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 June 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 address: 20 North Broadway, Oklahoma City, Oklahoma 73102-8260

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 July 18, 2012, 404.5 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
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			20
Item 3. Quantitative and Qualitative Disclosures About Market Risk			29
Item 4. Controls and Procedures			30

Part II Other Information
Item 1. Legal Proceedings			31
Item 1A. Risk Factors			31
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			31
Item 3. Defaults Upon Senior Securities			31
Item 4. Mine Safety Disclosures			31
Item 5. Other Information			31
Item 6. Exhibits			32

Signatures			33

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					Six Months
	Ended June 30,					Ended June 30,
	2012			2011		2012			2011
	(Unaudited)
	(In millions, except per share amounts)
Revenues:
Oil, gas and NGL sales	$	1,617		$	2,200	$	3,532		$	4,060
Oil, gas and NGL derivatives		665			416		810			248
Marketing and midstream revenues		277			604		714			1,059

Total revenue		2,559			3,220		5,056			5,367

Expenses and other, net:
Lease operating expenses		513			453		1,027			877
Marketing and midstream operating costs and expenses		209			456		534			789
Depreciation, depletion and amortization		684			550		1,364			1,056
General and administrative expenses		176			135		344			265
Taxes other than income taxes		100			120		202			228
Interest expense		99			85		186			166
Restructuring costs		—			6		—			1
Other, net		44			37		54			27

Total expenses and other, net		1,825			1,842		3,711			3,409

Earnings from continuing operations before income taxes		734			1,378		1,345			1,958
Current income tax expense (benefit)		31			36		49			(53	)
Deferred income tax expense		226			1,158		405			1,438

Earnings from continuing operations		477			184		891			573
Earnings (loss) from discontinued operations, net of tax		—			2,559		(21	)		2,586

Net earnings	$	477		$	2,743	$	870		$	3,159

Basic net earnings per share:
Basic earnings from continuing operations per share	$	1.18		$	0.44	$	2.20		$	1.35
Basic earnings (loss) from discontinued operations per share		—			6.06		(0.05	)		6.09

Basic net earnings per share	$	1.18		$	6.50	$	2.15		$	7.44

Diluted net earnings per share:
Diluted earnings from continuing operations per share	$	1.18		$	0.43	$	2.20		$	1.34
Diluted earnings (loss) from discontinued operations per share		—			6.05		(0.05	)		6.07

Diluted net earnings per share	$	1.18		$	6.48	$	2.15		$	7.41

Comprehensive earnings:
Net earnings	$	477		$	2,743	$	870		$	3,159
Other comprehensive earnings, net of tax:
Foreign currency translation		(171	)		65		(19	)		250
Pension and postretirement plans		5			5		9			11

Other comprehensive earnings, net of tax		(166	)		70		(10	)		261

Comprehensive earnings	$	311		$	2,813	$	860		$	3,420

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months
	Ended June 30,
	2012			2011
	(Unaudited)
	(In millions)
Cash flows from operating activities:
Net earnings	$	870		$	3,159
Loss (earnings) from discontinued operations, net of tax		21			(2,586	)
Adjustments to reconcile earnings from continuing operations to net cash from operating activities:
Depreciation, depletion and amortization		1,364			1,056
Deferred income tax expense		405			1,438
Unrealized change in fair value of financial instruments		(362	)		(74	)
Other noncash charges		114			82
Net decrease (increase) in working capital		22			(89	)
Decrease in long-term other assets		3			45
Decrease in long-term other liabilities		(11	)		(201	)

Cash from operating activities – continuing operations		2,426			2,830
Cash from operating activities – discontinued operations		26			(20	)

Net cash from operating activities		2,452			2,810

Cash flows from investing activities:
Capital expenditures		(4,267	)		(3,720	)
Purchases of short-term investments		(1,471	)		(4,520	)
Redemptions of short-term investments		2,030			1,298
Proceeds from property and equipment divestitures		864			5
Other		14			(32	)

Cash from investing activities—continuing operations		(2,830	)		(6,969	)
Cash from investing activities—discontinued operations		58			3,170

Net cash from investing activities		(2,772	)		(3,799	)

Cash flows from financing activities:
Proceeds from borrowings of long-term debt, net of issuance costs		2,465			—
Net short-term (repayments) borrowings		(1,498	)		2,340
Credit facility borrowings		750			—
Credit facility repayments		(750	)		—
Proceeds from stock option exercises		22			96
Repurchases of common stock		—			(1,290	)
Dividends paid on common stock		(162	)		(140	)
Excess tax benefits related to share-based compensation		1			12

Net cash from financing activities		828			1,018

Effect of exchange rate changes on cash		38			32

Net increase in cash and cash equivalents		546			61

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

Cash and cash equivalents at end of period	$	6,101		$	3,351

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	June 30,			December 31,
	2012			2011
	(Unaudited)
	(In millions, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	6,101		$	5,555
Short-term investments		944			1,503
Accounts receivable		1,005			1,379
Other current assets		1,167			868

Total current assets		9,217			9,305

Property and equipment, at cost:
Oil and gas, based on full cost accounting:
Subject to amortization		64,965			61,696
Not subject to amortization		4,062			3,982

Total oil and gas		69,027			65,678
Other		5,545			5,098

Total property and equipment, at cost		74,572			70,776
Less accumulated depreciation, depletion and amortization		(47,331	)		(46,002	)

Property and equipment, net		27,241			24,774

Goodwill		6,007			6,013
Other long-term assets		1,005			1,025

Total assets	$	43,470		$	41,117

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,510		$	1,471
Revenues and royalties payable		591			678
Short-term debt		2,148			3,811
Other current liabilities		712			778

