Item 8. Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

Report of Independent Registered Public Accounting Firm			50
Consolidated Financial Statements
Consolidated Comprehensive Statements of Earnings			51
Consolidated Statements of Cash Flows			52
Consolidated Balance Sheets			53
Consolidated Statements of Stockholders’ Equity			54
Notes to Consolidated Financial Statements			55

All financial statement schedules are omitted as they are inapplicable or the required information has been included in the consolidated financial statements or notes thereto.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Devon Energy Corporation:

We have audited the accompanying consolidated balance sheets of Devon Energy Corporation and subsidiaries as of December 31, 2013 and 2012, and the related consolidated comprehensive statements of earnings, cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2013. We also have audited Devon Energy Corporation’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Devon Energy Corporation’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Annual Report contained in “Item 9A. Controls and Procedures” of Devon Energy Corporation’s Annual Report on Form 10-K. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Devon Energy Corporation and subsidiaries as of December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with United States generally accepted accounting principles. Also in our opinion, Devon Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ KPMG LLP

Oklahoma City, Oklahoma

February 28, 2014

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS

		Year Ended December 31,
		2013				2012				2011
		(In millions, except per share amounts)
Oil, gas and NGL sales		$	8,522			$	7,153			$	8,315
Oil, gas and NGL derivatives			(191	)			693				881
Marketing and midstream revenues			2,066				1,655				2,249
Total operating revenues			10,397				9,501				11,445
Lease operating expenses			2,268				2,074				1,851
Marketing and midstream operating expenses			1,553				1,246				1,716
General and administrative expenses			617				692				585
Production and property taxes			461				414				424
Depreciation, depletion and amortization			2,780				2,811				2,248
Asset impairments			1,976				2,024				—
Other operating items			121				92				(11	)
Total operating expenses			9,776				9,353				6,813
Operating income			621				148				4,632
Net financing costs			417				370				331
Restructuring costs			54				74				(2	)
Other nonoperating items			1				21				13
Earnings (loss) from continuing operations before income taxes			149				(317	)			4,290
Income tax expense (benefit)			169				(132	)			2,156
Earnings (loss) from continuing operations			(20	)			(185	)			2,134
Earnings (loss) from discontinued operations, net of tax			—				(21	)			2,570
Net earnings (loss)		$	(20	)		$	(206	)		$	4,704
Basic earnings (loss) from continuing operations per share		$	(0.06	)		$	(0.47	)		$	5.12
Basic earnings (loss) from discontinued operations per share			—				(0.05	)			6.17
Basic net earnings (loss) per share		$	(0.06	)		$	(0.52	)		$	11.29
Diluted earnings (loss) from continuing operations per share		$	(0.06	)		$	(0.47	)		$	5.10
Diluted earnings (loss) from discontinued operations per share			—				(0.05	)			6.15
Diluted net earnings (loss) per share		$	(0.06	)		$	(0.52	)		$	11.25
Comprehensive earnings (loss):
Net earnings (loss)		$	(20	)		$	(206	)		$	4,704
Other comprehensive earnings (loss), net of tax:
Foreign currency translation			(548	)			194				(191	)
Pension and postretirement plans			45				2				6
Other comprehensive earnings (loss), net of tax			(503	)			196				(185	)
Comprehensive earnings (loss)		$	(523	)		$	(10	)		$	4,519

See accompanying notes to consolidated financial statements.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

		Year Ended December 31,
		2013				2012				2011
		(In millions)
Cash flows from operating activities:
Net earnings (loss)		$	(20	)		$	(206	)		$	4,704
Loss (earnings) from discontinued operations, net of tax			—				21				(2,570	)
Adjustments to reconcile earnings (loss) from continuing operations to net cash from operating activities:
Depreciation, depletion and amortization			2,780				2,811				2,248
Asset impairments			1,976				2,024				—
Deferred income tax expense (benefit)			97				(184	)			2,299
Derivatives and other financial instruments			135				(660	)			(886	)
Cash settlements on derivatives and financial instruments			277				865				485
Other noncash charges			318				240				241
Net change in working capital			(298	)			(50	)			180
Change in long-term other assets			10				(36	)			33
Change in long-term other liabilities			161				105				(488	)
Cash from operating activities – continuing operations			5,436				4,930				6,246
Cash from operating activities – discontinued operations			—				26				(22	)
Net cash from operating activities			5,436				4,956				6,224
Cash flows from investing activities:
Capital expenditures			(6,758	)			(8,225	)			(7,534	)
Proceeds from property and equipment divestitures			419				1,468				129
Purchases of short-term investments			(1,076	)			(4,106	)			(6,691	)
Redemptions of short-term investments			3,419				3,266				5,333
Other			(3	)			14				(29	)
Cash from investing activities – continuing operations			(3,999	)			(7,583	)			(8,792	)
Cash from investing activities – discontinued operations			—				57				3,146
Net cash from investing activities			(3,999	)			(7,526	)			(5,646	)
Cash flows from financing activities:
Proceeds from borrowings of long-term debt, net of issuance costs			2,233				2,458				2,221
Net short-term debt borrowing (repayments)			(1,872	)			(537	)			3,726
Debt repayments			—				—				(1,760	)
Credit facility borrowings			—				750				—
Credit facility repayments			—				(750	)			—
Proceeds from stock option exercises			3				27				101
Repurchases of common stock			—				—				(2,332	)
Dividends paid on common stock			(348	)			(324	)			(278	)
Excess tax benefits related to share-based compensation			4				5				13
Net cash from financing activities			20				1,629				1,691
Effect of exchange rate changes on cash			(28	)			23				(4	)
Net change in cash and cash equivalents			1,429				(918	)			2,265
Cash and cash equivalents at beginning of period			4,637				5,555				3,290
Cash and cash equivalents at end of period		$	6,066			$	4,637			$	5,555

See accompanying notes to consolidated financial statements.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

		December 31,
		2013				2012
		(In millions, except share data)
ASSETS
Current assets:
Cash and cash equivalents		$	6,066			$	4,637
Short-term investments			—				2,343
Accounts receivable			1,520				1,245
Other current assets			419				746
Total current assets			8,005				8,971
Property and equipment, at cost:
Oil and gas, based on full cost accounting:
Subject to amortization			73,995				69,410
Not subject to amortization			2,791				3,308
Total oil and gas			76,786				72,718
Other			6,195				5,630
Total property and equipment, at cost			82,981				78,348
Less accumulated depreciation, depletion and amortization			(54,534	)			(51,032	)
Property and equipment, net			28,447				27,316
Goodwill			5,858				6,079
Other long-term assets			567				960
Total assets		$	42,877			$	43,326
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	1,229			$	1,451
Revenues and royalties payable			786				750
Short-term debt			4,066				3,189
Other current liabilities			574				613
Total current liabilities			6,655				6,003
Long-term debt			7,956				8,455
Asset retirement obligations			2,140				1,996
Other long-term liabilities			834				901
Deferred income taxes			4,793				4,693
Stockholders’ equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 406 million shares in 2013 and 2012, respectively			41				41
Additional paid-in capital			3,780				3,688
Retained earnings			15,410				15,778
Accumulated other comprehensive earnings			1,268				1,771
Total stockholders’ equity			20,499				21,278
Commitments and contingencies (Note 18)
Total liabilities and stockholders’ equity		$	42,877			$	43,326

See accompanying notes to consolidated financial statements.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

		Common Stock								Additional Paid-In Capital				Retained Earnings				Accumulated Other Comprehensive Earnings				Treasury Stock				Total Stockholders’ Equity
		Shares				Amount
		(In millions)
Balance as of December 31, 2010			432			$	43			$	5,601			$	11,882			$	1,760			$	(33	)		$	19,253
Net earnings			—				—				—				4,704				—				—				4,704
Other comprehensive loss, net of tax			—				—				—				—				(185	)			—				(185	)
Stock option exercises			2				—				112				—				—				(11	)			101
Restricted stock grants, net of cancellations			1				—				—				—				—				—				—
Common stock repurchased			—				—				—				—				—				(2,337	)			(2,337	)
Common stock retired			(31	)			(3	)			(2,378	)			—				—				2,381				—
Common stock dividends			—				—				—				(278	)			—				—				(278	)
Share-based compensation			—				—				159				—				—				—				159
Share-based compensation tax benefits			—				—				13				—				—				—				13
Balance as of December 31, 2011			404				40				3,507				16,308				1,575				—				21,430
Net loss			—				—				—				(206	)			—				—				(206	)
Other comprehensive earnings, net of tax			—				—				—				—				196				—				196
Stock option exercises			1				1				49				—				—				(23	)			27
Restricted stock grants, net of cancellations			1				—				—				—				—				—				—
Common stock repurchased			—				—				—				—				—				(29	)			(29	)
Common stock retired			—				—				(52	)			—				—				52				—
Common stock dividends			—				—				—				(324	)			—				—				(324	)
Share-based compensation			—				—				179				—				—				—				179
Share-based compensation tax benefits			—				—				5				—				—				—				5
Balance as of December 31, 2012			406				41				3,688				15,778				1,771				—				21,278
Net loss			—				—				—				(20	)			—				—				(20	)
Other comprehensive loss, net of tax			—				—				—				—				(503	)			—				(503	)
Stock option exercises			—				—				3				—				—				—				3
Common stock repurchased			—				—				—				—				—				(36	)			(36	)
Common stock retired			—				—				(36	)			—				—				36				—
Common stock dividends			—				—				—				(348	)			—				—				(348	)
Share-based compensation			—				—				121				—				—				—				121
Share-based compensation tax benefits			—				—				4				—				—				—				4
Balance as of December 31, 2013			406			$	41			$	3,780			$	15,410			$	1,268			$	—			$	20,499

See accompanying notes to consolidated financial statements.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	Summary of Significant Accounting Policies

Devon Energy Corporation (“Devon”) is a leading independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Devon’s operations are concentrated in various North American onshore areas in the U.S. and Canada. Devon also owns natural gas pipelines, plants and treatment facilities in many of its producing areas, making it one of North America’s larger processors of natural gas.

Accounting policies used by Devon and its subsidiaries conform to accounting principles generally accepted in the United States of America and reflect industry practices. The more significant of such policies are discussed below.

Principles of Consolidation

The accounts of Devon and its wholly owned and controlled subsidiaries are included in the accompanying financial statements. All significant intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following:

	•		proved reserves and related present value of future net revenues;

	•		the carrying value of oil and gas properties;

	•		derivative financial instruments;

	•		the fair value of reporting units and related assessment of goodwill for impairment;

	•		income taxes;

	•		asset retirement obligations;

	•		obligations related to employee pension and postretirement benefits; and

	•		legal and environmental risks and exposures.

Revenue Recognition and Gas Balancing

Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck. Cash received relating to future production is deferred and recognized when all revenue recognition criteria are met. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying comprehensive statements of earnings.

Devon follows the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Devon is entitled based on its interests in the properties. These differences

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The liability is measured based on current market prices. No receivables are recorded for those wells where Devon has taken less than its share of production unless all revenue recognition criteria are met. If an imbalance exists at the time the wells’ reserves are depleted, settlements are made among the joint interest owners under a variety of arrangements.

