Devon Energy (DVN) 10-Q 2009 Q2 Quarterly report

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, 2009

or

o 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 (State of other jurisdiction of incorporation or organization)	73-1567067 (I.R.S. Employer identification No.)
20 North Broadway, Oklahoma City, Oklahoma (Address of principal executive offices)	73102-8260 (Zip code)

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

Former name, former 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. Yesþ Noo

     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). Yesþ Noo

     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. (Check one):

Large accelerated filerþ Accelerated filero Non-accelerated filero
(Do not check if a smaller reporting company) Smaller reporting companyo

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

     On July 31, 2009, 443.8 million shares of common stock were outstanding.

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2

DEVON ENERGY CORPORATION

FORM 10-Q

For the Quarterly Period Ended June 30, 2009

INDEX

DEFINITIONS	4
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS	5
PART I. Financial Information
Item 1. Consolidated Financial Statements	6
Consolidated Balance Sheets	6
Consolidated Statements of Operations	7
Consolidated Statements of Comprehensive Income (Loss)	8
Consolidated Statements of Stockholders’ Equity	9
Consolidated Statements of Cash Flows	10
Notes to Consolidated Financial Statements	11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3. Quantitative and Qualitative Disclosures About Market Risk	43
Item 4. Controls and Procedures	44
PART II. Other Information
Item 4. Submission of Matters to a Vote of Security Holders	46
Item 6. Exhibits	47
SIGNATURES	48
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

3

DEFINITIONS

As used in this document:

     “Bbl” or “Bbls” means barrel or barrels.

     “Bcf” means billion cubic feet.

     “Boe” means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.

     “Btu” means British thermal units, a measure of heating value.

     “Canada” means the operations of Devon encompassing oil and gas properties located in Canada.

     “Domestic” means the operations of Devon encompassing oil and gas properties in the onshore continental United States and the offshore Gulf of Mexico.

     “Federal Funds Rate” means the interest rate at which depository institutions lend balances at the Federal Reserve to other depository institutions overnight.

     “Inside FERC” refers to the publicationInside F.E.R.C.’s Gas Market Report.

     “International” means the operations of Devon encompassing oil and gas properties that lie outside the United States and Canada.

     “LIBOR” means London Interbank Offered Rate.

     “Mcf” means thousand cubic feet.

     “MMBbls” means million barrels.

     “MMBoe” means million Boe.

     “MMBtu” means million Btu.

     “NGL” or “NGLs” means natural gas liquids.

     “NYMEX” means New York Mercantile Exchange.

     “Oil” includes crude oil and condensate.

     “SEC” means United States Securities and Exchange Commission.

     “U.S. Offshore” means the operations of Devon encompassing oil and gas properties in the Gulf of Mexico.

     “U.S. Onshore” means the operations of Devon encompassing oil and gas properties in the continental United States.

4

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

     This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare the December 31, 2008 reserve reports and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:

• energy markets, including the supply and demand for oil, gas, NGLs and other products or services, and the prices of oil, gas, NGLs, including regional pricing differentials, and other products or services;

• production levels, including Canadian production subject to government royalties, which fluctuate with prices and production, and international production governed by payout agreements, which affect reported production;

• reserve levels;

• competitive conditions;

• technology;

• the availability of capital resources within the securities or capital markets and related risks such as general credit, liquidity, market and interest-rate risks;

• capital expenditure and other contractual obligations;

• currency exchange rates;

• the weather;

• inflation;

• the availability of goods and services;

• drilling risks;

• future processing volumes and pipeline throughput;

• general economic conditions, whether internationally, nationally or in the jurisdictions in which we or our subsidiaries conduct business;

• legislative or regulatory changes, including retroactive royalty or production tax regimes, changes in environmental regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations;

• terrorism;

• occurrence of property acquisitions or divestitures; and

• other factors disclosed in our 2008 Annual Report on Form 10-K under “Item 2. Properties — Proved Reserves and Estimated Future Net Revenue,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

     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. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.

5

PART I. Financial Information

Item 1. Consolidated Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	June 30,		December 31,
	2009		2008
	(Unaudited)
	(In millions, except
	share data)
ASSETS
Current assets:
Cash and cash equivalents	$	648	$	379
Accounts receivable		1,318		1,412
Income taxes receivable		27		334
Derivative financial instruments, at fair value		226		282
Other current assets		358		277
Total current assets		2,577		2,684
Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($4,298 and $4,551 excluded from amortization in 2009 and 2008, respectively)		59,086		55,664
Less accumulated depreciation, depletion and amortization		40,999		32,683
Property and equipment, net		18,087		22,981
Goodwill		5,710		5,579
Other long-term assets, including $180 million and $199 million at fair value in 2009 and 2008, respectively		683		664
Total assets	$	27,057	$	31,908
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable — trade	$	1,074	$	1,825
Revenues and royalties due to others		377		496
Short-term debt		1,508		180
Current portion of asset retirement obligations, at fair value		175		138
Accrued expenses and other current liabilities		358		496
Total current liabilities		3,492		3,135
Long-term debt		5,849		5,661
Asset retirement obligations, at fair value		1,411		1,347
Other long-term liabilities		1,036		1,026
Deferred income taxes		1,587		3,679
Stockholders’ equity:
Common stock of $0.10 par value. Authorized 1.0 billion shares; issued 443.9 million and 443.7 million shares in 2009 and 2008, respectively		44		44
Additional paid-in capital		6,363		6,257
Retained earnings		6,589		10,376
Accumulated other comprehensive income		686		383
Total stockholders’ equity		13,682		17,060
Commitments and contingencies (Note 11)
Total liabilities and stockholders’ equity	$	27,057	$	31,908

See accompanying notes to consolidated financial statements.

6

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(Unaudited)
	(In millions, except per share amounts)
Revenues:
Oil sales	$	808		$	1,455		$	1,262		$	2,705
Gas sales		740			2,210			1,653			3,840
NGL sales		170			379			306			707
Net gain (loss) on oil and gas derivative financial instruments		13			(1,215	)		167			(2,003	)
Marketing and midstream revenues		359			719			730			1,274
Total revenues		2,090			3,548			4,118			6,523
Expenses and other income, net:
Lease operating expenses		510			537			1,034			1,043
Production taxes		47			176			89			310
Marketing and midstream operating costs and expenses		234			515			463			897
Depreciation, depletion and amortization of oil and gas properties		494			762			1,093			1,499
Depreciation and amortization of non-oil and gas properties		74			62			144			119
Accretion of asset retirement obligations		24			22			48			44
General and administrative expenses		182			180			348			328
Interest expense		90			90			173			192
Change in fair value of other financial instruments		(10	)		(40	)		(15	)		(24	)
Reduction of carrying value of oil and gas properties		—			—			6,516			—
Other expense (income), net		20			(17	)		27			(38	)
Total expenses and other income, net		1,665			2,287			9,920			4,370
Earnings (loss) from continuing operations before income taxes		425			1,261			(5,802	)		2,153
Income tax expense (benefit):
Current		51			414			53			517
Deferred		77			253			(2,194	)		391
Total income tax expense (benefit)		128			667			(2,141	)		908
Earnings (loss) from continuing operations		297			594			(3,661	)		1,245
Discontinued operations:
Earnings from discontinued operations before income taxes		17			851			16			1,040
Income tax expense		—			144			—			235
Earnings from discontinued operations		17			707			16			805
Net earnings (loss)		314			1,301			(3,645	)		2,050
Preferred stock dividends		—			3			—			5
Net earnings (loss) applicable to common stockholders	$	314		$	1,298		$	(3,645	)	$	2,045
Basic net earnings (loss) per share:
Earnings (loss) from continuing operations	$	0.67		$	1.33		$	(8.25	)	$	2.80
Earnings from discontinued operations		0.04			1.58			0.04			1.80
Net earnings (loss)	$	0.71		$	2.91		$	(8.21	)	$	4.60
Diluted net earnings (loss) per share:
Earnings (loss) from continuing operations	$	0.66		$	1.31		$	(8.25	)	$	2.76
Earnings from discontinued operations		0.04			1.57			0.04			1.79
Net earnings (loss)	$	0.70		$	2.88		$	(8.21	)	$	4.55

See accompanying notes to consolidated financial statements.

7

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
				(Unaudited)
				(In millions)
Net earnings (loss)	$	314		$	1,301		$	(3,645	)	$	2,050
Foreign currency translation:
Change in cumulative translation adjustment		467			88			306			(294	)
Income tax (expense) benefit		(30	)		(3	)		(19	)		14
Total		437			85			287			(280	)
Pension and postretirement benefit plans:
Recognition of net actuarial loss and prior service cost in net earnings (loss)		12			4			24			8
Income tax expense		(4	)		(1	)		(8	)		(2	)
Total		8			3			16			6
Other comprehensive earnings (loss), net of tax		445			88			303			(274	)
Comprehensive income (loss)	$	759		$	1,389		$	(3,342	)	$	1,776

See accompanying notes to consolidated financial statements.

8

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

																Accumulated
										Additional						Other						Total
	Preferred			Common Stock						Paid-In			Retained			Comprehensive			Treasury			Stockholders'
	Stock			Shares			Amount			Capital			Earnings			Income			Stock			Equity
	(Unaudited)
	(In millions)
Six Months Ended June 30, 2009:
Balance as of December 31, 2008					444		$	44		$	6,257		$	10,376		$	383		$	—		$	17,060
Net loss					—			—			—			(3,645	)		—			—			(3,645	)
Other comprehensive income					—			—			—			—			303			—			303
Stock option exercises					—			—			9			—			—			—			9
Common stock repurchased					—			—			—			—			—			(11	)		(11	)
Common stock retired					—			—			(11	)		—			—			11			—
Common stock dividends					—			—			—			(142	)		—			—			(142	)
Share-based compensation					—			—			103			—			—			—			103
Share-based compensation tax benefits					—			—			5			—			—			—			5
Balance as of June 30, 2009					444		$	44		$	6,363		$	6,589		$	686		$	—		$	13,682
Six Months Ended June 30, 2008:
Balance as of December 31, 2007	$	1			444		$	44		$	6,743		$	12,813		$	2,405		$	—		$	22,006
Net earnings		—			—			—			—			2,050			—			—			2,050
Other comprehensive loss		—			—			—			—			—			(274	)		—			(274	)
Stock option exercises		—			4			1			107			—			—			(4	)		104
Common stock repurchased		—			—			—			—			—			—			(316	)		(316	)
Common stock retired		—			(3	)		(1	)		(269	)		—			—			270			—
Redemption of preferred stock		(1	)		—			—			(149	)		—			—			—			(150	)
Common stock dividends		—			—			—			—			(141	)		—			—			(141	)
Preferred stock dividends		—			—			—			—			(5	)		—			—			(5	)
Share-based compensation		—			—			—			104			—			—			—			104
Share-based compensation tax benefits		—			—			—			55			—			—			—			55
Balance as of June 30, 2008	$	—			445		$	44		$	6,591		$	14,717		$	2,131		$	(50	)	$	23,433

See accompanying notes to consolidated financial statements.

9

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months
	Ended June 30,
	2009			2008
	(Unaudited)
	(In millions)
Cash flows from operating activities:
Net (loss) earnings	$	(3,645	)	$	2,050
Earnings from discontinued operations, net of tax		(16	)		(805	)
Adjustments to reconcile (loss) earnings from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization		1,237			1,618
Deferred income tax (benefit) expense		(2,194	)		391
Reduction of carrying value of oil and gas properties		6,516			—
Net unrealized loss on oil and gas derivative financial instruments		65			1,692
Other noncash charges		134			122
Net increase in working capital		(89	)		(132	)
Decrease (increase) in long-term other assets		43			(37	)
Increase in long-term other liabilities		19			181
Cash provided by operating activities — continuing operations		2,070			5,080
Cash provided by operating activities — discontinued operations		7			106
Net cash provided by operating activities		2,077			5,186
Cash flows from investing activities:
Proceeds from sales of property and equipment		2			108
Capital expenditures		(3,201	)		(3,870	)
Purchases of short-term investments		—			(50	)
Sales of long-term and short-term investments		4			295
Cash used in investing activities — continuing operations		(3,195	)		(3,517	)
Cash provided by investing activities — discontinued operations		2			1,712
Net cash used in investing activities		(3,193	)		(1,805	)
Cash flows from financing activities:
Proceeds from borrowings of long-term debt, net of issuance costs		1,187			—
Credit facility repayments		—			(3,070	)
Credit facility borrowings		—			1,620
Net commercial paper borrowings (repayments)		325			(1,004	)
Debt repayments		(1	)		(47	)
Redemption of preferred stock		—			(150	)
Proceeds from stock option exercises		9			104
Repurchases of common stock		—			(252	)
Dividends paid on common and preferred stock		(142	)		(146	)
Excess tax benefits related to share-based compensation		5			55
Net cash provided by (used in) financing activities		1,383			(2,890	)
Effect of exchange rate changes on cash		5			(19	)
Net increase in cash and cash equivalents		272			472
Cash and cash equivalents at beginning of period (including cash related to assets held for sale)		384			1,373
Cash and cash equivalents at end of period (including cash related to assets held for sale)	$	656		$	1,845

See accompanying notes to consolidated financial statements.

