Devon Energy (DVN) 10-Q 2008 Q3 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 September 30, 2008

or

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

Commission File No. 001-32318

Devon Energy Corporation

(Exact Name of Registrant as Specified in its Charter)

Delaware
(State or Other Jurisdiction of
Incorporation or Organization) 73-1567067
(I.R.S. Employer
Identification Number)

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 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.

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

     As of October 31, 2008, 441.5 million shares of the registrant’s common stock were outstanding.

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2

DEVON ENERGY CORPORATION

INDEX TO FORM 10-Q QUARTERLY REPORT
TO THE SECURITIES AND EXCHANGE COMMISSION

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS	4
DEFINITIONS	5
PART I. FINANCIAL INFORMATION	6
Item 1. Consolidated Financial Statements	6
Consolidated Balance Sheets as of September 30, 2008 (Unaudited) and December 31, 2007	6
Consolidated Statements of Operations (Unaudited) for the Three Months and Nine Months Ended September 30, 2008 and 2007	7
Consolidated Statements of Comprehensive Income (Unaudited) for the Three Months and Nine Months Ended September 30, 2008 and 2007	8
Consolidated Statements of Stockholders’ Equity (Unaudited) for the Nine Months Ended September 30, 2008 and 2007	9
Consolidated Statements of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2008 and 2007	10
Notes to Consolidated Financial Statements (Unaudited)	11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3. Quantitative and Qualitative Disclosures About Market Risk	46
Item 4. Controls and Procedures	47
PART II. OTHER INFORMATION	48
Item 1. Legal Proceedings	48
Item 1A. Risk Factors	48
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	48
Item 3. Defaults Upon Senior Securities	48
Item 4. Submission of Matters to a Vote of Security Holders	48
Item 5. Other Information	48
Item 6. Exhibits	49
SIGNATURES	49
EX-10.1
EX-10.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2

3

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 that was used to prepare the December 31, 2007 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,” or “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;

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

• reserve levels;

• competitive conditions;

• technology;

• the availability of capital resources;

• capital expenditure and other contractual obligations;

• the supply and demand for oil, natural gas, NGLs and other energy products or services;

• the price of oil, natural gas, NGLs and other energy products or services;

• currency exchange rates, particularly the Canadian-to-U.S. dollar exchange rate;

• 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 or the timing of such planned transactions;

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

• other factors disclosed in Devon’s 2007 Annual Report on Form 10-K/A 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.

4

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.

     “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.

     “LIBOR” means London Interbank Offered Rate.

     “Mcf” means thousand cubic feet.

     “MMBbls” means million barrels.

     “MMBoe” means million Boe.

     “MMBtu” means million Btu.

     “Oil” includes crude oil and condensate.

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

     “NYMEX” means New York Mercantile Exchange.

     “SEC” means United States Securities and Exchange Commission.

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

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

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

5

PART I. Financial Information

Item 1.Consolidated Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	September 30,		December 31,
	2008		2007
	(Unaudited)
	(In millions)
ASSETS
Current assets:
Cash and cash equivalents	$	1,193	$	1,364
Short-term investments, at fair value		1		372
Accounts receivable		1,710		1,779
Current assets held for sale		88		120
Other current assets, including $142 million at fair value in 2008		427		279
Total current assets		3,419		3,914
Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($4,073 and $3,417 excluded from amortization in 2008 and 2007, respectively)		53,750		48,473
Less accumulated depreciation, depletion and amortization		22,300		20,394
		31,450		28,079
Investment in Chevron Corporation common stock, at fair value		1,170		1,324
Goodwill		5,966		6,172
Long-term assets held for sale		19		1,512
Other long-term assets, including $158 million at fair value in 2008		631		455
Total assets	$	42,655	$	41,456
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable — trade	$	1,559	$	1,360
Revenues and royalties due to others		775		578
Income taxes payable		188		97
Short-term debt		—		1,004
Current portion of asset retirement obligation, at fair value		115		82
Current liabilities associated with assets held for sale		12		145
Accrued expenses and other current liabilities		410		391
Total current liabilities		3,059		3,657
Debentures exchangeable into shares of Chevron Corporation common stock		—		641
Other long-term debt		4,837		6,283
Derivative financial instruments, at fair value		—		488
Asset retirement obligation, at fair value		1,456		1,236
Long-term liabilities associated with assets held for sale		1		404
Other long-term liabilities		833		699
Deferred income taxes		7,179		6,042
Stockholders’ equity:
Preferred stock of $1.00 par value. Authorized 4.5 million shares; issued 1.5 million shares ($150 million aggregate liquidation value) in 2007		—		1
Common stock of $0.10 par value. Authorized 1.0 billion shares; issued 441.4 million and 444.2 million shares in 2008 and 2007, respectively		44		44
Additional paid-in capital		6,219		6,743
Retained earnings		17,265		12,813
Accumulated other comprehensive income		1,762		2,405
Total stockholders’ equity		25,290		22,006
Commitments and contingencies (Note 9)
Total liabilities and stockholders’ equity	$	42,655	$	41,456

See accompanying notes to consolidated financial statements.

6

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(Unaudited)
	(In millions, except per share amounts)
Revenues:
Oil sales	$	1,296		$	905		$	4,001		$	2,461
Gas sales		2,107			1,175			5,947			3,787
NGL sales		362			242			1,069			643
Net gain (loss) on oil and gas derivative financial instruments		1,592			7			(411	)		1
Marketing and midstream revenues		621			434			1,895			1,273
Total revenues		5,978			2,763			12,501			8,165
Expenses and other income, net:
Lease operating expenses		591			457			1,634			1,326
Production taxes		152			85			462			255
Marketing and midstream operating costs and expenses		452			301			1,349			912
Depreciation, depletion and amortization of oil and gas properties		781			705			2,280			1,937
Depreciation and amortization of non-oil and gas properties		67			51			186			146
Accretion of asset retirement obligation		22			19			66			55
General and administrative expenses		146			126			474			358
Interest expense		69			108			261			325
Change in fair value of other financial instruments		46			(22	)		22			(31	)
Other income, net		(83	)		(28	)		(121	)		(71	)
Total expenses and other income, net		2,243			1,802			6,613			5,212
Earnings from continuing operations before income tax expense		3,735			961			5,888			2,953
Income tax expense:
Current		226			96			743			459
Deferred		1,000			221			1,391			452
Total income tax expense		1,226			317			2,134			911
Earnings from continuing operations		2,509			644			3,754			2,042
Discontinued operations:
Earnings from discontinued operations before income tax expense		93			177			1,133			442
Income tax (benefit) expense		(16	)		86			219			194
Earnings from discontinued operations		109			91			914			248
Net earnings		2,618			735			4,668			2,290
Preferred stock dividends		—			2			5			7
Net earnings applicable to common stockholders	$	2,618		$	733		$	4,663		$	2,283
Basic net earnings per share:
Earnings from continuing operations	$	5.67		$	1.45		$	8.44		$	4.57
Earnings from discontinued operations		0.25			0.20			2.06			0.56
Net earnings	$	5.92		$	1.65		$	10.50		$	5.13
Diluted net earnings per share:
Earnings from continuing operations	$	5.63		$	1.43		$	8.36		$	4.52
Earnings from discontinued operations		0.24			0.20			2.04			0.55
Net earnings	$	5.87		$	1.63		$	10.40		$	5.07
Weighted average common shares outstanding:
Basic		442			445			444			445
Diluted		446			450			448			450

See accompanying notes to consolidated financial statements.

7

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(Unaudited)
	(In millions)
Net earnings	$	2,618		$	735		$	4,668		$	2,290
Foreign currency translation:
Change in cumulative translation adjustment		(386	)		579			(679	)		1,311
Income tax benefit (expense)		15			(33	)		29			(74	)
Total		(371	)		546			(650	)		1,237
Pension and postretirement benefit plans:
Recognition of net actuarial loss and prior service cost in net earnings		4			4			12			12
Income tax expense		(2	)		(2	)		(5	)		(5	)
Total		2			2			7			7
Other		—			—			—			(1	)
Other comprehensive (loss) income, net of tax		(369	)		548			(643	)		1,243
Comprehensive income	$	2,249		$	1,283		$	4,025		$	3,533

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)
Nine Months Ended September 30, 2008:
Balance as of December 31, 2007	$	1			444		$	44		$	6,743		$	12,813		$	2,405		$	—		$	22,006
Net earnings		—			—			—			—			4,668			—			—			4,668
Other comprehensive loss		—			—			—			—			—			(643	)		—			(643	)
Stock option exercises		—			4			1			112			—			—			(4	)		109
Common stock repurchased		—			—			—			—			—			—			(681	)		(681	)
Common stock retired		—			(7	)		(1	)		(684	)		—			—			685			—
Redemption of preferred stock		(1	)		—			—			(149	)		—			—			—			(150	)
Common stock dividends		—			—			—			—			(211	)		—			—			(211	)
Preferred stock dividends		—			—			—			—			(5	)		—			—			(5	)
Share-based compensation		—			—			—			139			—			—			—			139
Excess tax benefits on share-based compensation		—			—			—			58			—			—			—			58
Balance as of September 30, 2008	$	—			441		$	44		$	6,219		$	17,265		$	1,762		$	—		$	25,290
Nine Months Ended September 30, 2007:
Balance as of December 31, 2006	$	1			444		$	44		$	6,840		$	9,114		$	1,444		$	(1	)	$	17,442
Adoption of FASB Statement No. 159		—			—			—			—			364			(364	)		—			—
Adoption of FASB Interpretation No. 48		—			—			—			—			(10	)		—			—			(10	)
Adoption of FASB Statement No. 158		—			—			—			—			(1	)		16			—			15
Net earnings		—			—			—			—			2,290			—			—			2,290
Other comprehensive income		—			—			—			—			—			1,243			—			1,243
Stock option exercises		—			3			1			70			—			—			—			71
Common stock repurchased		—			—			—			—			—			—			(138	)		(138	)
Common stock retired		—			(2	)		—			(139	)		—			—			139			—
Common stock dividends		—			—			—			—			(186	)		—			—			(186	)
Preferred stock dividends		—			—			—			—			(7	)		—			—			(7	)
Share-based compensation		—			—			—			92			—			—			—			92
Excess tax benefits on share-based compensation		—			—			—			20			—			—			—			20
Balance as of September 30, 2007	$	1			445		$	45		$	6,883		$	11,564		$	2,339		$	—		$	20,832

See accompanying notes to consolidated financial statements.

9

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months
	Ended September 30,
	2008			2007
	(Unaudited)
	(In millions)
Cash flows from operating activities:
Net earnings	$	4,668		$	2,290
Earnings from discontinued operations, net of tax		(914	)		(248	)
Adjustments to reconcile earnings from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization		2,466			2,083
Deferred income tax expense		1,391			452
Net unrealized (gain) loss on oil and gas derivative financial instruments		(140	)		30
Other noncash charges		217			94
(Increase) decrease in assets:
Accounts receivable		32			(12	)
Other current assets		(85	)		(65	)
Other long-term assets		(63	)		(53	)
Increase (decrease) in liabilities:
Accounts payable		223			113
Revenues and royalties due to others		278			(2	)
Income taxes payable		36			139
Other current liabilities		(124	)		(78	)
Other long-term liabilities		94			(4	)
Cash provided by operating activities — continuing operations		8,079			4,739
Cash provided by operating activities — discontinued operations		102			370
Net cash provided by operating activities		8,181			5,109
Cash flows from investing activities:
Proceeds from sales of property and equipment		116			39
Capital expenditures		(6,179	)		(4,477	)
Purchases of short-term investments		(50	)		(659	)
Redemptions of short-term and long-term investments		297			892
Cash used in investing activities — continuing operations		(5,816	)		(4,205	)
Cash provided by (used in) investing activities — discontinued operations		1,854			(153	)
Net cash used in investing activities		(3,962	)		(4,358	)
Cash flows from financing activities:
Credit facility repayments		(3,191	)		—
Credit facility borrowings		1,741			400
Net commercial paper repayments		(1,004	)		(129	)
Principal payments on debt		(1,031	)		(166	)
Preferred stock redemption		(150	)		—
Proceeds from stock option exercises		109			71
Repurchases of common stock		(665	)		(133	)
Dividends paid on common and preferred stock		(216	)		(193	)
Excess tax benefits related to share-based compensation		58			20
Net cash used in financing activities		(4,349	)		(130	)
Effect of exchange rate changes on cash		(47	)		44
Net (decrease) increase in cash and cash equivalents		(177	)		665
Cash and cash equivalents at beginning of period (including cash related to assets held for sale)		1,373			756
Cash and cash equivalents at end of period (including cash related to assets held for sale)	$	1,196		$	1,421
Supplementary cash flow data:
Interest paid (net of capitalized interest)	$	298		$	226
Income taxes paid — continuing and discontinued operations	$	1,162		$	293

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 2007 Annual Report on Form 10-K/A.