Marketing and midstream revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil, gas and NGL purchases, transportation and processing contracts are reported on a gross basis when Devon takes title to the products and has risks and rewards of ownership.

During 2013, 2012 and 2011, no purchaser accounted for more than 10 percent of Devon’s operating revenues from continuing operations.

Derivative Financial Instruments

Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk, interest rate risk and foreign exchange risk. Devon does not intend to issue or hold derivative financial instruments for speculative trading purposes.

Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility. Devon’s derivative financial instruments typically include financial price swaps, basis swaps, costless price collars and call options. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional index prices and pays a variable differential on the same two index prices to the contract counterparty. The 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, Devon will cash-settle the difference with the counterparty to the collars. The call options give counterparties the right to purchase production at a predetermined price.

Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon periodically enters into foreign exchange forward contracts to manage its exposure to fluctuations in exchange rates.

All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in earnings unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2013, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon’s derivative financial instruments are also recorded in earnings.

By using derivative financial instruments to hedge exposures to changes in commodity prices, interest rates and foreign currency rates, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

a number of counterparties whom Devon believes are acceptable credit risks. It is Devon’s policy to enter into derivative contracts only with investment grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts generally require cash collateral to be posted if either its or the counterparty’s credit rating falls below certain credit rating levels. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below such credit levels. As of December 31, 2013, Devon held $3 million of cash collateral, which represented the estimated fair value of certain derivative positions in excess of Devon’s credit guidelines. The collateral is reported in other current liabilities in the accompanying balance sheet.

General and Administrative Expenses

General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Devon and net of amounts capitalized pursuant to the full cost method of accounting.

Share Based Compensation

Devon grants stock options, restricted stock awards and other types of share-based awards to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of general and administrative expenses in the accompanying comprehensive statements of earnings over the applicable requisite service periods. As a result of Devon’s consolidation of its U.S. operations announced in October 2012, certain share based awards were accelerated and recognized as a component of restructuring costs in the accompanying comprehensive statements of earnings.

Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are available to be issued as part of Devon’s share based awards. However, Devon has historically cancelled these shares upon repurchase.

Income Taxes

Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of carryforwards is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Devon does not recognize U.S. deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be indefinitely reinvested. When such earnings are no longer deemed indefinitely reinvested, Devon recognizes the appropriate deferred, or even current, income tax liabilities.

Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense.

Net Earnings (Loss) Per Common Share

Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon’s outstanding restricted stock awards. Diluted earnings per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of outstanding stock options.

Cash and Cash Equivalents

Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.

Investments

Devon periodically invests excess cash in United States and Canadian treasury securities and other marketable securities. Devon considers securities with original contractual maturities in excess of three months, but less than one year to be short-term investments. Investments with contractual maturities in excess of one year are classified as long-term, unless such investments are classified as trading or available-for-sale.

Devon reports its investments and other marketable securities at fair value, except for debt securities in which management has the ability and intent to hold until maturity. Such debt securities totaled $62 million and $64 million at December 31, 2013 and 2012, respectively, and are included in other long-term assets in the accompanying balance sheet. Devon has the ability to hold the securities until maturity.

Property and Equipment

Devon follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Internal costs incurred that are directly identified with acquisition, exploration and development activities undertaken by Devon for its own account, and that are not related to production, general corporate overhead or similar activities, are also capitalized. Interest costs incurred and attributable to unproved oil and gas properties under current evaluation and major development projects of oil and gas properties are also capitalized. All costs related to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.

Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of gas to one barrel of oil. Depletion is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.

Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment quarterly. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are transferred into the depletion calculation over holding periods ranging from three to four years.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves in a particular country.

Under the full cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the full cost “ceiling” at the end of each quarter. The ceiling is calculated separately for each country and is based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent per annum, net of related tax effects. The estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties.

Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts in place that qualify for hedge accounting treatment. None of Devon’s derivative contracts held during the three-year period ended December 31, 2013, qualified for hedge accounting treatment.

Any excess of the net book value, less related deferred taxes, over the ceiling is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher commodity prices may have increased the ceiling applicable to the subsequent period.

Costs for midstream assets that are in use are depreciated over the assets’ estimated useful lives, using either the unit-of-production or straight-line method. Depreciation and amortization of other property and equipment, including corporate and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 60 years. Interest costs incurred and attributable to major midstream and corporate construction projects are also capitalized.

Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites and midstream pipelines and processing plants when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Devon’s asset retirement obligations include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of such long-lived assets. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.

Goodwill

Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. Such test includes an assessment of qualitative and quantitative factors. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense. Because quoted market prices are not available for Devon’s reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid.

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Devon performed annual impairment tests of goodwill in the fourth quarters of 2013, 2012 and 2011. Based on these assessments, no impairment of goodwill was required.

The table below provides a summary of Devon’s goodwill, by assigned reporting unit. The decrease in Devon’s goodwill from 2012 to 2013 was primarily due to changes in the exchange rate between the United States dollar and the Canadian dollar.

		December 31,
		2013				2012
		(In millions)
U.S.		$	3,020			$	3,046
Canada			2,838				3,033
Total		$	5,858			$	6,079

Commitments and Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims resulting from improper operation of assets are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon’s accounting policy for property and equipment.

Fair Value Measurements

Certain of Devon’s assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels:

	•		Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

	•		Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.

	•		Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model.

Discontinued Operations

All amounts related to Devon’s International operations that were sold in 2012 and 2011 are classified as discontinued operations.

Foreign Currency Translation Adjustments

The United States dollar is the functional currency for Devon’s consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. Assets and liabilities of the Canadian subsidiaries are translated to United States dollars using the applicable exchange rate as of the end of a reporting

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period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. Translation adjustments have no effect on net income and are included in accumulated other comprehensive earnings in stockholders’ equity.

2.	Derivative Financial Instruments

Commodity Derivatives

As of December 31, 2013, Devon had the following open oil derivative positions. Devon’s oil derivatives settle against the average of the prompt month NYMEX West Texas Intermediate futures price.

		Price Swaps								Price Collars												Call Options Sold
Period		Volume (Bbls/d)				Weighted Average Price ($/Bbl)				Volume (Bbls/d)				Weighted Average Floor Price ($/Bbl)				Weighted Average Ceiling Price ($/Bbl)				Volume (Bbls/d)				Weighted Average Price ($/Bbl)
Q1-Q4 2014			75,000			$	94.14				70,453			$	89.38			$	100.58				42,000			$	116.43
Q1-Q4 2015			37,500			$	90.15				—			$	—			$	—				22,000			$	115.45
Q1-Q4 2016			—			$	—				—			$	—			$	—				12,500			$	95.00

As of December 31, 2013, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas derivatives that settle against the AECO index.

		Price Swaps								Price Collars												Call Options Sold
Period		Volume (MMBtu/d)				Weighted Average Price ($/MMBtu)				Volume (MMBtu/d)				Weighted Average Floor Price ($/MMBtu)				Weighted Average Ceiling Price ($/MMBtu)				Volume (MMBtu/d)				Weighted Average Price ($/MMBtu)
Q1-Q4 2014			800,000			$	4.42				460,000			$	4.03			$	4.51				500,000			$	5.00
Q1-Q4 2015			—			$	—				—			$	—			$	—				550,000			$	5.09
Q1-Q4 2016			—			$	—				—			$	—			$	—				110,000			$	5.00

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

As of December 31, 2013, Devon had the following open NGL derivative positions. Devon’s NGL positions settle against the average of the prompt month OPIS Mont Belvieu, Texas Index.

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

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Foreign Currency Derivatives

As of December 31, 2013, Devon had the following open foreign currency derivative position:

Forward Contract
Currency		Contract Type				CAD Notional				Weighted Average Fixed Rate Received				Expiration
						(In millions)				(CAD-USD)
Canadian Dollar			Sell			$	1,002				0.938				March 2014

Financial Statement Presentation

The following table presents the net gains and losses recognized in the accompanying comprehensive statements of earnings associated with derivative financial instruments. Net gains and losses associated with Devon’s commodity derivatives are presented in oil, gas and NGL derivatives in the accompanying comprehensive statements of earnings. Net gains and losses associated with Devon’s interest rate and foreign currency derivatives are presented in other nonoperating items in the accompanying comprehensive statements of earnings.

		Year Ended December 31,
		2013				2012				2011
		(In millions)
Commodity derivatives		$	(191	)		$	693			$	881
Interest rate derivatives			—				(15	)			(11	)
Foreign currency derivatives			56				(18	)			16
Net gains (losses) recognized in comprehensive statements of earnings		$	(135	)		$	660			$	886

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

				December 31
		Balance Sheet Caption		2013				2012
				(In millions)
Asset derivatives:
Commodity derivatives		Other current assets		$	75			$	379
Commodity derivatives		Other long-term assets			28				22
Interest rate derivatives		Other current assets			—				23
Foreign currency derivatives		Other current assets			—				1
Total asset derivatives				$	103			$	425
Liability derivatives:
Commodity derivatives		Other current liabilities		$	58			$	3
Commodity derivatives		Other long-term liabilities			62				29
Foreign currency derivatives		Other current liabilities			1				—
Total liability derivatives				$	121			$	32

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3.	Share-Based Compensation

On June 3, 2009, Devon’s stockholders adopted the 2009 Long-Term Incentive Plan, which expires on June 2, 2019. This plan authorizes the Compensation Committee, which consists of independent non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards, performance restricted stock awards, Canadian restricted stock units, performance share units, stock appreciation rights and cash-out rights to eligible employees. The plan also authorizes the grant of nonqualified stock options, restricted stock awards, restricted stock units and stock appreciation rights to directors.

In the second quarter of 2012, Devon’s stockholders adopted an amendment to the 2009 Long-Term Incentive Plan, which also expires June 2, 2019. This amendment increases the number of shares authorized for issuance from 21.5 million shares to 47.0 million shares. To calculate shares issued under the 2009 Long-Term Incentive Plan subsequent to this amendment, options and stock appreciation rights represent one share and other awards represent 2.38 shares.

Devon also has a stock option plan that was adopted in 2005 under which stock options were issued to certain employees. Options granted under this plan remain exercisable by the employees owning such options, but no new options or restricted stock awards will be granted under this plan.

Devon did not have an annual long-term incentive grant in 2013 due to revisions in the timing of the employee compensation cycle. The annual long-term incentive grant related to 2013 performance was granted in February 2014. The following table presents the effects of share-based compensation included in Devon’s accompanying comprehensive statements of earnings. The vesting for certain share-based awards was accelerated as part of Devon’s consolidation of its U.S. operations announced in October 2012. The associated expense for these accelerated awards is included in restructuring costs in the accompanying comprehensive statements of earnings. See Note 6 for further details.

