Devon Energy 10Q 2008 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the Quarterly Period Ended June 30, 2008


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. Yes þ No o

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 filer o (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). Yes o No þ

As of July 31, 2008, 441.8 million shares of the registrant’s common stock were outstanding.

[This page intentionally left blank.]

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 June 30, 2008 (Unaudited) and December 31, 2007			6
Consolidated Statements of Operations (Unaudited) for the Three Months and Six Months Ended June 30, 2008 and 2007			7
Consolidated Statements of Comprehensive Income (Unaudited) for the Three Months and Six Months Ended June 30, 2008 and 2007			8
Consolidated Statements of Stockholders’ Equity (Unaudited) for the Six Months Ended June 30, 2008 and 2007			9
Consolidated Statements of Cash Flows (Unaudited) for the Six Months Ended June 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			27
Item 3.Quantitative and Qualitative Disclosures About Market Risk			42
Item 4.Controls and Procedures			43

PART II. OTHER INFORMATION			44

Item 1.Legal Proceedings			44
Item 1A.Risk Factors			44
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds			44
Item 3.Defaults Upon Senior Securities			44
Item 4.Submission of Matters to a Vote of Security Holders			44
Item 5.Other Information			45
Item 6.Exhibits			46

SIGNATURES			46
Registrant's Certificate of Amendment of Restated Certificate of Incorporation
Form of Amendment to Nonqualified Stock Option Award Agreements
Form of Amendment to Restricted Stock Award Agreements
Form of Non-Management Director Nonqualified Stock Option Award Agreement
Form of Non-Management Director Restricted Stock Award Agreement
Certification of J. Larry Nichols, Chief Executive Officer Pursuant to Section 302
Certification of Danny J. Heatly, Vice President - Accounting and Chief Accounting Officer Pursuant to Section 302
Certification of J. Larry Nichols, Chief Executive Officer Pursuant to Section 906
Certification of Danny J. Heatly, Vice President - Accounting and Chief Accounting Officer Pursuant to Section 906

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.

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 that financial institutions charge each other for the use of United States Treasury funds.

“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.

PART I. Financial Information

Item 1.Consolidated Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	June 30,			December 31,
	2008			2007
	(Unaudited)
	(In millions)
ASSETS
Current assets:
Cash and cash equivalents	$	1,837		$	1,364
Short-term investments, at fair value		1			372
Accounts receivable		2,460			1,779
Deferred income taxes		775			44
Current assets held for sale		105			120
Other current assets		255			235

Total current assets		5,433			3,914

Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($3,741 and $3,417 excluded from amortization in 2008 and 2007, respectively)		51,953			48,473
Less accumulated depreciation, depletion and amortization		21,769			20,394

		30,184			28,079
Investment in Chevron Corporation common stock, at fair value		1,406			1,324
Goodwill		6,081			6,172
Long-term assets held for sale		84			1,512
Other long-term assets, including $126 million at fair value in 2008		592			455

Total assets	$	43,780		$	41,456


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable – trade	$	1,525		$	1,360
Revenues and royalties due to others		966			578
Income taxes payable		306			97
Debentures exchangeable into shares of Chevron Corporation common stock		621			—
Other short-term debt		—			1,004
Derivative financial instruments, at fair value		2,125			—
Current portion of asset retirement obligation, at fair value		63			82
Current liabilities associated with assets held for sale		16			145
Accrued expenses and other current liabilities		410			391

Total current liabilities		6,032			3,657

Debentures exchangeable into shares of Chevron Corporation common stock		—			641
Other long-term debt		4,829			6,283
Derivative financial instruments, at fair value		83			488
Asset retirement obligation, at fair value		1,430			1,236
Long-term liabilities associated with assets held for sale		24			404
Other long-term liabilities		905			699
Deferred income taxes		7,044			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 444.9 million and 444.2 million shares in 2008 and 2007, respectively		44			44
Additional paid-in capital		6,591			6,743
Retained earnings		14,717			12,813
Accumulated other comprehensive income		2,131			2,405
Treasury stock, at cost. 0.4 million shares in 2008		(50	)		—

Total stockholders’ equity		23,433			22,006

Commitments and contingencies (Note 8)
Total liabilities and stockholders’ equity	$	43,780		$	41,456

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(Unaudited)
	(In millions, except per share amounts)
Revenues:
Oil sales	$	1,455		$	865		$	2,705		$	1,556
Gas sales		2,210			1,366			3,840			2,612
NGL sales		379			224			707			401
Net (loss) gain on oil and gas derivative financial instruments		(1,215	)		14			(2,003	)		(6	)
Marketing and midstream revenues		719			460			1,274			839

Total revenues		3,548			2,929			6,523			5,402

Expenses and other income, net:
Lease operating expenses		537			439			1,043			869
Production taxes		176			90			310			170
Marketing and midstream operating costs and expenses		515			341			897			611
Depreciation, depletion and amortization of oil and gas properties		762			645			1,499			1,232
Depreciation and amortization of non-oil and gas properties		62			49			119			95
Accretion of asset retirement obligation		22			18			44			36
General and administrative expenses		180			113			328			232
Interest expense		90			107			192			217
Change in fair value of non-oil and gas derivative financial instruments		(40	)		(10	)		(24	)		(9	)
Other income, net		(17	)		(17	)		(38	)		(43	)

Total expenses and other income, net		2,287			1,775			4,370			3,410
Earnings from continuing operations before income tax expense		1,261			1,154			2,153			1,992
Income tax expense:
Current		414			174			517			363
Deferred		253			156			391			231

Total income tax expense		667			330			908			594

Earnings from continuing operations		594			824			1,245			1,398
Discontinued operations:
Earnings from discontinued operations before income tax expense		851			128			1,040			265
Income tax expense		144			48			235			108

Earnings from discontinued operations		707			80			805			157

Net earnings		1,301			904			2,050			1,555
Preferred stock dividends		3			3			5			5

Net earnings applicable to common stockholders	$	1,298		$	901		$	2,045		$	1,550


Basic net earnings per share:
Earnings from continuing operations	$	1.33		$	1.84		$	2.79		$	3.13
Earnings from discontinued operations		1.58			0.18			1.80			0.35

Net earnings	$	2.91		$	2.02		$	4.59		$	3.48


Diluted net earnings per share:
Earnings from continuing operations	$	1.31		$	1.82		$	2.76		$	3.09
Earnings from discontinued operations		1.57			0.18			1.79			0.35

Net earnings	$	2.88		$	2.00		$	4.55		$	3.44


Weighted average common shares outstanding:
Basic		446			446			445			445

Diluted		450			450			450			450

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(Unaudited)
	(In millions)
Net earnings	$	1,301		$	904		$	2,050		$	1,555
Foreign currency translation:
Change in cumulative translation adjustment		88			649			(294	)		732
Income tax benefit (expense)		(3	)		(35	)		14			(41	)

Total		85			614			(280	)		691

Pension and postretirement benefit plans:
Recognition of net actuarial loss and prior service cost in net earnings		4			4			9			8
Income tax expense		(1	)		(2	)		(3	)		(3	)

Total		3			2			6			5

Other		—			—			—			(1	)

Other comprehensive income (loss), net of tax		88			616			(274	)		695

Comprehensive income	$	1,389		$	1,520		$	1,776		$	2,250

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY


																Accumulated
										Additional						Other						Total
	Preferred			Common Stock						Paid-In			Retained			Comprehensive			Treasury			Stockholders’
	Stock			Shares			Amount			Capital			Earnings			Income			Stock			Equity
	(Unaudited)
	(In millions)
Six Months Ended June 30, 2008:
Balance as of December 31, 2007	$	1			444		$	44		$	6,743		$	12,813		$	2,405		$	—		$	22,006
Net earnings		—			—			—			—			2,050			—			—			2,050
Other comprehensive loss		—			—			—			—			—			(274	)		—			(274	)
Stock option exercises		—			4			1			107			—			—			(4	)		104
Common stock repurchased		—			—			—			—			—			—			(316	)		(316	)
Common stock retired		—			(3	)		(1	)		(269	)		—			—			270			—
Redemption of preferred stock		(1	)		—			—			(149	)		—			—			—			(150	)
Common stock dividends		—			—			—			—			(141	)		—			—			(141	)
Preferred stock dividends		—			—			—			—			(5	)		—			—			(5	)
Share-based compensation		—			—			—			104			—			—			—			104
Excess tax benefits on share-based compensation		—			—			—			55			—			—			—			55

