based on the amount of the cash and intercompany loans as of September 30, 2013, 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, 2013, 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 2012 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 2012 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 2013.


Period	Total Number of Shares Purchased⁽¹⁾		Average Price Paid per Share
July 1 – July 31		818	$	55.36
August 1 – August 31		1,100	$	57.14
September 1 – September 30		1,103	$	57.87

Total		3,021	$	56.92

(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 2,000 shares of our common stock in the third quarter of 2013, 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

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

Item 6. Exhibits

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


Exhibit Number		Description

10.1		Extension Agreement dated as of September 3, 2013 to the Credit Agreement dated as of October 24, 2012, among Registrant, as U.S. Borrower, Devon NEC Corporation and Devon Canada Corporation, as Canadian Borrowers, Devon Financing Company, L.L.C., consenting lenders and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender with respect to Borrower’s extension of the Maturity Date from October 24, 2017 to October 24, 2018.

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

10.1		Extension Agreement dated as of September 3, 2013 to the Credit Agreement dated as of October 24, 2012, among Registrant, as U.S. Borrower, Devon NEC Corporation and Devon Canada Corporation, as Canadian Borrowers, Devon Financing Company, L.L.C., consenting lenders and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender with respect to Borrower’s extension of the Maturity Date from October 24, 2017 to October 24, 2018.

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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