     The unaudited interim consolidated financial statements furnished in this report reflect all adjustments which are, in the opinion of management, necessary to a fair statement of Devon’s financial position as of September 30, 2008 and Devon’s results of operations and cash flows for the three-month and nine-month periods ended September 30, 2008 and 2007. Except for the reclassification of auction rate securities discussed below, all such adjustments are of a normal recurring nature.

Reclassification of Auction Rate Securities

     At December 31, 2007, Devon held $372 million of auction rate securities. Such securities are rated AAA—the highest rating—by one or more rating agencies and are collateralized by student loans that are substantially guaranteed by the United States government. Although Devon’s auction rate securities generally have contractual maturities of more than 20 years, the underlying interest rates on such securities are scheduled to reset every seven to 28 days. Therefore, these auction rate securities were generally priced and subsequently traded as short-term investments because of the interest rate reset feature. As a result, Devon classified its auction rate securities as short-term investments in the accompanying December 31, 2007 consolidated balance sheet and in prior periods.

     During the first nine months of 2008, Devon reduced its auction rate securities holdings to $125 million. However, since February 8, 2008, Devon has experienced difficulty selling its securities due to the failure of the auction mechanism, which provided liquidity to these securities. An auction failure means that the parties wishing to sell securities could not do so. The securities for which auctions have failed will continue to accrue interest and be auctioned every seven to 28 days until the auction succeeds, the issuer calls the securities or the securities mature.

     From February 2008, when auctions began failing, to September 30, 2008, issuers redeemed $27 million of Devon’s auction rate securities holdings at par. Additionally, Devon’s auction rate securities holdings as of September 30, 2008, include approximately $1 million of securities that were called at par value by the issuer and were repaid on October 1, 2008. These called securities are classified as short-term investments in the accompanying September 30, 2008 consolidated balance sheet. However, based on continued auction failures and the current market for Devon’s auction rate securities, Devon has classified the $124 million of securities that have not been called as of September 30, 2008 as long-term investments. These securities are included in other long-term assets in the accompanying September 30, 2008 consolidated balance sheet. Devon has the ability to hold the securities until maturity. At this time, Devon does not believe the values of its long-term securities are impaired.

Recently Issued Accounting Standards Not Yet Adopted

     In December 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 141(R),Business Combinations, which replaces Statement No. 141. Statement No. 141(R) retains the fundamental requirements of Statement No. 141 that an acquirer be identified and the acquisition method of accounting (previously called the purchase method) be used for all business combinations. Statement No. 141(R)’s scope is broader than that of Statement No. 141, which applied only to business combinations in which control was obtained by transferring consideration. By applying the acquisition method to all transactions and other events in which one entity obtains control over one or more other businesses, Statement No. 141(R) improves the comparability of the information about business combinations provided in financial reports. Statement No. 141(R) establishes principles and requirements for how an acquirer recognizes and measures identifiable assets acquired, liabilities assumed and any noncontrolling interest in the acquiree, as well as any resulting goodwill. Statement No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Devon will evaluate how the new requirements of Statement No. 141(R) would impact any business combinations completed in 2009 or thereafter.

11

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

     In December 2007, the FASB also issued Statement of Financial Accounting Standards No. 160,Noncontrolling Interests in Consolidated Financial Statements—an amendment of Accounting Research Bulletin No. 51. A noncontrolling interest, sometimes called a minority interest, is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. Statement No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Under Statement No. 160, noncontrolling interests in a subsidiary must be reported as a component of consolidated equity separate from the parent’s equity. Additionally, the amounts of consolidated net income attributable to both the parent and the noncontrolling interest must be reported separately on the face of the income statement. Statement No. 160 is effective for fiscal years beginning on or after December 15, 2008 and earlier adoption is prohibited. Devon does not expect the adoption of Statement No. 160 to have a material impact on its financial statements and related disclosures.

     In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161,Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133. Statement No. 161 requires additional disclosures about derivative and hedging activities and is effective for fiscal years and interim periods beginning after November 15, 2008. Devon is evaluating the impact the adoption of Statement No. 161 will have on its financial statement disclosures. However, Devon’s adoption of Statement No. 161 will not affect its current accounting for derivative and hedging activities.

2. Other Current Assets

     The components of other current assets include the following:

	September 30, 2008		December 31, 2007
	(In millions)
Inventories	$	217	$	144
Derivative financial instruments, at fair value		142		12
Other current assets		68		123
Total	$	427	$	279

3. Property and Equipment and Asset Retirement Obligations

Divestitures

     Near the beginning of 2007, Devon announced plans to sell its assets and terminate its operations located in Africa. This divestiture package consisted primarily of Devon’s operations located in Egypt and the West African countries of Equatorial Guinea, Gabon and Cote d’Ivoire. All of the assets in these countries were sold prior to September 30, 2008. Additional information regarding Devon’s Egyptian and West African operations, which are presented as discontinued in the accompanying financial statements, is provided in Note 13.

Asset Retirement Obligations (“ARO”)

     The following is a summary of the changes in Devon’s ARO for the first nine months of 2008 and 2007.

	Nine Months
	Ended September 30,
	2008			2007
	(In millions)
Asset retirement obligation as of beginning of period	$	1,318		$	857
Liabilities incurred		48			44
Liabilities settled		(59	)		(52	)
Revision of estimated obligation		244			311
Accretion expense on discounted obligation		66			55
Foreign currency translation adjustment		(46	)		85
Asset retirement obligation as of end of period		1,571			1,300
Less current portion		115			54
Asset retirement obligation, long-term	$	1,456		$	1,246

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(Unaudited)

     During the first nine months of 2008 and 2007, Devon recognized increases of $244 million and $311 million, respectively, to its ARO. The ARO increased $162 million in 2008 as a result of an overall increase in abandonment cost estimates and the effect of a decrease in the discount rate used to present value the obligations. In the third quarter of 2008, the ARO increased $82 million as a result of higher abandonment cost estimates related to certain offshore platforms that were destroyed by Hurricane Ike. See additional discussion regarding this revision in Note 9 — Hurricane Contingencies. The primary factors causing the 2007 fair value increase were an overall increase in abandonment cost estimates and an increase in the assumed inflation rate.

4. Derivative Financial Instruments

     Devon periodically enters into derivative financial instruments with respect to a portion of its oil and gas production that hedge the future prices received. These instruments are used to manage the inherent uncertainty of future revenues due to oil and gas price volatility. Devon’s derivative financial instruments include financial price swaps, whereby Devon will receive a fixed price for its production and pay a variable market price to the contract counterparty, and costless price collars that set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty to the collars.

     Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. In the third quarter of 2008, Devon entered into interest rate swaps to mitigate a portion of the fair value effects of interest rate fluctuations on its fixed-rate debt. Under the terms of these swaps, Devon receives a fixed rate and pays a variable rate on a total notional amount of $1.05 billion.

     As discussed more fully in Note 1 to the consolidated financial statements in Devon’s 2007 Annual Report on Form 10-K/A, Devon’s derivative financial instruments are recognized at the current fair value on the balance sheet. Unrealized changes in such fair values are recorded in the statement of operations. Cash settlements with counterparties to Devon’s price swaps, price collars and interest rate swaps are also recorded in the statement of operations.

Commodity Derivative Financial Instruments

     The following tables present the fair values included in the accompanying balance sheet and the cash settlements and net unrealized gains and losses included in the accompanying statement of operations associated with Devon’s commodity derivative financial instruments.

	September 30, 2008		December 31, 2007
	(In millions)
Fair values:
Other current assets:
Gas price swaps	$	39	$	12
Gas price collars		98		—
Total commodity derivative financial instruments, other current assets	$	137	$	12
Other long-term assets — gas price collars	$	16	$	—
Accrued expenses and other current liabilities — oil collars	$	1	$	—

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(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(In millions)
Cash settlements:
Gas price swaps	$	(115	)	$	14		$	(276	)	$	29
Gas price collars		(125	)		—			(275	)		2
Total cash settlements (paid) received		(240	)		14			(551	)		31
Unrealized gains (losses) on fair value changes:
Gas price swaps		645			(7	)		27			(26	)
Gas price collars		1,142			—			114			(4	)
Oil price collars		45			—			(1	)		—
Total unrealized gains (losses) on fair value changes		1,832			(7	)		140			(30	)
Net gain (loss) on oil and gas derivative financial instruments	$	1,592		$	7		$	(411	)	$	1

Interest Rate Swaps

     As of September 30, 2008, Devon’s interest rate swaps had a positive fair value of $23 million. Based on scheduled settlement dates for these swaps, $5 million of this amount is classified as other current assets in the accompanying balance sheet. The remaining $18 million is classified as other long-term assets. In addition, the $23 million unrealized gain during the third quarter of 2008 is included in change in fair value of other financial instruments in the accompanying statement of operations. There were no cash settlements in the third quarter of 2008.

5. Debt

Senior Credit Facility

     In April 2008, Devon extended the maturity of $2.0 billion of its existing $2.5 billion five-year, syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) from April 7, 2012 to April 7, 2013. Lenders representing $0.5 billion of the Senior Credit Facility did not approve a maturity date extension. Therefore, the maturity date for $0.5 billion of the Senior Credit Facility remains at April 7, 2012. In August 2008, Devon secured an additional $150 million of available credit under its Senior Credit Facility. The additional $150 million will mature on April 7, 2013. This increases Devon’s total line of credit under its Senior Credit Facility to $2.65 billion.

     The Senior Credit Facility contains 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 September 30, 2008, Devon was in compliance with this covenant. Devon’s debt-to-capitalization ratio at September 30, 2008, as calculated pursuant to the terms of the agreement, was 15.4%.

     During the second quarter of 2008, Devon repaid $2.5 billion of outstanding commercial paper and Senior Credit Facility borrowings primarily with proceeds received from the sales of assets in West Africa and cash generated from operations. As of November 5, 2008, Devon’s available capacity under its Senior Credit Facility was approximately $2.4 billion. This available capacity is net of $118 million of outstanding letters of credit and $137 million of outstanding commercial paper borrowings as of November 5, 2008.

Short-Term Credit Facilities

     Devon had a $1.5 billion 364-day, syndicated, unsecured revolving senior credit facility. This facility matured on August 5, 2008 and was not extended.

     On November 5, 2008, Devon established a new $700 million 364-day, syndicated, unsecured revolving senior credit facility (the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

“Short-Term Facility”). This new facility provides Devon with incremental liquidity to support the retirement of maturing debentures during 2008 and near-term capital expenditures. The Short-Term Facility also supports an increase in Devon’s commercial paper program to $2.85 billion.

     The Short-Term Facility matures on November 3, 2009. On the maturity date, all amounts outstanding will be due and payable at that time. Amounts borrowed under the Short-Term Facility bear interest at various fixed rate options for periods of up to 12 months. Such rates are generally based on LIBOR or the prime rate. The Short-Term Facility currently provides for an annual facility fee of approximately $0.7 million that is payable quarterly in arrears.

     The agreement governing the Short-Term Facility contains substantially the same covenants and restrictions as Devon’s existing Senior Credit Facility, including a maximum allowed debt-to-capitalization ratio of 65% as defined in the agreement.

     As of November 5, 2008, there were no amounts borrowed under the Short-Term Facility, and the available capacity was $700 million.

Exchangeable Debentures

     During 2008, virtually all holders of exchangeable debentures exercised their option to exchange their debentures for shares of Chevron Corporation (“Chevron”) common stock owned by Devon. The debentures matured on August 15, 2008. In lieu of delivering its shares of Chevron common stock, Devon exercised its option to pay the exchanging debenture holders cash totaling $1.0 billion.

6. 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 fair value measurement information for such assets and liabilities as of September 30, 2008 and December 31, 2007. Following the tables, additional information is provided for those assets and liabilities in which Devon uses significant unobservable inputs (Level 3) to measure fair value.