Total current liabilities		4,961			6,738

Long-term debt		8,455			5,969
Asset retirement obligations		1,942			1,496
Other long-term liabilities		799			721
Deferred income taxes		5,088			4,763
Stockholders’ equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 404.5 million and 404.1 million shares in 2012 and 2011, respectively		40			40
Additional paid-in capital		3,604			3,507
Retained earnings		17,016			16,308
Accumulated other comprehensive earnings		1,565			1,575

Total stockholders’ equity		22,225			21,430

Commitments and contingencies (Note 17)
Total liabilities and stockholders’ equity	$	43,470		$	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)
Six Months Ended June 30, 2012:
Balance as of December 31, 2011		404		$	40		$	3,507		$	16,308		$	1,575		$	—		$	21,430
Net earnings		—			—			—			870			—			—			870
Other comprehensive earnings, net of tax		—			—			—			—			(10	)		—			(10	)
Stock option exercises		1			—			22			—			—			—			22
Common stock repurchased		—			—			—			—			—			(1	)		(1	)
Common stock retired		—			—			(1	)		—			—			1			—
Common stock dividends		—			—			—			(162	)		—			—			(162	)
Share-based compensation		—			—			75			—			—			—			75
Share-based compensation tax benefits		—			—			1			—			—			—			1

Balance as of June 30, 2012		405		$	40		$	3,604		$	17,016		$	1,565		$	—		$	22,225

Six Months Ended June 30, 2011:
Balance as of December 31, 2010		432		$	43		$	5,601		$	11,882		$	1,760		$	(33	)	$	19,253
Net earnings		—			—			—			3,159			—			—			3,159
Other comprehensive earnings, net of tax		—			—			—			—			261			—			261
Stock option exercises		2			—			96			—			—			—			96
Common stock repurchased		—			—			—			—			—			(1,285	)		(1,285	)
Common stock retired		(16	)		(1	)		(1,292	)		—			—			1,293			—
Common stock dividends		—			—			—			(140	)		—			—			(140	)
Share-based compensation		—			—			72			—			—			—			72
Share-based compensation tax benefits		—			—			12			—			—			—			12

Balance as of June 30, 2011		418		$	42		$	4,489		$	14,901		$	2,021		$	(25	)	$	21,428

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 June 30, 2012 and Devon’s results of operations and cash flows for the three-month and six-month periods ended June 30, 2012 and 2011.

Accounts Payable

Included in accounts payable at June 30, 2012, are liabilities of $99 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.

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 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 June 30, 2012, Devon holds $107 million 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.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Commodity Derivatives

As of June 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)
Q3-Q4 2012		54,000	$	105.90		74,000	$	89.71	$	123.09		19,500	$	95.00
Q1-Q4 2013		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

As of June 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)
Q3-Q4 2012		573,370	$	4.04		991,685	$	3.71	$	4.40		487,500	$	6.00
Q1-Q4 2013		150,000	$	4.50		—		—		—		—		—
Q1-Q4 2014		—		—		—		—		—		150,000	$	5.00

Interest Rate Derivatives

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


Notional	Fixed Rate Received			Variable Rate Paid	Expiration
(In millions)
$ 100		1.90	%	Federal funds rate		August 2012
750		3.88	%	Federal funds rate		July 2013
$ 850		3.65	%

Foreign Exchange Derivatives

As of June 30, 2012, Devon had the following open foreign exchange rate derivative position:

Forward Contract

Currency

Contract
Type

CAD
Notional

Fixed Rate
Received

Expiration

(In millions)

(CAD-USD)

Canadian Dollar

Sell

755

0.9708

September 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.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In millions)
Cash settlements:
Commodity derivatives	$	267		$	59		$	425		$	145
Interest rate derivatives		(11	)		5			(1	)		21
Foreign currency derivatives		20			—			9			—

Total cash settlements		276			64			433			166

Unrealized gains (losses):
Commodity derivatives		398			357			385			103
Interest rate derivatives		(5	)		(30	)		(15	)		(29	)
Foreign currency derivatives		(9	)		—			(8	)		—

Total unrealized gains		384			327			362			74

Net gain recognized on comprehensive statements of earnings	$	660		$	391		$	795		$	240

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


	Balance Sheet Caption	June 30, 2012		December 31, 2011
		(In millions)
Asset derivatives:
Commodity derivatives	Other current assets	$	759	$	611
Commodity derivatives	Other long-term assets		209		17
Interest rate derivatives	Other current assets		28		30
Interest rate derivatives	Other long-term assets		9		22

Total asset derivatives		$	1,005	$	680

Liability derivatives:
Commodity derivatives	Other current liabilities	$	10	$	82
Commodity derivatives	Other long-term liabilities		27		—
Foreign exchange derivatives	Other current liabilities		8		—

Total liability derivatives		$	45	$	82

3. Restructuring Costs

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

The schedule below summarizes restructuring costs presented in the accompanying comprehensive statements of earnings. Restructuring costs related to Devon’s discontinued operations totaled $(8) million and $(2) million in the second quarter and first six months of June 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 six months ended June 30, 2012.