Balance as of June 30, 2008	$	—			445		$	44		$	6,591		$	14,717		$	2,131		$	(50	)	$	23,433


Six Months Ended June 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		—			—			—			—			1,555			—			—			1,555
Other comprehensive income		—			—			—			—			—			695			—			695
Stock option exercises		—			2			1			59			—			—			—			60
Common stock repurchased		—			—			—			—			—			—			(16	)		(16	)
Common stock retired		—			—			—			(17	)		—			—			17			—
Common stock dividends		—			—			—			—			(124	)		—			—			(124	)
Preferred stock dividends		—			—			—			—			(5	)		—			—			(5	)
Share-based compensation		—			—			—			57			—			—			—			57
Excess tax benefits on share-based compensation		—			—			—			17			—			—			—			17

Balance as of June 30, 2007	$	1			446		$	45		$	6,956		$	10,893		$	1,791		$	—		$	19,686

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months
	Ended June 30,
	2008			2007
	(Unaudited)
	(In millions)
Cash flows from operating activities:
Net earnings	$	2,050		$	1,555
Earnings from discontinued operations, net of tax		(805	)		(157	)
Adjustments to reconcile earnings from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization		1,618			1,327
Deferred income tax expense		391			231
Net unrealized loss on oil and gas derivative financial instruments		1,692			23
Other noncash charges		122			71
(Increase) decrease in assets:
Accounts receivable		(604	)		32
Other current assets		(44	)		(27	)
Other long-term assets		(40	)		(46	)
Increase (decrease) in liabilities:
Accounts payable		120			64
Revenues and royalties due to others		348			(17	)
Income taxes payable		136			178
Other current liabilities		(99	)		(96	)
Other long-term liabilities		181			14

Cash provided by operating activities – continuing operations		5,066			3,152
Cash provided by operating activities – discontinued operations		120			197

Net cash provided by operating activities		5,186			3,349


Cash flows from investing activities:
Proceeds from sales of property and equipment		108			37
Capital expenditures		(3,867	)		(2,990	)
Purchases of short-term investments		(50	)		(589	)
Redemptions of short-term and long-term investments		295			848

Cash used in investing activities – continuing operations		(3,514	)		(2,694	)
Cash provided by (used in) investing activities – discontinued operations		1,709			(115	)

Net cash used in investing activities		(1,805	)		(2,809	)


Cash flows from financing activities:
Credit facility repayments		(3,070	)		—
Credit facility borrowings		1,620			—
Net commercial paper repayments		(1,004	)		(183	)
Principal payments on debt		(47	)		—
Preferred stock redemption		(150	)		—
Proceeds from stock option exercises		104			60
Repurchases of common stock		(252	)		(10	)
Dividends paid on common and preferred stock		(146	)		(129	)
Excess tax benefits related to share-based compensation		55			17

Net cash used in financing activities		(2,890	)		(245	)

Effect of exchange rate changes on cash		(19	)		16

Net increase in cash and cash equivalents		472			311
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)	$	1,845		$	1,067

Supplementary cash flow data:
Interest paid (net of capitalized interest)	$	189		$	202
Income taxes paid – continuing and discontinued operations	$	826		$	159

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

The accompanying unaudited 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 June 30, 2008 and Devon’s results of operations and cash flows for the three-month and six-month periods ended June 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 half of 2008, Devon reduced its auction rate securities holdings to $127 million. However, since February 8, 2008 Devon has experienced difficulty selling its securities due to the failure of the auction mechanism, which provides 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 June 30, 2008, issuers redeemed $26 million of Devon’s auction rate securities holdings at par. Additionally, Devon’s auction rate securities holdings as of June 30, 2008 include approximately $1 million of securities that were called at par value by the issuer and were repaid on July 10, 2008. These called securities are classified as short-term investments in the accompanying June 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 $126 million of securities that have not been called as of June 30, 2008 as long-term investments. These securities are included in other long-term assets in the accompanying June 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.

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. 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. Additional information regarding Devon’s Egyptian and West African operations, which are presented as discontinued in the accompanying financial statements, is provided in Note 12.

Asset Retirement Obligations (“ARO”)

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


	Six Months
	Ended June 30,
	2008			2007
	(In millions)
Asset retirement obligation as of beginning of period	$	1,318		$	857
Liabilities incurred		29			32
Liabilities settled		(40	)		(24	)
Revision of estimated obligation		162			311
Accretion expense on discounted obligation		44			36
Foreign currency translation adjustment		(20	)		47

Asset retirement obligation as of end of period		1,493			1,259
Less current portion		63			45

Asset retirement obligation, long-term	$	1,430		$	1,214

During the first six months of 2008 and 2007, Devon recognized increases of $162 million and $311 million, respectively, to its ARO. The primary factors causing the 2008 fair value increase were an overall increase in abandonment cost estimates and the effect of a decrease in the discount rate used to present value the obligations. 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.

3. Commodity 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

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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.

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 and price collars are also recorded in the statement of operations.

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


	June 30, 2008		December 31, 2007
	(In millions)
Fair values:
Other current assets – gas price swaps	$	—	$	12
Derivative financial instruments, current liability:
Gas price swaps	$	606	$	—
Gas price collars		945		—
Oil price collars		46		—

Total derivative financial instruments, current liability	$	1,597	$	—

Derivative financial instruments, long-term liability:
Gas price swaps	$	—	$	—
Gas price collars		83		—
Oil price collars		—		—

Total derivative financial instruments, long-term liability	$	83	$	—


	Three Months Ended June 30,					Six Months Ended June 30,
	2008			2007		2008			2007
	(In millions)
Cash settlements:
Gas price swaps	$	(153	)	$	5	$	(161	)	$	15
Gas price collars		(150	)		—		(150	)		2

Total cash settlements (paid) received		(303	)		5		(311	)		17

Unrealized (losses) gains on fair value changes:
Gas price swaps		(247	)		9		(618	)		(19	)
Gas price collars		(620	)		—		(1,028	)		(4	)
Oil price collars		(45	)		—		(46	)		—

Total unrealized (losses) gains on fair value changes		(912	)		9		(1,692	)		(23	)

Net (loss) gain on oil and gas derivative financial instruments	$	(1,215	)	$	14	$	(2,003	)	$	(6	)

4. Debt

Credit Facilities

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

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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.

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.

On August 7, 2007, Devon established a $1.5 billion 364-day, syndicated, unsecured revolving senior credit facility (the “Short-Term Facility”). This facility matured on August 5, 2008 and was not extended. As a result of the Short-Term Facility’s maturity, Devon’s commercial paper program capacity decreased from $3.5 billion to $2.0 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 June 30, 2008, Devon was in compliance with this covenant. Devon’s debt-to-capitalization ratio at June 30, 2008, as calculated pursuant to the terms of the agreement, was 16.3%.

As of August 5, 2008, Devon’s available capacity under its Senior Credit Facility was approximately $2.4 billion. This available capacity is net of $140 million of outstanding letters of credit. There were no outstanding commercial paper or Senior Credit Facility borrowings as of August 5, 2008.

Exchangeable Debentures

During the first six months of 2008, certain holders of exchangeable debentures exercised their option to exchange their debentures for shares of Chevron Corporation (“Chevron”) common stock that Devon owns prior to the debentures’ August 15, 2008 maturity date. In lieu of delivering Chevron common stock to an exchanging debenture holder, Devon may, at its option, pay to such holder an amount of cash equal to the market value of Chevron common stock. During the first half of 2008, Devon elected to pay the exchanging debenture holders cash totaling $47 million in lieu of delivering shares of Chevron common stock. As a result of these exchanges, Devon retired outstanding exchangeable debentures with a book value totaling $28 million and reduced the related embedded derivative option’s balance by $19 million.

As of June 30, 2008, Devon has classified the exchangeable debentures as short-term borrowings in the accompanying consolidated balance sheet. Although the exchangeable debentures have been due within one year since August 15, 2007, Devon previously classified the debt as long-term borrowings. The long-term classification was based on the uncertain timing of the closings of sales of assets in West Africa, particularly the sale of assets in Equatorial Guinea. Based on the sale proceeds received during the second quarter of 2008, Devon now intends to repay the exchangeable debentures with cash on hand or short-term commercial paper borrowings.