	As of September 30, 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):
Short-term and long-term investments	$	125		$	125		$	1	$	—	$	124
Investment in Chevron common stock	$	1,170		$	1,170		$	1,170	$	—	$	—
Net oil and gas price swaps and collars	$	152		$	152		$	—	$	152	$	—
Interest rate swaps	$	23		$	23		$	—	$	23	$	—
Asset retirement obligation	$	(1,571	)	$	(1,571	)	$	—	$	—	$	(1,571	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

	As of December 31, 2007
							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):
Short-term investments	$	372		$	372		$	372	$	—		$	—
Investment in Chevron common stock	$	1,324		$	1,324		$	1,324	$	—		$	—
Gas price swaps	$	12		$	12		$	—	$	12		$	—
Embedded option in exchangeable debentures	$	(488	)	$	(488	)	$	—	$	(488	)	$	—
Asset retirement obligation	$	(1,318	)	$	(1,318	)	$	—	$	—		$	(1,318	)

Level 3 Fair Value Measurements

     Short-term and long-term investments— Devon’s short-term and long-term investments presented in the tables above as of September 30, 2008 and December 31, 2007 consisted entirely of auction rate securities, which are discussed in greater detail in Note 1. As of December 31, 2007, Devon estimated the fair values of its short-term investments using quoted market prices. However, due to the auction failures discussed in Note 1 and the lack of an active market for Devon’s long-term auction rate securities, quoted market prices for the vast majority of these securities were not available as of September 30, 2008. Therefore, Devon used valuation techniques that rely on unobservable, or Level 3, inputs to estimate the fair values of its long-term auction rate securities as of September 30, 2008. These inputs were based on the AAA credit rating of the securities, the probability of full repayment of the securities considering the United States government guarantees of substantially all of the underlying student loans, the collection of all accrued interest to date and continued receipts of principal at par. As a result of using these inputs, Devon concluded the estimated fair values of its long-term auction rate securities approximated the par values as of September 30, 2008. At this time, Devon does not believe the values of its long-term securities are impaired.

     Included below is a summary of the changes in Devon’s Level 3 short-term and long-term investments during the first nine months of 2008 (in millions).

Beginning balance	$	—
Transfers from Level 1 to Level 3		129
Redemptions of principal		(5	)
Ending balance	$	124

     Asset retirement obligation— The fair values of the asset retirement obligations are estimated using internal discounted cash flow calculations based upon Devon’s estimates of future retirement costs. A summary of the changes in Devon’s asset retirement obligation, including revisions of the estimated fair value in 2008 and 2007, is presented in Note 3.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

7. 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 nine-month periods ended September 30, 2008 and 2007.

	Pension Benefits													Other Postretirement Benefits
	Three Months							Nine Months						Three Months				Nine Months
	Ended September 30,							Ended September 30,						Ended September 30,				Ended September 30,
	2008			2007				2008			2007			2008		2007		2008		2007
	(In millions)
Net periodic benefit cost:
Service cost	$	10		$	8			$	30		$	23		$	—	$	—	$	—	$	—
Interest cost		14			11		��		42			33			2		1		6		3
Expected return on plan assets		(13	)		(12	)			(39	)		(36	)		—		—		—		—
Net actuarial loss and prior service cost		4			3				12			10			—		—		—		—
Net periodic benefit cost		15			10				45			30			2		1		6		3
Other comprehensive income:
Recognition of net actuarial loss and prior service cost in net periodic benefit cost		(4	)		(4	)			(12	)		(12	)		—		—		—		—
Total recognized	$	11		$	6			$	33		$	18		$	2	$	1	$	6	$	3

     Devon previously disclosed in its financial statements for the year ended December 31, 2007, that it expected to contribute $8 million to its defined benefit pension plans and $6 million to its defined benefit postretirement plans in 2008. Subsequent to the end of 2007, Devon raised its estimated 2008 contributions to its pension plans to $24 million. As of September 30, 2008, Devon had contributed $14 million to the pension plans and $5 million to the postretirement plans.

     Devon’s assets related to its pension plans have been adversely impacted by the performance of the equity markets in recent months, especially since September 30, 2008. Losses incurred on these investments will likely cause Devon to contribute more to its pension plans in 2009 than what would otherwise have been expected. Such losses will also likely cause an increase in Devon’s pension expense in 2009. However, the amounts of additional contributions and pension expense are not expected to have a material impact on Devon’s liquidity or results of operations.

8. Stockholders’ Equity

Preferred Stock Redemption

     On June 20, 2008, Devon redeemed all 1.5 million outstanding shares of its 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.

Stock Repurchases

     During the first nine months of 2008, Devon repurchased 6.5 million shares for $665 million, or $102.56 per share, under programs approved by its Board of Directors. The 6.5 million shares include 4.5 million shares that were repurchased under Devon’s 50 million share program and 2.0 million shares that were repurchased under Devon’s ongoing, annual stock repurchase program.

Dividends

     Devon paid common stock dividends of $211 million (or a quarterly rate of $0.16 per share) and $186 million (or a quarterly rate of $0.14 per share) in the first nine months of 2008 and 2007, respectively. Devon paid preferred stock dividends of $5 million and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

$7 million in the first nine months of 2008 and 2007, respectively. The decrease in the preferred stock dividend is due to the redemption of the preferred stock in the second quarter of 2008.

9. Commitments and Contingencies

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

Royalty Matters

     Numerous 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 is scheduled to begin in February 2009. Devon is 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 natural 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. In 2006, the MMS informed Devon and other oil and gas companies that the omission of price thresholds from these leases was an error on its part and was not its intention. Accordingly, the MMS invited Devon and the other affected oil and gas producers to renegotiate the terms and conditions of the 1998 and 1999 leases to add price threshold provisions to the lease agreements for periods after October 1, 2006. Devon has not renegotiated any of its existing leases.

     On several occasions in 2007 and the first nine months of 2008, the U.S. House of Representatives passed or attempted to pass legislation that would have required companies to pay additional fees or renegotiate the 1998 and 1999 leases as a condition of securing future federal leases. The legislation that was passed by the U.S. House of Representatives was not passed by the U.S. Senate. However, Congress may consider similar legislation in the future. Although Devon has not signed renegotiated leases, it has accrued through September 30, 2008, approximately $44 million for royalties that would be due if price thresholds were added to its 1998 and 1999 leases effective October 1, 2006.

     Additionally, Devon has $37 million accrued at September 30, 2008 for royalties related to leases issued under the Deep Water Royalty Relief Act in years other than 1998 or 1999. The leases issued in these other years did include price thresholds, but in October 2007 a federal district court ruled in favor of a plaintiff who had challenged the legality of including price thresholds in these leases. This judgment is subject to appeal, and Devon will continue to accrue for royalties on these leases until the matter is resolved.

Environmental Matters

     Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations,

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(Unaudited)

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 September 30, 2008, Devon’s balance sheet included $2 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.

Hurricane Contingencies

     Historically, Devon maintained a comprehensive insurance program that included coverage for physical damage to its offshore facilities caused by hurricanes. Devon’s historical insurance program also included substantial business interruption coverage. Under the terms of this insurance program, Devon was entitled to be reimbursed for the portion of production suspended longer than forty-five days, subject to upper limits to oil and natural gas prices. Also, the terms of the insurance included a standard, per-event deductible of $1 million for offshore losses as well as a $15 million aggregate annual deductible.

     Devon suffered insured damages in the third quarter of 2005 related to hurricanes that struck the Gulf of Mexico. As of September 30, 2008, Devon had received $467 million in 2006 as a full settlement of the amount due from its primary insurers and an additional $13 million in 2007 as a full settlement of the amount due from certain of its secondary insurers. Devon’s claims under its then existing insurance arrangements included both physical damages and business interruption claims. As of September 30, 2008, $418 million of these proceeds had been utilized as reimbursement of past repair costs and deductible amounts, and only $5 million is expected to be spent on future repairs. The $57 million of excess recoveries to date were recorded as other income in the third quarter of 2008. Devon expects to receive approximately $44 million of additional recoveries in the fourth quarter of 2008. Such amount will be recorded as other income at the time it is received. While Devon continues to negotiate with its secondary insurers, it may be forced to initiate litigation against these insurers to recover the remaining amounts Devon believes it is entitled to under the terms of its insurance coverage in 2005.

     The policy underlying the insurance program terms described above expired on August 31, 2006. Due to significant changes in the insurance marketplace, Devon no longer has coverage for damage that may be caused by named windstorms from the Gulf of Mexico. As a result, Devon’s current insurance program includes coverage for physical damage and business interruption but does not have such coverage for damages or business interruption caused from named windstorms.

     During the third quarter of 2008, Hurricanes Ike and Gustav damaged certain of Devon’s oil and gas facilities and transportation systems in the Gulf of Mexico. These damages relate to both production operations that will be repaired and restored and production operations that will not be restored. These damages are uninsured losses because they resulted from named windstorms.

     For the damaged facilities and transportation systems for which Devon intends to resume operations after repairs have been made, a $14 million loss was recognized in the third quarter of 2008. This loss is included in lease operating expenses in the accompanying statement of operations.

     The facilities for which Devon will not restore production operations consist of certain platforms that were completely destroyed.

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(Unaudited)

Devon has begun performing asset retirement activities associated with the destroyed platforms and related wells. The time and effort required to complete such activities is expected to be significant due to the hazardous conditions created by the hurricanes. As a result, the estimated costs to complete the asset retirement activities are $82 million higher than Devon’s previously estimated asset retirement obligation related to the destroyed platforms and related wells. Therefore, in the third quarter of 2008, Devon increased its asset retirement obligation by $82 million with a corresponding increase to oil and gas property and equipment in the accompanying balance sheet. Based on the projected timing of the retirement activities, half of this asset retirement obligation increase was recorded to the current portion and half was recorded to the long-term portion.

Other Matters

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

10. Share-Based Compensation

     With the approval of Devon’s Compensation Committee, Devon modified the share-based compensation arrangements for certain members of senior management (“executives”) in the second quarter of 2008. 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. Additionally, when the modification was made in the second quarter of 2008, certain executives had already met the years-of-service and age criteria. As a result, Devon recognized an additional $27 million of share-based compensation expense in the second quarter of 2008 related to this modification. This additional expense would have been recognized in future reporting periods if the modification had not been made and the executives continued their employment at Devon.

     With the approval of Devon’s Compensation Committee, Devon granted 0.4 million restricted stock awards and units to certain non-executive employees in the third quarter of 2008. The grant date fair value was $39 million based upon a grant price of $87.33 per share.

11. Change in Fair Value of Other Financial Instruments

     The components of the change in fair value of other financial instruments include the following:

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2008			2007			2008			2007
	(In millions)
Losses (gains) from:
Chevron common stock	$	236		$	(133	)	$	154		$	(285	)
Option embedded in exchangeable debentures		(167	)		111			(109	)		255
Interest rate swaps		(23	)		—			(23	)		(1	)
Total	$	46		$	(22	)	$	22		$	(31	)

12. Income Taxes

     During the first nine months of 2008, Devon repatriated $2.3 billion in earnings from certain foreign subsidiaries to the United States. Devon also expects to repatriate approximately $0.4 billion in earnings from certain foreign subsidiaries to the United States during the last three months of 2008. Subsequent to these repatriations, Devon does not expect to repatriate similar earnings from its

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(Unaudited)

historical operations in the foreseeable future. Also in the second quarter of 2008, Devon made certain tax policy election changes to minimize the taxes Devon 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 completed and planned repatriations, as well as the tax policy election changes, Devon 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. Included in the $312 million additional tax expense is $183 million for tax positions in which the resulting tax benefits are not recognized in the accompanying consolidated financial statements. If recognized, all of these unrecognized tax benefits would affect Devon’s effective income tax rate.

13. Discontinued Operations

Divestiture Activity

     In November 2006 and January 2007, Devon announced its plans to divest its operations in Egypt and West Africa, including Equatorial Guinea, Gabon, Cote d’Ivoire and other countries in the region. Pursuant to accounting rules for discontinued operations, Devon has classified all amounts related to its operations in Egypt and West Africa as discontinued 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).

     In the third quarter of 2008, Devon sold its assets and terminated its operations in Cote d’Ivoire. As a result of this sale, Devon recognized a gain of $83 million ($101 million after tax) in the third quarter of 2008 from proceeds of $205 million ($163 million net of purchase price adjustments).

     With the completion of the Cote d’Ivoire transaction, Devon has divested all its oil and gas producing properties in Africa. The Africa divestitures have generated just over $3.0 billion of sales proceeds. After income taxes and purchase price adjustments, such proceeds totaled $2.2 billion and generated after-tax gains of $0.8 billion.

Financial Statement Information

     Operating revenues related to Devon’s discontinued operations totaled $17 million and $206 million in the three months ended September 30, 2008 and September 30, 2007 and $349 million and $596 million in the nine months ended September 30, 2008 and 2007, respectively. These amounts do not include the divestiture gains discussed in the previous section.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

     The following table presents the main classes of assets and liabilities associated with Devon’s discontinued operations as of September 30, 2008 and December 31, 2007.

	September 30, 2008		December 31, 2007
	(In millions)
Assets:
Cash	$	3	$	9
Accounts receivable		—		83
Other current assets		85		28
Current assets	$	88	$	120
Long-term assets — property and equipment, net of accumulated depreciation, depletion and amortization	$	19	$	1,512
Liabilities:
Accounts payable — trade	$	1	$	23
Revenues and royalties due to others		—		11
Income taxes payable		6		100
Current portion of asset retirement obligation		—		9
Accrued expenses and other current liabilities		5		2
Current liabilities	$	12	$	145
Asset retirement obligation, long-term	$	—	$	35
Deferred income taxes		1		366
Other long-term liabilities		—		3
Long-term liabilities	$	1	$	404

14. Earnings Per Share

     The following table reconciles earnings from continuing operations and common shares outstanding used in the calculations of basic and diluted earnings per share for the three-month and nine-month periods ended September 30, 2008 and 2007.