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(In millions)
Lease obligations	$	—	$	2	$	—	$	(2	)
Asset impairments		—		2		—		2
Other		—		2		—		1

Restructuring costs	$	—	$	6	$	—	$	1

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 $10 million at June 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	)		(1	)		(10	)
Cash severance settled		(5	)		—			(5	)

Balance as of June 30, 2012	$	15		$	15		$	30

Balance as of December 31, 2010	$	31		$	51		$	82
Lease obligations settled		(1	)		(7	)		(8	)
Cash severance settled		(16	)		—			(16	)
Other		—			(1	)		(1	)

Balance as of June 30, 2011	$	14		$	43		$	57

4. Other, net

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In millions)
Accretion of asset retirement obligations	$	28		$	23		$	55		$	46
Interest rate swaps – cash settlements		11			(5	)		1			(21	)
Interest rate swaps – unrealized fair value changes		5			30			15			29
Interest income		(9	)		(4	)		(16	)		(6	)
Other		9			(7	)		(1	)		(21	)

Other, net	$	44		$	37		$	54		$	27

5. Earnings Per Share

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


	Earnings			Common Shares			Earnings per Share
	(In millions, except per share amounts)
Three Months Ended June 30, 2012:
Earnings from continuing operations	$	477			404
Attributable to participating securities		(6	)		(4	)

Basic earnings per share		471			400		$	1.18
Dilutive effect of potential common shares issuable		—			—

Diluted earnings per share	$	471			400		$	1.18

Three Months Ended June 30, 2011:
Earnings from continuing operations	$	184			422
Attributable to participating securities		(2	)		(5	)

Basic earnings per share		182			417		$	0.44
Dilutive effect of potential common shares issuable		—			2

Diluted earnings per share	$	182			419		$	0.43

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


	Earnings			Common Shares			Earnings per Share
	(In millions, except per share amounts)
Six Months Ended June 30, 2012:
Earnings from continuing operations	$	891			404
Attributable to participating securities		(10	)		(4	)

Basic earnings per share		881			400		$	2.20
Dilutive effect of potential common shares issuable		—			1

Diluted earnings per share	$	881			401		$	2.20

Six Months Ended June 30, 2011:
Earnings from continuing operations	$	573			425
Attributable to participating securities		(6	)		(5	)

Basic earnings per share		567			420		$	1.35
Dilutive effect of potential common shares issuable		—			2

Diluted earnings per share	$	567			422		$	1.34

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 six-month periods ended June 30, 2012, 8.9 million shares and 6.7 million shares, respectively, were excluded from the diluted earnings per share calculations. During the three-month and six-month periods ended June 30, 2011, 3.1 million shares 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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In millions)
Foreign currency translation:
Beginning accumulated foreign currency translation	$	1,954		$	2,178		$	1,802		$	1,993
Change in cumulative translation adjustment		(179	)		67			(20	)		262
Income tax expense		8			(2	)		1			(12	)

Ending accumulated foreign currency translation		1,783			2,243			1,783			2,243

Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits		(223	)		(227	)		(227	)		(233	)
Recognition of net actuarial loss and prior service cost in earnings		7			8			13			17
Income tax expense		(2	)		(3	)		(4	)		(6	)

Ending accumulated pension and postretirement benefits		(218	)		(222	)		(218	)		(222	)

Accumulated other comprehensive earnings, net of tax	$	1,565		$	2,021		$	1,565		$	2,021

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

7. Supplemental Information to Statements of Cash Flows


	Six Months Ended June 30,
	2012			2011
	(In millions)
Net change in working capital:
Decrease (increase) in accounts receivable	$	384		$	(100	)
Increase in other current assets		(191	)		(41	)
Increase in accounts payable		13			9
(Decrease) increase in revenues and royalties payable		(139	)		130
Decrease in other current liabilities		(45	)		(87	)

Net decrease (increase) in working capital	$	22		$	(89	)

Supplementary cash flow data – total operations:
Interest paid (net of capitalized interest)	$	169		$	160
Income taxes paid (received)	$	88		$	(125	)

8. Short-Term Investments

The components of short-term investments include the following:


	June 30, 2012		December 31, 2011
	(In millions)
Canadian treasury, agency and provincial securities	$	644	$	1,155
U.S. treasuries		300		201
Other		—		147

Short-term investments	$	944	$	1,503

9. Accounts Receivable

The components of accounts receivable include the following:


	June 30, 2012			December 31, 2011
	(In millions)
Oil, gas and NGL sales	$	668		$	928
Joint interest billings		199			247
Marketing and midstream revenues		105			174
Other		47			39

Gross accounts receivable		1,019			1,388
Allowance for doubtful accounts		(14	)		(9	)

Net accounts receivable	$	1,005		$	1,379

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

10. Other Current Assets

The components of other current assets include the following:


	June 30, 2012		December 31, 2011
	(In millions)
Derivative financial instruments	$	787	$	641
Inventories		220		102
Income taxes receivable		40		35
Current assets held for sale		—		21
Other		120		69

Other current assets	$	1,167	$	868

11. Property and Equipment

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.

12. Other Current Liabilities

The components of other current liabilities include the following:


	June 30, 2012		December 31, 2011
	(In millions)
Deferred income taxes payable	$	253	$	172
Accrued interest		142		131
Other		317		475

Other current liabilities	$	712	$	778

13. 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 June 30, 2012, Devon had $2.1 billion of outstanding commercial paper at an average rate of 0.40 percent.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Credit Lines

On April 7, 2012, $0.46 billion of Devon’s Senior Credit Facility matured and was not extended. After the maturity, Devon maintains a $2.19 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). As of June 30, 2012, 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 less than 65 percent. As of June 30, 2012, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 23.8 percent.