10

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

     The accompanying unaudited consolidated 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 consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes included in Devon’s 2008 Annual Report on Form 10-K.

     The unaudited interim consolidated 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, 2009 and Devon’s results of operations and cash flows for the three-month and six-month periods ended June 30, 2009 and 2008. To prepare the accompanying financial statements and notes, Devon’s management evaluated events or transactions that occurred subsequent to June 30, 2009 and before August 5, 2009, which was the date these financial statements were issued.

Recently Issued Accounting Standards Not Yet Adopted

     In December 2008, the FASB issued Staff Position No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” Staff Position 132(R)-1 amends FASB Statement No. 132 (revised 2003), Employers’ Disclosures about Pensions and Other Postretirement Benefits, to require additional disclosures about the types of assets and associated risks in an employer’s defined benefit pension or other postretirement plan. Staff Position 132(R)-1 is effective for fiscal years ending after December 15, 2009. Devon is evaluating the impact the adoption of Staff Position 132(R)-1 will have on its financial statement disclosures. However, Devon’s adoption of Staff Position 132(R)-1 will not affect its current accounting for its pension and postretirement plans.

Modernization of Oil and Gas Reporting

     In December 2008, the SEC adopted revisions to its required oil and gas reporting disclosures. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. In the three decades that have passed since adoption of these disclosure items, there have been significant changes in the oil and gas industry. The amendments are designed to modernize and update the oil and gas disclosure requirements to align them with current practices and changes in technology. In addition, the amendments concurrently align the SEC’s full cost accounting rules with the revised disclosures. The revised disclosure requirements must be incorporated in registration statements filed on or after January 1, 2010, and annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. A company may not apply the new rules to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required.

     The following amendments have the greatest likelihood of affecting Devon’s reserve disclosures, including the comparability of its reserves disclosures with those of its peer companies:

• Pricing mechanism for oil and gas reserves estimation— The SEC’s current rules require proved reserve estimates to be calculated using prices as of the end of the period and held constant over the life of the reserves. Price changes can be made only to the extent provided by contractual arrangements. The revised rules require reserve estimates to be calculated using a 12-month average price. The 12-month average price will also be used for purposes of calculating the full cost ceiling limitations. Price changes can still be incorporated to the extent defined by contractual arrangements. The use of a 12-month average price rather than a single-day price is expected to reduce the impact on reserve estimates and the full cost ceiling limitations due to short-term volatility and seasonality of prices.

• Reasonable certainty— The SEC’s current definition of “proved oil and gas reserves” incorporate certain specific concepts such as “lowest known hydrocarbons,” which limits the ability to claim proved reserves in the absence of information on fluid contacts in a well penetration, notwithstanding the existence of other engineering and geoscientific evidence. The revised rules amend the definition to permit the use of new reliable technologies to establish the reasonable certainty of proved reserves. This revision also includes provisions for establishing levels of lowest known hydrocarbons and highest known oil through reliable technology other than well penetrations.

11

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

	The revised rules also amend the definition of proved oil and gas reserves to include reserves located beyond development spacing areas that are immediately adjacent to developed spacing areas if economic producibility can be established with reasonable certainty. These revisions are designed to permit the use of reliable technologies to establish proved reserves in lieu of requiring companies to use specific tests. In addition, they establish a uniform standard of reasonable certainty that applies to all proved reserves, regardless of location or distance from producing wells.
	Because the revised rules generally expand the definition of proved reserves, Devon expects its proved reserve estimates will increase upon adoption of the revised rules. However, Devon is not able to estimate the magnitude of the potential increase at this time.
•	Unproved reserves— The SEC’s current rules prohibit disclosure of reserve estimates other than proved in documents filed with the SEC. The revised rules permit disclosure of probable and possible reserves and provide definitions of probable reserves and possible reserves. Disclosure of probable and possible reserves is optional. However, such disclosures must meet specific requirements. Disclosures of probable or possible reserves must provide the same level of geographic detail as proved reserves and must state whether the reserves are developed or undeveloped. Probable and possible reserve disclosures must also provide the relative uncertainty associated with these classifications of reserves estimations. Devon has not yet determined whether it will disclose its probable and possible reserves in documents filed with the SEC.

2. Accounts Receivable

     The components of accounts receivable include the following:

	June 30, 2009			December 31, 2008
	(In millions)
Oil, gas and NGL revenues	$	719		$	789
Joint interest billings		207			263
Marketing and midstream revenues		127			153
Production tax credits		210			170
Other		61			42
Gross accounts receivable		1,324			1,417
Allowance for doubtful accounts		(6	)		(5	)
Net accounts receivable	$	1,318		$	1,412

3. Derivative Financial Instruments

     Devon periodically enters into commodity and interest rate derivative financial instruments. These instruments are used to manage the inherent uncertainty of future revenues due to oil and gas price volatility and to manage Devon’s exposure to interest rate volatility. Also, during the first eight months of 2008, Devon was subject to an embedded option derivative related to the fair value of its debentures exchangeable into shares of Chevron common stock.

12

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

     The following table presents the fair values of derivative assets and liabilities included in the accompanying balance sheets. None of Devon’s derivative instruments included in the table have been designated as hedging instruments.

	Balance Sheet Caption	Asset		Liability
		(In millions)
June 30, 2009:
Gas price collars	Derivative financial instruments, current	$	190	$	—
Interest rate swaps	Derivative financial instruments, current		36		—
Interest rate swaps	Long-term other assets		62		—
Total derivatives		$	288	$	—
December 31, 2008:
Gas price collars	Derivative financial instruments, current	$	255	$	—
Interest rate swaps	Derivative financial instruments, current		27		—
Interest rate swaps	Long-term other assets		77		—
Total derivatives		$	359	$	—

     The following table presents the cash settlements and unrealized gains and losses on fair value changes included in the accompanying statements of operations associated with these derivative financial instruments. None of Devon’s derivative instruments included in the table have been designated as hedging instruments.

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
				(In millions)
Cash settlements receipts (payments):
Gas price collars (1)	$	114		$	(150	)	$	232		$	(150	)
Gas price swaps (1)		—			(153	)		—			(161	)
Interest rate swaps (2)		5			—			21			—
Total cash settlements		119			(303	)		253			(311	)
Unrealized (losses) gains:
Gas price collars (1)		(101	)		(620	)		(65	)		(1,028	)
Gas price swaps (1)		—			(247	)		—			(618	)
Oil price collars (1)		—			(45	)		—			(46	)
Interest rate swaps (2)		5			—			(6	)		—
Embedded option (2)		—			(155	)		—			(58	)
Total unrealized losses		(96	)		(1,067	)		(71	)		(1,750	)
Net gain (loss) recognized on statement of operations	$	23		$	(1,370	)	$	182		$	(2,061	)

(1)	Cash settlements and unrealized gains and losses on fair value changes associated with Devon’s gas price collars, gas price swaps and oil price collars have been recorded in the “Net gain (loss) on oil and gas derivate financial instruments” line item in the accompanying statements of operations.
(2)	Cash settlements and unrealized gains and losses on fair value changes associated with Devon’s interest rate swaps and embedded option have been recorded in the “Change in fair value of other financial instruments” line item in the accompanying statements of operations.

13

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

4. Other Current Assets

     The components of other current assets include the following:

	June 30, 2009		December 31, 2008
	(In millions)
Inventories	$	275	$	197
Prepaid assets		43		49
Other		40		31
Other current assets	$	358	$	277

5. Property and Equipment

     In the first quarter of 2009, Devon reduced the carrying values of certain of its oil and gas properties due to full cost ceiling limitations. These reductions are discussed in Note 13.

6. Goodwill

     During the first six months of 2009, Devon’s goodwill increased $131 million. This increase related to Devon’s Canadian goodwill and was entirely due to foreign currency translation.

7. Debt

5.625% Senior Notes Due January 15, 2014 and 6.30% Senior Notes Due January 15, 2019

     In January 2009, Devon issued $500 million of 5.625% senior unsecured notes due January 15, 2014 and $700 million of 6.30% senior unsecured notes due January 15, 2019. The net proceeds received of $1.187 billion, after discounts and issuance costs, were used primarily to repay Devon’s $1.0 billion of outstanding commercial paper as of December 31, 2008.

Credit Lines

     Devon has two syndicated, unsecured revolving lines of credit that can be accessed to provide liquidity as needed. The following schedule summarizes the capacity of Devon’s credit facilities by maturity date, as well as its available capacity as of June 30, 2009.

Description	Amount
	(In millions)
Senior Credit Facility maturities:
April 7, 2012	$	500
April 7, 2013		2,150
Senior Credit Facility total capacity		2,650
Short-Term Facility total capacity — November 3, 2009 maturity		700
Total credit facility capacity		3,350
Less:
Outstanding credit facility borrowings		—
Outstanding commercial paper borrowings		1,330
Outstanding letters of credit		111
Total available capacity	$	1,909

     The credit facilities contain only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization to be less than 65%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the consolidated financial statements. Also, total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling impairments or goodwill

14

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

impairments. As of June 30, 2009, Devon was in compliance with this covenant. Devon’s debt-to-capitalization ratio at June 30, 2009, as calculated pursuant to the terms of the agreement, was 21.8%.

Commercial Paper

     Subsequent to the $1.0 billion commercial paper repayment in January 2009, Devon utilized additional commercial paper borrowings of $1.3 billion to fund capital expenditure payments in excess of cash generated by operating activities during the first half of 2009. As of June 30, 2009, Devon’s average borrowing rate on its $1.3 billion of commercial paper debt was 0.48%.

8. Asset Retirement Obligations

     The following is a summary of the changes in Devon’s asset retirement obligations (“ARO”) for the first six months of 2009 and 2008.

	Six Months
	Ended June 30,
	2009			2008
	(In millions)
ARO as of beginning of period	$	1,485		$	1,318
Liabilities incurred		43			29
Liabilities settled		(43	)		(40	)
Revision of estimated obligation		23			162
Accretion expense on discounted obligation		48			44
Foreign currency translation adjustment		30			(20	)
ARO as of end of period		1,586			1,493
Less current portion		175			63
ARO, long-term	$	1,411		$	1,430

9. Retirement Plans

Net Periodic Benefit Cost and Other Comprehensive Income

     The following table presents the components of net periodic benefit cost and other comprehensive income for Devon’s pension and other post retirement benefit plans for the three-month and six-month periods ended June 30, 2009 and 2008.

	Pension Benefits												Other Postretirement Benefits
	Three Months Ended						Six Months Ended						Three Months Ended				Six Months Ended
	June 30,						June 30,						June 30,				June 30,
	2009			2008			2009			2008			2009		2008		2009		2008
										(In millions)
Net periodic benefit cost:
Service cost	$	11		$	10		$	22		$	20		$	—	$	—	$	—	$	—
Interest cost		14			14			28			28			1		2		2		4
Expected return on plan assets		(9	)		(13	)		(18	)		(26	)		—		—		—		—
Amortization of prior service cost		1			—			2			—			—		—		—		—
Net actuarial loss		11			4			22			8			—		—		—		—
Net periodic benefit cost		28			15			56			30			1		2		2		4
Other comprehensive income:
Recognition of prior service cost in net periodic benefit cost		(1	)		—			(2	)		—			—		—		—		—
Recognition of net actuarial loss in net periodic benefit cost		(11	)		(4	)		(22	)		(8	)		—		—		—		—
Total recognized	$	16		$	11		$	32		$	22		$	1	$	2	$	2	$	4

15

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

     Devon previously disclosed in its 2008 Annual Report on Form 10-K that it expected to contribute up to approximately $183 million to its defined benefit pension plans in 2009 and $5 million to its defined benefit postretirement plans in 2009. Devon has revised its estimate of 2009 defined benefit pension plan contributions to $55 million. As of June 30, 2009, Devon has contributed $15 million to its defined benefit pension plans and $2 million to its defined benefit postretirement plans.

10. Stockholders’ Equity

Stock Repurchases

     During the first six months of 2008, Devon repurchased 2.8 million common shares for $302 million, or $106.01 per share, under programs approved by its Board of Directors. The 2.8 million common shares include 2.0 million shares that were repurchased under Devon’s 50 million share repurchase program and 0.8 million shares that were repurchased under Devon’s ongoing, annual stock repurchase program. No such repurchases were made during the first six months of 2009.