	Net			Weighted
	Earnings			Average
	Applicable to			Common		Net
	Common			Shares		Earnings
	Stockholders			Outstanding		per Share
	(In millions, except per share amounts)
Three Months Ended September 30, 2008:
Basic earnings per share	$	2,509			442	$	5.67
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options		—			4
Diluted earnings per share	$	2,509			446	$	5.63
Three Months Ended September 30, 2007:
Earnings from continuing operations	$	644
Less preferred stock dividends		(2	)
Basic earnings per share		642			445	$	1.45
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options		—			5
Diluted earnings per share	$	642			450	$	1.43

22

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

	Net			Weighted
	Earnings			Average
	Applicable to			Common		Net
	Common			Shares		Earnings
	Stockholders			Outstanding		per Share
	(In millions, except per share amounts)
Nine Months Ended September 30, 2008:
Earnings from continuing operations	$	3,754
Less preferred stock dividends		(5	)
Basic earnings per share		3,749			444	$	8.44
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options		—			4
Diluted earnings per share	$	3,749			448	$	8.36
Nine Months Ended September 30, 2007:
Earnings from continuing operations	$	2,042
Less preferred stock dividends		(7	)
Basic earnings per share		2,035			445	$	4.57
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options		—			5
Diluted earnings per share	$	2,035			450	$	4.52

     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 nine-month periods ended September 30, 2008, 1.6 million shares and 1.5 million shares, respectively, were excluded from the diluted earnings per share calculations. During the three-month and nine-month periods ended September 30, 2007, 2.1 million shares and 4.0 million shares, respectively, were excluded from the diluted earnings per share calculations.

15. Segment Information

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

	U.S.		Canada		International		Total
	(In millions)
As of September 30, 2008:
Current assets	$	1,775	$	963	$	681	$	3,419
Property and equipment, net of accumulated depreciation, depletion and amortization		21,230		8,786		1,434		31,450
Goodwill		3,050		2,848		68		5,966
Other long-term assets		1,527		62		231		1,820
Total assets	$	27,582	$	12,659	$	2,414	$	42,655
Current liabilities	$	2,098	$	525	$	436	$	3,059
Long-term debt		1,859		2,978		—		4,837
Asset retirement obligation, long-term		725		635		96		1,456
Other long-term liabilities		785		43		6		834
Deferred income taxes		5,049		2,062		68		7,179
Stockholders’ equity		17,066		6,416		1,808		25,290
Total liabilities and stockholders’ equity	$	27,582	$	12,659	$	2,414	$	42,655

23

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

	U.S.			Canada			International			Total
	(In millions)
Three Months Ended September 30, 2008:
Revenues:
Oil sales	$	467		$	507		$	322		$	1,296
Gas sales		1,598			504			5			2,107
NGL sales		288			74			—			362
Net gain on oil and gas derivative financial instruments		1,592			—			—			1,592
Marketing and midstream revenues		607			14			—			621
Total revenues		4,552			1,099			327			5,978
Expenses and other income, net:
Lease operating expenses		318			217			56			591
Production taxes		87			1			64			152
Marketing and midstream operating costs and expenses		447			5			—			452
Depreciation, depletion and amortization of oil and gas properties		505			224			52			781
Depreciation and amortization of non-oil and gas properties		60			7			—			67
Accretion of asset retirement obligation		11			10			1			22
General and administrative expenses		114			31			1			146
Interest expense		15			54			—			69
Change in fair value of other financial instruments		46			—			—			46
Other income, net		(75	)		(7	)		(1	)		(83	)
Total expenses and other income, net		1,528			542			173			2,243
Earnings from continuing operations before income tax expense		3,024			557			154			3,735
Income tax expense (benefit):
Current		83			85			58			226
Deferred		946			74			(20	)		1,000
Total income tax expense		1,029			159			38			1,226
Earnings from continuing operations		1,995			398			116			2,509
Discontinued operations:
Earnings from discontinued operations before income tax benefit		—			—			93			93
Income tax benefit		—			—			(16	)		(16	)
Earnings from discontinued operations		—			—			109			109
Net earnings applicable to common stockholders	$	1,995		$	398		$	225		$	2,618
Capital expenditures, before revision of future ARO	$	1,717		$	508		$	132		$	2,357
Revision of future ARO		82			—			—			82
Capital expenditures, continuing operations	$	1,799		$	508		$	132		$	2,439

24

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

	U.S.			Canada			International			Total
	(In millions)
Three Months Ended September 30, 2007:
Revenues:
Oil sales	$	359		$	224		$	322		$	905
Gas sales		860			312			3			1,175
NGL sales		196			46			—			242
Net gain on oil and gas derivative financial instruments		7			—			—			7
Marketing and midstream revenues		421			13			—			434
Total revenues		1,843			595			325			2,763
Expenses and other income, net:
Lease operating expenses		247			177			33			457
Production taxes		50			1			34			85
Marketing and midstream operating costs and expenses		296			5			—			301
Depreciation, depletion and amortization of oil and gas properties		457			193			55			705
Depreciation and amortization of non-oil and gas properties		45			5			1			51
Accretion of asset retirement obligation		10			8			1			19
General and administrative expenses		95			31			—			126
Interest expense		58			50			—			108
Change in fair value of other financial instruments		(22	)		—			—			(22	)
Other income, net		(10	)		(6	)		(12	)		(28	)
Total expenses and other income, net		1,226			464			112			1,802
Earnings from continuing operations before income tax expense		617			131			213			961
Income tax expense (benefit):
Current		(2	)		40			58			96
Deferred		215			8			(2	)		221
Total income tax expense		213			48			56			317
Earnings from continuing operations		404			83			157			644
Discontinued operations:
Earnings from discontinued operations before income tax expense		—			—			177			177
Income tax expense		—			—			86			86
Earnings from discontinued operations		—			—			91			91
Net earnings		404			83			248			735
Preferred stock dividends		2			—			—			2
Net earnings applicable to common stockholders	$	402		$	83		$	248		$	733
Capital expenditures, continuing operations	$	1,182		$	291		$	114		$	1,587

25

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

	U.S.			Canada			International			Total
	(In millions)
Nine Months Ended September 30, 2008:
Revenues:
Oil sales	$	1,476		$	1,345		$	1,180		$	4,001
Gas sales		4,522			1,410			15			5,947
NGL sales		859			210			—			1,069
Net loss on oil and gas derivative financial instruments		(411	)		—			—			(411	)
Marketing and midstream revenues		1,856			39			—			1,895
Total revenues		8,302			3,004			1,195			12,501
Expenses and other income, net:
Lease operating expenses		863			622			149			1,634
Production taxes		270			3			189			462
Marketing and midstream operating costs and expenses		1,334			15			—			1,349
Depreciation, depletion and amortization of oil and gas properties		1,446			662			172			2,280
Depreciation and amortization of non-oil and gas properties		165			20			1			186
Accretion of asset retirement obligation		32			30			4			66
General and administrative expenses		373			99			2			474
Interest expense		103			158			—			261
Change in fair value of other financial instruments		22			—			—			22
Other income, net		(92	)		(12	)		(17	)		(121	)
Total expenses and other income, net		4,516			1,597			500			6,613
Earnings from continuing operations before income tax expense		3,786			1,407			695			5,888
Income tax expense:
Current		428			149			166			743
Deferred		1,159			226			6			1,391
Total income tax expense		1,587			375			172			2,134
Earnings from continuing operations		2,199			1,032			523			3,754
Discontinued operations:
Earnings from discontinued operations before income tax expense		—			—			1,133			1,133
Income tax expense		—			—			219			219
Earnings from discontinued operations		—			—			914			914
Net earnings		2,199			1,032			1,437			4,668
Preferred stock dividends		5			—			—			5
Net earnings applicable to common stockholders	$	2,194		$	1,032		$	1,437		$	4,663
Capital expenditures, before revision of future ARO	$	4,682		$	1,206		$	433		$	6,321
Revision of future ARO		152			73			19			244
Capital expenditures, continuing operations	$	4,834		$	1,279		$	452		$	6,565

26

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

	U.S.			Canada			International			Total
	(In millions)
Nine Months Ended September 30, 2007:
Revenues:
Oil sales	$	898		$	562		$	1,001		$	2,461
Gas sales		2,732			1,048			7			3,787
NGL sales		509			134			—			643
Net loss on oil and gas derivative financial instruments		1			—			—			1
Marketing and midstream revenues		1,244			29			—			1,273
Total revenues		5,384			1,773			1,008			8,165
Expenses and other income, net:
Lease operating expenses		751			460			115			1,326
Production taxes		165			3			87			255
Marketing and midstream operating costs and expenses		900			12			—			912
Depreciation, depletion and amortization of oil and gas properties		1,230			535			172			1,937
Depreciation and amortization of non-oil and gas properties		130			15			1			146
Accretion of asset retirement obligation		29			23			3			55
General and administrative expenses		278			83			(3	)		358
Interest expense		174			151			—			325
Change in fair value of other financial instruments		(30	)		(1	)		—			(31	)
Other income, net		(28	)		(11	)		(32	)		(71	)
Total expenses and other income, net		3,599			1,270			343			5,212
Earnings from continuing operations before income tax expense		1,785			503			665			2,953
Income tax expense (benefit):
Current		120			145			194			459
Deferred		467			3			(18	)		452
Total income tax expense		587			148			176			911
Earnings from continuing operations		1,198			355			489			2,042
Discontinued operations:
Earnings from discontinued operations before income tax expense		—			—			442			442
Income tax expense		—			—			194			194
Earnings from discontinued operations		—			—			248			248
Net earnings		1,198			355			737			2,290
Preferred stock dividends		7			—			—			7
Net earnings applicable to common stockholders	$	1,191		$	355		$	737		$	2,283
Capital expenditures, before revision of future ARO	$	3,204		$	952		$	329		$	4,485
Revision of future ARO		210			99			2			311
Capital expenditures, continuing operations	$	3,414		$	1,051		$	331		$	4,796

27

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 nine-month periods ended September 30, 2008, compared to the three-month and nine-month periods ended September 30, 2007, and in our financial condition and liquidity since December 31, 2007. It is presumed that readers have read or have access to our 2007 Annual Report on Form 10-K/A, which includes disclosures regarding critical accounting policies and estimates as part of 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

     During the third quarter and first nine months of 2008, we generated net earnings of $2.6 billion and $4.7 billion, respectively, or $5.87 and $10.40 per diluted share, representing increases of 260% and 105% over the same periods of 2007. Additionally, net cash provided by operating activities for the first nine months of 2008 climbed to a record amount of $8.2 billion, representing a 60% increase over 2007. These increases in earnings and cash flow were largely attributable to the following factors:

• Production increased 3% and 6% in the third quarter and first nine months of 2008, respectively.

• The combined realized price without hedges for oil, gas and NGLs increased 57% and 51% in the third quarter and first nine months of 2008, respectively.

• Oil and gas hedges generated a net gain of $1.6 billion in the third quarter of 2008 and a net loss of $411 million in the first nine months of 2008. Included in these amounts were cash payments of $240 million and $551 million, respectively.

• Marketing and midstream operating profit increased 28% and 52% in the third quarter and first nine months of 2008, respectively.

• Per unit operating costs rose 26% and 17% in the third quarter and first nine months of 2008, respectively.

• General and administrative expenses increased 17% and 33% in the third quarter and first nine months of 2008, respectively.

• Cash spent on capital expenditures for oil and gas exploration and development activities was $5.7 billion during the first nine months of 2008.

     In the third quarter of 2008, we sold our operations in Cote d’Ivoire, completing another sale under our African divestiture program. The sales price was $205 million ($163 million net of purchase price adjustments). As a result of this sale, we recognized an after-tax gain of $101 million in the third quarter of 2008.

     With the completion of the Cote d’Ivoire transaction, we have divested all our oil and gas producing properties in Africa, including Equatorial Guinea—the largest individual transaction in the divestiture program. The Africa divestitures have generated just over $3.0 billion of sales proceeds. After income taxes and purchase price adjustments, such proceeds totaled $2.2 billion and generated after-tax gains of $0.8 billion. Also, in conjunction with these asset sales, we repatriated an additional $2.3 billion of earnings from certain foreign subsidiaries to the United States in the first nine months of 2008. We also expect to repatriate $0.4 billion from certain foreign subsidiaries to the United States in the fourth quarter of 2008.