14. Asset Retirement Obligations

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


	Six Months Ended June 30,
	2012			2011
	(In millions)
Asset retirement obligations as of beginning of period	$	1,563		$	1,497
Liabilities incurred		33			23
Liabilities settled		(34	)		(39	)
Revision of estimated obligation		399			16
Accretion expense on discounted obligation		55			46
Foreign currency translation adjustment		(10	)		28

Asset retirement obligations as of end of period		2,006			1,571
Less current portion		64			72

Asset retirement obligations, long-term	$	1,942		$	1,499

During the first quarter of 2012, Devon recognized revisions to its asset retirement obligations totaling $399 million. The primary factor contributing to this revision was an overall increase in abandonment cost estimates for certain of its production operations facilities.

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 June 30,						Six Months Ended June 30,						Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011			2012			2011			2012		2011			2012			2011
	(In millions)
Service cost	$	10		$	9		$	21		$	18		$	—	$	1		$	—		$	1
Interest cost		15			15			30			30			—		—			1			1
Expected return on plan assets		(16	)		(11	)		(32	)		(21	)		—		—			—			—
Amortization of prior service cost		1			1			2			2			—		(1	)		(1	)		(1	)
Net actuarial loss		6			8			12			16			—		—			—			—

Net periodic benefit cost	$	16		$	22		$	33		$	45		$	—	$	—		$	—		$	1

16. 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.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Dividends

Devon paid common stock dividends of $162 million and $140 million in the first six 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.

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 agreements 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.

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 June 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.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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.

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 payables and accrued expenses included in the accompanying balance sheets approximated fair value at June 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)
June 30, 2012 assets (liabilities):
Cash equivalents	$	5,841		$	5,841		$	850	$	4,991		$	—
Short-term investments	$	944		$	944		$	300	$	644		$	—
Long-term investments	$	69		$	69		$	—	$	—		$	69
Commodity derivatives	$	968		$	968		$	—	$	968		$	—
Commodity derivatives	$	(37	)	$	(37	)	$	—	$	(37	)	$	—
Interest rate derivatives	$	37		$	37		$	—	$	37		$	—
Foreign exchange derivatives	$	(8	)	$	(8	)	$	—	$	(8	)	$	—
Debt	$	(10,603	)	$	(12,260	)	$	—	$	(12,241	)	$	(19	)

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 quotes from brokers, which approximate the carrying value.

Commodity, interest rate and foreign exchange derivatives — The fair values of commodity and interest rate derivatives are estimated using internal discounted cash flow calculations based upon forward curves and quotes obtained from brokers for contracts with similar terms or quotes 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.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 the AAA credit rating of the securities, the probability of full repayment of the securities considering the U.S. government guarantees substantially all of the underlying student loans, the collection of all accrued interest to date and continued receipts of principal at par. 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 June 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.

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


	Six Months Ended June 30,
	2012			2011
	(In millions)
Long-term investments balance at beginning of period	$	84		$	94
Redemptions of principal		(15	)		(1	)

Long-term investments balance at end of period	$	69		$	93


	Six Months Ended June 30,
	2012			2011
	(In millions)
Debt balance at beginning of period	$	(85	)	$	(144	)
Foreign exchange translation adjustment		(1	)		(4	)
Accretion of promissory note		—			(2	)
Redemptions of principal		67			46

Debt balance at end of period	$	(19	)	$	(104	)

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

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 June 30, 2012.


	Balance Sheet Caption	December 31, 2011
		(In millions)
Other current assets	Other current assets	$	21
Property and equipment, net	Other long-term assets	$	132

Accounts payable	Other current liabilities	$	20
Other current liabilities	Other current liabilities	$	28

20. Segment Information

Devon manages its operations through distinct operating segments, or divisions, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. divisions into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian division 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 June 30, 2012:
Oil, gas and NGL sales	$	1,014	$	603		$	1,617
Oil, gas and NGL derivatives	$	665	$	—		$	665
Marketing and midstream revenues	$	250	$	27		$	277
Depreciation, depletion and amortization	$	439	$	245		$	684
Interest expense	$	84	$	15		$	99
Earnings from continuing operations before income taxes	$	727	$	7		$	734
Income tax expense (benefit)	$	259	$	(2	)	$	257
Earnings from continuing operations	$	468	$	9		$	477
Capital expenditures	$	1,985	$	384		$	2,369

Three Months Ended June 30, 2011:
Oil, gas and NGL sales	$	1,438	$	762		$	2,200
Oil, gas and NGL derivatives	$	416	$	—		$	416
Marketing and midstream revenues	$	554	$	50		$	604
Depreciation, depletion and amortization	$	350	$	200		$	550
Interest expense	$	40	$	45		$	85
Earnings from continuing operations before income taxes	$	1,148	$	230		$	1,378
Income tax expense	$	1,135	$	59		$	1,194
Earnings from continuing operations	$	13	$	171		$	184
Capital expenditures	$	1,499	$	334		$	1,833

Six Months Ended June 30, 2012:
Oil, gas and NGL sales	$	2,250	$	1,282		$	3,532
Oil, gas and NGL derivatives	$	810	$	—		$	810
Marketing and midstream revenues	$	649	$	65		$	714
Depreciation, depletion and amortization	$	870	$	494		$	1,364
Interest expense	$	155	$	31		$	186
Earnings from continuing operations before income taxes	$	1,260	$	85		$	1,345
Income tax expense	$	444	$	10		$	454
Earnings from continuing operations	$	816	$	75		$	891
Property and equipment, net	$	18,818	$	8,423		$	27,241
Total assets	$	24,916	$	18,554		$	43,470
Capital expenditures (2)	$	3,531	$	1,183		$	4,714