5. 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 June 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.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	As of June 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	$	127		$	127		$	1	$	—		$	126
Investment in Chevron common stock	$	1,406		$	1,406		$	1,406	$	—		$	—
Net oil and gas price swaps and collars	$	(1,680	)	$	(1,680	)	$	—	$	(1,680	)	$	—
Embedded option in exchangeable debentures	$	(528	)	$	(528	)	$	—	$	(528	)	$	—
Asset retirement obligation	$	(1,493	)	$	(1,493	)	$	—	$	—		$	(1,493	)


	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 June 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 June 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 June 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 and the collection of all accrued interest to date. As a result of using these inputs, Devon concluded the estimated fair values of its long-term auction rate securities approximated the par values as of June 30, 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 half of 2008 (in millions).


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

Ending balance	$	126

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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 2.

6. Retirement Plans

Net Periodic Benefit Cost and Other Comprehensive Income

The following table presents the components of net periodic benefit cost and other comprehensive income for Devon’s pension and other post retirement benefit plans for the three-month and six-month periods ended June 30, 2008 and 2007.


	Pension Benefits												Other Postretirement Benefits
	Three Months						Six Months						Three Months				Six Months
	Ended June 30,						Ended June 30,						Ended June 30,				Ended June 30,
	2008			2007			2008			2007			2008		2007		2008		2007
	(In millions)
Net periodic benefit cost:
Service cost	$	10		$	7		$	20		$	15		$	—	$	—	$	—	$	—
Interest cost		14			11			28			22			2		1		4		2
Expected return on plan assets		(13	)		(13	)		(26	)		(25	)		—		—		—		—
Net actuarial loss		4			4			8			8			—		—		—		—

Net periodic benefit cost		15			9			30			20			2		1		4		2
Other comprehensive income:
Recognition of net actuarial loss in net periodic benefit cost		(4	)		(4	)		(8	)		(8	)		—		—		—		—

Total recognized	$	11		$	5		$	22		$	12		$	2	$	1	$	4	$	2

Devon previously disclosed in its financial statements for the year ended December 31, 2007, that it expected to contribute $8 million to the Qualified and Supplemental Plans in 2008 and $6 million to the Postretirement Plans in 2008. Devon presently anticipates contributing an additional $10 million to the Qualified and Supplemental Plans in 2008 for a total of $18 million. As of June 30, 2008, Devon has contributed $13 million to the Qualified and Supplemental Plans and $2 million to the Postretirement Plans.

7. 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 six months of 2008, Devon repurchased 2.8 million shares for $302 million, or $106.01 per share, under programs approved by its Board of Directors. The 2.8 million shares include 2.0 million shares that were repurchased under Devon’s 50 million share program and 0.8 million shares that were repurchased under Devon’s ongoing, annual stock repurchase program.

Dividends

Devon paid common stock dividends of $141 million (or a quarterly rate of $0.16 per share) and $124 million (or a quarterly rate of $0.14 per share) in the first six months of 2008 and 2007, respectively. During the first half of 2008 and 2007, Devon also paid $5 million in dividends to preferred stockholders.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

8. 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 although 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, with the first scheduled to begin in August 2008 and the second 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.

The U.S. House of Representatives in January 2007 passed legislation that would have required companies to renegotiate the 1998 and 1999 leases as a condition of securing future federal leases. This legislation was not passed by the U.S. Senate. However, Congress may consider similar legislation in the future. Although Devon has not signed renegotiated leases, it has accrued through June 30, 2008, approximately $40 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 $35 million accrued at June 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, 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.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Certain of Devon’s subsidiaries are involved in matters in which it has been alleged that such subsidiaries are potentially responsible parties (“PRPs”) under CERCLA or similar state legislation with respect to various waste disposal areas owned or operated by third parties. As of June 30, 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, which Devon is utilizing to recover costs associated with the suspended production related to hurricanes that struck the Gulf of Mexico in the third quarter of 2005. 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 include a standard, per-event deductible of $1 million for offshore losses as well as a $15 million aggregate annual deductible.

Based on current estimates of physical damage and the anticipated length of time Devon will have had production suspended, Devon expects its policy recoveries will exceed repair costs and deductible amounts. This expectation is based upon several variables, including the $467 million received in 2006 as a full settlement of the amount due from Devon’s primary insurers and $13 million received in 2007 as a full settlement of the amount due from certain of Devon’s secondary insurers. As of June 30, 2008, $388 million of these proceeds had been utilized as reimbursement of past repair costs and deductible amounts. The remaining proceeds of $92 million are expected to be utilized as reimbursement of Devon’s anticipated future repair costs. Devon continues to negotiate with its other secondary insurers and expects to receive additional policy recoveries as a result of such negotiations.

Should Devon’s total policy recoveries, including the partial settlements already received from Devon’s primary and secondary insurers, exceed all repair costs and deductible amounts, such excess will be recognized as other income in the statement of operations in the period in which such determination can be made.

The policy underlying the insurance program terms described above expired on August 31, 2006. Devon’s current insurance program includes business interruption and physical damage coverage for its business. However, due to significant changes in the insurance marketplace, Devon no longer has coverage for damage that may be caused by named windstorms in the Gulf of Mexico.

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.

9. 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.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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.

10. Change in Fair Value of Non-Oil and Gas Financial Instruments

The components of the change in fair value of non-oil and gas financial instruments include the following:


	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2008			2007			2008			2007
	(In millions)
Losses (gains) from:
Chevron common stock	$	(195	)	$	(146	)	$	(82	)	$	(152	)
Option embedded in exchangeable debentures		155			136			58			144
Other		—			—			—			(1	)

Total	$	(40	)	$	(10	)	$	(24	)	$	(9	)

11. Income Taxes

In the second quarter of 2008, Devon repatriated $1.3 billion in earnings from certain foreign subsidiaries to the United States. Devon also expects to repatriate approximately $1.5 billion in earnings from certain foreign subsidiaries to the United States during the last six months of 2008. Subsequent to these repatriations, Devon does not expect to repatriate similar earnings from its 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 repatriation and 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.

12. 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 fourth quarter of 2007, Devon sold its assets and terminated its operations in Egypt and recognized a $90 million after-tax gain from proceeds of $341 million.

Devon has entered into agreements to sell its operations in Cote D’Ivoire and other countries located in West Africa for approximately $250 million. Devon is obtaining the necessary partner and government approvals for these properties and expects to complete the remaining sales during the third quarter of 2008. Had these transactions closed on June 30, 2008, Devon would have recognized after-tax gains of approximately $100 million. The gains ultimately recorded when the transactions close will depend on

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

the carrying values of Devon’s assets and liabilities at the closing dates, as well as the effect of any purchase price adjustments between the effective dates and the actual closing dates of the sales.

Financial Statement Information

Revenues related to Devon’s discontinued operations totaled $127 million and $215 million in the three months ended June 30, 2008 and June 30, 2007 and $332 million and $390 million in the six months ended June 30, 2008 and 2007, respectively. These amounts do not include the divestiture gains discussed in the previous section.

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


	June 30, 2008		December 31, 2007
	(In millions)
Assets:
Cash	$	8	$	9
Accounts receivable		5		83
Deferred tax asset		68		—
Other current assets		24		28

Current assets	$	105	$	120


Long-term assets — property and equipment, net of accumulated depreciation, depletion and amortization	$	84	$	1,512


Liabilities:
Accounts payable — trade	$	2	$	23
Revenues and royalties due to others		2		11
Income taxes payable		6		100
Current portion of asset retirement obligation		—		9
Accrued expenses and other current liabilities		6		2

Current liabilities	$	16	$	145


Asset retirement obligation, long-term	$	5	$	35
Deferred income taxes		19		366
Other long-term liabilities		—		3

Long-term liabilities	$	24	$	404

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

13. 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 six-month periods ended June 30, 2008 and 2007.