     With the proceeds from asset sales, repatriated funds and growing cash flow from operations, we repaid $2.5 billion of commercial paper and credit facility borrowings. During 2008, we fully redeemed our exchangeable debentures for cash payments totaling $1.0 billion. We also repurchased 6.5 million common shares for $665 million and redeemed $150 million of preferred stock during the first nine months of 2008.

Industry Overview and Outlook

     As disclosed in our 2007 Annual Report on Form 10-K/A, our current and future earnings depend largely on our ability to replace and grow oil and gas reserves, increase production and exert cost discipline. We must also manage commodity pricing risks to achieve long-term success. Recently, managing and reacting to the volatility of oil and natural gas prices has been an important part of our strategy.

28

     Oil and natural gas prices have reached historical high levels in recent years and during the first half of 2008. These high prices have been a key factor in the oil and gas industry experiencing cost increases that have exceeded general inflation trends. We are no different from others in the industry in that we have been impacted by these cost increases. However, we have continued to remain disciplined with regards to our operating costs and capital expenditures. We have utilized the record operating cash flows generated by high commodity prices, along with proceeds from our African divestitures, to, among other uses, repay outstanding debt. During 2007 and the first nine months of 2008, we repaid outstanding debt totaling $3.4 billion. During this same period, we also repurchased $1.0 billion of our common stock and redeemed $150 million of preferred stock.

     As we exited the third quarter of 2008, oil and natural gas prices had declined sharply from their recent record levels. In addition, recent problems in the credit markets, steep stock market declines, financial institution failures and government bail-outs provide evidence of a weakening United States and global economy. As a result of the market turmoil and price decreases, oil and gas companies with high debt levels and lack of liquidity have been and will continue to be negatively impacted.

     However, we do not expect to be significantly impacted by these recent events. We are in a financially-strong position due to our past strategies. We continue to have access to the commercial paper market, and we had $3.1 billion of available capacity under our credit facilities as of November 5, 2008. We also anticipate our operating cash flow and other capital resources, if needed, will adequately fund our planned capital expenditures and other capital uses over the near-term.

Results of Operations

Revenues

Oil, Gas and NGL Sales

     The three-month and nine-month comparison of our oil, gas and NGL production and the related prices realized without the effect of hedges is shown in the following tables. The amounts for all periods presented exclude our Egyptian operations that were sold in the fourth quarter of 2007 and our West African operations, which are classified as discontinued operations in our financial statements.

	Total
	Three Months Ended September 30,							Nine Months Ended September 30,
	2008		2007		Change(2)			2008		2007		Change(2)
Production
Oil (MMBbls)		12		13		-10	%		39		41		-4	%
Gas (Bcf)		239		223		+7	%		692		637		+9	%
NGLs (MMBbls)		7		7		+5	%		21		19		+10	%
Oil, Gas and NGLs (MMBoe)(1)		58		57		+3	%		175		166		+6	%
Realized prices without hedges
Oil (Per Bbl)	$	106.95	$	67.41		+59	%	$	101.42	$	59.88		+69	%
Gas (Per Mcf)	$	8.82	$	5.28		+67	%	$	8.60	$	5.95		+45	%
NGLs (Per Bbl)	$	54.72	$	38.34		+43	%	$	52.03	$	34.31		+52	%
Oil, Gas and NGLs (Per Boe)(1)	$	64.29	$	40.86		+57	%	$	62.84	$	41.52		+51	%
Revenues($ in millions)
Oil sales	$	1,296	$	905		+43	%	$	4,001	$	2,461		+63	%
Gas sales		2,107		1,175		+79	%		5,947		3,787		+57	%
NGL sales		362		242		+50	%		1,069		643		+66	%
Oil, Gas and NGL sales	$	3,765	$	2,322		+62	%	$	11,017	$	6,891		+60	%

29

	Domestic
	Three Months Ended September 30,							Nine Months Ended September 30,
	2008		2007		Change(2)			2008		2007		Change(2)
Production
Oil (MMBbls)		4		5		-20	%		13		14		-7	%
Gas (Bcf)		185		164		+13	%		532		465		+14	%
NGLs (MMBbls)		6		6		+5	%		18		16		+13	%
Oil, Gas and NGLs (MMBoe)(1)		40		38		+7	%		119		107		+11	%
Realized prices without hedges
Oil (Per Bbl)	$	118.70	$	73.19		+62	%	$	111.94	$	63.01		+78	%
Gas (Per Mcf)	$	8.66	$	5.23		+65	%	$	8.50	$	5.87		+45	%
NGLs (Per Bbl)	$	51.50	$	36.78		+40	%	$	48.96	$	32.68		+50	%
Oil, Gas and NGLs (Per Boe)(1)	$	58.38	$	37.62		+55	%	$	57.43	$	38.55		+49	%
Revenues($ in millions)
Oil sales	$	467	$	359		+30	%	$	1,476	$	898		+64	%
Gas sales		1,598		860		+86	%		4,522		2,732		+66	%
NGL sales		288		196		+47	%		859		509		+69	%
Oil, Gas and NGL sales	$	2,353	$	1,415		+66	%	$	6,857	$	4,139		+66	%

	Canada
	Three Months Ended September 30,							Nine Months Ended September 30,
	2008		2007		Change(2)			2008		2007		Change(2)
Production
Oil (MMBbls)		5		4		+30	%		15		12		+32	%
Gas (Bcf)		54		59		-7	%		159		171		-7	%
NGLs (MMBbls)		1		1		5	%		3		3		-5	%
Oil, Gas and NGLs (MMBoe)(1)		15		15		+4	%		45		43		+4	%
Realized prices without hedges
Oil (Per Bbl)	$	92.98	$	53.40		+74	%	$	87.28	$	48.01		+82	%
Gas (Per Mcf)	$	9.36	$	5.40		+73	%	$	8.90	$	6.16		+45	%
NGLs (Per Bbl)	$	72.19	$	46.77		+54	%	$	70.00	$	42.36		+65	%
Oil, Gas and NGLs (Per Boe)(1)	$	70.24	$	39.28		+79	%	$	66.16	$	40.33		+64	%
Revenues($ in millions)
Oil sales	$	507	$	224		+127	%	$	1,345	$	562		+139	%
Gas sales		504		312		+61	%		1,410		1,048		+35	%
NGL sales		74		46		+61	%		210		134		+57	%
Oil, Gas and NGL sales	$	1,085	$	582		+86	%	$	2,965	$	1,744		+70	%

30

	International
	Three Months Ended September 30,							Nine Months Ended September 30,
	2008		2007		Change(2)			2008		2007		Change(2)
Production
Oil (MMBbls)		3		4		-37	%		11		15		-28	%
Gas (Bcf)		—		—		2	%		1		1		+17	%
NGLs (MMBbls)		—		—		N/M			—		—		N/M
Oil, Gas and NGLs (MMBoe)(1)		3		4		-36	%		11		16		-28	%
Realized prices without hedges
Oil (Per Bbl)	$	117.97	$	74.43		+58	%	$	108.73	$	66.10		+64	%
Gas (Per Mcf)	$	10.72	$	6.61		+62	%	$	9.95	$	5.73		+74	%
NGLs (Per Bbl)	$	—	$	—		N/M		$	—	$	—		N/M
Oil, Gas and NGLs (Per Boe)(1)	$	116.35	$	73.77		+58	%	$	107.63	$	65.66		+64	%
Revenues($ in millions)
Oil sales	$	322	$	322		+0	%	$	1,180	$	1,001		+18	%
Gas sales		5		3		+66	%		15		7		+103	%
NGL sales		—		—		N/M			—		—		N/M
Oil, Gas and NGL sales	$	327	$	325		+0	%	$	1,195	$	1,008		+18	%

(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 natural 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 September 30, 2008 and 2007.

	Oil			Gas		NGLs		Total
	(In millions)
2007 sales	$	905		$	1,175	$	242	$	2,322
Changes due to volumes		(88	)		87		12		11
Changes due to prices		479			845		108		1,432
2008 sales	$	1,296		$	2,107	$	362	$	3,765

     The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between the nine months ended September 30, 2008 and 2007.

	Oil			Gas		NGLs		Total
	(In millions)
2007 sales	$	2,461		$	3,787	$	643	$	6,891
Changes due to volumes		(99	)		328		62		291
Changes due to prices		1,639			1,832		364		3,835
2008 sales	$	4,001		$	5,947	$	1,069	$	11,017

Oil Sales

     Oil sales decreased $88 million in the third quarter of 2008 due to a one million barrel, or 10%, decrease in production. Our International production decreased approximately one million barrels due to reaching certain cost recovery thresholds of our carried interest in Azerbaijan. We also deferred 0.4 million barrels of oil production during the third quarter of 2008 as the result of the effects of Hurricanes Ike and Gustav. These decreases were partially offset by additional production resulting from increased development activity at our Jackfish and Lloydminster areas in Canada.

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     Oil sales increased $479 million in the third quarter of 2008 as a result of a 59% increase in our realized price without hedges. The average NYMEX West Texas Intermediate index price increased 58% during the same time period, accounting for the majority of the increase.

     Oil sales decreased $99 million in the first nine months of 2008 due to a two million barrel, or 4%, decrease in production. Our International production decreased approximately four million barrels due to reaching certain cost recovery thresholds of our carried interest in Azerbaijan. We also deferred 0.4 million barrels of oil production due to hurricanes. These decreases were partially offset by additional production resulting from increased development activity at our Jackfish and Lloydminster areas in Canada.

     Oil sales increased $1.6 billion in the first nine months of 2008 as a result of a 69% increase in our realized price without hedges. The average NYMEX West Texas Intermediate index price increased 72% during the same time period, accounting for the majority of the increase.

Gas Sales

     A 16 Bcf, or 7%, increase in production during the third quarter of 2008 caused gas sales to increase by $87 million. Our drilling and development program in the Barnett Shale field in north Texas contributed 23 Bcf to the gas production increase. We also deferred 5 Bcf of gas production in the third quarter of 2008 due to Hurricanes Ike and Gustav. This net increase and the effect of new drilling and development in our other North American properties were partially offset by natural production declines.

     Gas sales increased $845 million during the third quarter of 2008 as a result of a 67% increase in our realized price without hedges. This increase was largely due to increases in the regional index prices upon which our gas sales are based.

     A 55 Bcf, or 9%, increase in production during the first nine months of 2008 caused gas sales to increase by $328 million. Our drilling and development program in the Barnett Shale field in north Texas contributed 64 Bcf to the gas production increase. We also deferred 5 Bcf of gas production due to hurricanes. This net increase and the effect of new drilling and development in our other North American properties were partially offset by natural production declines.

     Gas sales increased $1.8 billion during the first nine months of 2008 as a result of a 45% increase in our realized price without hedges. This increase was largely due to increases in the regional index prices upon which our gas sales are based.

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 third quarter and first nine months of 2008 and 2007. 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 third quarter and first nine months of 2008 and 2007. The prices do not include the effects of unrealized gains and losses.

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2008			2007			2008			2007
	(In millions)
Cash settlements:
Gas price swaps	$	(115	)	$	14		$	(276	)	$	29
Gas price collars		(125	)		—			(275	)		2
Total cash settlements (paid) received		(240	)		14			(551	)		31
Unrealized gains (losses) on fair value changes:
Gas price swaps		645			(7	)		27			(26	)
Gas price collars		1,142			—			114			(4	)
Oil price collars		45			—			(1	)		—
Total unrealized gains (losses) on fair value changes		1,832			(7	)		140			(30	)
Net gain (loss) on oil and gas derivative financial instruments	$	1,592		$	7		$	(411	)	$	1

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	Three Months Ended September 30, 2008
	Oil			Gas			NGLs		Total
	(Per Bbl)			(Per Mcf)			(Per Bbl)		(Per Boe)
Realized price without hedges	$	106.95		$	8.82		$	54.72	$	64.29
Cash settlements of hedges		(0.01	)		(1.01	)		—		(4.10	)
Realized price, including cash settlements	$	106.94		$	7.81		$	54.72	$	60.19

	Three Months Ended September 30, 2007
	Oil		Gas		NGLs		Total
	(Per Bbl)		(Per Mcf)		(Per Bbl)		(Per Boe)
Realized price without hedges	$	67.41	$	5.28	$	38.34	$	40.86
Cash settlements of hedges		—		0.06		—		0.24
Realized price, including cash settlements	$	67.41	$	5.34	$	38.34	$	41.10

	Nine Months Ended September 30, 2008
	Oil		Gas			NGLs		Total
	(Per Bbl)		(Per Mcf)			(Per Bbl)		(Per Boe)
Realized price without hedges	$	101.42	$	8.60		$	52.03	$	62.84
Cash settlements of hedges		—		(0.80	)		—		(3.15	)
Realized price, including cash settlements	$	101.42	$	7.80		$	52.03	$	59.69

	Nine Months Ended September 30, 2007
	Oil		Gas		NGLs		Total
	(Per Bbl)		(Per Mcf)		(Per Bbl)		(Per Boe)
Realized price without hedges	$	59.88	$	5.95	$	34.31	$	41.52
Cash settlements of hedges		—		0.05		—		0.19
Realized price, including cash settlements	$	59.88	$	6.00	$	34.31	$	41.71

     Our oil and gas derivative financial instruments include price swaps and costless collars. For the price swaps, we receive a fixed price for our production and pay a variable market price to the contract counterparty. The costless price collars set a floor and ceiling price for the hedged production. 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 losses or gains related to our price swaps and collars.