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


	U.S.		Canada		Total
	(In millions)
Six Months Ended June 30, 2011:
Oil, gas and NGL sales	$	2,650	$	1,410	$	4,060
Oil, gas and NGL derivatives	$	248	$	—	$	248
Marketing and midstream revenues	$	977	$	82	$	1,059
Depreciation, depletion and amortization	$	668	$	388	$	1,056
Interest expense	$	77	$	89	$	166
Earnings from continuing operations before income taxes	$	1,586	$	372	$	1,958
Income tax expense	$	1,290	$	95	$	1,385
Earnings from continuing operations	$	296	$	277	$	573
Property and equipment, net	$	14,472	$	7,955	$	22,427
Total continuing assets (1)	$	19,972	$	18,435	$	38,407
Capital expenditures	$	2,751	$	880	$	3,631

(1)	Amounts in the table above do not include assets held for sale related to Devon’s discontinued operations, which totaled $130 million at June 30, 2011. There were no assets held for sale at June 30, 2012.

(2)	Capital expenditures for the first six months of 2012 presented above include the $399 million revision to Devon’s asset retirement obligations presented in Note 14. Of the $399 million, $110 million relates to the U.S. and $289 million relates to Canada.

21. Subsequent Event

In August 2012, Devon announced a transaction with Sumitomo Corporation that Devon expects to close in the third quarter of 2012. Under the agreement, Sumitomo will pay $1.365 billion, including $340 million at closing and $1.025 billion toward Devon’s share of future drilling costs, and will receive a 30% interest in the Cline and Midland-Wolfcamp shale plays.

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 six month periods ended June 30, 2012, compared to the three-month and six-month periods ended June 30, 2011, and in our financial condition and liquidity since December 31, 2011. For information regarding our critical accounting policies and estimates, see our 2011 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Overview of 2012 Results

During the second quarter and first six months of 2012, our continuing operations generated net earnings of $477 million, or $1.18 per diluted share, and $891 million, or $2.20 per diluted share, for the respective periods. This compares to net earnings of $184 million, or $0.43 per diluted share, and $573 million, or $1.34 per diluted share for the second quarter and first six months of 2011, respectively. Key measures of our financial performance are summarized below:

•

Total production rose by 3% and 6% during the second quarter and first six months of 2012, respectively. Our production growth was driven by oil production, which climbed 26% to 149 MBbls per day in the second quarter of 2012.

•

The combined realized price without hedges for oil, gas and NGLs decreased 29% to $26.18 per Boe and 19% to $28.28 per Boe in the second quarter and first six months of 2012, respectively.

•

Oil, gas and NGL derivatives generated a net gain of $665 million and $810 million in the second quarter and first six months of 2012, respectively, and generated a net gain of $416 million and $248 million in the second quarter and first six months of 2011, respectively. Included in these amounts were cash receipts of $267 million and $425 million in the second quarter and first six months of 2012, respectively, and $59 million and $145 million in the second quarter and first six months of 2011, respectively.

•

Marketing and midstream operating profit decreased 54% to $68 million and 33% to $180 million in the second quarter and first six months of 2012, respectively.

•

Per unit operating costs increased 10% to $8.30 per Boe and 9% to $8.23 per Boe in the second quarter and first six months of 2012, respectively.

•

Operating cash flow from continuing operations decreased 14% to $2.4 billion.

•

Capital spending totaled approximately $4.3 billion in the first six months of 2012.

Second Quarter Operational Developments

•

Permian Basin oil production increased 24 percent over the second quarter of 2011. Oil production accounted for nearly 60 percent of the 59,000 Boe per day produced in the Permian Basin during the second quarter.

•

We brought 19 Bone Spring wells online in the second quarter. Initial daily production averaged 680 Boe per day.

•

Net production from our Jackfish oil sands projects averaged a record 51,000 barrels per day in the second quarter. This represents a 63 percent increase in oil production over the year-ago quarter. Construction of our third Jackfish oil sands project is now approximately 40 percent complete. Plant startup is targeted for late 2014.

•

We filed a regulatory application in June for the first phase of our Pike, an oil sands project with gross production capacity of 105,000 barrels per day. Pike is located immediately adjacent to the company’s highly successful Jackfish projects.

•

In April, we closed our $2.5 billion joint venture agreement with Sinopec. The transaction included an approximate $900 million cash payment at closing, recovering significantly more than 100 percent of our initial land and exploration costs. The remaining $1.6 billion drilling-carry will fund 80 percent of the joint venture’s capital requirements over the next few years.

•

We continued to increase our exposure in the Mississippian oil play by adding 400,000 net acres in Oklahoma. In total, we now have 545,000 net acres in this emerging light-oil resource play.

•

We brought six Granite Wash wells online in the second quarter. Initial production from these wells averaged 1,270 Boe per day.

•

Net production from the Cana-Woodford Shale averaged 280 million cubic feet of natural gas equivalent per day in the second quarter of 2012. Liquids production increased 59 percent year-over-year, accounting for 30 percent of total Cana-Woodford production.