	Net
	Earnings			Weighted
	Applicable to			Average		Net
	Common			Common Shares		Earnings
	Stockholders			Outstanding		per Share
	(In millions, except per share amounts)
Three Months Ended June 30, 2008:
Earnings from continuing operations	$	594
Less preferred stock dividends		(3	)

Basic earnings per share		591			446	$	1.33
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options		—			4

Diluted earnings per share	$	591			450	$	1.31


Three Months Ended June 30, 2007:
Earnings from continuing operations	$	824
Less preferred stock dividends		(3	)

Basic earnings per share		821			446	$	1.84
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options		—			4

Diluted earnings per share	$	821			450	$	1.82


Six Months Ended June 30, 2008:
Earnings from continuing operations	$	1,245
Less preferred stock dividends		(5	)

Basic earnings per share		1,240			445	$	2.79
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options		—			5

Diluted earnings per share	$	1,240			450	$	2.76


Six Months Ended June 30, 2007:
Earnings from continuing operations	$	1,398
Less preferred stock dividends		(5	)

Basic earnings per share		1,393			445	$	3.13
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options		—			5

Diluted earnings per share	$	1,393			450	$	3.09

Certain options to purchase shares of Devon’s common stock are excluded from the dilution calculations because the options are antidilutive. During the three-month and six-month periods ended June 30, 2008, no shares and 1.5 million shares, respectively, were excluded from the diluted earnings per share calculations. During the three-month and six-month periods ended June 30, 2007, 4.0 million shares and 4.1 million shares, respectively, were excluded from the diluted earnings per share calculations.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

14. 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 June 30, 2008:
Current assets	$	3,110	$	1,622	$	701	$	5,433
Property and equipment, net of accumulated depreciation, depletion and amortization		19,976		8,857		1,351		30,184
Goodwill		3,050		2,963		68		6,081
Other long-term assets		1,726		61		295		2,082

Total assets	$	27,862	$	13,503	$	2,415	$	43,780


Current liabilities	$	4,994	$	582	$	456	$	6,032
Long-term debt		1,852		2,977		—		4,829
Asset retirement obligation, long-term		689		646		95		1,430
Other long-term liabilities		938		46		28		1,012
Deferred income taxes		4,871		2,086		87		7,044
Stockholders’ equity		14,518		7,166		1,749		23,433

Total liabilities and stockholders’ equity	$	27,862	$	13,503	$	2,415	$	43,780

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	U.S.			Canada		International			Total
	(In millions)
Three Months Ended June 30, 2008:
Revenues:
Oil sales	$	566		$	498	$	391		$	1,455
Gas sales		1,688			517		5			2,210
NGL sales		305			74		—			379
Net loss on oil and gas derivative financial instruments		(1,215	)		—		—			(1,215	)
Marketing and midstream revenues		707			12		—			719

Total revenues		2,051			1,101		396			3,548

Expenses and other income, net:
Lease operating expenses		279			211		47			537
Production taxes		104			1		71			176
Marketing and midstream operating costs and expenses		510			5		—			515
Depreciation, depletion and amortization of oil and gas properties		481			227		54			762
Depreciation and amortization of non-oil and gas properties		54			7		1			62
Accretion of asset retirement obligation		10			10		2			22
General and administrative expenses		145			34		1			180
Interest expense		36			54		—			90
Change in fair value of non-oil and gas derivative financial instruments		(40	)		—		—			(40	)
Other income, net		(11	)		—		(6	)		(17	)

Total expenses and other income, net		1,568			549		170			2,287

Earnings from continuing operations before income tax expense		483			552		226			1,261
Income tax expense (benefit):
Current		299			46		69			414
Deferred		163			104		(14	)		253

Total income tax expense		462			150		55			667

Earnings from continuing operations		21			402		171			594
Discontinued operations:
Earnings from discontinued operations before income tax expense		—			—		851			851
Income tax expense		—			—		144			144

Earnings from discontinued operations		—			—		707			707

Net earnings		21			402		878			1,301
Preferred stock dividends		3			—		—			3

Net earnings applicable to common stockholders	$	18		$	402	$	878		$	1,298


Capital expenditures, before revision of future ARO	$	1,654		$	182	$	150		$	1,986
Revision of future ARO		—			—		22			22

Capital expenditures, continuing operations	$	1,654		$	182	$	172		$	2,008

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	U.S.			Canada			International			Total
	(In millions)
Three Months Ended June 30, 2007:
Revenues:
Oil sales	$	305		$	185		$	375		$	865
Gas sales		983			380			3			1,366
NGL sales		177			47			—			224
Net gain on oil and gas derivative financial instruments		14			—			—			14
Marketing and midstream revenues		452			8			—			460

Total revenues		1,931			620			378			2,929

Expenses and other income, net:
Lease operating expenses		256			140			43			439
Production taxes		59			1			30			90
Marketing and midstream operating costs and expenses		338			3			—			341
Depreciation, depletion and amortization of oil and gas properties		402			182			61			645
Depreciation and amortization of non-oil and gas properties		44			5			—			49
Accretion of asset retirement obligation		9			8			1			18
General and administrative expenses		91			27			(5	)		113
Interest expense		57			50			—			107
Change in fair value of non-oil and gas derivative financial instruments		(10	)		—			—			(10	)
Other income, net		(6	)		(2	)		(9	)		(17	)

Total expenses and other income, net		1,240			414			121			1,775

Earnings from continuing operations before income tax expense		691			206			257			1,154
Income tax expense (benefit):
Current		55			43			76			174
Deferred		166			(4	)		(6	)		156

Total income tax expense		221			39			70			330

Earnings from continuing operations		470			167			187			824
Discontinued operations:
Earnings from discontinued operations before income tax expense		—			—			128			128
Income tax expense		—			—			48			48

Earnings from discontinued operations		—			—			80			80

Net earnings		470			167			267			904
Preferred stock dividends		3			—			—			3

Net earnings applicable to common stockholders	$	467		$	167		$	267		$	901


Capital expenditures, continuing operations	$	1,079		$	192		$	109		$	1,380

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	U.S.			Canada			International			Total
	(In millions)
Six Months Ended June 30, 2008:
Revenues:
Oil sales	$	1,009		$	838		$	858		$	2,705
Gas sales		2,924			906			10			3,840
NGL sales		571			136			—			707
Net loss on oil and gas derivative financial instruments		(2,003	)		—			—			(2,003	)
Marketing and midstream revenues		1,249			25			—			1,274

Total revenues		3,750			1,905			868			6,523

Expenses and other income, net:
Lease operating expenses		545			405			93			1,043
Production taxes		183			2			125			310
Marketing and midstream operating costs and expenses		887			10			—			897
Depreciation, depletion and amortization of oil and gas properties		941			438			120			1,499
Depreciation and amortization of non-oil and gas properties		105			13			1			119
Accretion of asset retirement obligation		21			20			3			44
General and administrative expenses		259			68			1			328
Interest expense		88			104			—			192
Change in fair value of non-oil and gas derivative financial instruments		(24	)		—			—			(24	)
Other income, net		(17	)		(5	)		(16	)		(38	)

Total expenses and other income, net		2,988			1,055			327			4,370

Earnings from continuing operations before income tax expense		762			850			541			2,153
Income tax expense:
Current		345			64			108			517
Deferred		213			152			26			391

Total income tax expense		558			216			134			908

Earnings from continuing operations		204			634			407			1,245
Discontinued operations:
Earnings from discontinued operations before income tax expense		—			—			1,040			1,040
Income tax expense		—			—			235			235

Earnings from discontinued operations		—			—			805			805

Net earnings		204			634			1,212			2,050
Preferred stock dividends		5			—			—			5

Net earnings applicable to common stockholders	$	199		$	634		$	1,212		$	2,045


Capital expenditures, before revision of future ARO	$	2,965		$	698		$	301		$	3,964
Revision of future ARO		70			73			19			162

Capital expenditures, continuing operations	$	3,035		$	771		$	320		$	4,126

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	U.S.			Canada			International			Total
	(In millions)
Six Months Ended June 30, 2007:
Revenues:
Oil sales	$	539		$	338		$	679		$	1,556
Gas sales		1,872			736			4			2,612
NGL sales		313			88			—			401
Net loss on oil and gas derivative financial instruments		(6	)		—			—			(6	)
Marketing and midstream revenues		823			16			—			839

Total revenues		3,541			1,178			683			5,402

Expenses and other income, net:
Lease operating expenses		504			283			82			869
Production taxes		115			2			53			170
Marketing and midstream operating costs and expenses		604			7			—			611
Depreciation, depletion and amortization of oil and gas properties		773			342			117			1,232
Depreciation and amortization of non-oil and gas properties		85			10			—			95
Accretion of asset retirement obligation		19			15			2			36
General and administrative expenses		183			52			(3	)		232
Interest expense		116			101			—			217
Change in fair value of non-oil and gas derivative financial instruments		(8	)		(1	)		—			(9	)
Other income, net		(18	)		(5	)		(20	)		(43	)

Total expenses and other income, net		2,373			806			231			3,410

Earnings from continuing operations before income tax expense		1,168			372			452			1,992
Income tax expense (benefit):
Current		122			105			136			363
Deferred		252			(5	)		(16	)		231

Total income tax expense		374			100			120			594

Earnings from continuing operations		794			272			332			1,398
Discontinued operations:
Earnings from discontinued operations before income tax expense		—			—			265			265
Income tax expense		—			—			108			108

Earnings from discontinued operations		—			—			157			157

Net earnings		794			272			489			1,555
Preferred stock dividends		5			—			—			5

Net earnings applicable to common stockholders	$	789		$	272		$	489		$	1,550


Capital expenditures, before revision of future ARO	$	2,022		$	661		$	215		$	2,898
Revision of future ARO		210			99			2			311

Capital expenditures, continuing operations	$	2,232		$	760		$	217		$	3,209

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

The following discussion addresses material changes in our results of operations and capital resources and uses for the three-month and six-month periods ended June 30, 2008, compared to the three-month and six-month periods ended June 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.