		Year Ended December 31,
		2013				2012				2011
		(In millions)
Gross general and administrative expense		$	157			$	179			$	181
Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties		$	60			$	56			$	56
Related income tax benefit		$	22			$	31			$	33

Stock Options

In accordance with Devon’s incentive plans, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. In addition, options granted are exercisable during a period established for each grant, which may not exceed eight years from the date of grant. The recipient must pay the exercise price in cash or in common stock, or a combination thereof, at the time that the option is exercised. Generally, the service requirement for vesting ranges from zero to four years.

The fair value of stock options on the date of grant is expensed over the applicable vesting period. Devon estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires Devon to make several assumptions. The volatility of Devon’s common stock is based on the historical volatility of the market price of Devon’s common stock over a period of time equal to the expected term of the option and ending on the grant date. The dividend yield is based on Devon’s historical and current yield in effect at the date

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of grant. The risk-free interest rate is based on the zero-coupon United States Treasury yield for the expected term of the option at the date of grant. The expected term of the options is based on historical exercise and termination experience for various groups of employees and directors. Each group is determined based on the similarity of their historical exercise and termination behavior. The following table presents a summary of the grant-date fair values of stock options granted and the related assumptions for 2012 and 2011. All such amounts represent the weighted-average amounts for each year. No stock options were granted in 2013.

		2012				2011
Grant-date fair value		$	22.20			$	23.11
Volatility factor			42.5	%			46.0	%
Dividend yield			1.2	%			1.0	%
Risk-free interest rate			1.1	%			0.8	%
Expected term (in years)			6.0				4.2

The following table presents a summary of Devon’s outstanding stock options.

						Weighted Average
		Options				Exercise Price				Remaining Term				Intrinsic Value
		(In thousands)								(In years)				(In millions)
Outstanding at December 31, 2012			7,828			$	69.12
Exercised			(61	)		$	57.66
Expired			(1,212	)		$	68.47
Forfeited			(109	)		$	69.23
Outstanding at December 31, 2013			6,446			$	69.35				3.76			$	1
Vested and expected to vest at December 31, 2013			6,416			$	69.36				3.75			$	1
Exercisable at December 31, 2013			5,361			$	69.50				3.39			$	1

The aggregate intrinsic value of stock options that were exercised during 2013, 2012 and 2011 was $0.3 million, $34 million and $81 million, respectively. As of December 31, 2013, Devon’s unrecognized compensation cost related to unvested stock options was $19 million. Such cost is expected to be recognized over a weighted-average period of 1.6 years.

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Restricted Stock Awards and Units

Restricted stock awards and units are subject to the terms, conditions, restrictions and limitations, if any, that the Compensation Committee deems appropriate, including restrictions on continued employment. Generally, the service requirement for vesting ranges from zero to four years. During the vesting period, recipients of restricted stock awards receive dividends that are not subject to restrictions or other limitations. Devon estimates the fair values of restricted stock awards and units as the closing price of Devon’s common stock on the grant date of the award or unit, which is expensed over the applicable vesting period. The following table presents a summary of Devon’s unvested restricted stock awards and units.

		Restricted Stock Awards & Units				Weighted Average Grant-Date Fair Value
		(In thousands)
Unvested at December 31, 2012			5,740			$	61.75
Granted			258			$	57.27
Vested			(2,365	)		$	64.13
Forfeited			(341	)		$	59.82
Unvested at December 31, 2013			3,292			$	59.76

The aggregate fair value of restricted stock awards and units that vested during 2013, 2012 and 2011 was $141 million, $112 million and $145 million, respectively. As of December 31, 2013, Devon’s unrecognized compensation cost related to unvested restricted stock awards and units was $166 million. Such cost is expected to be recognized over a weighted-average period of 2.2 years.

Performance Based Restricted Stock Awards

Performance based restricted stock awards are granted to certain members of Devon’s senior management. Vesting of the awards is dependent on Devon meeting certain internal performance targets and the recipient meeting certain service requirements. Generally, the service requirement for vesting ranges from zero to four years. If Devon meets or exceeds the performance target, the awards vest after the recipient meets the related requisite service period. If the performance target and service period requirement are not met, the award does not vest. Once vested, recipients are entitled to dividends on the awards. Devon estimates the fair values of the awards as the closing price of Devon’s common stock on the grant date of the award, which is expensed over the applicable vesting period. The following table presents a summary of Devon’s performance based restricted stock awards.

		Performance Restricted Stock Awards				Weighted Average Grant-Date Fair Value
		(In thousands)
Unvested at December 31, 2012			408			$	58.25
Vested			(92	)		$	65.10
Unvested at December 31, 2013			316			$	56.25

As of December 31, 2013, Devon’s unrecognized compensation cost related to these awards was $3 million. Such cost is expected to be recognized over a weighted-average period of 1.4 years.

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Performance Share Units

Performance share units are granted to certain members of Devon’s senior management. Each unit that vests entitles the recipient to one share of Devon common stock. The vesting of these units is based on comparing Devon’s total shareholder return (“TSR”) to the TSR of a predetermined group of fourteen peer companies over the specified two- or three-year performance period. The vesting of units may be between zero and 200 percent of the units granted depending on Devon’s TSR as compared to the peer group on the vesting date.

At the end of the vesting period, recipients receive dividend equivalents with respect to the number of units vested. The fair value of each performance share unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of Devon and the designated peer group; and (iii) an estimated ranking of Devon among the designated peer group. The fair value of the unit on the date of grant is expensed over the applicable vesting period. The following table presents a summary of the grant-date fair values of performance share units granted and the related assumptions.

		2013		2012		2011
Grant-date fair value		$61.27 – $63.48		$61.27 – $63.48		$80.24 – $83.15
Risk-free interest rate		0.26% – 0.36%		0.26% – 0.36%		0.28% – 0.43%
Volatility factor		30.3%		30.3%		41.8%
Contractual term (in years)		3.0		3.0		3.0

The following table presents a summary of Devon’s performance share units.

		Performance Share Units				Weighted Average Grant-Date Fair Value
		(In thousands)
Unvested at December 31, 2012			878			$	66.93
Granted			55			$	61.57
Forfeited			(8	)		$	63.37
Unvested at December 31, 2013 (1)			925			$	66.64

(1)	A maximum of 1.9 million common shares could be awarded based upon Devon’s final TSR ranking.

As of December 31, 2013, Devon’s unrecognized compensation cost related to unvested units was $24 million. Such cost is expected to be recognized over a weighted-average period of 1.6 years.

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4.	Asset impairments

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

		Year Ended December 31, 2013								Year Ended December 31, 2012
		Gross				Net of Taxes				Gross				Net of Taxes
		(In millions)
U.S. oil and gas assets		$	1,110			$	707			$	1,793			$	1,142
Canada oil and gas assets			843				632				163				122
Midstream assets			23				14				68				44
Total asset impairments		$	1,976			$	1,353			$	2,024			$	1,308

Oil and Gas Impairments

Under the full cost method of accounting, capitalized costs of oil and gas properties are subject to a quarterly full cost ceiling test, which is discussed in Note 1.

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

Midstream Impairments

Due to declining natural gas production resulting from low natural gas and NGL prices, Devon determined that the carrying amounts of certain of its midstream facilities were not recoverable from estimated future cash flows. Consequently, the assets were written down to their estimated fair values, which were determined using discounted cash flow models. The fair value of Devon’s midstream assets is considered a Level 3 fair value measurement.

5.	Other Operating Items

		Year Ended December 31,
		2013				2012				2011
		(In millions)
Accretion of asset retirement obligations		$	115			$	110			$	92
(Gain) loss on sale of assets			9				(13	)			(2	)
Other			(3	)			(5	)			(101	)
Other operating items		$	121			$	92			$	(11	)

During 2011, Devon received $88 million of excess insurance recoveries related to certain weather and operational claims.

6.	Restructuring Costs

Office Consolidation

In October 2012, Devon announced plans to consolidate its U.S. personnel into a single operations group centrally located at the company’s corporate headquarters in Oklahoma City. As a result, Devon closed its office in Houston, transferred operational responsibilities for assets in south Texas, east Texas and Louisiana to Oklahoma City and incurred $134 million of restructuring costs associated with the consolidation.

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Divestiture of Offshore Assets

In the fourth quarter of 2009, Devon announced plans to divest its offshore assets. As of December 31, 2012, Devon had divested all of its U.S. Offshore and International assets and incurred $196 million of restructuring costs associated with the divestitures.

Financial Statement Presentation

The schedule below summarizes restructuring costs presented in the accompanying comprehensive statements of earnings.

		Year Ended December 31,
		2013				2012				2011
		(In millions)
Office consolidation:
Employee severance and retention		$	13			$	77			$	—
Lease obligations and other			41				3				—
Total			54				80				—
Offshore divestitures:
Employee severance		$	—			$	(3	)		$	8
Lease obligations and other			—				(3	)			(10	)
Total			—				(6	)			(2	)
Restructuring costs		$	54			$	74			$	(2	)

Employee severance and retention – As of December 31, 2013, Devon had incurred $90 million of employee severance and retention costs associated with the office consolidation. This included amounts related to cash severance costs and accelerated vesting of share-based grants.

Lease obligations and other – As of December 31, 2013, Devon had incurred $28 million of restructuring costs related to certain office space that is subject to non-cancellable operating lease agreements and that it ceased using as a part of the office consolidation. Devon’s estimate of lease obligations was based upon certain key estimates that could change over the term of the leases. These estimates include the estimated sublease income that it may receive over the term of the leases, as well as the amount of variable operating costs that it will be required to pay under the leases.

The schedule below summarizes Devon’s restructuring liabilities.

		Other Current Liabilities				Other Long-Term Liabilities				Total
		(In millions)
Balance as of December 31, 2011		$	29			$	16			$	45
Employee severance – Office consolidation			49				—				49
Lease obligations – Offshore			(17	)			(7	)			(24	)
Employee severance – Offshore			(9	)			—				(9	)
Balance as of December 31, 2012			52				9				61
Employee severance – Office consolidation			(43	)			—				(43	)
Lease obligations – Offshore			(3	)			(2	)			(5	)
Lease obligations and other – Office consolidation			21				11				32
Balance as of December 31, 2013		$	27			$	18			$	45

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

7.	Income Taxes

Income Tax Expense (Benefit)

Devon’s income tax components are presented in the following table.

		Year Ended December 31,
		2013				2012				2011
		(In millions)
Current income tax expense (benefit):
United States federal		$	73			$	60			$	(143	)
Various states			(5	)			(3	)			20
Canada and various provinces			4				(5	)			(20	)
Total current tax expense (benefit)			72				52				(143	)
Deferred income tax expense (benefit):
United States federal			198				(188	)			1,986
Various states			59				34				95
Canada and various provinces			(160	)			(30	)			218
Total deferred tax expense (benefit)			97				(184	)			2,299
Total income tax expense (benefit)		$	169			$	(132	)		$	2,156

Total income tax expense (benefit) differed from the amounts computed by applying the United States federal income tax rate to earnings from continuing operations before income taxes as a result of the following:

		Year Ended December 31,
		2013				2012				2011
		(In millions)
Expected income tax expense (benefit) based on United States statutory tax rate of 35%		$	52			$	(111	)		$	1,502
Repatriations			97				—				725
State income taxes			35				20				70
Taxation on Canadian operations			14				(19	)			(91	)
Other			(29	)			(22	)			(50	)
Total income tax expense (benefit)		$	169			$	(132	)		$	2,156

Pursuant to the completed and planned divestitures of Devon’s International assets located outside North America, a portion of Devon’s foreign earnings had been deemed to no longer be indefinitely reinvested. As of December 31, 2012, Devon had recognized a $936 million deferred income tax liability related to assumed repatriations of earnings from its foreign subsidiaries, including $725 million of deferred income tax expense recognized in 2011.