Results of Operations

Production, Prices and Revenues


	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Change⁽¹⁾			2012		2011		Change⁽¹⁾
Oil (MBbls/d)
U.S.		56		46		+21	%		55		44		+27	%
Canada		93		72		+29	%		90		72		+25	%

Total		149		118		+26	%		145		116		+26	%

Gas (MMcf/d)
U.S.		2,050		2,029		+1	%		2,061		1,996		+3	%
Canada		519		612		-15	%		538		591		-9	%

Total		2,569		2,641		-3	%		2,599		2,587		0	%

NGLs (MBbls/d)
U.S.		90		92		-2	%		96		88		+9	%
Canada		12		10		+22	%		12		10		+19	%

Total		102		102		0	%		108		98		+10	%

Combined (MBoe/d)⁽²⁾
U.S.		488		476		+2	%		495		465		+7	%
Canada		191		184		+4	%		191		180		+6	%

Total		679		660		+3	%		686		645		+6	%

(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 June 30,							Six Months Ended June 30,
	2012⁽¹⁾		2011⁽¹⁾		Change			2012⁽¹⁾		2011⁽¹⁾		Change
Oil (per Bbl)
U.S.	$	88.74	$	98.28		-10	%	$	93.98	$	93.84		0	%
Canada	$	54.88	$	73.65		-25	%	$	58.47	$	67.29		-13	%
Total	$	67.67	$	83.31		-19	%	$	72.02	$	77.32		-7	%
Gas (per Mcf)
U.S.	$	1.72	$	3.72		-54	%	$	2.00	$	3.61		-45	%
Canada	$	1.91	$	4.08		-53	%	$	2.24	$	4.05		-45	%
Total	$	1.76	$	3.80		-54	%	$	2.05	$	3.71		-45	%
NGLs (per Bbl)
U.S.	$	29.50	$	40.43		-27	%	$	31.56	$	38.04		-17	%
Canada	$	45.87	$	58.80		-22	%	$	49.92	$	56.49		-12	%
Total	$	31.42	$	42.20		-26	%	$	33.55	$	39.90		-16	%
Combined (per Boe)
U.S.	$	22.86	$	33.19		-31	%	$	24.98	$	31.53		-21	%
Canada	$	34.66	$	45.55		-24	%	$	36.83	$	43.23		-15	%
Total	$	26.18	$	36.63		-29	%	$	28.28	$	34.80		-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 June 30, 2012 and 2011.


	Oil			Gas			NGLs			Total
	(In millions)
2011 sales	$	897		$	913		$	390		$	2,200
Changes due to volumes		229			(25	)		2			206
Changes due to prices		(211	)		(478	)		(100	)		(789	)

2012 sales	$	915		$	410		$	292		$	1,617

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


	Oil			Gas			NGLs			Total
	(In millions)
2011 sales	$	1,616		$	1,737		$	707		$	4,060
Changes due to volumes		428			17			76			521
Changes due to prices		(139	)		(785	)		(125	)		(1,049	)

2012 sales	$	1,905		$	969		$	658		$	3,532

Oil Sales

A 26 percent increase in production during the second quarter and first six months of 2012 caused oil sales to increase by $229 million and $428 million, respectively. The increases were primarily due to continued development of our Jackfish thermal heavy oil projects and Permian Basin properties.

Oil sales decreased $211 million and $139 million during the second quarter and first six months of 2012, respectively, as a result of 19 percent and 7 percent decreases, respectively, in our realized price without hedges. The largest contributor to the decreases in each period to our realized price was the widening differential to the NYMEX West Texas Intermediate index price attributable to our Canadian oil production.

Gas Sales

Gas sales decreased $478 million and $785 million in the second quarter and first six months of 2012, respectively, as a result of 54 percent and 45 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 $25 million during the second quarter due to a 3 percent decrease in production and increased $17 million during the first six months of 2012 as a result of a slight increase 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 other operating areas, particularly those that produce dry gas.

NGL Sales

NGL sales decreased $100 million and $125 million in the second quarter and first six months of 2012, respectively, as a result of 26 percent and 16 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 price.

NGL sales increased $2 million and $76 million in the second quarter and first six months of 2012, respectively, as a result of production increases in each period. 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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In millions)
Cash settlements:
Gas derivatives	$	211		$	74		$	374		$	165
Oil derivatives		57			(16	)		51			(21	)
NGL derivatives		(1	)		1			—			1

Total cash settlements		267			59			425			145

Unrealized gains (losses) on fair value changes:
Gas derivatives		(280	)		49			(184	)		(8	)
Oil derivatives		679			308			570			110
NGL derivatives		(1	)		—			(1	)		1

Total unrealized gains on fair value changes		398			357			385			103

Oil, gas and NGL derivatives	$	665		$	416		$	810		$	248


	Three Months Ended June 30, 2012
	Oil (Per Bbl)			Gas (Per Mcf)			NGLs (Per Bbl)			Total (Per Boe)
Realized price without hedges	$	67.67		$	1.76		$	31.42		$	26.18
Cash settlements of hedges		4.17			0.90			—			4.33

Realized price, including cash settlements	$	71.84		$	2.66		$	31.42		$	30.51


	Three Months Ended June 30, 2011
	Oil (Per Bbl)			Gas (Per Mcf)			NGLs (Per Bbl)			Total (Per Boe)
Realized price without hedges	$	83.31		$	3.80		$	42.20		$	36.63
Cash settlements of hedges		(1.49	)		0.31			0.05			0.99

Realized price, including cash settlements	$	81.82		$	4.11		$	42.25		$	37.62


	Six Months Ended June 30, 2012
	Oil (Per Bbl)			Gas (Per Mcf)			NGLs (Per Bbl)			Total (Per Boe)
Realized price without hedges	$	72.02		$	2.05		$	33.55		$	28.28
Cash settlements of hedges		1.92			0.79			0.01			3.40

Realized price, including cash settlements	$	73.94		$	2.84		$	33.56		$	31.68


	Six Months Ended June 30, 2011
	Oil (Per Bbl)			Gas (Per Mcf)			NGLs (Per Bbl)			Total (Per Boe)
Realized price without hedges	$	77.32		$	3.71		$	39.90		$	34.80
Cash settlements of hedges		(1.00	)		0.35			0.06			1.25

Realized price, including cash settlements	$	76.32		$	4.06		$	39.96		$	36.05

A summary of our outstanding commodity derivatives is included 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 these various instruments.