Overview

During the second quarter and first six months of 2008, we generated net earnings of $1.3 billion and $2.1 billion, respectively, or $2.88 and $4.55 per diluted share, representing increases of 44% and 32% over the same periods of 2007. Additionally, net cash provided by operating activities for the first half of 2008 climbed to a record amount of $5.2 billion, representing a 55% increase over 2007. These increases in earnings and cash flow are largely attributable to the following factors:

	•		Production increased 4% and 7% in the second quarter and first six months of 2008, respectively.

	•		The combined realized price without hedges for oil, gas and NGLs increased 58% and 48% in the second quarter and first six months of 2008, respectively.

	•		Oil and gas hedges generated net losses of $1.2 billion and $2.0 billion in the second quarter and first six months of 2008, respectively. Included in these amounts are cash payments of $303 million and $311 million, respectively.

	•		Marketing and midstream operating profit increased 71% and 65% in the second quarter and first six months of 2008, respectively.

	•		Per unit operating costs rose 18% and 12% in the second quarter and first six months of 2008, respectively.

	•		General and administrative expenses increased 59% and 41% in the second quarter and first six months of 2008, respectively.

	•		The effective income tax rates for the second quarter and first six months of 2008 were 53% and 42%, respectively.

	•		Cash spent on capital expenditures for oil and gas exploration and development activities were $3.6 billion during the first half of 2008.

Additionally, we made significant progress toward completion of our African divestiture program during 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. As a result of the sales, we recognized after-tax gains totaling $647 million in the second quarter of 2008 from proceeds of $2.4 billion ($1.7 billion net of income taxes and purchase price adjustments). Also, in conjunction with these asset sales, we repatriated an additional $1.3 billion of earnings from certain foreign subsidiaries to the United States in the second quarter of 2008. We also expect to repatriate $1.5 billion from certain foreign subsidiaries to the United States in the second half 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 the first six months of 2008. We also repurchased 2.8 million common shares for $302 million during the first six months of 2008.

Results of Operations

Revenues

Oil, Gas and NGL Sales

The three-month and six-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 June 30,							Six Months Ended June 30,
	2008		2007		Change⁽²⁾			2008		2007		Change⁽²⁾
Production
Oil (MMBbls)		13		15		-9	%		27		28		-1	%
Gas (Bcf)		230		212		+8	%		453		414		+9	%
NGLs (MMBbls)		7		6		+9	%		14		12		+12	%
Oil, Gas and NGLs (MMBoe)⁽¹⁾		59		56		+4	%		117		109		+7	%

Realized prices without hedges
Oil (Per Bbl)	$	110.56	$	60.01		+84	%	$	98.98	$	56.22		+76	%
Gas (Per Mcf)	$	9.61	$	6.43		+49	%	$	8.48	$	6.31		+34	%
NGLs (Per Bbl)	$	54.08	$	35.03		+54	%	$	50.76	$	32.26		+57	%
Oil, Gas and NGLs (Per Boe)⁽¹⁾	$	69.14	$	43.68		+58	%	$	62.12	$	41.87		+48	%

Revenues($ in millions)
Oil sales	$	1,455	$	865		+68	%	$	2,705	$	1,556		+74	%
Gas sales		2,210		1,366		+62	%		3,840		2,612		+47	%
NGL sales		379		224		+69	%		707		401		+76	%

Oil, Gas and NGL sales	$	4,044	$	2,455		+65	%	$	7,252	$	4,569		+59	%


	Domestic
	Three Months Ended June 30,							Six Months Ended June 30,
	2008		2007		Change⁽²⁾			2008		2007		Change⁽²⁾
Production
Oil (MMBbls)		5		5		-5	%		9		9		-1	%
Gas (Bcf)		176		155		+14	%		347		301		+15	%
NGLs (MMBbls)		6		5		+13	%		12		10		+17	%
Oil, Gas and NGLs (MMBoe)⁽¹⁾		40		36		+11	%		79		70		+13	%

Realized prices without hedges
Oil (Per Bbl)	$	122.47	$	62.68		+95	%	$	109.08	$	57.67		+89	%
Gas (Per Mcf)	$	9.56	$	6.35		+51	%	$	8.42	$	6.22		+35	%
NGLs (Per Bbl)	$	50.66	$	33.26		+52	%	$	47.78	$	30.54		+56	%
Oil, Gas and NGLs (Per Boe)⁽¹⁾	$	63.88	$	40.71		+57	%	$	56.95	$	39.05		+46	%

Revenues($ in millions)
Oil sales	$	566	$	305		+86	%	$	1,009	$	539		+87	%
Gas sales		1,688		983		+72	%		2,924		1,872		+56	%
NGL sales		305		177		+72	%		571		313		+83	%

Oil, Gas and NGL sales	$	2,559	$	1,465		+75	%	$	4,504	$	2,724		+65	%


	Canada
	Three Months Ended June 30,							Six Months Ended June 30,
	2008		2007		Change⁽²⁾			2008		2007		Change⁽²⁾
Production
Oil (MMBbls)		5		4		+32	%		10		8		+32	%
Gas (Bcf)		53		56		-7	%		105		112		-7	%
NGLs (MMBbls)		1		1		-8	%		2		2		-10	%
Oil, Gas and NGLs (MMBoe)⁽¹⁾		16		14		+4	%		30		28		+3	%

Realized prices without hedges
Oil (Per Bbl)	$	94.35	$	46.32		+104	%	$	84.16	$	45.01		+87	%
Gas (Per Mcf)	$	9.76	$	6.66		+47	%	$	8.66	$	6.55		+32	%
NGLs (Per Bbl)	$	75.10	$	43.82		+71	%	$	68.86	$	40.37		+71	%
Oil, Gas and NGLs (Per Boe)⁽¹⁾	$	72.14	$	41.99		+72	%	$	64.01	$	40.88		+57	%

Revenues($ in millions)
Oil sales	$	498	$	185		+168	%	$	838	$	338		+148	%
Gas sales		517		380		+36	%		906		736		+23	%
NGL sales		74		47		+57	%		136		88		+54	%

Oil, Gas and NGL sales	$	1,089	$	612		+78	%	$	1,880	$	1,162		+62	%


	International
	Three Months Ended June 30,							Six Months Ended June 30,
	2008		2007		Change⁽²⁾			2008		2007		Change⁽²⁾
Production
Oil (MMBbls)		3		6		-41	%		8		11		-25	%
Gas (Bcf)		1		1		-14	%		1		1		+27	%
NGLs (MMBbls)		—		—		N/M			—		—		N/M
Oil, Gas and NGLs (MMBoe)⁽¹⁾		3		6		-41	%		8		11		-24	%

Realized prices without hedges
Oil (Per Bbl)	$	119.87	$	67.57		+77	%	$	105.63	$	62.76		+68	%
Gas (Per Mcf)	$	11.00	$	6.19		+78	%	$	9.56	$	5.16		+85	%
NGLs (Per Bbl)	$	—	$	—		N/M		$	—	$	—		N/M
Oil, Gas and NGLs (Per Boe)⁽¹⁾	$	118.70	$	67.11		+77	%	$	104.68	$	62.39		+68	%

Revenues($ in millions)
Oil sales	$	391	$	375		+4	%	$	858	$	679		+26	%
Gas sales		5		3		+52	%		10		4		+134	%
NGL sales		—		—		N/M			—		—		N/M

Oil, Gas and NGL sales	$	396	$	378		+5	%	$	868	$	683		+27	%


⁽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 June 30, 2008 and 2007.