     During the third quarter and first nine months of 2008, we paid $240 million, or $1.01 per Mcf, and $551 million, or $0.80 per Mcf, respectively, to counterparties to settle our gas price swaps and collars. During the third quarter and nine months of 2007, we received $14 million, or $0.06 per Mcf, and $31 million, or $0.05 per Mcf, respectively, from 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 and/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 price swaps and collars at September 30, 2008, a 10% increase in these forward curves would have decreased our third quarter 2008 unrealized gain for our oil and gas derivative financial instruments by approximately $130 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.

     In spite of the recent turmoil in the financial markets, counterparty credit risk has not had a significant effect on our cash flow calculations and commodity derivative valuations. This is primarily the result of two factors. First, we have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Our commodity

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derivative contracts are held with thirteen separate counterparties. Second, 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 for collateral posting 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 September 30, 2008, the credit ratings of all our counterparties were investment grade.

     The $1.8 billion unrealized gain in the third quarter of 2008 was primarily the result of large fluctuations in the forward curves of the Inside FERC Henry Hub index. As a result of a significant increase in the Inside FERC Henry Hub forward curve from our contract trade dates to the end of the second quarter of 2008, we recognized a $1.7 billion unrealized loss during the first half of 2008. During the third quarter of 2008, the Inside FERC Henry Hub forward curve decreased considerably. As a result we recognized an unrealized gain of $1.8 billion, in effect, reversing the unrealized loss recognized in the first half of 2008.

     The $140 million unrealized gain in the first nine months of 2008 was primarily the result of a decrease in the Inside FERC Henry Hub index subsequent to our trade dates.

     During the third quarter and first nine months of 2007, we recognized unrealized losses totaling $7 million and $30 million, respectively, related to our gas derivative instruments.

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 September 30, 2008 and 2007 and the nine months ended September 30, 2008 and 2007 are shown in the table below.

	Three Months Ended September 30,							Nine Months Ended September 30,
	2008		2007		Change(1)			2008		2007		Change(1)
Marketing and midstream ($ in millions):
Revenues	$	621	$	434		+43	%	$	1,895	$	1,273		+49	%
Operating costs and expenses		452		301		+50	%		1,349		912		+48	%
Operating profit	$	169	$	133		+28	%	$	546	$	361		+52	%

⁽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 third quarter of 2008, marketing and midstream revenues increased $187 million and operating costs and expenses also increased $151 million, causing operating profit to increase $36 million. During the first nine months of 2008, marketing and midstream revenues increased $622 million and operating costs and expenses also increased $437 million, causing operating profit to increase $185 million. Revenues and expenses increased during these periods primarily due to higher natural gas and NGL prices, as well as higher gas pipeline throughput in the Barnett Shale.

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Oil, Gas and NGL Production and Operating Expenses

     The three-month and nine-month comparisons of oil, gas and NGL production and operating expenses are shown in the table below.

	Three Months Ended September 30,							Nine Months Ended September 30,
	2008		2007		Change(1)			2008		2007		Change(1)
Production and operating expenses ($ in millions):
Lease operating expenses	$	591	$	457		+29	%	$	1,634	$	1,326		+23	%
Production taxes		152		85		+80	%		462		255		+81	%
Total production and operating expenses	$	743	$	542		+37	%	$	2,096	$	1,581		+33	%
Production and operating expenses per Boe:
Lease operating expenses	$	10.09	$	8.04		+26	%	$	9.32	$	7.99		+17	%
Production taxes		2.60		1.49		+74	%		2.64		1.54		+71	%
Total production and operating expenses per Boe	$	12.69	$	9.53		+33	%	$	11.96	$	9.53		+26	%

⁽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 increased $134 million in the third quarter of 2008. The largest contributor to this increase, as well as the increase in LOE per Boe, was higher per-unit costs associated with new thermal heavy oil production from our Jackfish operations in Canada as well as new oil production from Brazil. As these large-scale projects are in the early phases of production, per-unit operating costs are higher than the per-unit costs for our overall portfolio of producing properties. LOE also increased $14 million due to our 3% growth in production. Additionally, LOE increased $14 million due to damages of certain of our facilities and transportation systems that were caused by Hurricane Ike in the third quarter of 2008. These hurricane damages also contributed to the increase in LOE per Boe.

     LOE increased $308 million in the first nine months of 2008. The largest contributor to this increase, as well as the increase in LOE per Boe, was higher per-unit costs associated with new thermal heavy oil production from our Jackfish operations in Canada as well as new oil production from Brazil. LOE also increased $75 million due to our 6% growth in production. Additionally, LOE increased $14 million due to damages caused by Hurricane Ike. Changes in the exchange rate between the U.S. and Canadian dollar also caused LOE to increase $46 million. This exchange rate also contributed to the increase in LOE per Boe.

Production Taxes

     The following table details the changes in production taxes between the three months ended September 30, 2008 and 2007 and the nine months ended September 30, 2008 and 2007. The majority of our production taxes are assessed on our U.S. onshore properties and are based on a fixed percentage of revenues. 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 properties.

	Three Months		Nine Months
	Ended September 30,		Ended September 30,
	(In millions)
2007 production taxes	$	85	$	255
Change due to revenues		52		153
Change due to rate		15		54
2008 production taxes	$	152	$	462

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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 nine months ended September 30, 2008 and 2007 are shown in the table below.

	Three Months Ended September 30,							Nine Months Ended September 30,
	2008		2007		Change(1)			2008		2007		Change(1)
Production volumes (MMBoe)		58		57		+3	%		175		166		+6	%
DD&A rate ($  per Boe)	$	13.34	$	12.41		+8	%	$	13.01	$	11.67		+11	%
DD&A expense ($ in millions)	$	781	$	705		+11	%	$	2,280	$	1,937		+18	%

⁽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 months and nine months ended September 30, 2008 and 2007.

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	(In millions)
2007 DD&A	$	705	$	1,937
Change due to volumes		21		109
Change due to rate		55		234
2008 DD&A	$	781	$	2,280

     The 3% production increase during the third quarter of 2008 caused oil and gas property related DD&A to increase $21 million. In addition, oil and gas property related DD&A increased $55 million due to an 8% increase in the DD&A rate. The largest contributor to the rate increase was inflationary pressure on costs incurred during 2007 and 2008, as well as the estimated development costs to be spent in future periods on proved undeveloped reserves. Other factors contributing to the rate increase included the transfer of previously unproved costs to the depletable base as a result of 2007 and 2008 drilling activities.

     The 6% production increase during the first nine months of 2008 caused oil and gas property related DD&A to increase $109 million. In addition, oil and gas property related DD&A increased $234 million due to an 11% increase in the DD&A rate. The largest contributor to the rate increase was inflationary pressure on costs incurred during 2007 and 2008, as well as the estimated development costs to be spent in future periods on proved undeveloped reserves. Other factors contributing to the rate increase included a higher Canadian-to-U.S. dollar exchange rate in 2008 and the transfer of previously unproved costs to the depletable base as a result of 2007 and 2008 drilling activities.

General and Administrative Expenses (“G&A”)

     The following schedule includes the components of G&A expense for the three-month and nine-month periods ended September 30, 2008 and 2007.

	Three Months									Nine Months
	Ended September 30,									Ended September 30,
	2008			2007			Change(1)			2008			2007			Change(1)
	(In millions)									(In millions)
Gross G&A	$	280		$	239			+17	%	$	864		$	673			+29	%
Capitalized G&A		(99	)		(84	)		+18	%		(298	)		(230	)		+30	%
Reimbursed G&A		(35	)		(29	)		+18	%		(92	)		(85	)		+8	%
Net G&A	$	146		$	126			+17	%	$	474		$	358			+33	%

⁽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.

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     Gross G&A increased $41 million in the third quarter of 2008 compared to the same period of 2007. The largest contributor to the increase was higher employee compensation and benefits costs related to our workforce growth and industry inflation.

     The $15 million increase in capitalized G&A during the third quarter of 2008 is primarily due to the higher employee compensation and benefits costs.

     Gross G&A increased $191 million in the first nine months of 2008 compared to the same period of 2007. The largest contributor to the increase was higher employee compensation and benefits costs related to our workforce growth and industry inflation. Additionally, gross G&A increased $27 million due to the accelerated expense recognition of share-based compensation. In the second quarter of 2008, we modified the share-based compensation arrangements for certain members of senior management (“executives”). 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. This modification results in accelerated expense recognition as executives approach the years-of-service and age criteria. Additionally, when the modification was made in the second quarter of 2008, certain executives had already met the years-of-service and age criteria. As a result, we recognized an additional $27 million of share-based compensation expense in the second quarter of 2008 related to this modification. This additional expense would have been recognized in future reporting periods if the modification had not been made and the executives continued their employment at Devon.

     The $68 million increase in capitalized G&A during the first nine months of 2008 was primarily due to higher employee compensation and benefits costs.

Interest Expense

     The following schedule includes the components of interest expense for the three-month and nine-month periods ended September 30, 2008 and 2007.

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2008			2007			2008			2007
	(In millions)
Interest based on debt outstanding	$	96		$	127		$	332		$	380
Capitalized interest		(28	)		(26	)		(84	)		(73	)
Other		1			7			13			18
Total	$	69		$	108		$	261		$	325

     Interest based on debt outstanding decreased during the third quarter of 2008 and the first nine months of 2008 primarily due to a decrease in outstanding borrowings. The decrease in borrowings resulted largely from the use of proceeds from our West African divestiture program and cash flow from operations to repay all commercial paper and credit facility borrowings in the second quarter of 2008. Additionally, we retired our exchangeable debentures during the third quarter of 2008.

Change in Fair Value of Other Financial Instruments

     The following schedule includes the components of the change in fair value of non-oil and gas financial instruments for the three months and nine months ended September 30, 2008 and 2007.

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2008			2007			2008			2007
	(In millions)
Losses (gains) from:
Chevron common stock	$	236		$	(133	)	$	154		$	(285	)
Option embedded in exchangeable debentures		(167	)		111			(109	)		255
Interest rate swaps		(23	)		—			(23	)		(1	)
Total	$	46		$	(22	)	$	22		$	(31	)

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     Each reporting period, we recognize unrealized changes in the fair values of our investment in 14.2 million shares of Chevron common stock and the conversion option embedded in the debentures exchangeable into shares of Chevron common stock. We calculate the fair value of our investment in Chevron common stock using Chevron’s published market price.

     The embedded option was not actively traded in an established market. Therefore, we estimated its fair value using quotes obtained from a broker for trades occurring near the valuation date. Because the exchangeable debentures matured in August 2008, the embedded option’s recent fair value changes largely coincided with changes in the market price of Chevron’s common stock. As a result, when Chevron’s common stock price has increased from one valuation date to another, we have recognized a gain on our investment and a loss on the embedded option. The inverse is also true. Since the exchangeable debentures were retired in August 2008, we will not recognize any future gains or losses from the embedded option.

     The loss on our investment in Chevron common stock was directly attributable to a $16.65 decrease in the price per share of Chevron’s common stock during the third quarter of 2008. The gain on the embedded option during the third quarter of 2008 was directly attributable to the change in fair value of the Chevron common stock from July 1, 2008 to the maturity date of August 15, 2008. The gain on our investment in Chevron common stock and loss on the embedded option during the third quarter of 2007 were directly attributable to a $9.34 increase in the price per share of Chevron’s common stock during the third quarter of 2007.

     The loss on our investment in Chevron common stock and gain on the embedded option during the first nine months of 2008 were primarily attributable to a $10.85 increase in the price per share of Chevron’s common stock during the first nine months of 2008. The gain on our investment in Chevron common stock and loss on the embedded option during the first nine months of 2007 were directly attributable to a $20.05 increase in the price per share of Chevron’s common stock during the first nine months of 2007.

     We also recognize unrealized changes in the fair values of our interest rate swaps each reporting period. 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. From time to time, we validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties and/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 subject to the interest rate swaps at September 30, 2008, a 10% increase in these forward curves would have decreased our third quarter 2008 unrealized gain for our interest rate swaps by approximately $15 million.

     In the third quarter of 2008, we recorded a $23 million unrealized gain as a result of changes in interest rates subsequent to the trade date. There were no cash settlements in the third quarter of 2008.