Dividends

     Devon paid common stock dividends of $142 million and $141 million (quarterly rates of $0.16 per share) in the first six months of 2009 and 2008, respectively. Devon paid preferred stock dividends of $5 million in the first half of 2008. Devon redeemed all 1.5 million outstanding shares of its preferred stock on June 20, 2008.

11. 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 that 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. However, actual amounts could differ materially from management’s estimate.

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 (“CERCLA”) and similar state statutes. In response to liabilities associated with these activities, accruals have been established when reasonable estimates are possible. Such accruals primarily include estimated costs associated with remediation. Devon has not used discounting in determining its accrued liabilities for environmental remediation, and no material claims for possible recovery from third party insurers or other parties related to environmental costs have been recognized in Devon’s consolidated financial statements. Devon adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates must be adjusted to reflect new information.

     Certain of Devon’s subsidiaries are involved in matters in which it has been alleged that such subsidiaries are potentially responsible parties (“PRPs”) under CERCLA or similar state legislation with respect to various waste disposal areas owned or operated by third parties. As of June 30, 2009, Devon’s balance sheet included $1 million of accrued liabilities, reflected in other long-term liabilities, related to these and other environmental remediation liabilities. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the current accruals recognized for such environmental remediation activities. With respect to the sites in which Devon subsidiaries are PRPs, Devon’s conclusion is based in large part on (i) Devon’s participation in consent decrees with both other PRPs and the Environmental Protection Agency, which provide for performing the scope of work required for remediation and contain covenants not to sue as protection to the PRPs, (ii) participation in groups as ade minimisPRP,and (iii) the availability of other defenses to liability. As a result, Devon’s monetary exposure is not expected to be material.

16

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Royalty Matters

     Numerous natural gas producers and related parties, including Devon, have been named in various lawsuits alleging violation of the federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper deductions, improper measurement techniques and transactions with affiliates, which resulted in underpayment of royalties in connection with natural gas and NGLs produced and sold from federal and Indian owned or controlled lands. The principal suit in which Devon is a defendant isUnited States ex rel. Wright v. Chevron USA, Inc. et al.(the “Wright case”). The suit was originally filed in August 1996 in the United States District Court for the Eastern District of Texas, but was consolidated in October 2000 with other suits for pre-trial proceedings in the United States District Court for the District of Wyoming. On July 10, 2003, the District of Wyoming remanded the Wright case back to the Eastern District of Texas to resume proceedings. On April 12, 2007, the court entered a trial plan and scheduling order in which the case will proceed in phases. Two phases have been scheduled to date. The first phase was scheduled to begin in August 2008, but the defendant settled prior to trial. The second phase was scheduled to begin in February 2009, but the defendants settled prior to trial. Devon was not included in the groups of defendants selected for these first two phases. Devon believes that it has acted reasonably, has legitimate and strong defenses to all allegations in the suit, and has paid royalties in good faith. Devon does not currently believe that it is subject to material exposure with respect to this lawsuit and, therefore, no liability related to this lawsuit has been recorded.

     In 1995, the United States Congress passed the Deep Water Royalty Relief Act. The intent of this legislation was to encourage deep water exploration in the Gulf of Mexico by providing relief from the obligation to pay royalties on certain federal leases. Deep water leases issued in certain years by the Minerals Management Service (the “MMS”) have contained price thresholds, such that if the market prices for oil or gas exceeded the thresholds for a given year, royalty relief would not be granted for that year. Deep water leases issued in 1998 and 1999 did not include price thresholds.

     The U.S. House of Representatives in January 2007 passed legislation that would have required companies to renegotiate the 1998 and 1999 leases as a condition of securing future federal leases. This legislation was not passed by the U.S. Senate. However, Congress may consider similar legislation in the future. In October 2007, a federal district court ruled in favor of a plaintiff who had challenged the legality of including price thresholds in deep water leases. Additionally, in January 2009 a federal appellate court upheld this district court ruling. This judgment is subject to further appeals.

     As of June 30, 2009, Devon had $82 million accrued for potential royalties on various deep water leases. Due to the uncertainty of this issue caused by the favorable federal court decisions and potential Congressional actions, Devon has ceased accruing additional royalties on its affected leases. Devon will continue to monitor developments and adjust its accruals as necessary.

Other Matters

     Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon’s knowledge as of the date these financial statements were issued, neither Devon nor its property is subject to any material pending legal proceedings.

17

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

12. Fair Value Measurements

     Certain of Devon’s assets and liabilities are reported at fair value in the accompanying balance sheets. Such assets and liabilities include amounts for both financial and nonfinancial instruments. The following tables provide carrying value and fair value measurement information for such assets and liabilities as of June 30, 2009 and December 31, 2008.

	As of June 30, 2009
							Fair Value Measurements Using:
							Quoted			Significant
							Prices in			Other			Significant
							Active			Observable			Unobservable
	Carrying			Total Fair			Markets			Inputs			Inputs
	Amount			Value			(Level 1)			(Level 2)			(Level 3)
	(In millions)
Financial Assets (Liabilities):
Long-term investments	$	118		$	118		$	—		$	—		$	118
Gas price collars	$	190		$	190		$	—		$	190		$	—
Interest rate swaps	$	98		$	98		$	—		$	98		$	—
Debt	$	(7,357	)	$	(8,000	)	$	(1,330	)	$	(6,670	)	$	—
Asset retirement obligations	$	(1,586	)	$	(1,586	)	$	—		$	—		$	(1,586	)

	As of December 31, 2008
							Fair Value Measurements Using:
							Quoted			Significant
							Prices in			Other			Significant
							Active			Observable			Unobservable
	Carrying			Total Fair			Markets			Inputs			Inputs
	Amount			Value			(Level 1)			(Level 2)			(Level 3)
	(In millions)
Financial Assets (Liabilities):
Long-term investments	$	122		$	122		$	—		$	—		$	122
Gas price collars	$	255		$	255		$	—		$	255		$	—
Interest rate swaps	$	104		$	104		$	—		$	104		$	—
Debt	$	(5,841	)	$	(6,106	)	$	(1,005	)	$	(5,101	)	$	—
Asset retirement obligations	$	(1,485	)	$	(1,485	)	$	—		$	—		$	(1,485	)

     A summary of the changes in Devon’s asset retirement obligations during the first half of 2009 is included in Note 8. Included below is a summary of the changes in Devon’s other Level 3 fair value measurements during the first half of 2009 (in millions).

Beginning balance	$	122
Redemptions of principal		(4	)
Ending balance	$	118

13. Reduction of Carrying Value of Oil and Gas Properties

     In the first quarter of 2009, Devon reduced the carrying values of certain of its oil and gas properties due to full cost ceiling limitations. A summary of these reductions and additional discussion is provided below.

	March 31, 2009
			Net of
	Gross		Taxes
	(In millions)
United States	$	6,408	$	4,085
Brazil		103		103
Russia		5		2
Total	$	6,516	$	4,190

18

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

     The United States reduction resulted primarily from a significant decrease in the full cost ceiling during the first three months of 2009. The lower ceiling value in the United States largely resulted from the continued effects of declining natural gas prices subsequent to December 31, 2008.

     Although oil prices improved subsequent to December 31, 2008, Brazil’s reduction resulted largely from an exploratory well drilled at the BM-BAR-3 block in the offshore Barreirinhas Basin. After drilling this well in the first quarter of 2009, Devon concluded that the well did not have adequate reserves for commercial viability. As a result, the seismic, leasehold and drilling costs associated with this well contributed to the reduction recognized in the first quarter of 2009.

     To demonstrate the changes in the full-cost ceiling for the United States and Brazil, the March 31, 2009 and December 31, 2008 weighted average wellhead prices are presented in the following table.

	March 31, 2009						December 31, 2008
	Oil		Gas		NGLs		Oil		Gas		NGLs
Country	(Per Bbl)		(Per Mcf)		(Per Bbl)		(Per Bbl)		(Per Mcf)		(Per Bbl)
United States	$	47.30	$	2.67	$	17.04	$	42.21	$	4.68	$	16.16
Brazil	$	36.71		N/A		N/A	$	26.61		N/A		N/A

     N/A — Not applicable.

     The March 31, 2009 oil and gas wellhead prices in the table above compare to the NYMEX cash price of $49.66 per Bbl for crude oil and the Henry Hub spot price of $3.63 per MMBtu for gas. The December 31, 2008 oil and gas wellhead prices in the table above compare to the NYMEX cash price of $44.60 per Bbl for crude oil and the Henry Hub spot price of $5.71 per MMBtu for gas.

14. Discontinued Operations

     At the end of 2008, Devon’s operations in Angola were classified as discontinued as a result of Devon’s plans and ongoing activities to sell its operations in Angola. Due to a commercial discovery in the second quarter of 2009, Devon suspended marketing its Angolan operations for sale. Although Devon intends to resume marketing activities in 2010 once it has drilled its remaining commitment wells, Devon’s operations in Angola do not currently qualify as discontinued. Therefore, Devon has classified all amounts related to its Angolan operations for 2009 and prior years as continuing operations.

     In the second quarter of 2008, Devon sold its assets and terminated its operations in certain West African countries, consisting primarily of Equatorial Guinea and Gabon. As a result of the sales, Devon recognized gains totaling $736 million ($647 million after taxes) in the second quarter of 2008 from proceeds of $2.4 billion ($1.7 billion net of income taxes and purchase price adjustments). During the second quarter of 2009, Devon recognized a $17 million gain in conjunction with post-closing settlements related to these sales, as well as the sale of its assets in Cote D’Ivoire in the third quarter of 2008.

     Operating revenues related to Devon’s discontinued operations totaled $127 million in the three months ended June 30, 2008 and $332 million in the six months ended June 30, 2008. There were no operating revenues related to Devon’s discontinued operations for the three-month and six-month periods ended June 30, 2009.

     The following table presents the main classes of assets and liabilities associated with Devon’s discontinued operations as of June 30, 2009 and December 31, 2008.

	Devon's Consolidated	June 30,		December 31,
	Balance Sheet Caption	2009		2008
		(In millions)
Cash and other current assets	Other current assets	$	18	$	14
Property and equipment, net of accumulated depreciation, depletion and amortization	Other long-term assets	$	8	$	9
Accounts payable and other current liabilities	Other current liabilities	$	10	$	6

19

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

15. 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 (loss) per share for the three-month and six-month periods ended June 30, 2009 and 2008. Because a net loss from continuing operations was generated during the six-month period ended June 30, 2009, the dilutive shares produce an antidilutive net loss per share result. Therefore, the diluted loss per share from continuing operations in the six months ended June 30, 2009 reported in the accompanying 2009 statement of operations is the same as the basic loss per share amount.

							Earnings
	Earnings			Common			(Loss)
	(Loss)			Shares			per Share
	(In millions, except per share amounts)
Three Months Ended June 30, 2009:
Earnings from continuing operations	$	297			444
Attributable to participating securities		(5	)		(5	)
Basic earnings per share		292			439		$	0.67
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options		—			2
Diluted earnings per share	$	292			441		$	0.66
Three Months Ended June 30, 2008:
Earnings from continuing operations	$	594			446
Attributable to participating securities		(4	)		(4	)
Less preferred stock dividends		(3	)		—
Basic earnings per share		587			442		$	1.33
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options		—			4
Diluted earnings per share	$	587			446		$	1.31
Six Months Ended June 30, 2009:
Loss from continuing operations	$	(3,661	)		444
Attributable to participating securities		43			(5	)
Basic and diluted loss per share	$	(3,618	)		439		$	(8.25	)
Six Months Ended June 30, 2008:
Earnings from continuing operations	$	1,245			445
Attributable to participating securities		(10	)		(4	)
Less preferred stock dividends		(5	)
Basic earnings per share		1,230			441		$	2.80
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options		—			4
Diluted earnings per share	$	1,230			445		$	2.76

     Certain options to purchase shares of Devon’s common stock are excluded from the dilution calculations because the options are antidilutive. During the three-month and six-month periods ended June 30, 2009, 7.1 million shares and 8.9 million shares, respectively, were excluded from the diluted earnings per share calculations. During the three-month and six-month periods ended June 30, 2008, no shares and 1.5 million shares, respectively, were excluded from the diluted earnings per share calculations.

20

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

16. Segment Information

     Following is certain financial information regarding Devon’s reporting segments. The revenues reported are all from external customers.