In the second and fourth quarters of 2013, Devon repatriated to the U. S. a total of $4.3 billion of its cash held outside of the U. S. In the fourth quarter of 2013, Devon announced plans to divest of its Canadian conventional assets. These events resulted in an incremental income tax expense of $97 million. The incremental expense included $180 million of current income tax expense offset by $83 million of deferred income tax benefit. The $83 million deferred tax benefit was comprised of $180 million of deferred tax benefits that offset the incremental current income tax expense and an additional $97 million of deferred income tax expense accrued in the fourth quarter for assumed repatriations.

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Deferred Tax Assets and Liabilities

The tax effects of temporary differences that gave rise to Devon’s deferred tax assets and liabilities are presented below:

		December 31,
		2013				2012
		(In millions)
Deferred tax assets:
Asset retirement obligations		$	673			$	618
Foreign tax credits			248				—
Net operating loss carryforwards			183				427
Alternative minimum tax credits			105				198
Pension benefit obligations			104				129
Other			163				134
Total deferred tax assets			1,476				1,506
Deferred tax liabilities:
Property and equipment			(5,895	)			(4,970	)
Long-term debt			(161	)			(198	)
Taxes on unremitted foreign earnings			(157	)			(936	)
Fair value of financial instruments			(7	)			(141	)
Other			(52	)			(76	)
Total deferred tax liabilities			(6,272	)			(6,321	)
Net deferred tax liability		$	(4,796	)		$	(4,815	)

Devon has recognized a $248 million deferred tax asset related to foreign tax credit carryforwards which expire between 2019 and 2023. Devon expects the tax benefits from the foreign tax credits to be utilized between 2014 and 2016. Devon also has recognized $183 million of deferred tax assets related to various net operating loss carryforwards available to offset future income taxes. The carryforwards consist of $673 million of Canadian net operating loss carryforwards, which expire between 2028 and 2033, and $197 million of state net operating loss carryforwards, which expire primarily between 2014 and 2032. Devon expects the tax benefits from the Canadian net operating loss carryforwards to be utilized between 2014 and 2017 and the state net operating loss carryforwards to be utilized between 2014 and 2020. Devon has also recognized a $105 million deferred tax asset related to alternative minimum tax credits which have no expiration date and will be available for use against tax on future taxable income.

The expected utilization of Devon’s carryforwards and credits is based upon current estimates of taxable income, considering limitations on the annual utilization of these benefits as set forth by tax regulations. Significant changes in such estimates caused by variables such as future oil, gas and NGL prices or capital expenditures could alter the timing of the eventual utilization of such carryforwards. There can be no assurance that Devon will generate any specific level of continuing taxable earnings. However, management believes that Devon’s future taxable income will more likely than not be sufficient to utilize its tax carryforwards and credits prior to their expiration.

As of December 31, 2013, Devon’s unremitted foreign earnings totaled approximately $4.3 billion. Of this amount, approximately $1.5 billion was deemed to be indefinitely reinvested into the development and growth of Devon’s Canadian business. Therefore, Devon has not recognized a deferred tax liability for United States

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income taxes associated with such earnings. If such earnings were to be repatriated to the U.S., Devon may be subject to United States income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of such additional taxes that may be payable due to the inter-relationship of the various factors involved in making such an estimate.

Devon has deemed the remaining $2.8 billion of unremitted earnings not to be indefinitely reinvested. Consequently, Devon has recognized a $157 million deferred tax liability associated with such unremitted earnings as of December 31, 2013.

Unrecognized Tax Benefits

The following table presents changes in Devon’s unrecognized tax benefits.

		December 31,
		2013				2012
		(In millions)
Balance at beginning of year		$	216			$	165
Tax positions taken in prior periods			(17	)			(46	)
Tax positions taken in current year			42				92
Accrual of interest related to tax positions taken			5				7
Lapse of statute of limitations			—				(3	)
Foreign currency translation			(3	)			1
Balance at end of year		$	243			$	216

Devon’s unrecognized tax benefit balance at December 31, 2013 and 2012, included $32 million and $27 million, respectively, of interest and penalties. If recognized, $198 million of Devon’s unrecognized tax benefits as of December 31, 2013 would affect Devon’s effective income tax rate. Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities.

Jurisdiction		Tax Years Open
United States federal			2008-2013
Various U.S. states			2008-2013
Canada federal			2004-2013
Various Canadian provinces			2004-2013

Certain statute of limitation expirations are scheduled to occur in the next twelve months. However, Devon is currently in various stages of the administrative review process for certain open tax years. In addition, Devon is currently subject to various income tax audits that have not reached the administrative review process. As a result, Devon cannot reasonably anticipate the extent that the liabilities for unrecognized tax benefits will increase or decrease within the next twelve months.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

8.	Earnings Per Share

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

		Earnings (loss)				Common Shares				Earnings (loss) per Share
		(In millions, except per share amounts)
Year Ended December 31, 2013:
Loss from continuing operations		$	(20	)			406
Attributable to participating securities			(2	)			(4	)
Basic loss per share			(22	)			402			$	(0.06	)
Dilutive effect of potential common shares issuable			—				—
Diluted loss per share		$	(22	)			402			$	(0.06	)
Year Ended December 31, 2012:
Loss from continuing operations		$	(185	)			404
Attributable to participating securities			(3	)			(4	)
Basic loss per share			(188	)			400			$	(0.47	)
Dilutive effect of potential common shares issuable			—				—
Diluted loss per share		$	(188	)			400			$	(0.47	)
Year Ended December 31, 2011:
Earnings from continuing operations		$	2,134				417
Attributable to participating securities			(23	)			(5	)
Basic earnings per share			2,111				412			$	5.12
Dilutive effect of potential common shares issuable			—				2
Diluted earnings per share		$	2,111				414			$	5.10

Certain options to purchase shares of Devon’s common stock were excluded from the dilution calculations because the options were antidilutive. These excluded options totaled 7 million, 9 million and 3 million in 2013, 2012 and 2011, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

9.	Other Comprehensive Earnings

Components of other comprehensive earnings consist of the following:

		Year Ended December 31,
		2013				2012				2011
		(In millions)
Foreign currency translation:
Beginning accumulated foreign currency translation		$	1,996			$	1,802			$	1,993
Change in cumulative translation adjustment			(574	)			203				(200	)
Income tax benefit (expense)			26				(9	)			9
Ending accumulated foreign currency translation			1,448				1,996				1,802
Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits			(225	)			(227	)			(233	)
Net actuarial gain (loss) and prior service cost arising in current year			48				(47	)			(21	)
Recognition of net actuarial loss and prior service cost in earnings (1)			24				51				30
Income tax expense			(27	)			(2	)			(3	)
Ending accumulated pension and postretirement benefits			(180	)			(225	)			(227	)
Accumulated other comprehensive earnings, net of tax		$	1,268			$	1,771			$	1,575

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

10.	Supplemental Information to Statements of Cash Flows

		Year Ended December 31,
		2013				2012				2011
		(In millions)
Net change in working capital accounts:
Accounts receivable		$	(288	)		$	140			$	(185	)
Other current assets			49				(128	)			125
Accounts payable			26				(8	)			64
Revenues and royalties payable			35				19				144
Other current liabilities			(120	)			(73	)			32
Net change in working capital		$	(298	)		$	(50	)		$	180
Interest paid (net of capitalized interest)		$	406			$	334			$	325
Income taxes paid (received)		$	13			$	100			$	(383	)

11.	Short-Term Investments

The components of short-term investments include the following:

		December 31, 2013				December 31, 2012
		(In millions)
Canadian treasury, agency and provincial securities		$	—			$	1,865
United States treasuries			—				429
Other			—				49
Short-term investments		$	—			$	2,343

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

12.	Accounts Receivable

The components of accounts receivable include the following:

		December 31, 2013				December 31, 2012
		(In millions)
Oil, gas and NGL sales		$	851			$	752
Joint interest billings			447				270
Marketing and midstream revenues			172				161
Other			61				72
Gross accounts receivable			1,531				1,255
Allowance for doubtful accounts			(11	)			(10	)
Net accounts receivable		$	1,520			$	1,245

13.	Acquisitions and Divestitures

Crosstex Merger

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

In exchange for a controlling interest in both EnLink and the Partnership, Devon will contribute its equity interest in a newly formed Devon subsidiary (“EnLink Holdings”) and $100 million in cash. EnLink Holdings will own Devon’s midstream assets in the Barnett Shale in north Texas and the Cana and Arkoma Woodford Shales in Oklahoma, as well as Devon’s economic interest in Gulf Coast Fractionators in Mt. Belvieu, Texas. The Partnership and EnLink will each own 50% of EnLink Holdings. The completion of these transactions is subject to Crosstex Energy, Inc. shareholder approval. Devon expects Crosstex Energy, Inc. shareholders will approve the transaction, allowing Devon and Crosstex to complete the transaction near the end of the first quarter of 2014.

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

	•		70% – Devon Energy Corporation

	•		30% – Current Crosstex Energy, Inc. public stockholders

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

	•		53% – Devon Energy Corporation

	•		40% – Current Crosstex Energy, L.P. public unitholders

	•		7% – the General Partner

GeoSouthern Acquisition

On November 20, 2013, Devon entered into an agreement with GeoSouthern Intermediate Holdings, LLC, to acquire certain oil and gas properties, leasehold mineral interests and related assets located in the Eagle Ford Shale in south Texas for $6 billion in cash. The transaction is expected to close in the first quarter of 2014.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Subsequent Event (unaudited)

In conjunction with the announcement of the GeoSouthern acquisition, Devon also announced plans to divest certain non-core properties located throughout Canada and the U.S. On February 19, 2014, Devon announced its first transaction as part of this divestiture program, in which it agreed to sell the majority of its Canadian conventional assets to Canadian Natural Resources Limited for approximately $2.8 billion ($3.125 billion in Canadian dollars). This transaction is expected to close early in the second quarter of 2014.