	Oil			Gas		NGLs		Total
	(In millions)
2007 sales	$	865		$	1,366	$	224	$	2,455
Changes due to volumes		(75	)		113		21		59
Changes due to prices.		665			731		134		1,530

2008 sales	$	1,455		$	2,210	$	379	$	4,044

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


	Oil			Gas			NGLs		Total
	(In millions)
2007 sales	$	1,556		$	2,612		$	401	$	4,569
Changes due to volumes		(20	)		245			48		273
Changes due to prices.		1,169			983	��		258		2,410

2008 sales	$	2,705		$	3,840		$	707	$	7,252

Oil Sales

Oil sales decreased $75 million in the second quarter of 2008 due to a two million barrel, or 9%, decrease in production. International production decreased approximately three million barrels due to reaching certain cost recovery thresholds of our carried interest in Azerbaijan. This was partially offset by an additional one million barrels of production due to increased development activity at our Jackfish and Lloydminster areas in Canada.

Oil sales increased $665 million in the second quarter of 2008 as a result of an 84% increase in our realized price without hedges. The average NYMEX West Texas Intermediate index price increased 91% during the same time period, accounting for the majority of the increase.

Oil sales increased $1.2 billion in the first half of 2008 as a result of a 76% increase in our realized price without hedges. The average NYMEX West Texas Intermediate index price increased 80% during the same time period, accounting for the majority of the increase.

Gas Sales

An 18 Bcf, or 8%, increase in production during the second quarter of 2008 caused gas sales to increase by $113 million. Our drilling and development program in the Barnett Shale field in north Texas contributed 22 Bcf to the gas production increase. This 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 $731 million during the second quarter of 2008 as a result of a 49% increase in our realized price without hedges. This increase is largely due to increases in the regional index prices upon which our gas sales are based.

A 39 Bcf, or 9%, increase in production during the first half of 2008 caused gas sales to increase by $245 million. Our drilling and development program in the Barnett Shale field in north Texas contributed 42 Bcf to the gas production increase. This 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 $983 million during the first half of 2008 as a result of a 34% increase in our realized price without hedges. This increase is largely due to increases in the regional index prices upon which our gas sales are based.

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

The following tables provide financial information associated with our oil and gas hedges for the second quarter and first half of 2008 and 2007. The first table presents the cash settlements and unrealized losses and gains 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 second quarter and first half of 2008 and 2007. The prices do not include the effects of unrealized losses and gains.


	Three Months Ended June 30,					Six Months Ended June 30,
	2008			2007		2008			2007
	(In millions)
Cash settlements:
Gas price swaps	$	(153	)	$	5	$	(161	)	$	15
Gas price collars		(150	)		—		(150	)		2
Oil price collars		—			—		—			—

Total cash settlements (paid) received		(303	)		5		(311	)		17

Unrealized (losses) gains on fair value changes:
Gas price swaps		(247	)		9		(618	)		(19	)
Gas price collars		(620	)		—		(1,028	)		(4	)
Oil price collars		(45	)		—		(46	)		—

Total unrealized (losses) gains on fair value changes		(912	)		9		(1,692	)		(23	)

Net (loss) gain on oil and gas derivative financial Instruments	$	(1,215	)	$	14	$	(2,003	)	$	(6	)


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

Realized price, including cash settlements	$	110.55		$	8.29		$	54.08	$	63.96


	Three Months Ended June 30, 2007
	Oil		Gas		NGLs		Total
	(Per Bbl)		(Per Mcf)		(Per Bbl)		(Per Boe)
Realized price without hedges	$	60.01	$	6.43	$	35.03	$	43.68
Cash settlements of hedges		—		0.03		—		0.10

Realized price, including cash settlements	$	60.01	$	6.46	$	35.03	$	43.78


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

Realized price, including cash settlements	$	98.98	$	7.79		$	50.76	$	59.45


	Six Months Ended June 30, 2007
	Oil		Gas		NGLs		Total
	(Per Bbl)		(Per Mcf)		(Per Bbl)		(Per Boe)
Realized price without hedges	$	56.22	$	6.31	$	32.26	$	41.87
Cash settlements of hedges		—		0.04		—		0.16

Realized price, including cash settlements	$	56.22	$	6.35	$	32.26	$	42.03

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 second quarter and first half of 2008, we paid $303 million, or $1.32 per Mcf, and $311 million, or $0.69 per Mcf, respectively, to counterparties to settle our gas price swaps and collars. During the second quarter and first half of 2007, we received $5 million, or $0.03 per Mcf, and $17 million, or $0.04 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 June 30, 2008, a 10% increase in these forward curves would have increased our second quarter 2008 unrealized loss for our oil and gas derivative financial instruments by approximately $550 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.

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

During the second quarter and first half of 2007, we recognized an unrealized gain totaling $9 million and an unrealized loss totaling $23 million, 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 June 30, 2008 and 2007 and the six months ended June 30, 2008 and 2007 are shown in the table below.


	Three Months Ended June 30,							Six Months Ended June 30,
	2008		2007		Change⁽¹⁾			2008		2007		Change⁽¹⁾
Marketing and midstream ($ in millions):
Revenues	$	719	$	460		+56	%	$	1,274	$	839		+52	%
Operating costs and expenses		515		341		+51	%		897		611		+47	%

Operating profit	$	204	$	119		+71	%	$	377	$	228		+65	%


⁽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.

Marketing and midstream revenues increased $259 million and operating costs and expenses also increased $174 million, causing operating profit to increase $85 million during the second quarter of 2008. Revenues and expenses increased primarily due to higher natural gas and NGL prices, as well as higher gas pipeline throughput in the Barnett Shale.

Marketing and midstream revenues increased $435 million and operating costs and expenses also increased $286 million, causing operating profit to increase $149 million during the first six months of 2008. Revenues and expenses increased primarily due to higher natural gas and NGL prices, as well as higher gas pipeline throughput in the Barnett Shale.

Oil, Gas and NGL Production and Operating Expenses

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


	Three Months Ended June 30,							Six Months Ended June 30,
	2008		2007		Change⁽¹⁾			2008		2007		Change⁽¹⁾
Production and operating expenses ($ in millions):
Lease operating expenses	$	537	$	439		+22	%	$	1,043	$	869		+20	%
Production taxes		176		90		+95	%		310		170		+82	%

Total production and operating expenses	$	713	$	529		+35	%	$	1,353	$	1,039		+30	%


Production and operating expenses per Boe:
Lease operating expenses	$	9.18	$	7.81		+18	%	$	8.93	$	7.96		+12	%
Production taxes		3.01		1.61		+88	%		2.66		1.57		+70	%

Total production and operating expenses per Boe	$	12.19	$	9.42		+30	%	$	11.59	$	9.53		+22	%


⁽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 $98 million in the second 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 $17 million due to our 4% growth in production. Additionally, the effects of changes in the exchange rate between the U.S. and Canadian dollar caused LOE to increase $17 million. The exchange rate effect also contributed to the increase in LOE per Boe.

LOE increased $174 million in the first half 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 $61 million due to our 7% growth in production. Furthermore, 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 June 30, 2008 and 2007 and the six months ended June 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		Six Months
	Ended June 30,		Ended June 30,
	(In millions)
2007 production taxes	$	90	$	170
Change due to revenues		58		100
Change due to rate		28		40

2008 production taxes	$	176	$	310

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

The changes in our production volumes, DD&A rate per unit and DD&A of oil and gas properties between the three and six months ended June 30, 2008 and 2007 are shown in the table below.


	Three Months Ended June 30,							Six Months Ended June 30,
	2008		2007		Change⁽¹⁾			2008		2007		Change⁽¹⁾
Production volumes (MMBoe)		59		56		+4	%		117		109		+7	%
DD&A rate ($ per Boe)	$	13.03	$	11.48		+14	%	$	12.84	$	11.29		+14	%

DD&A expense ($ in millions)	$	762	$	645		+18	%	$	1,499	$	1,232		+22	%


⁽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 six months ended June 30, 2008 and 2007.


	Three Months		Six Months
	Ended June 30,		Ended June 30,
	(In millions)
2007 DD&A	$	645	$	1,232
Change due to volumes		26		86
Change due to rate		91		181

2008 DD&A	$	762	$	1,499

The 4% production increase during the second quarter of 2008 caused oil and gas property related DD&A to increase $26 million. In addition, oil and gas property related DD&A increased $91 million due to a 14% 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 include 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.

The 7% production increase during the first half of 2008 caused oil and gas property related DD&A to increase $86 million. In addition, oil and gas property related DD&A increased $181 million due to a 14% 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 include 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 six-month periods ended June 30, 2008 and 2007.