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 generated a net gain of $665 million and $416 million in the second quarter of 2012 and 2011, respectively. Including the cash settlements discussed above, our oil, gas and NGL derivatives generated a net gain of $810 million and $248 million in the first six months of 2012 and 2011, respectively.

Marketing and Midstream Revenues and Operating Costs and Expenses


	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Change⁽¹⁾			2012		2011		Change⁽¹⁾
	($ in millions)
Marketing and midstream:
Revenues	$	277	$	604		-54	%	$	714	$	1,059		-33	%
Operating costs and expenses		209		456		-54	%		534		789		-32	%

Operating profit	$	68	$	148		-54	%	$	180	$	270		-33	%

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

During the second quarter and first six months of 2012, marketing and midstream operating profit decreased $80 million and $90 million, respectively, primarily due to lower gas and NGL prices.

Lease Operating Expenses (“LOE”)


	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Change⁽¹⁾			2012		2011		Change⁽¹⁾
LOE ($ in millions):
U.S.	$	259	$	224		+15	%	$	511	$	432		+18	%
Canada		254		229		+11	%		516		445		+16	%

Total	$	513	$	453		+13	%	$	1,027	$	877		+17	%

LOE per Boe:
U.S.	$	5.84	$	5.18		+13	%	$	5.68	$	5.15		+10	%
Canada	$	14.61	$	13.71		+7	%	$	14.83	$	13.63		+9	%
Total	$	8.30	$	7.55		+10	%	$	8.23	$	7.52		+9	%

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

LOE increased $0.75 per Boe and $0.71 per Boe during the second quarter and first six 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 June 30,							Six Months Ended June 30,
	2012		2011		Change⁽¹⁾			2012		2011		Change⁽¹⁾
DD&A ($ in millions):
Oil & gas properties	$	612	$	485		+26	%	$	1,228	$	927		+32	%
Other properties		72		65		+12	%		136		129		+6	%

Total	$	684	$	550		+24	%	$	1,364	$	1,056		+29	%

DD&A per Boe:
Oil & gas properties	$	9.89	$	8.08		+22	%	$	9.83	$	7.95		+24	%
Other properties		1.18		1.08		+9	%		1.09		1.10		-1	%

Total	$	11.07	$	9.16		21	%	$	10.92	$	9.05		21	%

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

Oil and gas property DD&A increased during the second quarter and first six 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 second quarter of 2011.

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 the present value of estimated future net cash flows from proved oil and gas reserves, discounted 10 percent, 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. If natural gas prices remain depressed, we expect to incur full-cost ceiling write-downs, or additional DD&A, related to our U.S. oil and gas properties in the third quarter of 2012.

General and Administrative Expenses (“G&A”)


	Three Months Ended June 30,									Six Months Ended June 30,
	2012			2011			Change⁽¹⁾			2012			2011			Change⁽¹⁾
	($ in millions)
Gross G&A	$	296		$	245			+21	%	$	584		$	483			+21	%
Capitalized G&A		(92	)		(81	)		+14	%		(183	)		(162	)		+13	%
Reimbursed G&A		(28	)		(29	)		-3	%		(57	)		(56	)		+1	%

Net G&A	$	176		$	135			+30	%	$	344		$	265			+30	%

Net G&A per Boe	$	2.85		$	2.26			+26	%	$	2.76		$	2.27			+21	%

(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 June 30,									Six Months Ended June 30,
	2012			2011			Change⁽¹⁾			2012			2011			Change⁽¹⁾
	($ in millions)
Production	$	51		$	68			-25	%	$	104		$	124			-16	%
Ad valorem and other		49			52			-5	%		98			104			-5	%

Taxes other than income taxes	$	100		$	120			-16	%	$	202		$	228			-11	%

Percentage of oil, gas and NGL revenue:
Production		3.16	%		3.10	%		+2	%		2.95	%		3.06	%		-4	%
Ad valorem and other		3.04	%		2.34	%		+29	%		2.78	%		2.55	%		+9	%

Total		6.20	%		5.44	%		+14	%		5.73	%		5.61	%		+2	%

(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 June 30,									Six Months Ended June 30,
	2012			2011			Change⁽¹⁾			2012			2011			Change⁽¹⁾
	($ in millions)
Interest based on debt outstanding	$	108		$	100			+9	%	$	207		$	198			+5	%
Capitalized interest		(13	)		(17	)		-28	%		(29	)		(37	)		-22	%
Other		4			2			+18	%		8			5			+46	%

Interest expense	$	99		$	85			+17	%	$	186		$	166			+12	%

Interest based on debt outstanding increased during the second quarter and first six months of 2012 as a result of additional debt borrowings. Borrowings were primarily used to fund capital expenditures in excess of our operating cash flow.