14.	Debt and Related Expenses

A summary of Devon’s debt is as follows:

		December 31,
		2013				2012
		(In millions)
Commercial paper		$	1,317			$	3,189
Other debentures and notes:
5.625% due January 15, 2014			500				500
Floating rate due December 15, 2015			500				—
2.40% due July 15, 2016			500				500
Floating rate due December 15, 2016			350				—
1.20% due December 15, 2016			650				—
1.875% due May 15, 2017			750				750
8.25% due July 1, 2018			125				125
2.25% due December 15, 2018			750				—
6.30% due January 15, 2019			700				700
4.00% due July 15, 2021			500				500
3.25% due May 15, 2022			1,000				1,000
7.50% due September 15, 2027			150				150
7.875% due September 30, 2031			1,250				1,250
7.95% due April 15, 2032			1,000				1,000
5.60% due July 15, 2041			1,250				1,250
4.75% due May 15, 2042			750				750
Net discount on debentures and notes			(20	)			(20	)
Total debt			12,022				11,644
Less amount classified as short-term debt (1)			4,066				3,189
Long-term debt		$	7,956			$	8,455

(1)	2013 short-term debt consists of $2.25 billion of senior notes recently issued in conjunction with the planned GeoSouthern acquisition, $1.3 billion of commercial paper and $500 million of senior notes due January 15, 2014.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Debt maturities as of December 31, 2013, excluding premiums and discounts, are as follows (in millions):

2014		$	4,067
2015			—
2016			500
2017			750
2018			125
2019 and thereafter			6,600
Total		$	12,042

Credit Lines

Devon has a $3.0 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) that matures on October 24, 2018. However, prior to the maturity date, Devon has the option to extend the maturity for up to one additional one-year period, subject to the approval of the lenders.

Amounts borrowed under the Senior Credit Facility may, at the election of Devon, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, Devon may elect to borrow at the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $3.8 million that is payable quarterly in arrears. As of December 31, 2013, there were no borrowings under the Senior Credit Facility.

The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65 percent. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the accompanying financial statements. Also, total capitalization is adjusted to add back noncash financial write-downs such as full cost ceiling impairments or goodwill impairments. As of December 31, 2013, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 25.7 percent.

Commercial Paper

Devon has access to $3.0 billion of short-term credit under its commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found in the commercial paper market. As of December 31, 2013, Devon’s weighted average borrowing rate on its commercial paper borrowings was 0.30 percent.

Other Debentures and Notes

Following are descriptions of the various other debentures and notes outstanding at December 31, 2013, as listed in the table presented at the beginning of this note.

GeoSouthern Debt

In December 2013, in conjunction with the planned GeoSouthern acquisition, Devon issued $2.25 billion aggregate principal amount of fixed and floating rate senior notes resulting in cash proceeds of approximately

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

$2.2 billion, net of discounts and issuance costs. The floating rate senior notes due in 2015 bear interest at a rate equal to three-month LIBOR plus 0.45 percent, which rate will be reset quarterly. The floating rate senior notes due in 2016 bears interest at a rate equal to three-month LIBOR plus 0.54 percent, which rate will be reset quarterly. The schedule below summarizes the key terms of these notes ($ in millions).

Floating rate due December 15, 2015		$	500
Floating rate due December 15, 2016			350
1.20% due December 15, 2016			650
2.25% due December 15, 2018			750
Discount and issuance costs			(2	)
Net proceeds		$	2,248

In the event that GeoSouthern acquisition is not completed on or prior to June 30, 2014, Devon is required to redeem each series of new senior notes at 101% of the aggregate principal amount of such series, plus accrued and unpaid interest. Due to the redemption features, these senior notes were classified as short-term debt on Devon’s consolidated balance sheet as of December 31, 2013 and will be reclassified as long-term debt once the acquisition is completed.

Additionally, during December 2013, Devon entered into a term loan agreement with a group of major financial institutions pursuant to which Devon may draw up to $2.0 billion to finance, in part, the GeoSouthern acquisition and to pay transaction costs. Half of any loans under the term loan agreement will have a maturity of three years and the other half will have a maturity of five years (the “5-Year Loans”). The 5-Year Loans will provide for the partial amortization of principal during the last two years that they are outstanding. Loans borrowed under the term loan agreement may, at the election of Devon, bear interest at various fixed rate options for periods up to six months. Such rates are generally less than the prime rate. However, Devon may elect to borrow at the prime rate. There were no borrowings under the term loan agreement as of December 31, 2013.

Other Notes

In 2012, 2011, 2009 and 2002 Devon issued senior notes that are unsecured and unsubordinated obligations of Devon. Devon used the net proceeds to repay outstanding commercial paper and credit facility borrowings. The schedule below summarizes the key terms of these notes ($ in millions).

		Date Issued
		May 2012				July 2011				January 2009				March 2002
1.875% due May 15, 2017		$	750			$	—			$	—			$	—
3.25% due May 15, 2022			1,000				—				—				—
4.75% due May 15, 2042			750				—				—				—
2.40% due July 15, 2016			—				500				—				—
4.00% due July 15, 2021			—				500				—				—
5.60% due July 15, 2041			—				1,250				—				—
5.625% due January 15, 2014			—				—				500				—
6.30% due January 15, 2019			—				—				700				—
7.95% due April 15, 2032			—				—				—				1,000
Discount and issuance costs			(35	)			(29	)			(13	)			(14	)
Net proceeds		$	2,465			$	2,221			$	1,187			$	986

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Ocean Debt

On April 25, 2003, Devon merged with Ocean Energy, Inc. and assumed certain debt instruments. The table below summarizes the debt assumed that remains outstanding as of December 31, 2013, including the fair value of the debt at April 25, 2003, and the effective interest rate of the debt after determining the fair values using April 25, 2003, market interest rates. The premiums resulting from fair values exceeding face values are being amortized using the effective interest method. Both notes are general unsecured obligations of Devon.

Debt Assumed		Fair Value of Debt Assumed				Effective Rate of Debt Assumed
	(In millions)
8.250% due July 2018 (principal of $125 million)		$	147				5.5	%
7.500% due September 2027 (principal of $150 million)		$	169				6.5	%

7.875% Debentures due September 30, 2031

In October 2001, Devon, through Devon Financing Corporation, U.L.C. (“Devon Financing”), a wholly owned finance subsidiary, sold debentures, which are unsecured and unsubordinated obligations of Devon Financing. Devon has fully and unconditionally guaranteed on an unsecured and unsubordinated basis the obligations of Devon Financing under the debt securities. The proceeds were used to fund a portion of the acquisition of Anderson Exploration.

Net financing costs

The following schedule includes the components of net financing costs.

		Year Ended December 31,
		2013				2012				2011
		(In millions)
Interest based on debt outstanding		$	466			$	440			$	414
Capitalized interest			(56	)			(48	)			(72	)
Other fees and expenses			27				14				10
Interest expense			437				406				352
Interest income			(20	)			(36	)			(21	)
Net financing costs		$	417			$	370			$	331

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

15.	Asset Retirement Obligations

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

		Year Ended December 31,
		2013				2012
		(In millions)
Asset retirement obligations as of beginning of period		$	2,095			$	1,563
Liabilities incurred			112				90
Liabilities settled			(83	)			(86	)
Revision of estimated obligation			104				420
Liabilities assumed by others			(28	)			(23	)
Accretion expense on discounted obligation			115				110
Foreign currency translation adjustment			(87	)			21
Asset retirement obligations as of end of period			2,228				2,095
Less current portion			88				99
Asset retirement obligations, long-term		$	2,140			$	1,996

During 2012, Devon recognized revisions to its asset retirement obligations totaling $420 million. The primary factor contributing to this revision was an overall increase in abandonment cost estimates for certain of its production operations facilities.

16.	Retirement Plans

Devon has various non-contributory defined benefit pension plans, including qualified plans and nonqualified plans. The qualified plans provide retirement benefits for certain U.S. and Canadian employees meeting certain age and service requirements. Benefits for the qualified plans are based on the employees’ years of service and compensation and are funded from assets held in the plans’ trusts.

The nonqualified plans provide retirement benefits for certain employees whose benefits under the qualified plans are limited by income tax regulations. The nonqualified plans’ benefits are based on the employees’ years of service and compensation. For certain nonqualified plans, Devon has established trusts to fund these plans’ benefit obligations. The total value of these trusts was $27 million and $31 million at December 31, 2013 and 2012, respectively, and is included in other long-term assets in the accompanying balance sheets. For the remaining nonqualified plans for which trusts have not been established, benefits are funded from Devon’s available cash and cash equivalents.

Devon also has defined benefit postretirement plans that provide benefits for substantially all U.S. employees. The plans provide medical and, in some cases, life insurance benefits and are either contributory or non-contributory, depending on the type of plan. Benefit obligations for such plans are estimated based on Devon’s future cost-sharing intentions. Devon’s funding policy for the plans is to fund the benefits as they become payable with available cash and cash equivalents.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Benefit Obligations and Funded Status

The following table presents the funded status of Devon’s qualified and nonqualified pension and postretirement benefit plans. The benefit obligation for pension plans represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated benefit obligation. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated benefit obligation for pension plans was $1.1 billion and $1.2 billion at December 31, 2013 and 2012, respectively. Devon’s benefit obligations and plan assets are measured each year as of December 31. Devon’s 2012 plan settlements relate to a plan amendment which removed a dollar cap on lump sum payments and revised optional forms of payment to include a lump sum distribution feature. The projected benefit obligation for Devon’s qualified plans was fully funded as of December 31, 2013 and 2012.

		Pension Benefits								Postretirement Benefits
		2013				2012				2013				2012
		(In millions)
Change in benefit obligation:
Benefit obligation at beginning of year		$	1,360			$	1,303			$	34			$	37
Service cost			36				43				1				1
Interest cost			51				60				1				1
Actuarial loss (gain)			(158	)			95				(3	)			(4	)
Plan amendments			2				14				(8	)			—
Plan curtailments			—				(20	)			—				1
Plan settlements			—				(93	)			—				—
Foreign exchange rate changes			(2	)			1				—				—
Participant contributions			—				—				3				3
Benefits paid			(112	)			(43	)			(4	)			(5	)
Benefit obligation at end of year			1,177				1,360				24				34
Change in plan assets:
Fair value of plan assets at beginning of year			1,165				1,187				—				—
Actual return on plan assets			(57	)			102				—				—
Employer contributions			11				11				1				2
Participant contributions			—				—				3				3
Plan settlements			—				(93	)			—				—
Benefits paid			(112	)			(43	)			(4	)			(5	)
Foreign exchange rate changes			(1	)			1				—				—
Fair value of plan assets at end of year			1,006				1,165				—				—
Funded status at end of year		$	(171	)		$	(195	)		$	(24	)		$	(34	)
Amounts recognized in balance sheet:
Noncurrent assets		$	47			$	62			$	—			$	—
Current liabilities			(12	)			(12	)			(3	)			(3	)
Noncurrent liabilities			(206	)			(245	)			(21	)			(31	)
Net amount		$	(171	)		$	(195	)		$	(24	)		$	(34	)
Amounts recognized in accumulated other comprehensive earnings:
Net actuarial loss (gain)		$	279			$	340			$	(13	)		$	(11	)
Prior service cost (credit)			23				25				(11	)			(4	)
Total		$	302			$	365			$	(24	)		$	(15	)

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The plan assets for pension benefits in the table above exclude the assets held in trusts for the nonqualified plans. However, employer contributions for pension benefits in the table above include $11 million and $10 million for 2013 and 2012, respectively, which were transferred from the trusts established for the nonqualified plans.