	Three Months Ended June 30,									Six Months Ended June 30,
	2008			2007			Change⁽¹⁾			2008			2007			Change⁽¹⁾
	(In millions)									(In millions)
Gross G&A	$	307		$	222			+38	%	$	584		$	434			+35	%
Capitalized G&A		(100	)		(82	)		+22	%		(199	)		(146	)		+37	%
Reimbursed G&A		(27	)		(27	)		+1	%		(57	)		(56	)		+3	%

Net G&A	$	180		$	113			+59	%	$	328		$	232			+41	%


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

Gross G&A increased $85 million in the second 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. Additionally, gross G&A increased $27 million due to 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 $18 million increase in capitalized G&A during the second quarter of 2008 is primarily due to the higher employee compensation and benefits costs.

Gross G&A increased $150 million in the first half 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 discussed above.

The $53 million increase in capitalized G&A during the first half of 2008 is 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 six-month periods ended June 30, 2008 and 2007.


	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2008			2007			2008			2007
	(In millions)
Interest based on debt outstanding	$	110		$	125		$	236		$	253
Capitalized interest		(25	)		(24	)		(56	)		(47	)
Other		5			6			12			11

Total	$	90		$	107		$	192		$	217

Interest based on debt outstanding decreased during the second quarter of 2008 and the first half of 2008 primarily due to a decrease in outstanding borrowings. The decrease in borrowings resulted largely from the use of proceeds from asset sales and cash flow from operations to repay all commercial paper and credit facility borrowings in the second quarter of 2008.

Change in Fair Value of Non-Oil and Gas 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 six months ended June 30, 2008 and 2007.


	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	(In millions)
Losses (gains) from:
Chevron common stock	$	(195	)	$	(146	)	$	(82	)	$	(152	)
Option embedded in exchangeable debentures		155			136			58			144
Other		—			—			—			(1	)

Total	$	(40	)	$	(10	)	$	(24	)	$	(9	)

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 is not actively traded in an established market. Therefore, we estimate its fair value

using quotes obtained from a broker for trades occurring near the valuation date. Because the exchangeable debentures are due in August 2008, the embedded option’s recent fair value changes largely coincide 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.

The gain on our investment in Chevron common stock and loss on the embedded option during the second quarter of 2008 were directly attributable to a $13.77 increase in the price per share of Chevron’s common stock during the second quarter of 2008. The gain on our investment in Chevron common stock and loss on the embedded option during the second quarter of 2007 were directly attributable to a $10.28 increase in the price per share of Chevron’s common stock during the second quarter of 2007.

The gain on our investment in Chevron common stock and loss on the embedded option during the first half of 2008 were directly attributable to a $5.80 increase in the price per share of Chevron’s common stock during the first half of 2008. The gain on our investment in Chevron common stock and loss on the embedded option during the first half of 2007 were directly attributable to a $10.71 increase in the price per share of Chevron’s common stock during the first half of 2007.

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 six-month periods ended June 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						Six Months
	Ended June 30,						Ended June 30,
	2008			2007			2008			2007
Total income tax expense (In millions)	$	667		$	330		$	908		$	594

U.S. statutory income tax rate		35	%		35	%		35	%		35	%
Repatriations and tax policy election changes		25	%		—			14	%		—
Canadian statutory rate reductions		—			(2	%)		—			(1	%)
Other, primarily taxation on foreign operations		(7	%)		(4	%)		(7	%)		(4	%)

Effective income tax rate		53	%		29	%		42	%		30	%

In the both the second quarter and six months ended June 30, 2008, our effective income tax rate was higher than the U.S. statutory income tax rate largely due to two related factors. First, in the second quarter of 2008, we repatriated $1.3 billion in earnings from certain foreign subsidiaries to the United States. We also expect 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 rates would have been 28% for both the second quarter of 2008 and the first half of 2008. These rates, as well as the rates for the second quarter of 2007 and the first half of 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. The 2007 rates were also 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.

Additionally, we expect our effective income tax rate for the remainder of 2008 will approximate the 28% rate applicable to the first half of 2008, excluding the $312 million of additional tax expense.

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 six months ended June 30, 2008 and 2007.


	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
	(In millions)
Earnings from discontinued operations before income taxes	$	851	$	128	$	1,040	$	265
Income tax expense		144		48		235		108

Earnings from discontinued operations	$	707	$	80	$	805	$	157

Earnings from discontinued operations increased $627 million in the second quarter of 2008 and increased $648 million in the first half of 2008. The largest contributor to these increases was the recognition of after-tax gains totaling $647 million upon the sale of our assets in Equatorial Guinea, Gabon and other countries in the second quarter of 2008.

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


	Six Months Ended June 30,
	2008			2007
	(In millions)
Sources of cash and cash equivalents:
Operating cash flow — continuing operations	$	5,066		$	3,152
Sales of property and equipment		108			37
Stock option exercises		104			60
Net sales of short-term investments		245			259
Cash received from discontinued operations		1,746			—
Other		55			17

Total sources of cash and cash equivalents		7,324			3,525


Uses of cash and cash equivalents:
Capital expenditures		(3,867	)		(2,990	)
Net commercial paper repayments		(1,004	)		(183	)
Net repayments of debt		(1,497	)		—
Repurchases of common stock		(252	)		(10	)
Redemption of preferred stock		(150	)		—
Dividends		(146	)		(129	)

Total uses of cash and cash equivalents		(6,916	)		(3,312	)


Increase from continuing operations		408			213
Increase from discontinued operations, net		83			82
of distributions to continuing operations Effect of foreign exchange rates		(19	)		16

Net increase in cash and cash equivalents	$	472		$	311


Cash and cash equivalents at end of period	$	1,845		$	1,067

Short-term investments at end of period	$	1		$	315

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 half 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 half of 2008, our operating cash flow was sufficient to fund our capital expenditures. Additionally, during 2007, operating cash flow was sufficient to fund all of our capital expenditures.

Other Sources of Cash

As needed, we utilize cash on hand and access our available credit under our credit facilities and commercial paper program as sources of cash to supplement our operating cash flow. 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 $245 million. During 2007, we reduced our short-term investment balances by $259 million to supplement our operating cash flow and fund debt repayments.

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

During 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 and dividends on common and preferred stock.

Capital Expenditures

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


	Six Months
	Ended June 30,
	2008		2007
	(In millions)
U.S. Onshore	$	2,082	$	1,526
U.S. Offshore		538		300
Canada		707		682
International		274		269

Total exploration and development		3,601		2,777
Midstream		205		171
Other		61		42

Total capital expenditures	$	3,867	$	2,990

Our capital expenditures consist of amounts related to our oil and gas exploration and development operations, our midstream operations and other corporate activities. The vast majority of our capital expenditures are for the acquisition, drilling or development of oil and gas properties, which totaled $3.6 billion and $2.8 billion in the first six 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 $824 million in the first six months of 2008. The higher expenditures primarily relate to increased drilling activities in the Barnett Shale, Gulf of Mexico and Carthage areas of the United States. Expenditures also increased due to inflationary pressure driven by increased competition for field services.

Net Repayments of Debt

During the first half of 2008, we repaid $2.5 billion in outstanding credit facility and commercial paper borrowings primarily with proceeds received from the sales of assets under our African divestiture program and cash generated from operations. This compares to $183 million of commercial paper borrowings we repaid during the first half of 2007.

Also during the first half of 2008, certain holders of exchangeable debentures exercised their option to exchange their debentures for shares of Chevron common stock that we own prior to the debentures’ August 15, 2008 maturity date. We have the option, in lieu of delivering shares of Chevron common stock, to pay exchanging debenture holders an amount of cash equal to the market value of Chevron common stock. We paid $47 million in cash to debenture holders who exercised their exchange rights in the first half of 2008. This amount included the retirement of debentures with a book value of $28 million and a $19 million reduction of the related embedded derivative option’s balance.

Repurchases of Common Stock

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

Redemption of Preferred Stock

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

Dividends

Our common stock dividends were $141 million (or a quarterly rate of $0.16 per share) and $124 million (or a quarterly rate of $0.14 per share) in the first half of 2008 and 2007, respectively. The higher dividend rate was the primary cause of the increase in common dividends. We also paid $5 million of preferred stock dividends in the first six months of 2008 and 2007.

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. Other available sources of capital and liquidity include cash on hand and the issuance of equity securities and long-term debt. Another major source of near-term liquidity is proceeds from the sales of our operations in West Africa, including related repatriations of earnings from certain foreign subsidiaries to the United States. In the second quarter of 2008, we repatriated $1.3 billion in earnings. We expect to repatriate approximately $1.5 billion during the last six months of 2008.