Other, net


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In millions)
Accretion of asset retirement obligations	$	28		$	23		$	55		$	46
Interest rate swaps – cash settlements		11			(5	)		1			(21	)
Interest rate swaps – unrealized fair value changes		5			30			15			29
Interest income		(9	)		(4	)		(16	)		(6	)
Other		9			(7	)		(1	)		(21	)

Other, net	$	44		$	37		$	54		$	27

Income Taxes

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Total income tax expense (in millions)	$	257		$	1,194		$	454		$	1,385

U.S. statutory income tax rate		35	%		35	%		35	%		35	%
State income taxes		1	%		1	%		1	%		1	%
Taxation on Canadian operations		(1	%)		(2	%)		(2	%)		(2	%)
Assumed repatriations		—			54	%		—			38	%
Other		—			(1	%)		—			(1	%)

Effective income tax expense rate		35	%		87	%		34	%		71	%

Earnings (Loss) From Discontinued Operations


	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012			2011
	(In millions)
Operating earnings	$	—	$	12		$	—		$	42
Gain (loss) on sale of oil and gas properties		—		2,546			(16	)		2,546

Earnings (loss) before income taxes		—		2,558			(16	)		2,588
Income tax expense (benefit)		—		(1	)		5			2

Earnings (loss) from discontinued operations	$	—	$	2,559		$	(21	)	$	2,586

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.


	Six Months Ended June 30,
	2012			2011
	(In millions)
Operating cash flow – continuing operations	$	2,426		$	2,830
Debt activity, net		967			2,340
Divestitures of property and equipment		935			3,256
Short-term investment activity, net		559			(3,222	)
Capital expenditures		(4,267	)		(3,720	)
Common stock repurchases and dividends		(162	)		(1,430	)
Other		88			7

Net increase in cash and cash equivalents	$	546		$	61

Cash and cash equivalents at end of period	$	6,101		$	3,351

Short-term investments at end of period	$	944		$	3,367

Operating Cash Flow – Continuing Operations

Net cash provided by operating activities (“operating cash flow”) continued to be a significant source of capital and liquidity in the first six months of 2012. Our operating cash flow decreased approximately 14 percent during 2012 primarily due to lower commodity prices and higher expenses, partially offset by additional cash flow from our production growth.

In 2011, we completed our offshore divestiture program that was announced in November 2009. This program generated approximately $8 billion in after-tax proceeds, which provided us with substantial liquidity to invest in our North America property base. During the first six months of 2012 and 2011, our operating cash flow funded approximately 60 percent and 75 percent, respectively, of our cash payments for capital expenditures. Leveraging our liquidity, we largely 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 six 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.

During the first six months of 2011, we utilized commercial paper borrowings of $2.3 billion to fund capital expenditures and common share repurchases.

Divestitures of Property and Equipment

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 required to fund 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.

Short-term Investments

During the first six months of 2012 and 2011, we had net short-term investment redemptions totaling $0.6 billion and net purchases totaling $3.2 billion, respectively. The 2012 redemptions were used to supplement our operating cash flow to fund our capital expenditures. The 2011 activity was primarily related to our investment of a portion of the International offshore divestiture proceeds into marketable securities.

Capital Expenditures

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


	Six Months Ended June 30,
	2012		2011
	(In millions)
U.S.	$	3,055	$	2,375
Canada		807		936

Total oil and gas		3,862		3,311
Midstream		206		151
Other		199		258

Total continuing operations	$	4,267	$	3,720

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 $3.9 billion and $3.3 billion in the first six months of 2012 and 2011, respectively. The 17% growth in exploration and development capital spending in the first six 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.

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 second 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 six months of 2012 and 2011.


	2012						2011
	Amount		Shares		Per Share		Amount		Shares		Per Share
Repurchases	$	—		—	$	—	$	1,290		15.3	$	84.48
Dividends	$	162		N/A	$	0.20	$	140		N/A	$	0.165

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 oil, gas and NGL derivative financial instruments as of June 30, 2012 are presented in Note 2 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.

Credit Availability

As of July 18, 2012, we had $2.1 billion of available capacity under our syndicated, unsecured Senior Credit Facility and $2.6 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, of no more than 65 percent. As of June 30, 2012, we were in compliance with this covenant with a debt-to-capitalization ratio of 23.8 percent.

Although we ended the second quarter of 2012 with approximately $7.0 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. In the first half of 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 $1.0 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 six months of 2012, as well as 2013 and 2014. The key terms to all our oil, gas and NGL derivative financial instruments as of June 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 June 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	$	(380	)	$	397
Gas derivatives	$	(103	)	$	100

Interest Rate Risk

At June 30, 2012, we had total debt outstanding of $10.6 billion. Our long-term debt of $8.5 billion bears fixed interest rates averaging 5.4 percent. The remaining $2.1 billion of commercial paper borrowings bears interest at fixed rates which averaged 0.40 percent. Such borrowings typically have maturity rates between 1 and 90 days.

As of June 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 June 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 June 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 June 30, 2012, we held foreign currency exchange forward contracts to hedge exposures to fluctuations in exchange rates on the Canadian-dollar cash. 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 June 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 June 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

On April 1, 2012, we implemented SAP, a company-wide enterprise resource planning software system. SAP replaced certain of our accounting and other systems that are used to record and report our financial results and associated disclosures. In conjunction with the SAP implementation, we modified the design, operation and documentation of our internal controls over financial reporting.

Except as described above, there were no other 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 second quarter of 2012.


Period	Total Number of Shares Purchased (1)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
							(In millions)
April 1 – April 30		2,007	$	69.95		—	$	—
May 1 – May 31		5,971	$	62.47		—	$	—
June 1 – June 30		1,744	$	57.76		—	$	—

Total		9,722	$	63.17		—

(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 6,600 shares of our common stock in the second 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.


				DEVON ENERGY CORPORATION

Date: August 1, 2012				/s/ Jeffrey A. Agosta
				Jeffrey A. Agosta
				Executive Vice President and Chief Financial Officer

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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