Certain of Devon’s pension plans have a projected benefit obligation and accumulated benefit obligation in excess of plan assets at December 31, 2013 and 2012 as presented in the table below.

		December 31,
		2013				2012
		(In millions)
Projected benefit obligation		$	218			$	257
Accumulated benefit obligation		$	179			$	216
Fair value of plan assets		$	—			$	—

Net Periodic Benefit Cost and Other Comprehensive Earnings

The following table presents the components of net periodic benefit cost and other comprehensive earnings.

		Pension Benefits												Postretirement Benefits
		2013				2012				2011				2013				2012				2011
		(In millions)
Net periodic benefit cost:
Service cost		$	36			$	43			$	37			$	1			$	1			$	1
Interest cost			51				60				60				1				1				2
Expected return on plan assets			(62	)			(64	)			(42	)			—				—				—
Curtailment and settlement expense			—				26				—				—				1				(3	)
Recognition of net actuarial loss (gain) (1)			22				24				32				(1	)			(1	)			—
Recognition of prior service cost (1)			4				3				3				(1	)			(1	)			(2	)
Total net periodic benefit cost (2)			51				92				90				—				1				(2	)
Other comprehensive loss (earnings):
Actuarial loss (gain) arising in current year			(39	)			37				23				(3	)			(4	)			(7	)
Prior service cost (credit) arising in current year			2				14				—				(8	)			—				5
Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost			(22	)			(45	)			(32	)			1				1				3
Recognition of prior service cost, including curtailment, in net periodic benefit cost			(4	)			(8	)			(3	)			1				1				2
Total other comprehensive loss (earnings)			(63	)			(2	)			(12	)			(9	)			(2	)			3
Total recognized		$	(12	)		$	90			$	78			$	(9	)		$	(1	)		$	1

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents the estimated net actuarial loss and prior service cost that will be amortized from accumulated other comprehensive earnings into net periodic benefit cost during 2014.

		Pension Benefits				Postretirement Benefits
		(In millions)
Net actuarial loss (gain)		$	18			$	(1	)
Prior service cost (credit)			4				(1	)
Total		$	22			$	(2	)

Assumptions

The following table presents the weighted average actuarial assumptions used to determine obligations and periodic costs.

		Pension Benefits												Postretirement Benefits
		2013				2012				2011				2013				2012				2011
Assumptions to determine benefit obligations:
Discount rate			4.80	%			3.85	%			4.65	%			3.65	%			3.30	%			4.25	%
Rate of compensation increase			4.48	%			4.48	%			4.97	%			N/A				N/A				N/A
Assumptions to determine net periodic benefit cost:
Discount rate			3.85	%			4.65	%			5.50	%			3.30	%			4.25	%			4.90	%
Expected return on plan assets			5.48	%			5.48	%			6.48	%			N/A				N/A				N/A
Rate of compensation increase			4.48	%			4.97	%			6.94	%			N/A				N/A				N/A

Discount rate – Future pension and postretirement obligations are discounted at the end of each year based on the rate at which obligations could be effectively settled, considering the timing of estimated future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk.

Rate of compensation increase – For measurement of the 2013 benefit obligation for the pension plans, a 4.48 percent compensation increase was assumed.

Expected return on plan assets – The expected rate of return on plan assets was determined by evaluating input from external consultants and economists, as well as long-term inflation assumptions. Devon expects the long-term asset allocation to approximate the targeted allocation. Therefore, the expected long-term rate of return on plan assets is based on the target allocation of investment types. See the pension plan assets section below for more information on Devon’s target allocations.

Other assumptions – For measurement of the 2013 benefit obligation for the other postretirement medical plans, a 7.9 percent annual rate of increase in the per capita cost of covered health care benefits was assumed for 2014. The rate was assumed to decrease annually to an ultimate rate of 5 percent in the year 2029 and remain at that level thereafter. Assumed health care cost-trend rates affect the amounts reported for retiree health care costs. A one-percentage-point change in the assumed health care cost-trend rates would have changed the postretirement benefits obligation as of December 31, 2013, by less than $1 million and would change the 2014 service and interest cost components of net periodic benefit cost by less than $1 million.

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Pension Plan Assets

Devon’s overall investment objective for its pension plans’ assets is to achieve stability of the plans’ funded status while providing long-term growth of invested capital and income to ensure benefit payments can be funded when required. To assist in achieving this objective, Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing. Derivatives or other speculative investments considered high risk are generally prohibited. The following table presents Devon’s target allocation for its pension plan assets.

		December 31,
		2013				2012
Fixed income			70	%			70	%
Equity			20	%			20	%
Other			10	%			10	%

The fair values of Devon’s pension assets are presented by asset class in the following tables.

		As of December 31, 2013
										Fair Value Measurements Using:
		Actual Allocation				Total				Level 1 Inputs				Level 2 Inputs				Level 3 Inputs
		(In millions)
Fixed-income securities:
U.S. Treasury obligations			24.0	%		$	241			$	69			$	172			$	—
Corporate bonds			39.5	%			398				286				112				—
Other bonds			3.1	%			31				31				—				—
Total fixed-income securities			66.6	%			670				386				284				—
Equity securities:
Global (large, mid, small cap)			19.0	%			190				—				190				—
Other securities:
Hedge fund & alternative investments			12.5	%			127				15				—				112
Short-term investment funds			1.9	%			19				—				19				—
Total other securities			14.4	%			146				15				19				112
Total investments			100.0	%		$	1,006			$	401			$	493			$	112

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		As of December 31, 2012
										Fair Value Measurements Using:
		Actual Allocation				Total				Level 1 Inputs				Level 2 Inputs				Level 3 Inputs
		(In millions)
Fixed-income securities:
U.S. Treasury obligations			39.4	%		$	459			$	65			$	394			$	—
Corporate bonds			26.5	%			308				256				52				—
Other bonds			2.4	%			28				28				—				—
Total fixed-income securities			68.3	%			795				349				446				—
Equity securities:
Global (large, mid, small cap)			20.5	%			239				—				239				—
Other securities:
Hedge fund & alternative investments			10.3	%			120				17				—				103
Short-term investment funds			0.9	%			11				—				11				—
Total other securities			11.2	%			131				17				11				103
Total investments			100.0	%		$	1,165			$	366			$	696			$	103

The following methods and assumptions were used to estimate the fair values in the tables above.

Fixed-income securities – Devon’s fixed-income securities consist of United States Treasury obligations, bonds issued by investment-grade companies from diverse industries, and asset-backed securities. These fixed-income securities are actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices.

Devon’s fixed income securities also include commingled funds that primarily invest in long-term bonds and United States Treasury securities. These fixed income securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.

Equity securities – Devon’s equity securities include a commingled global equity fund that invests in large, mid and small capitalization stocks across the world’s developed and emerging markets. These equity securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.

Other securities – Devon’s other securities include commingled, short-term investment funds. These securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by investment managers.

Devon’s hedge fund and alternative investments include an investment in an actively traded global mutual fund that focuses on alternative investment strategies and a hedge fund of funds that invests both long and short using a variety of investment strategies. Devon’s hedge fund of funds is not actively traded and Devon is subject to redemption restrictions with regards to this investment. The fair value of this Level 3 investment represents the fair value as determined by the hedge fund manager.

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Included below is a summary of the changes in Devon’s Level 3 plan assets (in millions).

December 31, 2011		$	90
Purchases			6
Investment returns			7
December 31, 2012			103
Purchases			—
Investment returns			9
December 31, 2013		$	112

Expected Cash Flows

The following table presents expected cash flow information for Devon’s pension and postretirement benefit plans.

		Pension Benefits				Postretirement Benefits
		(In millions)
Devon’s 2014 contributions		$	12			$	3
Benefit payments:
2014		$	71			$	3
2015		$	74			$	3
2016		$	75			$	3
2017		$	78			$	3
2018		$	81			$	3
2019 to 2023		$	450			$	9

Expected contributions included in the table above include amounts related to Devon’s qualified plans, nonqualified plans and postretirement plans. Of the benefits expected to be paid in 2014, the $12 million of pension benefits is expected to be funded from the trusts established for the nonqualified plans and the $3 million of postretirement benefits is expected to be funded from Devon’s available cash and cash equivalents. Expected employer contributions and benefit payments for other postretirement benefits are presented net of employee contributions.

Defined Contribution Plans

Devon maintains several defined contribution plans covering its employees in the U.S. and Canada. Such plans include Devon’s 401(k) plan, enhanced contribution plan and Canadian pension and savings plan. Contributions are primarily based upon percentages of annual compensation and years of service. In addition, each plan is subject to regulatory limitations by each respective government. The following table presents Devon’s expense related to these defined contribution plans.

		Year Ended December 31,
		2013				2012				2011
		(In millions)
401(k) and enhanced contribution plans		$	41			$	36			$	33
Canadian pension and savings plans			26				23				21
Total		$	67			$	59			$	54

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17.	Stockholders’ Equity

The authorized capital stock of Devon consists of 1 billion shares of common stock, par value $0.10 per share, and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors.

Devon’s Board of Directors has designated 2.9 million shares of the preferred stock as Series A Junior Participating Preferred Stock (the “Series A Junior Preferred Stock”). At December 31, 2013, there were no shares of Series A Junior Preferred Stock issued or outstanding. The Series A Junior Preferred Stock is entitled to receive cumulative quarterly dividends per share equal to the greater of $1.00 or 100 times the aggregate per share amount of all dividends (other than stock dividends) declared on common stock since the immediately preceding quarterly dividend payment date or, with respect to the first payment date, since the first issuance of Series A Junior Preferred Stock. Holders of the Series A Junior Preferred Stock are entitled to 100 votes per share on all matters submitted to a vote of the stockholders. Devon, at its option, may redeem shares of the Series A Junior Participating Preferred Stock in whole at any time and in part from time to time, at a redemption price equal to 100 times the current per share market price of Devon’s common stock on the date of the mailing of the notice of redemption. The Series A Junior Preferred Stock ranks prior to the common stock but junior to all other classes of Preferred Stock.

Stock Repurchases

In the fourth quarter of 2011, Devon completed its 2010 repurchase program. In total, Devon repurchased 49.2 million shares for $3.5 billion, or $71.18 per share.

Dividends

Devon paid common stock dividends of $348 million, $324 million and $278 million in 2013, 2012 and 2011 respectively. The quarterly cash dividend was $0.16 per share in the first quarter of 2011. Devon increased the dividend rate to $0.17 per share in the second quarter of 2011 and further increased the dividend rate to $0.20 per share in the first quarter of 2012. Devon increased the dividend rate to $0.22 per share in the second quarter of 2013.

18.	Commitments and Contingencies

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

Royalty Matters

Numerous natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. The suits allege that the producers and related parties used below-market prices, made improper deductions, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in underpayment of royalties in connection with natural gas and NGLs produced and sold. Devon’s largest exposure for such matters relates to royalties in New Mexico. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.