     As previously discussed for our commodity derivative contracts, counterparty credit risk has not had a significant effect on our cash flow calculations and interest rate derivative valuations. Similar to our commodity derivative contracts, our interest rate derivative contracts are held with five separate counterparties and have cash collateral posting requirements. Additionally, the credit ratings of all our counterparties are investment grade as of September 30, 2008.

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Income Taxes

     The following table presents our total income tax expense 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 nine-month periods ended September 30, 2008 and 2007. The primary factors causing our effective rates to vary from 2007 to 2008, and differ from the U.S. statutory rate, are discussed below.

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2008			2007			2008			2007
Total income tax expense (In millions)	$	1,226		$	317		$	2,134		$	911
U.S. statutory income tax rate		35	%		35	%		35	%		35	%
Repatriations and tax policy election changes		—			—			5	%		—
Canadian statutory rate reductions		—			—			—			(1	%)
Other, primarily taxation on foreign operations		(2	%)		(2	%)		(4	%)		(3	%)
Effective income tax rate		33	%		33	%		36	%		31	%

     For the nine months ended September 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. At the end of the second quarter of 2008, we also expected to repatriate approximately $1.5 billion in earnings from foreign subsidiaries to the United States during the last six months of 2008. 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 rate would have been 31% for the first nine months of 2008.

     For the nine months ended September 30, 2007, our effective income tax rate was impacted by a $30 million tax benefit that we recognized as a result of a statutory rate reduction enacted by the Canadian Federal government in the second quarter of 2007. Excluding the effect of the rate reduction, our effective income tax rate would have been 32% for the first nine months of 2007.

     These rates, as well as the rates for the third quarters of 2008 and 2007, 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.

Earnings from Discontinued Operations

     Our discontinued operations consist of our operations in Egypt, which were sold in the fourth quarter of 2007, and our operations in West Africa, including Equatorial Guinea, Gabon, Cote d’Ivoire and other countries in the region.

     Following are the components of earnings from discontinued operations for the three months and nine months ended September 30, 2008 and 2007.

	Three Months					Nine Months
	Ended September 30,					Ended September 30,
	2008			2007		2008		2007
	(In millions)
Earnings from discontinued operations before income taxes	$	93		$	177	$	1,133	$	442
Income tax expense (benefit)		(16	)		86		219		194
Earnings from discontinued operations	$	109		$	91	$	914	$	248

     Earnings from discontinued operations increased $18 million in the third quarter of 2008. We recognized a $101 million after-tax gain from the sale of our assets in Cote d’Ivoire in the third quarter of 2008. This gain was largely offset by the effect of reduced earnings due to the sales of our operations in Equatorial Guinea and Gabon in the second quarter

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of 2008 and Egypt in the fourth quarter of 2007.

     Earnings from discontinued operations increased $666 million in the first nine months of 2008. We recognized after-tax gains totaling $748 million from the sale of our assets in Equatorial Guinea, Gabon, Cote d’Ivoire and other countries in the second and third quarters of 2008. These gains were largely offset by the effect of reduced earnings due to the sales of such operations.

Capital Resources, Uses and Liquidity

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

Sources and Uses of Cash

	Nine Months Ended September 30,
	2008			2007
	(In millions)
Sources of cash and cash equivalents:
Operating cash flow — continuing operations	$	8,079		$	4,739
Net credit facility borrowings		—			400
Sales of property and equipment		116			39
Stock option exercises		109			71
Net sales of short-term investments		247			233
Cash received from discontinued operations		1,898			—
Other		58			20
Total sources of cash and cash equivalents		10,507			5,502
Uses of cash and cash equivalents:
Capital expenditures		(6,179	)		(4,477	)
Net commercial paper repayments		(1,004	)		(129	)
Net repayments of debt		(2,481	)		(166	)
Repurchases of common stock		(665	)		(133	)
Redemption of preferred stock		(150	)		—
Dividends		(216	)		(193	)
Total uses of cash and cash equivalents		(10,695	)		(5,098	)
Increase (decrease) from continuing operations		(188	)		404
Increase from discontinued operations, net of distributions to continuing operations		58			217
Effect of foreign exchange rates		(47	)		44
Net (decrease) increase in cash and cash equivalents	$	(177	)	$	665
Cash and cash equivalents at end of period	$	1,196		$	1,421
Short-term investments at end of period	$	1		$	341

Operating Cash Flow — Continuing Operations

     Net cash provided by operating activities (“operating cash flow”) continued to be the primary source of capital and liquidity in the first nine months of 2008. 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 such noncash expenses as DD&A, financial instrument fair value changes and deferred income tax expense. As a result, our operating cash flow increased in 2008 primarily due to the increase in earnings as discussed in the “Results of Operations” section of this report.

     During the first nine months of 2008 and 2007, our operating cash flow was sufficient to fund our capital expenditures.

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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. 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. During 2008, we reduced our short-term investment balances by $247 million. During 2007, we reduced our short-term investment balances by $233 million and utilized $105 million of net borrowings from our unsecured revolving line of credit to supplement our operating cash flow and fund debt repayments.

     In 2008, another significant source of cash has been the proceeds from our African divestiture program. In the second and third quarters of 2008, we received $2.6 billion in proceeds ($1.9 billion net of income taxes and purchase price adjustments) from 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 $2.3 billion of earnings from certain foreign subsidiaries to the United States in the first nine months of 2008.

     During 2008, we have 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, redemptions of preferred stock and dividends on common and preferred stock.

Capital Expenditures

     Following are the components of our capital expenditures for the first nine months of 2008 and 2007.

	Nine Months
	Ended September 30,
	2008		2007
	(In millions)
U.S. Onshore	$	3,381	$	2,371
U.S. Offshore		813		485
Canada		1,137		928
International		412		366
Total exploration and development		5,743		4,150
Midstream		310		266
Other		126		61
Total capital expenditures	$	6,179	$	4,477

     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 $5.7 billion and $4.2 billion in the first nine months of 2008 and 2007, 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.

     Our exploration and development capital expenditures increased $1.6 billion in the first nine months of 2008. The higher expenditures primarily related to increased drilling activities in the Barnett Shale, Gulf of Mexico and Carthage areas of the United States and the Lloydminster area of Canada. Expenditures also increased due to inflationary pressure driven by increased competition for field services.

Net Repayments of Debt

     During the first nine months 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 nine months of 2008, virtually all holders of exchangeable debentures exercised their option to exchange their debentures for shares of Chevron common stock owned by Devon. The debentures matured on August 15, 2008. In lieu of delivering its shares of Chevron common stock, Devon exercised its option to pay the exchanging

41

debenture holders cash totaling $1.0 billion. This amount included the retirement of debentures with a book value of $652 million and a $379 million reduction of the related embedded derivative option’s balance.

Repurchases of Common Stock

     During the first nine months of 2008, we repurchased 6.5 million shares for $665 million, or $102.56 per share. The 6.5 million shares include 4.5 million shares that were repurchased under our 50 million share program and 2.0 million shares that were repurchased under our ongoing, annual stock repurchase program.

     During the first nine months of 2007, we repurchased 1.7 million shares at a cost of $133 million.

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 $211 million (or a quarterly rate of $0.16 per share) and $186 million (or a quarterly rate of $0.14 per share) in the first nine months of 2008 and 2007, respectively. The higher dividend rate was the primary cause of the increase in common dividends. Our preferred dividends were $5 million and $7 million in the first nine months of 2008 and 2007. The decrease in the 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 been our operating cash flow. Additionally, we maintain revolving lines of credit and a commercial paper program which can be accessed as needed to supplement operating cash flow. Another available source of liquidity includes our cash on hand which totaled $1.2 billion as of September 30, 2008. Additionally, the proceeds from the sales of our operations in West Africa, including related repatriations of earnings from certain foreign subsidiaries to the United States, has served as another major source of liquidity in 2008. During the first nine months of 2008, we repatriated $2.3 billion in earnings. We expect to repatriate approximately $0.4 billion during the last three months of 2008.

     We currently estimate these capital resources will provide sufficient liquidity to fund our planned uses of capital over the near-term. We are currently generating significant operating cash flow that adequately funds our capital expenditures. Additionally, we have no short-term debt. We also have approximately $3.1 billion of available capacity under our lines of credit.

     The issuance of equity securities and long-term debt has occasionally over the years been a source of capital and liquidity for us. The extraordinary conditions in the global financial and capital markets have currently limited the availability of these resources. However, we do not anticipate needing these types of capital resources for near-term liquidity needs.

Operating Cash Flow

     Our operating cash flow increased 71% to a record high of $8.1 billion in the first nine months of 2008. We expect operating cash flow to continue to be our primary source of liquidity. Our operating cash flow is sensitive to many variables, the most volatile of which is pricing of the oil, natural gas and NGLs produced.

     Commodity Prices- To mitigate some of the risk inherent in prices, we have utilized various price collars to set minimum and maximum prices on a portion of our production. We have also utilized various price swap contracts and fixed-price physical delivery contracts to fix the price of a portion of our future oil and natural gas production. As disclosed in “Item 7A. Quantitative and Qualitative Disclosures of Market Risk” of our 2007 Annual Report on Form 10-K/A, approximately 64% of our estimated 2008 natural gas production and 12% of our estimated oil production are subject to either price collars, swaps or fixed-price contracts. Additionally, subsequent to the filing of our 2007 Annual

42

Report, we have entered into additional gas price collars, which represent approximately 10% of our estimated 2009 natural gas production. The key terms of these 2009 price collars are included in “Item 3. Quantitative and Qualitative Disclosures of Market Risk” of this report.

     Interest Rates- Our operating cash flow can also be sensitive to interest rate fluctuations. As of September 30, 2008, we had long-term debt of $4.8 billion. All of this long-term debt bears interest at fixed rates with an overall weighted-average rate of 7.6%. In July 2008, we entered into interest rate swaps to mitigate a portion of the fair value effects of interest rate fluctuations on our fixed-rate debt. Under the terms of these swaps, we receive a fixed rate and pay a variable rate on a total notional amount of $1.05 billion. Including the effects of these swaps, the weighted-average interest rate related to our fixed-rate debt was 7.2% as of September 30, 2008. The key terms of these interest rate swaps are included in “Item 3. Quantitative and Qualitative Disclosures of Market Risk” of this report.

     Credit Losses- Our operating cash flow is also exposed to credit risk in a variety of ways. We are exposed to the credit risk of the customers who purchase our oil, natural gas and NGL production. We are also exposed to credit risk related to the collection of receivables from our joint-interest partners for their proportionate share of expenditures made on projects we operate. We are also exposed to the credit risk of counterparties to our derivative financial contracts as discussed previously in this report.

     The recent deterioration of the global financial and capital markets, combined with the drop in oil and natural gas prices, has increased our credit risk exposure. However, we utilize a variety of mechanisms to limit our exposure to the credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions, prepayment requirements for commodity sales and collateral posting requirements in our existing derivative contracts. As a result of these and other activities, we currently believe we have substantially mitigated the credit risk effect on our operating cash flow.

Credit Lines

     We have a five-year, syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). In August 2008, we added $150 million to our Senior Credit Facility, increasing the total capacity to $2.65 billion.

     On November 5, 2008, we established a new $700 million 364-day, syndicated, unsecured revolving senior credit facility (the “Short-Term Facility”). This new facility provides us with incremental liquidity to support the retirement of maturing debentures during 2008 and near-term capital expenditures. The Short-Term Facility also supports an increase in our commercial paper program to $2.85 billion.

     The Short-Term Facility matures on November 3, 2009. On the maturity date, all amounts outstanding will be due and payable at that time. Amounts borrowed under the Short-Term Facility bear interest at various fixed rate options for periods of up to 12 months. Such rates are generally based on LIBOR or the prime rate. The Short-Term Facility currently provides for an annual facility fee of approximately $0.7 million that is payable quarterly in arrears.

     The agreement governing the Short-Term Facility contains substantially the same covenants and restrictions as Devon’s existing Senior Credit Facility, including a maximum allowed debt-to-capitalization ratio of 65% as defined in the agreement.

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     The following schedule summarizes the capacity of our credit facilities by maturity date, as well as our available capacity as of November 5, 2008.

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		700
Total credit facility capacity		3,350
Less:
Outstanding credit facility borrowings		—
Outstanding commercial paper borrowings		137
Outstanding letters of credit		118
Total credit facility available capacity	$	3,095

     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 September 30, 2008, Devon was in compliance with this covenant. Devon’s debt-to-capitalization ratio at September 30, 2008, as calculated pursuant to the terms of the agreement, was 15.4%.

Debt Ratings

     During the first quarter of 2008, Standard and Poor’s upgraded our credit rating from BBB with a positive outlook to BBB+ with a stable outlook. During the second quarter of 2008, Fitch upgraded our credit rating from BBB with a positive outlook to BBB+ with a stable outlook. We are not aware of any potential downgrades or changes contemplated by the other rating agencies as of October 31, 2008.