	Domestic		Canada		International		Total
	(In millions)
As of June 30, 2009:
Current assets	$	1,477	$	555	$	545	$	2,577
Property and equipment, net		12,364		4,774		949		18,087
Goodwill		3,046		2,596		68		5,710
Other long-term assets		417		57		209		683
Total assets	$	17,304	$	7,982	$	1,771	$	27,057
Current liabilities	$	2,851	$	401	$	240	$	3,492
Long-term debt		2,870		2,979		—		5,849
Asset retirement obligation, long-term		724		586		101		1,411
Other long-term liabilities		992		42		2		1,036
Deferred income taxes		540		950		97		1,587
Stockholders’ equity		9,327		3,024		1,331		13,682
Total liabilities and stockholders’ equity	$	17,304	$	7,982	$	1,771	$	27,057

21

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

	Domestic			Canada			International			Total
	(In millions)
Three Months Ended June 30, 2009:
Revenues:
Oil sales	$	225		$	316		$	267		$	808
Gas sales		544			195			1			740
NGL sales		138			32			—			170
Net gain on oil and gas derivative financial instruments		13			—			—			13
Marketing and midstream revenues		351			8			—			359
Total revenues		1,271			551			268			2,090
Expenses and other income, net:
Lease operating expenses		289			167			54			510
Production taxes		27			1			19			47
Marketing and midstream operating costs and expenses		230			4			—			234
Depreciation, depletion and amortization of oil and gas properties		274			156			64			494
Depreciation and amortization of non-oil and gas properties		67			7			—			74
Accretion of asset retirement obligation		14			9			1			24
General and administrative expenses		153			31			(2	)		182
Interest expense		34			56			—			90
Change in fair value of other financial instruments		(10	)		—			—			(10	)
Other expense (income), net		18			6			(4	)		20
Total expenses and other income, net		1,096			437			132			1,665
Earnings from continuing operations before income taxes		175			114			136			425
Income tax expense (benefit):
Current		11			44			(4	)		51
Deferred		55			(4	)		26			77
Total income tax expense		66			40			22			128
Earnings from continuing operations		109			74			114			297
Earnings from discontinued operations		—			—			17			17
Net earnings applicable to common stockholders	$	109		$	74		$	131		$	314
Capital expenditures, continuing operations	$	761		$	185		$	113		$	1,059

22

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

	Domestic			Canada		International			Total
	(In millions)
Three Months Ended June 30, 2008:
Revenues:
Oil sales	$	566		$	498	$	391		$	1,455
Gas sales		1,688			517		5			2,210
NGL sales		305			74		—			379
Net loss on oil and gas derivative financial instruments		(1,215	)		—		—			(1,215	)
Marketing and midstream revenues		707			12		—			719
Total revenues		2,051			1,101		396			3,548
Expenses and other income, net:
Lease operating expenses		279			211		47			537
Production taxes		104			1		71			176
Marketing and midstream operating costs and expenses		510			5		—			515
Depreciation, depletion and amortization of oil and gas properties		481			227		54			762
Depreciation and amortization of non-oil and gas properties		54			7		1			62
Accretion of asset retirement obligation		10			10		2			22
General and administrative expenses		145			34		1			180
Interest expense		36			54		—			90
Change in fair value of other financial instruments		(40	)		—		—			(40	)
Other income, net		(11	)		—		(6	)		(17	)
Total expenses and other income, net		1,568			549		170			2,287
Earnings from continuing operations before income taxes		483			552		226			1,261
Income tax expense (benefit):
Current		299			46		69			414
Deferred		163			104		(14	)		253
Total income tax expense		462			150		55			667
Earnings from continuing operations		21			402		171			594
Discontinued operations:
Earnings from discontinued operations before income taxes		—			—		851			851
Income tax expense		—			—		144			144
Earnings from discontinued operations		—			—		707			707
Net earnings		21			402		878			1,301
Preferred stock dividends		3			—		—			3
Net earnings applicable to common stockholders	$	18		$	402	$	878		$	1,298
Capital expenditures, continuing operations	$	1,654		$	182	$	173		$	2,009

23

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

	Domestic			Canada			International			Total
	(In millions)
Six Months Ended June 30, 2009:
Revenues:
Oil sales	$	375		$	493		$	394		$	1,262
Gas sales		1,220			431			2			1,653
NGL sales		250			56			—			306
Net gain on oil and gas derivative financial instruments		167			—			—			167
Marketing and midstream revenues		715			15			—			730
Total revenues		2,727			995			396			4,118
Expenses and other income, net:
Lease operating expenses		602			344			88			1,034
Production taxes		59			1			29			89
Marketing and midstream operating costs and expenses		455			8			—			463
Depreciation, depletion and amortization of oil and gas properties		714			276			103			1,093
Depreciation and amortization of non-oil and gas properties		131			13			—			144
Accretion of asset retirement obligation		28			18			2			48
General and administrative expenses		290			60			(2	)		348
Interest expense		61			112			—			173
Change in fair value of other financial instruments		(15	)		—			—			(15	)
Reduction of carrying value of oil and gas properties		6,408			—			108			6,516
Other expense (income), net		14			16			(3	)		27
Total expenses and other income, net		8,747			848			325			9,920
(Loss) earnings from continuing operations before income taxes		(6,020	)		147			71			(5,802	)
Income tax expense (benefit):
Current		1			46			6			53
Deferred		(2,224	)		3			27			(2,194	)
Total income tax (benefit) expense		(2,223	)		49			33			(2,141	)
(Loss) earnings from continuing operations		(3,797	)		98			38			(3,661	)
Earnings from discontinued operations		—			—			16			16
Net (loss) earnings applicable to common stockholders	$	(3,797	)	$	98		$	54		$	(3,645	)
Capital expenditures, before revision of future ARO	$	1,908		$	486		$	203		$	2,597
Revision of future ARO		37			(15	)		1			23
Capital expenditures, continuing operations	$	1,945		$	471		$	204		$	2,620

24

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

	Domestic			Canada			International			Total
	(In millions)
Six Months Ended June 30, 2008:
Revenues:
Oil sales	$	1,009		$	838		$	858		$	2,705
Gas sales		2,924			906			10			3,840
NGL sales		571			136			—			707
Net loss on oil and gas derivative financial instruments		(2,003	)		—			—			(2,003	)
Marketing and midstream revenues		1,249			25			—			1,274
Total revenues		3,750			1,905			868			6,523
Expenses and other income, net:
Lease operating expenses		545			405			93			1,043
Production taxes		183			2			125			310
Marketing and midstream operating costs and expenses		887			10			—			897
Depreciation, depletion and amortization of oil and gas properties		941			438			120			1,499
Depreciation and amortization of non-oil and gas properties		105			13			1			119
Accretion of asset retirement obligation		21			20			3			44
General and administrative expenses		259			68			1			328
Interest expense		88			104			—			192
Change in fair value of other financial instruments		(24	)		—			—			(24	)
Other income, net		(17	)		(5	)		(16	)		(38	)
Total expenses and other income, net		2,988			1,055			327			4,370
Earnings from continuing operations before income taxes		762			850			541			2,153
Income tax expense:
Current		345			64			108			517
Deferred		213			152			26			391
Total income tax expense		558			216			134			908
Earnings from continuing operations		204			634			407			1,245
Discontinued operations:
Earnings from discontinued operations before income taxes		—			—			1,040			1,040
Income tax expense		—			—			235			235
Earnings from discontinued operations		—			—			805			805
Net earnings		204			634			1,212			2,050
Preferred stock dividends		5			—			—			5
Net earnings applicable to common stockholders	$	199		$	634		$	1,212		$	2,045
Capital expenditures, before revision of future ARO	$	2,965		$	698		$	304		$	3,967
Revision of future ARO		70			73			19			162
Capital expenditures, continuing operations	$	3,035		$	771		$	323		$	4,129

25

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

17. Supplemental Information to Statements of Cash Flows

     Additional information related to Devon’s cash flows for the six-month periods ended June 30, 2009 and 2008 are presented below.

	Six Months
	Ended June 30,
	2009			2008
	(In millions)
Net increase in working capital:
Decrease (increase) in accounts receivable	$	108		$	(604	)
Decrease (increase) in other current assets		167			(44	)
(Decrease) increase in accounts payable		(66	)		120
(Decrease) increase in revenues and royalties due to others		(115	)		348
(Decrease) increase in other current liabilities		(183	)		48
Net increase in working capital	$	(89	)	$	(132	)
Supplementary cash flow data — continuing and discontinued operations:
Interest paid — net of capitalized interest	$	138		$	189
Income taxes (received) paid	$	(139	)	$	826

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

     The following discussion addresses material changes in our results of operations and capital resources and uses for the three-month and six-month periods ended June 30, 2009, compared to the three-month and six-month periods ended June 30, 2008, and in our financial condition and liquidity since December 31, 2008. For information regarding our critical accounting policies and estimates, see our 2008 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.

Business Overview

     The downward pressure in natural gas prices that began in the last half of 2008 has continued into the first and second quarters of 2009. The Henry Hub natural gas index for the second quarter of 2009 was down 49% from the fourth quarter of 2008 and 68% from the second quarter of 2008. Additionally, although oil index prices have improved slightly since the end of 2008, the West Texas Intermediate oil index dropped 52% from the second quarter of 2008 to the second quarter of 2009.

     The lower oil and gas prices have significantly impacted our earnings for the second quarter and first six months of 2009. During the second quarter of 2009 and first six months of 2009, we generated net earnings of $314 million, or $0.70 per diluted share, and a net loss of $3.6 billion, or $8.21 per diluted share, for the respective periods. These amounts are significantly lower than the comparative earnings amounts for 2008. Additionally, the loss in the first half of 2009 was the result of noncash impairments of our oil and gas properties in the first quarter that totaled $4.2 billion, net of income taxes. Substantially all of this noncash charge was the result of the continuing drop in natural gas prices since December 31, 2008.

     Key measures of our performance for the second quarter and first six months of 2009 compared to 2008 are summarized below:

• Production increased 12% and 9% in the second quarter and first six months of 2009, respectively.

• The combined realized price without hedges for oil, gas and NGLs decreased 62% and 59% in the second quarter and first six months of 2009, respectively.

• Marketing and midstream operating profit decreased 39% to $125 million and 29% to $267 in the second quarter and first six months of 2009, respectively.

• Per unit operating costs decreased 30% to $8.51 per Boe and 24% to $8.84 per Boe in the second quarter and first six months of 2009, respectively.

• Oil and gas hedges generated net gains of $13 million and $167 million in the second quarter and first six months of 2009, respectively and net losses of $1.2 billion and $2.0 billion in the second quarter and first six months of 2008. Included in these amounts were cash receipts of $114 million and $232 million for the second quarter of 2009 and first six months of 2009, respectively and payments of $303 million and $311 million in the second quarter of 2008 and first six months of 2008, respectively.

• Operating cash flow decreased approximately 60% to $2.1 billion in the first half of 2009.

• Cash spent on capital expenditures was approximately $3.2 billion in the first six months of 2009. Approximately 65% this amount was funded with operating cash flow and the remainder was funded with commercial paper borrowings.

     Additionally, in January 2009, we issued $500 million of 5.625% senior unsecured notes due January 15, 2014 and $700 million of 6.30% senior unsecured notes due January 15, 2019. The net proceeds received of $1.187 billion, after discounts and issuance costs, were used primarily to repay our $1.0 billion of outstanding commercial paper as of December 31, 2008.

     During the second quarter of 2009, we announced the integration of our Gulf of Mexico and International operations into one offshore unit. This integration will provide greater focus and efficiency to these areas of our operations, which have similar scope, technical requirements and strategy. We continue to view our deepwater strategy as a means to enhance our long-term growth opportunities.

     We expect the challenging commodity price environment will likely persist throughout the remainder of 2009. As a result, we are continuing to execute the strategy we outlined at the beginning of the year. That strategy is to decrease our activity across our near-term development projects in North America and continue advancing our longer term development projects

27

like our second Jackfish heavy oil project in Canada and our Lower Tertiary developments in the Gulf of Mexico. We also continue to drive costs lower and maintain our strong liquidity position until we see signs of recovery in the hydrocarbon markets.

     As part of this strategy, in the second quarter of 2009, we announced plans to pursue a partner to participate in our Lower Tertiary projects in the Gulf of Mexico. The proceeds we may obtain from such a transaction would supplement the liquidity provided by our operating cash flow and credit lines. Additionally, such a transaction would give us greater flexibility to adjust capital expenditures to changes in cash flow, particularly in these times of low commodity prices.

     Although oil and gas prices remain depressed compared to recent highs achieved in 2008, and our operating cash flow has been negatively impacted, we expect to have adequate liquidity to execute our near-term operating strategy and maintain momentum on our longer-term projects. As of July 31, 2009, we had unused lines of credit totaling $2.0 billion and continue to have access to the commercial paper market. We anticipate these capital sources combined with our operating cash flow will be sufficient to fund our planned capital expenditures and other capital uses over the near-term.