Operating Cash Flow

Our operating cash flow increased 55% to a record high of $5.2 billion in the first half 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. 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 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 Rate Swaps

As of June 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. The key terms of these interest rate swaps are presented in the table below.


					Variable
Notional		Fixed Rate 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	%

Including the effects of these swaps, the weighted-average interest rate related to our fixed-rate debt was 7.2% as of July 31, 2008.

Credit Availability

In April 2008, we extended the maturity of $2.0 billion of our 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.

On August 7, 2007, we established a $1.5 billion 364-day, syndicated, unsecured revolving senior credit facility (the “Short-Term Facility”). This facility matured on August 5, 2008 and was not extended. As a result of the Short-Term Facility’s maturity, our commercial paper program capacity decreased from $3.5 billion to $2.0 billion.

The Senior Credit Facility contains only one material financial covenant. This covenant requires our ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no more than 65%. As of June 30, 2008, we were in compliance with this covenant. Our debt-to-capitalization ratio at June 30, 2008, as calculated pursuant to the terms of the agreement, was 16.3%.

As of August 5, 2008, our available capacity under our Senior Credit Facility was approximately $2.4 billion. This available capacity is net of $140 million of outstanding letters of credit. There were no outstanding commercial paper or Senior Credit Facility borrowings as of August 5, 2008.

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 July 31, 2008.

Property Divestitures

In the second quarter of 2008, we made significant progress toward completion of our African divestiture program. We completed the sales of assets in certain West African countries, including Equatorial Guinea—the largest individual transaction in the divestiture program. As a result of the sales, we received proceeds of $2.4 billion ($1.7 billion net of income taxes and purchase price adjustments).

We have also entered into agreements to sell our operations in Cote D’Ivoire and other countries located in West Africa for approximately $250 million. Devon is obtaining the necessary partner and government approvals for these properties and expects to complete the remaining sales during the third quarter of 2008.

Capital Expenditures

In February 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 $5.6 billion to $5.9 billion.

With higher than expected realized oil and gas prices through the first half of 2008 and the proceeds received from sales of assets in West Africa in the second quarter of 2008, we now have robust cash flow and liquidity that can be leveraged to optimize Devon’s value per share. In addition to repaying our commercial paper and credit facility borrowings and restarting our substantial share repurchase program, we are also increasing our planned 2008 investment in capital projects. Therefore, we have increased our estimate of 2008 capital expenditures for oil and gas exploration and development operations, which are now expected to range from $7.2 billion to $7.5 billion. A significant portion of this incremental capital is directed to additional acreage capture in North America and increased investment in the Lower Tertiary trend.

Common Stock Repurchase Programs

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 June 30, 2008, up to 4.0 million shares or $358 million can be repurchased under the ongoing, annual repurchase program and up to 48.0 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 half of 2008, we reduced our auction rate securities holdings to $127 million as of June 30, 2008. However, since February 8, 2008 we have experienced difficulty selling our securities due to the failure of the auction mechanism, which provides 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 June 30, 2008, issuers redeemed $26 million of our auction rate securities holdings at par. Additionally, our auction rate securities holdings as of June 30, 2008 include approximately $1 million of securities that were called at par value by the issuer and were repaid on July 10, 2008. These called securities continue to be considered short-term investments as of June 30, 2008. However, based on continued auction failures and the current market for our auction rate securities, we have classified the $126 million of securities that have not been called as long-term investments as of June 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 June 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 June 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 and the collection of all accrued interest to date. 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 June 30, 2008. At this time, we do not believe the values of our 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. 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.

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 June 30, 2008, a 10% increase in these forward curves would have increased the net liabilities recorded for our 2008 and 2009 commodity hedging instruments by approximately $550 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 June 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 second quarter of 2008 that has materially affected, or is reasonably likely to materially affect, Devon’s internal control over financial reporting.

Part II. Other Information

Item 1.Legal Proceedings

There have been no material changes to the information included in Item 3. “Legal Proceedings” in our 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 Number of		Maximum Number of
					Shares Purchased as		Shares that May Yet
	Total		Average Price		Part of Publicly		Be Purchased Under
	Number of Shares		Paid		Announced Plans or		the Plans or
Period	Purchased		per Share		Programs⁽¹⁾		Programs⁽¹⁾
April		—	$	—		—		53,991,900
May		—	$	—		—		53,991,900
June		2,036,715	$	116.57		2,036,715		51,955,185

Total		2,036,715	$	116.57		2,036,715


(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. All shares repurchased during the second quarter of 2008 were repurchased under the 50 million share repurchase program. As of June 30, 2008, up to 4.0 million shares or $358 million can be repurchased under the ongoing, annual repurchase program and up to 48.0 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

(a) Devon’s Annual Meeting of Stockholders was held in Oklahoma City, Oklahoma at 8:00 a.m., local time, on Wednesday, June 4, 2008.

(b) Proxies for the meeting were solicited pursuant to Regulation 14 under the Securities Exchange Act of 1934, as amended. There was no solicitation in opposition to the nominees for election as Directors as listed in the Proxy Statement for the June 4, 2008 meeting and all nominees were elected.

(c) A total of 401,657,101 shares of Devon’s common stock outstanding and entitled to vote were present at the June 4, 2008 meeting in person or by proxy, representing approximately 90.11% of the total outstanding shares. The matters voted upon were as follows:

1. The election of three Directors to serve on Devon’s Board of Directors until the 2011 Annual Meeting of Stockholders. A total of at least 98.65% of all voted shares were cast for approval of each nominee. The vote tabulation with respect to each nominee was as follows:


			Authority
Nominee	For		Withheld
David A. Hager		396,269,943		5,387,158
John A. Hill		396,241,980		5,415,121
Mary P. Ricciardello		396,253,911		5,403,190

2. Ratification of KPMG LLP as the Company’s Independent Auditors for 2008. A total of 97.99% of all voted shares were cast for ratification of KPMG LLP. The results of the votes were as follows:


FOR:			393,574,431
AGAINST:			4,480,321
ABSTAIN:			3,602,349

3. The adoption of an amendment to the Restated Certificate of Incorporation to increase the number of authorized shares of common stock. A total of 97.07% of all voted shares were cast to increase the number of authorized shares of common stock.


FOR:			389,884,929
AGAINST:			8,003,108
ABSTAIN:			3,769,064

4. The adoption of an amendment to the Restated Certificate of Incorporation to provide for the annual election of directors. A total of 98.06% of all voted shares were cast to provide for the annual election of directors.


FOR:			393,850,136
AGAINST:			4,165,847
ABSTAIN:			3,641,118

Item 5.Other Information

None.

Item 6.Exhibits

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


Exhibit
Number		Description
3.1		Registrant’s Certificate of Amendment of Restated Certificate of Incorporation.

10.1		Form of Amendment to Nonqualified Stock Option Award Agreements under the Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and Stephen J. Hadden, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Daryl G. Smette and Lyndon C. Taylor. *

10.2		Form of Amendment to Restricted Stock Award Agreements under the Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and Stephen J. Hadden, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette and Lyndon C. Taylor. *

10.3		Form of Non-Management Director Nonqualified Stock Option Award Agreement under the Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and all Non-Management Directors.*

10.4		Form of Non-Management Director Restricted Stock Award Agreement under the Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and all Non-Management Directors.*

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, 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, 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.


*		Compensatory plans or arrangements

SIGNATURES

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


		DEVON ENERGY CORPORATION

Date: August 7, 2008		/s/ Danny J. Heatly

		Danny J. Heatly
		Vice President – Accounting and Chief Accounting Officer

INDEX TO EXHIBITS


Exhibit
Number		Description
3.1		Registrant’s Certificate of Amendment of Restated Certificate of Incorporation.

10.1		Form of Amendment to Nonqualified Stock Option Award Agreements under the Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and Stephen J. Hadden, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Daryl G. Smette and Lyndon C. Taylor. *

10.2		Form of Amendment to Restricted Stock Award Agreements under the Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and Stephen J. Hadden, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette and Lyndon C. Taylor. *

10.3		Form of Non-Management Director Nonqualified Stock Option Award Agreement under the Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and all Non-Management Directors.*

10.4		Form of Non-Management Director Restricted Stock Award Agreement under the Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and all Non-Management Directors.*

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, 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, 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.


*		Compensatory plans or arrangements

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Avg

Devon Energy (DVN) 10-Q2008 Q2 Quarterly report

Content analysis