Property Divestitures

     At the end of the third quarter of 2008, we had substantially completed our Africa divestiture program. In the fourth quarter of 2007, we sold our assets in Egypt. In the second quarter of 2008, we completed the sales of assets in certain West African countries, including Equatorial Guinea—the largest individual transaction in the divestiture program. In the third quarter of 2008, we completed the sale of our assets in Cote d’Ivoire for $205 million ($163 million net of purchase price adjustments). As a result of this sale, we recognized an after-tax gain of $101 million in the third quarter of 2008.

     With the completion of the Cote d’Ivoire transaction, we have divested all of our oil and gas producing properties in Africa. The Africa divestitures have generated just over $3.0 billion of sales proceeds. After income taxes and purchase price adjustments, such proceeds totaled $2.2 billion and generated after-tax gains of $0.8 billion. As planned, we have used these proceeds and related repatriations to the United States to repay debt, repurchase common stock and redeem our outstanding preferred stock during 2008.

Capital Expenditures

     In August 2008, we provided guidance for our 2008 capital expenditures. At that time, we estimated capital expenditures for our oil and gas exploration and development operations would range from $7.2 billion to $7.5 billion. Based upon current oil and natural gas price expectations and the commodity price collars, swaps and fixed-price contracts we have in place, we anticipate having adequate capital resources to fund our planned capital expenditures in the near-term.

Common Stock Repurchase Programs

     Our Board of Directors approved an ongoing, annual stock repurchase program to mitigate dilution resulting from restricted stock issued to, and options exercised by, employees. In 2008, the repurchase program authorizes the repurchase of up to 4.8 million shares or a cost of $422 million, whichever amount is reached first. Our Board of Directors also approved a separate program to repurchase up to 50 million shares, which expires on December 31, 2009. As of

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September 30, 2008, up to 2.8 million shares or $244 million can be repurchased under the ongoing, annual repurchase program and up to 45.5 million shares can be repurchased under the 50 million share repurchase program.

Auction Rate Securities

     At December 31, 2007, we held $372 million of auction rate securities, which are asset-backed securities that have an auction rate reset feature. Our auction rate securities are rated AAA—the highest rating—by one or more rating agencies and are collateralized by student loans that are substantially guaranteed by the United States government. Although our auction rate securities generally have contractual maturities of more than 20 years, the underlying interest rates on such securities are scheduled to reset every seven to 28 days. Therefore, these auction rate securities were generally priced and subsequently traded as short-term investments because of the interest rate reset feature. As a result, we considered our auction rate securities to be short-term investments at the end of 2007.

     During the first nine months of 2008, we reduced our auction rate securities holdings to $125 million as of September 30, 2008. However, since February 8, 2008, we have experienced difficulty selling our securities due to the failure of the auction mechanism, which provided liquidity to these securities. An auction failure means that the parties wishing to sell securities could not do so. The securities for which auctions have failed will continue to accrue interest and be auctioned every seven to 28 days until the auction succeeds, the issuer calls the securities or the securities mature.

     From February 2008, when auctions began failing, to September 30, 2008, issuers redeemed $27 million of our auction rate securities holdings at par. Additionally, our auction rate securities holdings as of September 30, 2008, include approximately $1 million of securities that were called at par value by the issuer and were repaid on October 1, 2008. These called securities continue to be considered short-term investments as of September 30, 2008. However, based on continued auction failures and the current market for our auction rate securities, we have classified the $124 million of securities that have not been called as long-term investments as of September 30, 2008 and generally not available for short-term liquidity needs.

     As of December 31, 2007, we estimated the fair values of our short-term auction rate securities using quoted market prices. However, due to the auction failures discussed above and the lack of an active market for our long-term securities, quoted market prices for the vast majority of these securities were not available as of September 30, 2008. Therefore, we used valuation techniques that rely on unobservable inputs to estimate the fair values of our long-term auction rate securities as of September 30, 2008. These inputs were based on the AAA credit rating of the securities, the probability of full repayment of the securities considering the United States government guarantees of substantially all of the underlying student loans, the collection of all accrued interest to date and continued receipts of principal at par. As a result of using these inputs, we concluded the estimated fair values of our long-term auction rate securities approximated the par values as of September 30, 2008. At this time, we do not believe the values of our long-term securities are impaired.

Pension Plans

     Our assets related to our pension plans have been adversely impacted by the performance of the equity markets in recent months, especially since September 30, 2008. Losses incurred on these investments will likely cause us to contribute more to our pension plans in 2009 than what would otherwise have been expected. Such losses will also likely cause an increase in our pension expense in 2009. However, the amounts of additional contributions and pension expense are not expected to have a material impact on our liquidity or results of operations.

Critical Accounting Estimates

Full Cost Ceiling Calculations

     We follow the full cost method of accounting for our oil and gas properties. As disclosed in our 2007 Annual Report on Form 10-K/A, the full cost method subjects us to quarterly calculations of a “ceiling,” or limitation on the amount of properties that can be capitalized on the balance sheet. If our net book value of oil and gas properties, less related deferred income taxes, (“recoverable costs”) exceeds the calculated ceiling, the excess must be written off as an expense. The ceiling limitation is imposed separately for each country in which we have oil and gas properties. As of September 30, 2008, our recoverable costs were less than the calculated ceiling for all countries.

     Subsequent to September 30, 2008, most price indices associated with our oil, natural gas and NGL reserves declined significantly. These declines have increased the likelihood that our recoverable costs may exceed the calculated ceiling for certain countries in future periods, particularly in Brazil where we are in the early stages of development activities.

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However, it is not possible at this time to determine what the calculated ceiling will be as of December 31, 2008. The calculated ceiling at December 31, 2008 will be based on estimates of our proved oil, gas and NGL reserves as of that date and the associated commodity prices, operating expenses and future development costs on that date.

Recently Issued Accounting Standards Not Yet Adopted

     In December 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 141(R),Business Combinations, which replaces Statement No. 141. Statement No. 141(R) retains the fundamental requirements of Statement No. 141 that an acquirer be identified and the acquisition method of accounting (previously called the purchase method) be used for all business combinations. Statement No. 141(R)’s scope is broader than that of Statement No. 141, which applied only to business combinations in which control was obtained by transferring consideration. By applying the acquisition method to all transactions and other events in which one entity obtains control over one or more other businesses, Statement No. 141(R) improves the comparability of the information about business combinations provided in financial reports. Statement No. 141(R) establishes principles and requirements for how an acquirer recognizes and measures identifiable assets acquired, liabilities assumed and any noncontrolling interest in the acquiree, as well as any resulting goodwill. Statement No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We will evaluate how the new requirements of Statement No. 141(R) would impact any business combinations completed in 2009 or thereafter.

     In December 2007, the FASB also issued Statement of Financial Accounting Standards No. 160,Noncontrolling Interests in Consolidated Financial Statements—an amendment of Accounting Research Bulletin No. 51. A noncontrolling interest, sometimes called a minority interest, is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. Statement No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Under Statement No. 160, noncontrolling interests in a subsidiary must be reported as a component of consolidated equity separate from the parent’s equity. Additionally, the amounts of consolidated net income attributable to both the parent and the noncontrolling interest must be reported separately on the face of the income statement. Statement No. 160 is effective for fiscal years beginning on or after December 15, 2008 and earlier adoption is prohibited. We do not expect the adoption of Statement No. 160 to have a material impact on our financial statements and related disclosures.

     In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161,Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133. Statement No. 161 requires additional disclosures about derivative and hedging activities and is effective for fiscal years and interim periods beginning after November 15, 2008. We are evaluating the impact the adoption of Statement No. 161 will have on our financial statement disclosures. However, our adoption of Statement No. 161 will not affect our current accounting for derivative and hedging activities.

Item 3.Quantitative and Qualitative Disclosures About Market Risk

     Gas Collar Contracts

     We have various financial price swaps to fix the price of a portion of our 2008 gas production. We also have various financial price collars to set minimum and maximum prices on a portion of our 2008 oil and gas production. The key terms to these 2008 price swaps and collars are included in Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2007 Annual Report on Form 10-K/A.

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     We have also entered into various financial price collars to set minimum and maximum prices on approximately 10% of our expected 2009 gas production. The key terms to our 2009 gas financial collar contracts are not included in our 2007 Annual Report on Form 10-K/A but are presented in the following table.

Gas Price Collar Contracts
			Floor Price			Ceiling Price
				Weighted			Weighted
			Floor	Average		Ceiling	Average
	Volume		Range	Floor Price		Range	Ceiling Price
Period	(MMBtu/d)		($/MMBtu)	($/MMBtu)		($/MMBtu)	($/MMBtu)
First quarter		300,000	$8.00 - $8.50	$	8.25	$10.60 - $14.00	$	11.97
Second quarter		300,000	$8.00 - $8.50	$	8.25	$10.60 - $14.00	$	11.97
Third quarter		300,000	$8.00 - $8.50	$	8.25	$10.60 - $14.00	$	11.97
Fourth quarter		300,000	$8.00 - $8.50	$	8.25	$10.60 - $14.00	$	11.97
2009 average		300,000	$8.00 - $8.50	$	8.25	$10.60 - $14.00	$	11.97

     The fair values of all our oil and gas hedging instruments are largely determined by estimates of the forward curves of relevant oil and gas price indexes. At September 30, 2008, a 10% increase in these forward curves would have decreased the net assets recorded for our 2008 and 2009 commodity hedging instruments by approximately $130 million.

     Interest Rate Swap Contracts

     We have entered into various interest rate swaps to mitigate a portion of the fair value effects of interest rate fluctuations on our fixed-rate debt. Under the terms of these swaps, we receive a fixed rate and pay a variable rate on a total notional amount of $1.05 billion. The key terms of these interest rate swaps are presented in the table below.

		Fixed Rate			Variable
Notional		Received			Rate Paid	Expiration
(In millions)
$	500		3.90	%	Federal funds rate	July 18, 2013
$	300		4.30	%	Six month LIBOR	July 18, 2011
$	250		3.85	%	Federal funds rate	July 22, 2013
$	1,050		4.00	%

     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 September 30, 2008, a 10% increase in these forward curves would have decreased our net assets by approximately $15 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.

     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 September 30, 2008 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 third quarter of 2008 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 2007 Annual Report on Form 10-K/A.

Item 1A.Risk Factors

     There have been no material changes to the information included in Item 1A. “Risk Factors” in our 2007 Annual Report on Form 10-K/A.

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

	Total				Total Number of		Maximum Number of
	Number of		Average Price		Shares Purchased as		Shares that May Yet Be
	Shares		Paid per		Part of Publicly Announced		Purchased Under the
Period	Purchased		Share		Plans or Programs(1)		Plans or Programs(1)
July		2,828,541	$	102.17		2,828,541		49,126,644
August		810,500	$	91.80		810,500		48,316,144
September		—	$	—		—		48,316,144
Total		3,639,041	$	99.86		3,639,041

(1) Our Board of Directors approved an ongoing, annual stock repurchase program to minimize dilution resulting from restricted stock issued to, and options exercised by, employees. In 2008, the repurchase program authorizes the repurchase of up to 4.8 million shares or a cost of $422 million, whichever amount is reached first. Our Board of Directors also approved a separate program to repurchase up to 50 million shares, which expires on December 31, 2009. As of September 30, 2008, up to 2.8 million shares or $244 million can be repurchased under the ongoing, annual repurchase program and up to 45.5 million shares can be repurchased under the 50 million share repurchase program.

Item 3.Defaults Upon Senior Securities

     None.

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

     None.

Item 5.Other Information

     None.

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Item 6.Exhibits

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

Exhibit
Number	Description
10.1	364-Day Credit Agreement dated as of November 5, 2008 among Registrant as Borrower, Bank of America, N.A. as Administrative Agent, JPMorgan Chase Bank, N.A. as Syndication Agent, and The Other Lenders party thereto, Banc of America Securities LLC and J.P. Morgan Securities, Inc. as Joint Lead Arrangers and Book Managers for the $700 Million Short-Term Credit Facility.
10.2	Fifth Amendment to Amended and Restated Credit Agreement dated as of November 5, 2008, among Registrant as US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent, and the Lenders party thereto.
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.

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: November 6, 2008	/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
10.1	364-Day Credit Agreement dated as of November 5, 2008 among Registrant as Borrower, Bank of America, N.A. as Administrative Agent, JPMorgan Chase Bank, N.A. as Syndication Agent, and The Other Lenders party thereto, Banc of America Securities LLC and J.P. Morgan Securities, Inc. as Joint Lead Arrangers and Book Managers for the $700 Million Short-Term Credit Facility.
10.2	Fifth Amendment to Amended and Restated Credit Agreement dated as of November 5, 2008, among Registrant as US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent, and the Lenders party thereto.
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.

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