Results of Operations

Revenues

     The three-month and six-month comparison of our oil, gas and NGL production, prices and revenues for the second quarter and first half of 2009 and 2008 are shown in the following tables. The amounts for all periods presented exclude our West African operations that are classified as discontinued operations in our financial statements.

	Total
	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Change(2)			2009		2008		Change(2)
Production
Oil (MMBbls)		16		13		+17	%		29		27		+6	%
Gas (Bcf)		254		230		+11	%		499		453		+10	%
NGLs (MMBbls)		8		7		+9	%		15		14		+8	%
Oil, Gas and NGLs (MMBoe)(1)		65		59		+12	%		127		117		+9	%
Realized prices without hedges
Oil (Per Bbl)	$	52.44	$	110.56		-53	%	$	43.65	$	98.98		-56	%
Gas (Per Mcf)	$	2.91	$	9.61		-70	%	$	3.31	$	8.48		-61	%
NGLs (Per Bbl)	$	22.24	$	54.08		-59	%	$	20.45	$	50.76		-60	%
Oil, Gas and NGLs (Per Boe)(1)	$	26.27	$	69.14		-62	%	$	25.36	$	62.12		-59	%
Revenues($ in millions)
Oil sales	$	808	$	1,455		-44	%	$	1,262	$	2,705		-53	%
Gas sales		740		2,210		-67	%		1,653		3,840		-57	%
NGL sales		170		379		-55	%		306		707		-57	%
Oil, Gas and NGL sales	$	1,718	$	4,044		-58	%	$	3,221	$	7,252		-56	%

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	Domestic
	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Change(2)			2009		2008		Change(2)
Production
Oil (MMBbls)		4		5		-12	%		8		9		-12	%
Gas (Bcf)		194		176		+10	%		386		347		+11	%
NGLs (MMBbls)		7		6		+10	%		13		12		+9	%
Oil, Gas and NGLs (MMBoe)(1)		42		40		+7	%		85		79		+8	%
Realized prices without hedges
Oil (Per Bbl)	$	55.18	$	122.47		-55	%	$	46.07	$	109.08		-58	%
Gas (Per Mcf)	$	2.81	$	9.56		-71	%	$	3.16	$	8.42		-62	%
NGLs (Per Bbl)	$	20.89	$	50.66		-59	%	$	19.24	$	47.78		-60	%
Oil, Gas and NGLs (Per Boe)(1)	$	21.10	$	63.88		-67	%	$	21.61	$	56.95		-62	%
Revenues($ in millions)
Oil sales	$	225	$	566		-60	%	$	375	$	1,009		-63	%
Gas sales		544		1,688		-68	%		1,220		2,924		-58	%
NGL sales		138		305		-55	%		250		571		-56	%
Oil, Gas and NGL sales	$	907	$	2,559		-65	%	$	1,845	$	4,504		-59	%

	Canada
	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Change(2)			2009		2008		Change(2)
Production
Oil (MMBbls)		7		5		+24	%		13		10		+30	%
Gas (Bcf)		60		53		+13	%		113		105		+8	%
NGLs (MMBbls)		1		1		+4	%		2		2		-1	%
Oil, Gas and NGLs (MMBoe)(1)		18		16		+17	%		34		30		+15	%
Realized prices without hedges
Oil (Per Bbl)	$	48.14	$	94.35		-49	%	$	38.19	$	84.16		-55	%
Gas (Per Mcf)	$	3.25	$	9.76		-67	%	$	3.82	$	8.66		-56	%
NGLs (Per Bbl)	$	30.99	$	75.10		-59	%	$	28.52	$	68.86		-59	%
Oil, Gas and NGLs (Per Boe)(1)	$	30.85	$	72.14		-57	%	$	29.11	$	64.01		-55	%
Revenues($ in millions)
Oil sales	$	316	$	498		-37	%	$	493	$	838		-41	%
Gas sales		195		517		-62	%		431		906		-52	%
NGL sales		32		74		-57	%		56		136		-59	%
Oil, Gas and NGL sales	$	543	$	1,089		-50	%	$	980	$	1,880		-48	%

29

	International
	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Change(2)			2009		2008		Change(2)
Production
Oil (MMBbls)		5		3		+46	%		8		8		-3	%
Gas (Bcf)		—		1		-32	%		—		1		-39	%
NGLs (MMBbls)		—		—		N/M			—		—		N/M
Oil, Gas and NGLs (MMBoe)(1)		5		3		+44	%		8		8		-4	%
Realized prices without hedges
Oil (Per Bbl)	$	56.03	$	119.87		-53	%	$	50.10	$	105.63		-53	%
Gas (Per Mcf)	$	4.24	$	11.00		-61	%	$	3.85	$	9.56		-60	%
NGLs (Per Bbl)	$	—	$	—		N/M		$	—	$	—		N/M
Oil, Gas and NGLs (Per Boe)(1)	$	55.71	$	118.70		-53	%	$	49.76	$	104.68		-52	%
Revenues($ in millions)
Oil sales	$	267	$	391		-32	%	$	394	$	858		-54	%
Gas sales		1		5		-74	%		2		10		-76	%
NGL sales		—		—		N/M			—		—		N/M
Oil, Gas and NGL sales	$	268	$	396		-32	%	$	396	$	868		-54	%

(1)	Gas volumes are converted to Boe or MMBoe at the rate of six Mcf of gas per barrel of oil, based upon the approximate relative energy content of gas and oil, which rate is not necessarily indicative of the relationship of oil and gas prices. NGL volumes are converted to Boe on a one-to-one basis with oil.
(2)	All percentage changes included in this table are based on actual figures and are not calculated using the rounded figures included in this table.
N/M	Not meaningful.

     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, 2009 and 2008.

	Oil			Gas			NGLs			Total
	(In millions)
2008 sales	$	1,455		$	2,210		$	379		$	4,044
Changes due to volumes		248			232			34			514
Changes due to prices.		(895	)		(1,702	)		(243	)		(2,840	)
2009 sales	$	808		$	740		$	170		$	1,718

     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, 2009 and 2008.

	Oil			Gas			NGLs			Total
	(In millions)
2008 sales	$	2,705		$	3,840		$	707		$	7,252
Changes due to volumes		156			389			53			598
Changes due to prices.		(1,599	)		(2,576	)		(454	)		(4,629	)
2009 sales	$	1,262		$	1,653		$	306		$	3,221

Oil Sales

     Oil sales decreased $895 million in the second quarter of 2009 as a result of a 53% decrease in our realized price without hedges. The average NYMEX West Texas Intermediate index price decreased 52% during the same time period, accounting for the majority of the decrease.

30

     Oil sales increased $248 million in the second quarter of 2009 due to a three million barrel increase in production. The increased production resulted primarily from the continued development activities at our Jackfish operations in Canada and at our Polvo operations in Brazil.

     Oil sales decreased $1.6 billion in the first half of 2009 as a result of a 56% decrease in our realized price without hedges. The average NYMEX West Texas Intermediate index price decreased 54% during the same time period, accounting for the majority of the decrease.

     Oil sales increased $156 million in the first half of 2009 due to a two million barrel increase in production. The increased production resulted primarily from the continued development at our Jackfish operations in Canada and at our Polvo operations in Brazil. These increases were partially offset by decreased production in Azerbaijan as a result of reaching certain cost recovery thresholds. In addition, we deferred approximately 0.7 million barrels of Gulf of Mexico oil production due to hurricane damage suffered in the third quarter of 2008.

Gas Sales

     Gas sales decreased $1.7 billion during the second quarter of 2009 as a result of a 70% decrease in our realized price without hedges. This decrease was largely due to decreases in the North American regional index prices upon which our gas sales are based.

     A 24 Bcf increase in production during the second quarter of 2009 caused gas sales to increase by $232 million. Our drilling and development program in the Barnett Shale field in north Texas contributed 10 Bcf to the gas production increase. A decline in Canadian government royalties resulting from lower gas prices increased gas production by nine Bcf. These increases and the effect of new drilling and development in our other North American properties were partially offset by natural production declines, mainly in the Gulf of Mexico, and the deferral of approximately two Bcf of production due to hurricane damage suffered in the third quarter of 2008.

     Gas sales decreased $2.6 billion during the first half of 2009 as a result of a 61% decrease in our realized price without hedges. This decrease is largely due to decreases in the regional index prices upon which our gas sales are based.

     A 46 Bcf increase in production during the first half of 2009 caused gas sales to increase by $389 million. Our drilling and development program in the Barnett Shale field in north Texas contributed 25 Bcf to the gas production increase. A decline in Canadian government royalties resulting from lower gas prices increased gas production by 12 Bcf. These increases and the effect of new drilling and development in our other North American properties were partially offset by natural production declines, mainly in the Gulf of Mexico, and the deferral of approximately four Bcf of production due to hurricane damage suffered in the third quarter of 2008.

NGL Sales

     NGL sales decreased $243 million during the second quarter of 2009 as a result of a 59% decrease in our realized price without hedges. This decrease was largely due to decreases in the regional index prices upon which our NGL sales are based.

     NGL sales decreased $454 million during the first half of 2009 as a result of a 60% decrease in our realized price without hedges. This decrease is largely due to decreases in the regional index prices upon which our NGL sales are based.

31

Net Gain (Loss) on Oil and Gas Derivative Financial Instruments

     The following tables provide financial information associated with our oil and gas hedges for the second quarter and first half of 2009 and 2008. The first table presents the cash settlements and unrealized gains and losses 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 for the three and six months ended June 30, 2009 and 2008. The prices do not include the effects of unrealized gains and losses.

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(In millions)
Cash settlements receipts (payments):
Gas price swaps	$	—		$	(153	)	$	—		$	(161	)
Gas price collars		114			(150	)		232			(150	)
Total cash settlements		114			(303	)		232			(311	)
Unrealized losses on fair value changes:
Gas price swaps		—			(247	)		—			(618	)
Gas price collars		(101	)		(620	)		(65	)		(1,028	)
Oil price collars		—			(45	)		—			(46	)
Total unrealized losses on fair value changes		(101	)		(912	)		(65	)		(1,692	)
Net gain (loss) on oil and gas derivative financial instruments	$	13		$	(1,215	)	$	167		$	(2,003	)

	Three Months Ended June 30, 2009
	Oil		Gas		NGLs		Total
	(Per Bbl)		(Per Mcf)		(Per Bbl)		(Per Boe)
Realized price without hedges	$	52.44	$	2.91	$	22.24	$	26.27
Cash settlements of hedges		—		0.45		—		1.75
Realized price, including cash settlements	$	52.44	$	3.36	$	22.24	$	28.02

	Three Months Ended June 30, 2008
	Oil			Gas			NGLs		Total
	(Per Bbl)			(Per Mcf)			(Per Bbl)		(Per Boe)
Realized price without hedges	$	110.56		$	9.61		$	54.08	$	69.14
Cash settlements of hedges		(0.01	)		(1.32	)		—		(5.18	)
Realized price, including cash settlements	$	110.55		$	8.29		$	54.08	$	63.96

	Six Months Ended June 30, 2009
	Oil		Gas		NGLs		Total
	(Per Bbl)		(Per Mcf)		(Per Bbl)		(Per Boe)
Realized price without hedges	$	43.65	$	3.31	$	20.45	$	25.36
Cash settlements of hedges		—		0.47		—		1.83
Realized price, including cash settlements	$	43.65	$	3.78	$	20.45	$	27.19

	Six Months Ended June 30, 2008
	Oil		Gas			NGLs		Total
	(Per Bbl)		(Per Mcf)			(Per Bbl)		(Per Boe)
Realized price without hedges	$	98.98	$	8.48		$	50.76	$	62.12
Cash settlements of hedges		—		(0.69	)		—		(2.67	)
Realized price, including cash settlements	$	98.98	$	7.79		$	50.76	$	59.45

     In the second quarter and first half of 2009, our derivative financial instruments were comprised of gas price collars. In the second quarter and first half of 2008, our derivative financial instruments included gas price swaps and oil and gas price collars. For the price swaps, we receive a fixed price for our production and pay a variable market price to the contract counterparty. The price collars set a floor and ceiling price. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we cash-settle the difference with the counterparty to the collars. Cash settlements as presented in the tables above represent realized gains or losses related to our price swaps and collars.

32

     During the second quarter and first half of 2009, we received $114 million, or $0.45 per Mcf, and $232 million, or $0.47 per Mcf, respectively from counterparties to settle our gas price collars. During the second quarter and first half of 2008, we paid $303 million, or $1.32 per Mcf, and $311 million, or $0.69 per Mcf, respectively, to counterparties to settle our gas price swaps and collars.