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Environmental Matters

Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated uninsured remediation costs. Devon’s monetary exposure for environmental matters is not expected to be material.

Other Matters

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

Commitments

The following is a schedule by year of Devon’s commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2013.

Year Ending December 31,		Purchase Obligations				Drilling and Facility Obligations				Operational Agreements				Office and Equipment Leases
		(In millions)
2014		$	852			$	341			$	519			$	41
2015			874				18				477				38
2016			945				7				399				34
2017			871				—				388				33
2018			885				—				335				28
Thereafter			1,998				—				1,331				111
Total		$	6,425			$	366			$	3,449			$	285

Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at Devon’s heavy oil projects in Canada. Devon has entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in Devon’s ability to obtain condensate could negatively affect its ability to transport heavy oil at these locations. Devon’s total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and Devon’s internal estimate of future condensate market prices.

Devon has certain drilling and facility obligations under contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction.

Devon has certain operational agreements whereby Devon has committed to transport or process certain volumes of oil, gas and NGLs for a fixed fee. Devon has entered into these agreements to aid the movement of its production to downstream markets.

Devon leases certain office space and equipment under operating lease arrangements. Total rental expense included in general and administrative expenses under operating leases, net of sub-lease income, was $26 million, $42 million and $42 million in 2013, 2012 and 2011, respectively.

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19.	Fair Value Measurements

The following tables provide carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other payables and accrued expenses included in the accompanying balance sheets approximated fair value at December 31, 2013 and December 31, 2012. Therefore, such financial assets and liabilities are not presented in the following tables. Additionally, information regarding the fair values of Devon’s midstream and pension plan assets is provided in Note 4 and Note 16, respectively.

										Fair Value Measurements Using:
		Carrying Amount				Total Fair Value				Level 1 Inputs				Level 2 Inputs				Level 3 Inputs
		(In millions)
December 31, 2013 assets (liabilities):
Cash equivalents		$	5,305			$	5,305			$	4,191			$	1,114			$	—
Long-term investments		$	62			$	62			$	—			$	—			$	62
Commodity derivatives		$	103			$	103			$	—			$	103			$	—
Commodity derivatives		$	(120	)		$	(120	)		$	—			$	(120	)		$	—
Foreign currency derivatives		$	(1	)		$	(1	)		$	—			$	(1	)		$	—
Debt		$	(12,022	)		$	(12,908	)		$	—			$	(12,908	)		$	—
December 31, 2012 assets (liabilities):
Cash equivalents		$	4,149			$	4,149			$	32			$	4,117			$	—
Short-term investments		$	2,343			$	2,343			$	429			$	1,914			$	—
Long-term investments		$	64			$	64			$	—			$	—			$	64
Commodity derivatives		$	401			$	401			$	—			$	401			$	—
Commodity derivatives		$	(32	)		$	(32	)		$	—			$	(32	)		$	—
Interest rate derivatives		$	23			$	23			$	—			$	23			$	—
Foreign currency derivatives		$	1			$	1			$	—			$	1			$	—
Debt		$	(11,644	)		$	(13,435	)		$	—			$	(13,435	)		$	—

The following methods and assumptions were used to estimate the fair values in the tables above.

Level 1 Fair Value Measurements

Cash equivalents and short-term investments – Amounts consist primarily of United States and Canadian treasury securities and money market investments. The fair value approximates the carrying value.

Level 2 Fair Value Measurements

Cash equivalents and short-term investments – Amounts consist primarily of Canadian agency and provincial securities and commercial paper investments. The fair value approximates the carrying value.

Commodity, interest rate and foreign currency derivatives – The fair values of commodity, interest rate and foreign currency derivatives are estimated using internal discounted cash flow calculations based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.

Debt – Devon’s debt instruments do not actively trade in an established market. The fair values of its fixed-rate debt and floating-rate debt are estimated based on rates available for debt with similar terms and maturity. The fair value of Devon’s commercial paper and credit facility borrowings are the carrying values.

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Level 3 Fair Value Measurements

Long-term investments – Devon’s long-term investments presented in the tables above consisted entirely of auction rate securities. Due to auction failures and the lack of an active market for Devon’s auction rate securities, quoted market prices for these securities were not available. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair values of its long-term auction rate securities. These inputs were based on continued receipts of principal at par, the collection of all accrued interest to date, the probability of full repayment of the securities considering the United States government guarantees substantially all of the underlying student loans, and the AAA credit rating of the securities. As a result of using these inputs, Devon concluded the estimated fair values of its long-term auction rate securities approximated the par values as of December 31, 2013 and December 31, 2012.

Included below is a summary of the changes in Devon’s Level 3 fair value measurements.

		Year Ended December 31,
		2013				2012
		(In millions)
Long-term investments balance at beginning of period		$	64			$	84
Redemptions of principal			(2	)			(20	)
Long-term investments balance at end of period		$	62			$	64

20.	Discontinued Operations

Revenues related to Devon’s discontinued operations totaled $43 million during 2011. Devon did not have revenues related to its discontinued operations during 2013 or 2012. The following table presents the earnings (loss) from Devon’s discontinued operations.

		Year Ended December 31,
		2013				2012				2011
		(In millions)
Operating earnings		$	—			$	—			$	38
Gain (loss) on sale of oil and gas properties			—				(16	)			2,552
Earnings (loss) before income taxes			—				(16	)			2,590
Income tax expense			—				5				20
Earnings (loss) from discontinued operations		$	—			$	(21	)		$	2,570

21.	Segment Information

Devon manages its operations through distinct operating segments, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian operating segment is reported as a separate reporting segment primarily due to the significant differences between the U.S. and Canadian regulatory environments. Devon’s segments are all primarily engaged in oil and gas producing activities, and certain information regarding such activities for each segment is included in Note 22. Segment revenues are all from external customers.

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		U.S.				Canada				Total
		(In millions)
Year Ended December 31, 2013:
Oil, gas and NGL sales		$	5,964			$	2,558			$	8,522
Oil, gas and NGL derivatives		$	(197	)		$	6			$	(191	)
Marketing and midstream revenues		$	1,974			$	92			$	2,066
Depreciation, depletion and amortization		$	1,931			$	849			$	2,780
Interest expense		$	392			$	45			$	437
Asset impairments		$	1,133			$	843			$	1,976
Earnings (loss) from continuing operations before income taxes		$	646			$	(497	)		$	149
Income tax expense (benefit)		$	325			$	(156	)		$	169
Earnings (loss) from continuing operations		$	321			$	(341	)		$	(20	)
Property and equipment, net		$	19,969			$	8,478			$	28,447
Total assets		$	29,317			$	13,560			$	42,877
Capital expenditures		$	4,802			$	1,841			$	6,643
Year Ended December 31, 2012:
Oil, gas and NGL sales		$	4,679			$	2,474			$	7,153
Oil, gas and NGL derivatives		$	681			$	12			$	693
Marketing and midstream revenues		$	1,541			$	114			$	1,655
Depreciation, depletion and amortization		$	1,824			$	987			$	2,811
Interest expense		$	343			$	63			$	406
Asset impairments		$	1,861			$	163			$	2,024
Loss from continuing operations before income taxes		$	(263	)		$	(54	)		$	(317	)
Income tax benefit		$	(97	)		$	(35	)		$	(132	)
Loss from continuing operations		$	(166	)		$	(19	)		$	(185	)
Property and equipment, net		$	18,361			$	8,955			$	27,316
Total assets		$	24,256			$	19,070			$	43,326
Capital expenditures		$	6,511			$	1,963			$	8,474
Year Ended December 31, 2011:
Oil, gas and NGL sales		$	5,418			$	2,897			$	8,315
Oil, gas and NGL derivatives		$	881			$	—			$	881
Marketing and midstream revenues		$	2,050			$	199			$	2,249
Depreciation, depletion and amortization		$	1,439			$	809			$	2,248
Interest expense		$	204			$	148			$	352
Earnings from continuing operations before income taxes		$	3,477			$	813			$	4,290
Income tax expense		$	1,958			$	198			$	2,156
Earnings from continuing operations		$	1,519			$	615			$	2,134
Property and equipment, net		$	16,989			$	7,785			$	24,774
Total assets (1)		$	22,622			$	18,342			$	40,964
Capital expenditures		$	6,101			$	1,694			$	7,795

(1)	Amounts in the table above do not include assets held for sale related to Devon’s discontinued operations, which totaled $153 million in 2011.

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22.	Supplemental Information on Oil and Gas Operations (Unaudited)

Supplemental unaudited information regarding Devon’s oil and gas activities is presented in this note. The information is provided separately by country. Unless otherwise noted, this supplemental information excludes amounts for all periods presented related to Devon’s discontinued operations.

Costs Incurred

The following tables reflect the costs incurred in oil and gas property acquisition, exploration, and development activities.

		Year Ended December 31, 2013
		U.S.				Canada				Total
		(In millions)
Property acquisition costs:
Proved properties		$	19			$	3			$	22
Unproved properties			213				3				216
Exploration costs			443				152				595
Development costs			3,838				1,251				5,089
Costs incurred		$	4,513			$	1,409			$	5,922

		Year Ended December 31, 2012
		U.S.				Canada				Total
		(In millions)
Property acquisition costs:
Proved properties		$	2			$	71			$	73
Unproved properties			1,135				32				1,167
Exploration costs			351				315				666
Development costs			4,408				1,691				6,099
Costs incurred		$	5,896			$	2,109			$	8,005

		Year Ended December 31, 2011
		U.S.				Canada				Total
		(In millions)
Property acquisition costs:
Proved properties		$	34			$	14			$	48
Unproved properties			851				72				923
Exploration costs			272				282				554
Development costs			4,130				1,288				5,418
Costs incurred		$	5,287			$	1,656			$	6,943

Costs incurred in the tables above include additions and revisions to Devon’s asset retirement obligations. The proceeds received from our joint venture transactions at closing have not been netted against the costs incurred. At December 31, 2013, our partners’ remaining commitments to fund our future costs associated with these joint venture transactions totaled approximately $1.4 billion.

Pursuant to the full cost method of accounting, Devon capitalizes certain of its general and administrative expenses that are related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $368 million, $359 million and

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$337 million in the years 2013, 2012 and 2011, respectively. Also, Devon capitalizes interest costs incurred and attributable to unproved oil and gas properties and major development projects of oil and gas properties. Capitalized interest expenses, which are included in the costs shown in the preceding tables, were $42 million, $36 million and $45 million in the years 2013, 2012 and 2011, respectively.

Capitalized Costs

The following tables reflect the aggregate capitalized costs related to oil and gas activities.