     In addition to recognizing these cash settlement effects, we also recognize unrealized changes in the fair values of our oil and gas derivative instruments in each reporting period. We estimate the fair values of our oil and gas derivative financial instruments primarily by using internal discounted cash flow calculations. From time to time, we validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties or brokers.

     The most significant variable to our cash flow calculations is our estimate of future commodity prices. We base our estimate of future prices upon published forward commodity price curves such as the Inside FERC Henry Hub forward curve for gas instruments and the NYMEX West Texas Intermediate forward curve for oil instruments. Based on the amount of volumes subject to our gas price collars at June 30, 2009, a 10% increase in these forward curves would have increased our 2009 unrealized losses for our gas collar derivative financial instruments by approximately $20 million. Another key input to our cash flow calculations is our estimate of volatility for these forward curves, which we base primarily upon implied volatility.

     Counterparty credit risk is also a component of commodity derivative valuations. We have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Our commodity derivative contracts are held with eight separate counterparties. Additionally, our derivative contracts generally require cash collateral to be posted if either our or the counterparty’s credit rating falls below investment grade. The threshold, above which collateral must be posted, decreases as the debt rating falls further below investment grade. Such thresholds generally range from zero to $50 million for the majority of our contracts. As of June 30, 2009, the credit ratings of all our counterparties were investment grade.

     During the second quarter and first half of 2009, we reduced the fair value of our derivative financial instruments by $101 million and $65 million, respectively. These reductions largely represent the reversal of previously recorded unrealized gains, which is expected as our contracts near their December 31, 2009 expiration date.

     During the second quarter and first half of 2008, we recognized unrealized losses totaling $912 million and $1.7 billion, respectively, related to our oil and gas derivative instruments. These losses resulted primarily from a significant increase in the Inside FERC Henry Hub and the NYMEX West Texas Intermediate forward curves subsequent to our contract trade dates for our oil and gas price swaps and collars.

Marketing and Midstream Revenues and Operating Costs and Expenses

     The details of the changes in marketing and midstream revenues, operating costs and expenses and the resulting operating profit between the three months ended June 30, 2009 and 2008 and the six months ended June 30, 2009 and 2008 are shown in the table below.

	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Change(1)			2009		2008		Change(1)
	($ in millions)
Marketing and midstream:
Revenues	$	359	$	719		-50	%	$	730	$	1,274		-43	%
Operating costs and expenses		234		515		-54	%		463		897		-48	%
Operating profit	$	125	$	204		-39	%	$	267	$	377		-29	%

(1) All percentage changes included in this table are based on actual figures and are not calculated using the rounded figures included in this table.

     During the second quarter of 2009, marketing and midstream revenues decreased $360 million and operating costs and expenses decreased $281 million, causing operating profit to decrease $79 million. During the first half of 2009, marketing and midstream revenues decreased $544 million and operating costs and expenses also decreased $434 million, causing operating profit to decrease $110 million. Revenues and expenses decreased in 2009 primarily due to lower natural gas and NGL prices, partially offset by increased gas pipeline throughput and increased NGL production.

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Oil, Gas and NGL Production and Operating Expenses

     The details of the changes in oil, gas and NGL production and operating expenses between the three and six months ended June 30, 2009 and 2008 are shown in the table below.

	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Change(1)			2009		2008		Change(1)
	($ in millions)
Production and operating expenses:
Lease operating expenses	$	510	$	537		-5	%	$	1,034	$	1,043		-1	%
Production taxes		47		176		-74	%		89		310		-71	%
Total production and operating expenses	$	557	$	713		-22	%	$	1,123	$	1,353		-17	%
Production and operating expenses per Boe:
Lease operating expenses	$	7.80	$	9.18		-15	%	$	8.14	$	8.93		-9	%
Production taxes		0.71		3.01		-77	%		0.70		2.66		-74	%
Total production and operating expenses per Boe	$	8.51	$	12.19		-30	%	$	8.84	$	11.59		-24	%

(1) All percentage changes included in this table are based on actual figures and are not calculated using the rounded figures included in this table.

Lease Operating Expenses (“LOE”)

     LOE decreased $27 million in the second quarter of 2009. LOE decreased $64 million due to declining costs for fuel, materials, equipment and personnel, as well as a decline in recurring activities and well workover projects. Such declines largely result from decreasing demand for field services due to lower oil and gas prices compared to recent periods. LOE also decreased $26 million due to the effects of changes in the exchange rate between the U.S. and Canadian dollar. These decreases were the main contributors to the decrease in our LOE per Boe. Partially offsetting these decreases was a $63 million increase in LOE associated with our 12% production growth.

     LOE decreased $9 million in the first half of 2009. LOE decreased $32 million due to declining costs for fuel, materials, equipment and personnel, as well as a decline in recurring activities and well workover projects. LOE also decreased $69 million due to the effects of changes in the exchange rate between the U.S. and Canadian dollar. These decreases were the main contributors to the decrease in our LOE per Boe. Partially offsetting these decreases was a $92 million increase in LOE associated with our 9% production growth.

Production Taxes

     The following table details the changes in production taxes between the three and six months ended June 30, 2009 and 2008. The majority of our production taxes are assessed on our U.S. onshore properties and are based on a fixed percentage of revenues. Production taxes are also assessed on certain of our International properties based on a variable percentage of revenues that generally moves in tandem with commodity prices. Therefore, the changes due to revenues in the following table primarily relate to changes in oil, gas and NGL revenues from our U.S. onshore and International properties.

	Three Months			Six Months
	Ended June 30,			Ended June 30,
	(In millions)
2008 production taxes	$	176		$	310
Change due to revenues		(101	)		(172	)
Change due to rate		(28	)		(49	)
2009 production taxes	$	47		$	89

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

     The changes in our production volumes, DD&A rate per unit and DD&A of oil and gas properties between the three and six months ended June 30, 2009 and 2008 are shown in the table below.

	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Change(1)			2009		2008		Change(1)
Production volumes (MMBoe)		65		59		+12	%		127		117		+9	%
DD&A rate ($  per Boe)	$	7.56	$	13.03		-42	%	$	8.61	$	12.84		-33	%
DD&A expense ($ in millions)	$	494	$	762		-35	%	$	1,093	$	1,499		-27	%

(1) All percentage changes included in this table are based on actual figures and are not calculated using the rounded figures included in this table.

     The following table details the changes in DD&A of oil and gas properties between the three and six months ended June 30, 2009 and 2008.

	Three Months Ended			Six Months Ended
	June 30,			June 30,
	(In millions)
2008 DD&A	$	762		$	1,499
Change due to volumes		90			132
Change due to rate		(358	)		(538	)
2009 DD&A	$	494		$	1,093

     The 12% production increase during the second quarter of 2009 caused oil and gas property related DD&A to increase $90 million. Oil and gas property-related DD&A decreased $358 million during the second quarter of 2009 due to a 42% decrease in the DD&A rate. The 9% production increase during the first half of 2009 caused oil and gas property related DD&A to increase $132 million. Oil and gas property-related DD&A decreased $538 million during the first half of 2009 due to a 33% decrease in the DD&A rate.

     The largest contributors to the rate decreases in 2009 were reductions of the carrying values of certain of our oil and gas properties recognized in the first quarter of 2009 and the fourth quarter of 2008. These reductions totaled $16.9 billion and resulted from full cost ceiling limitations. In addition, the effects of changes in the exchange rate between the U.S. and Canadian dollar contributed to the rate decreases. These decreases were partially offset by the effects of costs incurred and transfers of previously unproved costs to the depletable base as a result of drilling activities subsequent to the second quarter of 2008.

General and Administrative Expenses (“G&A”)

     The details of the changes in G&A expense between the three and six months ended June 30, 2009 and 2008 are shown in the table below.

	Three Months									Six Months
	Ended June 30,									Ended June 30,
	2009			2008			Change(1)			2009			2008			Change(1)
	($ in millions)
Gross G&A	$	316		$	307			+3	%	$	621		$	584			+6	%
Capitalized G&A		(104	)		(100	)		+3	%		(208	)		(199	)		+4	%
Reimbursed G&A		(30	)		(27	)		+8	%		(65	)		(57	)		+13	%
Net G&A	$	182		$	180			+2	%	$	348		$	328			+6	%

(1) All percentage changes included in this table are based on actual figures and are not calculated using the rounded figures included in this table.

     Gross G&A increased $9 million in the second quarter of 2009 compared to the same period of 2008. Gross G&A increased $33 million due to employee severance costs resulting from our decision to integrate our Gulf of Mexico and

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International operations into one offshore unit in the second quarter of 2009. Gross G&A decreased $27 million due to accelerated share-based compensation expense recognized in the second quarter of 2008. In the second quarter of 2008, we modified the share-based compensation arrangements for certain members of senior management. The modified compensation arrangements provide that executives who meet certain years-of-service and age criteria can retire and continue vesting in outstanding share-based grants. As a condition to receiving the benefits of these modifications, the executives must agree not to use or disclose Devon’s confidential information and not to solicit Devon’s employees and customers. The executives are required to agree to these conditions at retirement and again in each subsequent year until all grants have vested. This modification results in accelerated expense recognition as executives approach the years-of-service and age criteria.

     Gross G&A increased $37 million in the first half of 2009 compared to the same period of 2008. Severance costs associated with the integration of the offshore unit and other employee departures in 2009 caused gross G&A to increase $50 million. Gross G&A decreased $27 million due to the accelerated share-based compensation expense discussed above. The remainder of the gross G&A increase largely relates to higher costs for employee compensation and benefits.

Interest Expense

     The following schedule includes the components of interest expense for the three-month and six-month periods ended June 30, 2009 and 2008.

	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
	(In millions)
Interest based on debt outstanding	$	110		$	110		$	218		$	236
Capitalized interest		(22	)		(25	)		(49	)		(56	)
Other		2			5			4			12
Total	$	90		$	90		$	173		$	192

     Interest based on debt outstanding decreased during the first half of 2009 primarily due to a decrease in outstanding borrowings. In the second quarter of 2008, we used proceeds from our West African divestiture program and cash flow from operations to repay commercial paper and credit facility borrowings. As a result, we had lower commercial paper and credit facility borrowings in 2009 than in 2008. Additionally, we retired our exchangeable debentures during the third quarter of 2008. These decreases were partially offset by interest related to the $500 million of 5.625% senior unsecured notes and $700 million of 6.30% senior unsecured notes that we issued in January 2009.

     Interest based on debt outstanding was consistent in the second quarters of 2009 and 2008 primarily due to the changes in outstanding borrowings discussed above.

Change in Fair Value of Other Financial Instruments

     The details of the changes in fair value of other financial instruments for the three months and six months ended June 30, 2009 and 2008 are shown in the table below.

	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
	(In millions)
(Gains) losses from:
Interest rate swaps — settlements	$	(5	)	$	—		$	(21	)	$	—
Interest rate swaps — fair value changes.		(5	)		—			6			—
Chevron common stock		—			(195	)		—			(82	)
Option embedded in exchangeable debentures		—			155			—			58
Total	$	(10	)	$	(40	)	$	(15	)	$	(24	)

Interest Rate Swaps

     During the second quarter and first six months of 2009, we received cash settlements totaling $5 million and $21 million, respectively, from counterparties to settle our interest rate swaps. We also recognize unrealized changes in the fair values of

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our interest rate swaps each reporting period. In the second quarter and first six months of 2009, we recorded a $5 million unrealized gain and a $6 million unrealized loss, respectively, as a result of changes in interest rates.

     We estimate the fair values of our interest rate swap financial instruments primarily by using internal discounted cash flow calculations based upon forward interest-rate yields. We periodically validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties or brokers.

     The most significant variable to our cash flow calculations is our estimate of future interest rate yields. We base our estimate of future yields upon our own internal model that utilizes forward curves such as the LIBOR or the Federal Funds Rate provided by a third party. Based on the notional amount subject to the interest rate swaps at June 30, 2009, a 10% increase in these forward curves would have increased our second quarter 2009 unrealized gain for our interest rate swaps by approximately $5 million.

     As previously discussed for our commodity derivative contracts, counterparty credit risk is also a component of interest rate derivative valuations. We have mitigated our exposure to any single counterparty by contracting with several counterparties. Our interest rate derivative contracts are held with five separate counterparties. Additionally, our derivative contracts generally require cash collateral to be posted if either our or the counterparty’s credit rating falls below investment grade. The threshold, above which collateral must be posted, decreases as the debt rating falls further below investment grade. Such thresholds generally range from zero to $50 million for the majority of our contracts. The credit ratings of all our counterparties were investment grade as of June 30, 2009.

Chevron Common Stock and Related Embedded Option

     The second quarter and first six months of 2008 gain on our investment in Chevron common stock and loss on the embedded option were directly attributable to a $13.77 and $5.80 per share increase of Chevron’s common stock during the second quarter and first six months of 2008, respectively. The Chevron common stock was exchanged for Chevron’s interest in certain oil and gas properties and cash in the fourth quarter of 2008. The exchangeable debentures were retired in August 2008.

Reduction of Carrying Value of Oil and Gas Properties

     In the first quarter of 2009, we reduced the carrying values of certain of our oil and gas properties due to full cost ceiling limitations. A summary of these reductions and additional discussion is provided below.

	March 31, 2009
			Net of
	Gross		Taxes
	(In millions)
United States	$	6,408	$	4,085
Brazil		103		103
Russia		5		2
Total	$	6,516	$	4,190

     The United States reduction resulted primarily from a significant decrease in the full cost ceiling during the first three months of 2009. The lower ceiling value in the United States largely resulted from the continued effects of declining natural gas prices subsequent to December 31, 2008.

     Although oil prices improved subsequent to December 31, 2008, Brazil’s reduction resulted largely from an exploratory well drilled at the BM-BAR-3 block in the offshore Barreirinhas Basin. After drilling this well in the first quarter of 2009, we concluded that the well did not have adequate reserves for commercial viability. As a result, the seismic, leasehold and drilling costs associated with this well contributed to the reduction recognized in the first quarter of 2009.

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     To demonstrate the changes in the full-cost ceiling for the United States and Brazil, the March 31, 2009 and December 31, 2008 weighted average wellhead prices are presented in the following table.

	March 31, 2009						December 31, 2008
	Oil		Gas		NGLs		Oil		Gas		NGLs
Country	(Per Bbl)		(Per Mcf)		(Per Bbl)		(Per Bbl)		(Per Mcf)		(Per Bbl)
United States	$	47.30	$	2.67	$	17.04	$	42.21	$	4.68	$	16.16
Brazil	$	36.71		N/A		N/A	$	26.61		N/A		N/A

N/A — Not applicable.

     The March 31, 2009 oil and gas wellhead prices in the table above compare to the NYMEX cash price of $49.66 per Bbl for crude oil and the Henry Hub spot price of $3.63 per MMBtu for gas. The December 31, 2008 oil and gas wellhead prices in the table above compare to the NYMEX cash price of $44.60 per Bbl for crude oil and the Henry Hub spot price of $5.71 per MMBtu for gas.

Income Taxes

     The following table presents our total income tax expense (benefit) related to continuing operations and a reconciliation of our effective income tax rate to the U.S. statutory income tax rate for the three-month and six-month periods ended June 30, 2009 and 2008. The primary factors causing our effective rates to vary from 2008 to 2009, and differ from the U.S. statutory rate, are discussed below.

	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
Total income tax expense (benefit) (In millions)	$	128		$	667		$	(2,141	)	$	908
U.S. statutory income tax rate		35	%		35	%		(35	%)		35	%
Repatriations and tax policy election changes		—			25	%		—			14	%
Other, primarily taxation on foreign operations		(5	%)		(7	%)		(2	%)		(7	%)
Effective income tax rate		30	%		53	%		(37	%)		42	%

     In the six months ended June 30, 2009, our effective tax rate was impacted by the reductions of carrying value that totaled $6.5 billion and had associated deferred tax benefits of $2.3 billion. Excluding the effects of these reductions, our effective tax rate was 26%.

     In both the second quarter and six months ended June 30, 2008, our effective income tax rate was higher than the U.S. statutory income tax rate largely due to two related factors. First, in the second quarter of 2008, we repatriated $1.3 billion in earnings from certain foreign subsidiaries to the United States. Second, we made certain tax policy election changes in the second quarter of 2008 to minimize the taxes we otherwise would pay to all relevant tax jurisdictions for the cash repatriations, as well as the taxable gains associated with the sales of assets in West Africa. As a result of the repatriation and tax policy election changes, we recognized additional tax expense of $312 million during the second quarter of 2008. Of the $312 million, $295 million was recognized as current income tax expense, and $17 million was recognized as deferred tax expense. Excluding the $312 million of additional tax expense, our effective income tax rates would have been 28% for both the second quarter of 2008 and the first half of 2008.

     After adjusting for the factors discussed in the two paragraphs above, our 2009 and 2008 effective tax rates were lower than the U.S. statutory income tax rate largely due to our foreign operations, which have statutory rates lower than the U.S. statutory income tax rate.

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Earnings from Discontinued Operations

     Following are the components of earnings from discontinued operations for the three months and six months ended June 30, 2009 and 2008.

	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2009		2008		2009		2008
	(In millions)
Earnings from discontinued operations before income taxes	$	17	$	851	$	16	$	1,040
Income tax expense		—		144		—		235
Earnings from discontinued operations	$	17	$	707	$	16	$	805

     Earnings from discontinued operations decreased $690 million in the second quarter of 2009 and decreased $789 million in the first half of 2009. Earnings in 2008 included $647 million of after-tax gains resulting from the sale of our assets in Equatorial Guinea, Gabon and other countries in the second quarter of 2008. Our discontinued earnings in 2008 also included operating earnings generated by the assets prior to their sale dates in the second and third quarters of 2008.

Capital Resources, Uses and Liquidity

     The following discussion of capital resources and liquidity should be read in conjunction with the consolidated statements of cash flows included in Part I, Item 1.

Sources and Uses of Cash

	Six Months Ended June 30,
	2009			2008
	(In millions)
Sources of cash and cash equivalents:
Operating cash flow — continuing operations	$	2,070		$	5,080
Commercial paper borrowings		1,330			—
Proceeds from debt issuance, net of commercial paper repayments		182			—
Sales of property and equipment		2			108
Stock option exercises		9			104
Net sales of long-term and short-term investments		4			245
Cash received from discontinued operations		6			1,746
Other		5			55
Total sources of cash and cash equivalents		3,608			7,338
Uses of cash and cash equivalents:
Capital expenditures		(3,201	)		(3,870	)
Net commercial paper repayments		—			(1,004	)
Repayments of debt		(1	)		(1,497	)
Repurchases of common stock		—			(252	)
Redemption of preferred stock		—			(150	)
Dividends		(142	)		(146	)
Total uses of cash and cash equivalents		(3,344	)		(6,919	)
Increase from continuing operations		264			419
Increase from discontinued operations, net of distributions to continuing operations		3			72
Effect of foreign exchange rates		5			(19	)
Net increase in cash and cash equivalents	$	272		$	472
Cash and cash equivalents at end of period	$	656		$	1,845

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 2009. Changes in operating cash flow are largely due to the same factors that affect our net earnings, with the exception of those earnings changes due to noncash expenses such as DD&A, property impairments,

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financial instrument fair value changes and deferred income taxes. Our operating cash flow decreased in 2009 primarily due to the decrease in revenues as discussed in the “Results of Operations” section of this report.

     During the first six months of 2009, our operating cash flow funded approximately 65% of our cash payments for capital expenditures. Commercial paper borrowings were used to fund the remainder of our cash-based capital expenditures. During the first six months of 2008, our operating cash flow was sufficient to fund our cash payments for capital expenditures.

Other Sources of Cash

     As needed, we utilize cash on hand and access our available credit under our credit facilities and commercial paper program as sources of cash to supplement our operating cash flow. We may also issue long-term debt to supplement our operating cash flow while maintaining adequate liquidity under our credit facilities. Additionally, we sometimes acquire short-term investments to maximize our income on available cash balances. As needed, we may reduce such short-term investment balances to further supplement our operating cash flow.

     In January 2009, we issued $500 million of 5.625% senior unsecured notes due January 15, 2014 and $700 million of 6.30% senior unsecured notes due January 15, 2019. The net proceeds received of $1.187 billion, after discounts and issuance costs, were used primarily to repay Devon’s $1.005 billion of outstanding commercial paper as of December 31, 2008.

     Subsequent to the $1.0 billion commercial paper repayment in January 2009, we utilized additional commercial paper borrowings of $1.3 billion to fund capital expenditure and dividend payments in excess of our operating cash flow during the first half of 2009.

     In 2008, another significant source of cash was the proceeds from our African divestiture program. In the second quarter of 2008, we received $2.4 billion in proceeds ($1.7 billion net of income taxes and purchase price adjustments) for sales of assets located in certain West African countries, including Equatorial Guinea—the largest individual transaction in the divestiture program. Also, in conjunction with these asset sales, we repatriated an additional $1.3 billion of earnings from certain foreign subsidiaries to the United States in the second quarter of 2008.

     During the first half of 2008, we used the proceeds from asset sales, repatriated funds and our operating cash flow in excess of capital expenditures to fund debt repayments, common stock repurchases, preferred stock redemptions and dividends on common and preferred stock.

Capital Expenditures

     Following are the components of our capital expenditures for the first half of 2009 and 2008. The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior quarters. Capital expenditures actually incurred during the first half of 2009 and 2008 were approximately $2.6 billion and $4.0 billion, respectively.

	Six Months
	Ended June 30,
	2009		2008
	(In millions)
U.S. Onshore	$	1,649	$	2,082
U.S. Offshore		505		538
Canada		562		707
International		249		277
Total exploration and development		2,965		3,604
Midstream		181		205
Other		55		61
Total cash paid for capital expenditures	$	3,201	$	3,870

     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 or development of oil and gas properties, which totaled $3.0 billion and $3.6 billion in the first half of 2009 and 2008, respectively. Capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas pipeline systems and oil pipelines. As we scale back our drilling activities in response to

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the decline in our operating cash flow, capital expenditures for exploration, development and midstream activities are expected to be lower in the second half of 2009 as compared to the first half.

     Our exploration and development capital expenditures decreased $640 million in the first half of 2009. The lower expenditures primarily related to decreased drilling activities in most of our operating areas.

Net Repayments of Debt

     During the first half of 2008, we repaid $2.5 billion in outstanding credit facility and commercial paper borrowings primarily with proceeds received from the sales of assets under our African divestiture program and cash generated from operations. Also during the first half of 2008, certain holders of exchangeable debentures exercised their option to exchange their debentures for shares of Chevron common stock prior to the debentures’ August 15, 2008 maturity date. In lieu of delivering shares of Chevron common stock we owned, we exercised our option to pay exchanging debenture holders cash equal to the market value of Chevron common stock. We paid $47 million in cash to debenture holders who exercised their exchange rights in the first half of 2008. This amount included the retirement of debentures with a book value of $28 million and a $19 million reduction of the related embedded derivative option’s balance.

Repurchases of Common Stock

     During the first half of 2008, we repurchased 2.8 million common shares for $302 million, or $106.01 per share. The 2.8 million shares include 2.0 million shares that were repurchased under our 50 million share repurchase program and 0.8 million shares that were repurchased under our ongoing, annual stock repurchase program.

Redemption of Preferred Stock

     On June 20, 2008, we redeemed all 1.5 million outstanding shares of our 6.49% Series A cumulative preferred stock. Each share of preferred stock was redeemed for cash at a redemption price of $100 per share, plus accrued and unpaid dividends up to the redemption date.

Dividends

     Our common stock dividends were $142 million and $141 million (quarterly rates of $0.16 per share) in the first six months of 2009 and 2008, respectively. Our preferred dividends were $5 million in the first half of 2008. The elimination of preferred dividends was due to the redemption of our preferred stock in the second quarter of 2008.

Liquidity

     Our primary source of capital and liquidity has historically been our operating cash flow and cash on hand. Additionally, we maintain revolving lines of credit and a commercial paper program that can be accessed as needed to supplement operating cash flow. Other available sources of capital and liquidity include the issuance of equity securities and long-term debt. We estimate these capital resources will provide sufficient liquidity to fund our planned uses of capital.

Operating Cash Flow

     Our operating cash flow is sensitive to many variables, the most volatile of which is pricing of the oil, natural gas and NGLs we produce. Due to sharp declines in commodity prices, our operating cash flow decreased approximately 60% to $2.1 billion in the first half of 2009 compared to the first half of 2008. In spite of this decline, we expect operating cash flow will continue to be a primary source of liquidity. However, based on current commodity prices and near-term price expectations, we also expect that debt borrowings will be a significant source of liquidity during 2009. During the first half of 2009, our net borrowings of long-term debt and commercial paper totaled $1.5 billion. We anticipate we will borrow additional commercial paper during 2009 to assist in funding our capital expenditures and other capital uses.

Credit Lines

     As of July 31, 2009, we had $2.0 billion of available capacity under our syndicated, unsecured credit facilities that can be used to supplement our operating cash flow and cash on hand to fund our capital expenditures and other commitments. The following schedule summarizes the capacity of our credit facilities by maturity date, as well as our available capacity as of July 31, 2009.

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Description	Amount
	(In millions)
Senior Credit Facility maturities:
April 7, 2012	$	500
April 7, 2013		2,150
Senior Credit Facility total capacity		2,650
Short-Term Facility total capacity — November 3, 2009 maturity		700
Total credit facility capacity		3,350
Less:
Outstanding credit facility borrowings		—
Outstanding commercial paper borrowings		1,238
Outstanding letters of credit		90
Total available capacity	$	2,022

     The credit facilities contain only one material financial covenant. This covenant requires Devon to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65%. As of June 30, 2009, Devon was in compliance with this covenant. Devon’s debt-to-capitalization ratio at June 30, 2009, as calculated pursuant to the terms of the agreement, was 21.8%.

Other Capital Resources

     We expect the challenging commodity price environment will likely persist throughout the remainder of 2009. As a result, we are continuing to execute the strategy we outlined at the beginning of the year. That strategy is to decrease our activity across our near-term development projects in North America, to continue advancing our longer term development projects like our second Jackfish heavy oil project in Canada and our Lower Tertiary developments in the Gulf of Mexico, and to continue to drive costs lower and to maintain our strong liquidity position until we see signs of recovery in the hydrocarbon markets.

     Our successes in the deepwater Lower Tertiary and the Jackfish projects in Canada have resulted in growing long-term development commitments. While these long-term projects provide tremendous opportunity, the increasing share of our capital expenditures directed to these longer-term projects reduces capital available to develop our near-term portfolio. This limits our flexibility to adjust capital expenditures to changes in cash flow, particularly in these times of low commodity prices.

     Therefore, we are pursuing a partner to participate in our Lower Tertiary projects in the Gulf of Mexico. The proceeds we may obtain from such a transaction would support the liquidity provided by our operating cash flow and credit lines. Furthermore, our share of the ongoing capital commitments would be reduced, which would provide additional liquidity as well.

Capital Expenditures

     In February 2009, we provided guidance for our 2009 capital expenditures. At that time, we estimated total capital expenditures would range from $4.7 billion to $5.4 billion. This estimate is significantly lower than our 2008 capital expenditures, which coincides with the significant decline in current oil, gas and NGL prices, as well as the near-term price expectations. Based upon current oil and natural gas price expectations, we anticipate having adequate capital resources to fund this planned level of 2009 capital expenditures.

Recently Issued Accounting Standards Not Yet Adopted

     In December 2008, the FASB issued Staff Position No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” Staff Position 132(R)-1 amends FASB Statement No. 132 (revised 2003), Employers’ Disclosures about Pensions and Other Postretirement Benefits, to require additional disclosures about the types of assets and associated risks in an employer’s defined benefit pension or other postretirement plan. Staff Position 132(R)-1 is effective for fiscal years ending after December 15, 2009. We are evaluating the impact the adoption of Staff Position 132(R)-1 will have on our financial statement disclosures. However, our adoption of Staff Position 132(R)-1 will not affect our current accounting for our pension and postretirement plans.

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Modernization of Oil and Gas Reporting

     In December 2008, the SEC adopted revisions to its required oil and gas reporting disclosures. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. In the three decades that have passed since adoption of these disclosure items, there have been significant changes in the oil and gas industry. The amendments are designed to modernize and update the oil and gas disclosure requirements to align them with current practices and changes in technology. In addition, the amendments concurrently align the SEC’s full cost accounting rules with the revised disclosures. The revised disclosure requirements must be incorporated in registration statements filed on or after January 1, 2010, and annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. A company may not apply the new rules to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required.

     The following amendments have the greatest likelihood of affecting our reserve disclosures, including the comparability of our reserves disclosures with those of our peer companies:

•	Pricing mechanism for oil and gas reserves estimation— The SEC’s current rules require proved reserve estimates to be calculated using prices as of the end of the period and held constant over the life of the reserves. Price changes can be made only to the extent provided by contractual arrangements. The revised rules require reserve estimates to be calculated using a 12-month average price. The 12-month average price will also be used for purposes of calculating the full cost ceiling limitations. Price changes can still be incorporated to the extent defined by contractual arrangements. The use of a 12-month average price rather than a single-day price is expected to reduce the impact on reserve estimates and the full cost ceiling limitations due to short-term volatility and seasonality of prices.
•	Reasonable certainty— The SEC’s current definition of “proved oil and gas reserves” incorporate certain specific concepts such as “lowest known hydrocarbons,” which limits the ability to claim proved reserves in the absence of information on fluid contacts in a well penetration, notwithstanding the existence of other engineering and geoscientific evidence. The revised rules amend the definition to permit the use of new reliable technologies to establish the reasonable certainty of proved reserves. This revision also includes provisions for establishing levels of lowest known hydrocarbons and highest known oil through reliable technology other than well penetrations.
	The revised rules also amend the definition of proved oil and gas reserves to include reserves located beyond development spacing areas that are immediately adjacent to developed spacing areas if economic producibility can be established with reasonable certainty. These revisions are designed to permit the use of reliable technologies to establish proved reserves in lieu of requiring companies to use specific tests. In addition, they establish a uniform standard of reasonable certainty that applies to all proved reserves, regardless of location or distance from producing wells.
	Because the revised rules generally expand the definition of proved reserves, we expect our proved reserve estimates will increase upon adoption of the revised rules. However, we are not able to estimate the magnitude of the potential increase at this time.
•	Unproved reserves— The SEC’s current rules prohibit disclosure of reserve estimates other than proved in documents filed with the SEC. The revised rules permit disclosure of probable and possible reserves and provide definitions of probable reserves and possible reserves. Disclosure of probable and possible reserves is optional. However, such disclosures must meet specific requirements. Disclosures of probable or possible reserves must provide the same level of geographic detail as proved reserves and must state whether the reserves are developed or undeveloped. Probable and possible reserve disclosures must also provide the relative uncertainty associated with these classifications of reserves estimations. We have not yet determined whether we will disclose our probable and possible reserves in documents filed with the SEC.

Item 3.Quantitative and Qualitative Disclosures About Market Risk

     Commodity Price Risk

     We have various financial price collars to set minimum and maximum prices on a portion of our 2009 gas production. The key terms to the price collars we had entered into prior to the filing of our 2008 Annual Report on Form 10-K are included in Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2008 Annual Report on Form 10-K.

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     In addition, subsequent to the preparation of our 2008 Annual Report on Form 10-K, we entered into additional gas financial price swaps related to a portion of our expected third and fourth quarter 2009 gas production. We also entered into oil financial price collars related to a portion of our expected 2010 oil production. The key terms to these gas and oil financial contracts as of August 3, 2009 are presented in the following tables.

Gas Price Swap Contracts
			Weighted
			Average
	Volume		Price
2009 Period	(MMBtu/d)		($/MMBtu)
Third Quarter		52,174	$	4.01
Fourth Quarter		600,000	$	4.81

Oil Price Collar Contracts
					Ceiling Price
							Weighted
			Floor		Ceiling		Average
	Volume		Price		Range		Ceiling Price
2010 Period	(Bbls/d)		($/Bbl)		($/Bbl)		($/Bbl)
First Quarter		4,000	$	65.00	$	90.35 - $92.00	$	90.93
Second Quarter		4,000	$	65.00	$	90.35 - $92.00	$	90.93
Third Quarter		4,000	$	65.00	$	90.35 - $92.00	$	90.93
Fourth Quarter		4,000	$	65.00	$	90.35 - $92.00	$	90.93

     The fair values of our commodity financial hedging instruments are largely determined by estimates of the forward curves of the Inside FERC Henry Hub and West Texas Intermediate indices. At August 3, 2009, a 10% increase in the forward curves for these two indices would have decreased the fair value of our financial hedging instruments by approximately $48 million.

     Interest Rate Risk

     At June 30, 2009, we had debt outstanding of $7.4 billion. Of this amount, $6.1 billion, or 82%, bears interest at fixed rates averaging 7.23%. Additionally, we had $1.3 billion of outstanding commercial paper, bearing interest at floating rates that averaged 0.48%.

     We also have interest rate swaps to mitigate a portion of the fair value effects of interest rate fluctuations on our fixed-rate debt. The key terms to these interest rate swaps are included in Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2008 Annual Report on Form 10-K.

     In addition, subsequent to the preparation of our 2008 Annual Report on Form 10-K, we entered into additional interest rate swaps that have a total notional value of $450 million as of July 31, 2009. These new swaps include a swap with a $100 million notional amount in which we receive a fixed rate of 1.90% and pay a floating rate based upon the Federal funds rate. This swap expires on August 3, 2012. The remainder of the new swaps with a total notional value of $350 million expire on September 30, 2011. Under the terms of these swaps, we will net settle these contracts in September 2011. The net settlement amount will be based upon us paying a weighted-average fixed rate of 3.86% and receiving a floating rate that is based upon the three-month LIBOR. The difference between the fixed and floating rate will be applied to the notional amount for the 30-year period from September 30, 2011 to September 30, 2041.

     The fair values of our interest rate instruments are largely determined by estimates of the forward curves of the Federal Funds Rate and LIBOR. At August 3, 2009, a 10% increase in these forward curves would have increased the fair value of our interest rate derivative instruments by approximately $16 million.

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.

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     Based on their evaluation, Devon’s principal executive and principal financial officers have concluded that Devon’s 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, 2009 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 was no change in Devon’s internal control over financial reporting during the second quarter of 2009 that has materially affected, or is reasonably likely to materially affect, Devon’s internal control over financial reporting.

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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 2008 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 2008 Annual Report on Form 10-K.

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

     No shares have been repurchased during the first half of 2009.

     As of June 30, 2009, we are authorized to repurchase 50.3 million common shares. This amount is comprised of 45.5 million remaining common shares authorized to be repurchased under a 50 million share repurchase program and 4.8 million common shares authorized to be repurchased in 2009 under an annual repurchase program.

Item 3.Defaults Upon Senior Securities

     None.

Item 4.Submission of Matters to a Vote of Security Holders

     (a) Devon’s Annual Meeting of Stockholders was held in Oklahoma City, Oklahoma at 8:00 a.m., local time, on Wednesday, June 3, 2009.

     (b) Proxies for the meeting were solicited pursuant to Regulation 14 under the Securities Exchange Act of 1934, as amended. There was no solicitation in opposition to the nominees for election as Directors as listed in the Proxy Statement for the June 3, 2009 meeting and all nominees were elected.

     (c) A total of 387,917,955 shares of Devon’s common stock outstanding and entitled to vote were present at the June 3, 2009 meeting in person or by proxy, representing approximately 87.39% of the total outstanding shares. The matters voted upon were as follows:

     1. The election of four Directors to serve on Devon’s Board of Directors until the 2011 Annual Meeting of Stockholders. A total of at least 94.7% of all voted shares were cast for approval of each nominee. The vote tabulation with respect to each nominee was as follows:

			Authority
Nominee	For		Withheld
Robert L. Howard		375,847,281		12,070,674
Michael M. Kanovsky		367,345,603		20,572,352
J. Todd Mitchell		380,022,026		7,895,929
J. Larry Nichols		372,677,625		15,240,330

     2. Ratification of the appointment of Robert A. Mosbacher, Jr., as a Director. A total of 98.50% of all voted shares were cast for ratification of Mr. Mosbacher’s appointment as a Director. The results of the votes are as follows:

FOR:	382,108,112
AGAINST:	5,481,303
ABSTAIN:	328,540

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     3. Ratification of KPMG LLP as the Company’s Independent Auditors for 2009. A total of 98.15% of all voted shares were cast for ratification of KPMG LLP. The results of the votes are as follows:

FOR:	380,778,605
AGAINST:	6,844,037
ABSTAIN:	295,313

     4. The adoption of the Devon Energy Corporation 2009 Long-Term Incentive Plan. A total of 83.47% of all voted shares were cast to adopt the Devon Energy Corporation 2009 Long-Term Incentive Plan.

FOR:	283,859,154
AGAINST:	55,115,197
ABSTAIN:	48,943,604

     5. A shareholder proposal for a Director Election Majority Vote Standard. A total of 51.55% of all voted shares were cast against the shareholder proposal for a Director Election Majority Vote Standard.

FOR:	164,104,358
AGAINST:	175,332,782
ABSTAIN:	48,480,815

Item 5.Other Information

     None.

Item 6.Exhibits

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

Exhibit
Number	Description
31.1	Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Danny J. Heatly, Senior Vice President — Accounting and Chief Accounting Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Danny J. Heatly, Senior Vice President — Accounting and Chief Accounting Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted 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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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 6, 2009	/s/ Danny J. Heatly
	Danny J. Heatly
	Senior Vice President — Accounting and Chief Accounting Officer

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INDEX TO EXHIBITS

Exhibit
Number	Description
31.1	Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Danny J. Heatly, Senior Vice President — Accounting and Chief Accounting Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Danny J. Heatly, Senior Vice President — Accounting and Chief Accounting Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted 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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