		December 31, 2013
		U.S.				Canada				Total
		(In millions)
Proved properties		$	51,366			$	22,629			$	73,995
Unproved properties			1,277				1,514				2,791
Total oil & gas properties			52,643				24,143				76,786
Accumulated DD&A			(35,848	)			(16,613	)			(52,461	)
Net capitalized costs		$	16,795			$	7,530			$	24,325
		December 31, 2012
		U.S.				Canada				Total
		(In millions)
Proved properties		$	46,570			$	22,840			$	69,410
Unproved properties			1,703				1,605				3,308
Total oil & gas properties			48,273				24,445				72,718
Accumulated DD&A			(33,098	)			(16,039	)			(49,137	)
Net capitalized costs		$	15,175			$	8,406			$	23,581

The following is a summary of Devon’s oil and gas properties not subject to amortization as of December 31, 2013.

		Costs Incurred In
		2013				2012				2011				Prior to 2011				Total
		(In millions)
Acquisition costs		$	207			$	725			$	62			$	848			$	1,842
Exploration costs			226				129				118				30				503
Development costs			113				132				66				9				320
Capitalized interest			41				33				33				19				126
Total oil and gas properties not subject to amortization		$	587			$	1,019			$	279			$	906			$	2,791

Included in the $2.8 billion of oil and gas properties not subject to amortization are approximately $1.6 billion of costs that we deem significant for individual assessment. These costs relate to our investments in the Pike thermal oil project in Canada, the Mississippian-Woodford Trend in Oklahoma and a portion of our properties in the Permian Basin in Texas. Based on our development plans, we expect to begin including the Pike costs in the amortization computation in 2015 when we receive regulatory approval for the first phase of this project and subsequently begin recognizing the associated proved reserves. We are evaluating and developing the Mississippian-Woodford and Permian properties over the next 3 to 4 years. We expect to include the costs in the amortization computation as we complete our evaluation activities.

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Results of Operations

The following tables include revenues and expenses associated with Devon’s oil and gas producing activities. They do not include any allocation of Devon’s interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of Devon’s oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil, gas and NGL sales after deducting costs, including depreciation, depletion and amortization and after giving effect to permanent differences.

		Year Ended December 31, 2013
		U.S.				Canada				Total
		(In millions)
Oil, gas and NGL sales		$	5,964			$	2,558			$	8,522
Lease operating expenses			(1,257	)			(1,011	)			(2,268	)
General and administrative expenses			(125	)			(77	)			(202	)
Production and property taxes			(380	)			(59	)			(439	)
Depreciation, depletion and amortization			(1,640	)			(825	)			(2,465	)
Asset impairments			(1,110	)			(843	)			(1,953	)
Accretion of asset retirement obligations			(47	)			(64	)			(111	)
Income tax benefit (expense)			(510	)			88				(422	)
Results of operations		$	895			$	(233	)		$	662
Depreciation, depletion and amortization per Boe		$	8.69			$	12.87			$	9.75

		Year Ended December 31, 2012
		U.S.				Canada				Total
		(In millions)
Oil, gas and NGL sales		$	4,679			$	2,474			$	7,153
Lease operating expenses			(1,059	)			(1,015	)			(2,074	)
General and administrative expenses			(159	)			(137	)			(296	)
Production and property taxes			(340	)			(55	)			(395	)
Depreciation, depletion and amortization			(1,563	)			(963	)			(2,526	)
Asset impairments			(1,793	)			(163	)			(1,956	)
Accretion of asset retirement obligations			(40	)			(69	)			(109	)
Income tax benefit (expense)			99				(3	)			96
Results of operations		$	(176	)		$	69			$	(107	)
Depreciation, depletion and amortization per Boe		$	8.55			$	14.41			$	10.12

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

		Year Ended December 31, 2011
		U.S.				Canada				Total
		(In millions)
Oil, gas and NGL sales		$	5,418			$	2,897			$	8,315
Lease operating expenses			(925	)			(926	)			(1,851	)
General and administrative expenses			(132	)			(119	)			(251	)
Production and property taxes			(357	)			(45	)			(402	)
Depreciation, depletion and amortization			(1,201	)			(786	)			(1,987	)
Accretion of asset retirement obligations			(34	)			(57	)			(91	)
Income tax expense			(1,005	)			(250	)			(1,255	)
Results of operations		$	1,764			$	714			$	2,478
Depreciation, depletion and amortization per Boe		$	6.94			$	11.74			$	8.28

Proved Reserves

The following tables present Devon’s estimated proved reserves by product by country.

		Oil (MMBbls)
		U.S.				Canada				Total
Proved developed and undeveloped reserves:
December 31, 2010			148				93				241
Revisions due to prices			2				1				3
Revisions other than price			(1	)			(5	)			(6	)
Extensions and discoveries			36				6				42
Production			(17	)			(15	)			(32	)
December 31, 2011			168				80				248
Revisions due to prices			(1	)			(5	)			(6	)
Revisions other than price			(6	)			(2	)			(8	)
Extensions and discoveries			65				7				72
Production			(21	)			(15	)			(36	)
December 31, 2012			205				65				270
Revisions due to prices			1				(1	)			—
Revisions other than price			(18	)			—				(18	)
Extensions and discoveries			69				7				76
Purchase of reserves			1				—				1
Production			(28	)			(15	)			(43	)
Sale of reserves			(1	)			—				(1	)
December 31, 2013			229				56				285
Proved developed reserves as of:
December 31, 2010			131				82				213
December 31, 2011			146				73				219
December 31, 2012			166				62				228
December 31, 2013			194				56				250
Proved developed-producing reserves as of:
December 31, 2010			123				72				195
December 31, 2011			139				65				204
December 31, 2012			155				56				211
December 31, 2013			178				51				229
Proved undeveloped reserves as of:
December 31, 2010			17				11				28
December 31, 2011			22				7				29
December 31, 2012			39				3				42
December 31, 2013			35				—				35

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

		Bitumen (MMBbls)
		U.S.				Canada				Total
Proved developed and undeveloped reserves:
December 31, 2010			—				440				440
Revisions due to prices			—				(16	)			(16	)
Revisions other than price			—				16				16
Extensions and discoveries			—				30				30
Production			—				(13	)			(13	)
December 31, 2011			—				457				457
Revisions due to prices			—				14				14
Revisions other than price			—				7				7
Extensions and discoveries			—				67				67
Production			—				(17	)			(17	)
December 31, 2012			—				528				528
Revisions due to prices			—				(11	)			(11	)
Revisions other than price			—				16				16
Extensions and discoveries			—				38				38
Production			—				(19	)			(19	)
December 31, 2013			—				552				552
Proved developed reserves as of:
December 31, 2010			—				44				44
December 31, 2011			—				90				90
December 31, 2012			—				99				99
December 31, 2013			—				111				111
Proved developed-producing reserves as of:
December 31, 2010			—				44				44
December 31, 2011			—				90				90
December 31, 2012			—				99				99
December 31, 2013			—				111				111
Proved undeveloped reserves as of:
December 31, 2010			—				396				396
December 31, 2011			—				367				367
December 31, 2012			—				429				429
December 31, 2013			—				441				441

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

		Gas (Bcf)
		U.S.				Canada				Total
Proved developed and undeveloped reserves:
December 31, 2010			9,065				1,218				10,283
Revisions due to prices			(1	)			(60	)			(61	)
Revisions other than price			(243	)			(38	)			(281	)
Extensions and discoveries			1,410				58				1,468
Purchase of reserves			16				20				36
Production			(740	)			(213	)			(953	)
Sale of reserves			—				(6	)			(6	)
December 31, 2011			9,507				979				10,486
Revisions due to prices			(831	)			(99	)			(930	)
Revisions other than price			(287	)			(33	)			(320	)
Extensions and discoveries			1,124				34				1,158
Purchase of reserves			2				—				2
Production			(752	)			(186	)			(938	)
Sale of reserves			(1	)			(11	)			(12	)
December 31, 2012			8,762				684				9,446
Revisions due to prices			405				161				566
Revisions other than price			(299	)			67				(232	)
Extensions and discoveries			471				19				490
Purchase of reserves			1				—				1
Production			(709	)			(165	)			(874	)
Sale of reserves			(81	)			(8	)			(89	)
December 31, 2013			8,550				758				9,308
Proved developed reserves as of:
December 31, 2010			7,280				1,144				8,424
December 31, 2011			7,957				951				8,908
December 31, 2012			7,391				679				8,070
December 31, 2013			7,707				752				8,459
Proved developed-producing reserves as of:
December 31, 2010			6,702				1,031				7,733
December 31, 2011			7,409				862				8,271
December 31, 2012			7,091				624				7,715
December 31, 2013			7,425				680				8,105
Proved undeveloped reserves as of:
December 31, 2010			1,785				74				1,859
December 31, 2011			1,550				28				1,578
December 31, 2012			1,371				5				1,376
December 31, 2013			843				6				849

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

		Natural Gas Liquids (MMBbls)
		U.S.				Canada				Total
Proved developed and undeveloped reserves:
December 31, 2010			449				30				479
Revisions due to prices			4				(1	)			3
Revisions other than price			1				—				1
Extensions and discoveries			102				2				104
Purchase of reserves			2				—				2
Production			(33	)			(4	)			(37	)
December 31, 2011			525				27				552
Revisions due to prices			(19	)			(5	)			(24	)
Revisions other than price			(13	)			—				(13	)
Extensions and discoveries			114				2				116
Production			(36	)			(4	)			(40	)
December 31, 2012			571				20				591
Revisions due to prices			8				3				11
Revisions other than price			(50	)			3				(47	)
Extensions and discoveries			64				1				65
Production			(41	)			(4	)			(45	)
December 31, 2013			552				23				575
Proved developed reserves as of:
December 31, 2010			353				28				381
December 31, 2011			402				26				428
December 31, 2012			431				20				451
December 31, 2013			468				23				491
Proved developed-producing reserves as of:
December 31, 2010			318				26				344
December 31, 2011			372				24				396
December 31, 2012			406				19				425
December 31, 2013			442				21				463
Proved undeveloped reserves as of:
December 31, 2010			96				2				98
December 31, 2011			123				1				124
December 31, 2012			140				—				140
December 31, 2013			84				—				84

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

		Total (MMBoe) (1)
		U.S.				Canada				Total
Proved developed and undeveloped reserves:
December 31, 2010			2,107				766				2,873
Revisions due to prices			6				(27	)			(21	)
Revisions other than price			(41	)			6				(35	)
Extensions and discoveries			374				47				421
Purchase of reserves			5				3				8
Production			(173	)			(67	)			(240	)
Sale of reserves			—				(1	)			(1	)
December 31, 2011			2,278				727				3,005
Revisions due to prices			(159	)			(12	)			(171	)
Revisions other than price			(67	)			(1	)			(68	)
Extensions and discoveries			367				82				449
Production			(183	)			(67	)			(250	)
Sale of reserves			—				(2	)			(2	)
December 31, 2012			2,236				727				2,963
Revisions due to prices			76				18				94
Revisions other than price			(117	)			29				(88	)
Extensions and discoveries			212				49				261
Purchase of reserves			1				—				1
Production			(189	)			(64	)			(253	)
Sale of reserves			(14	)			(1	)			(15	)
December 31, 2013			2,205				758				2,963
Proved developed reserves as of:
December 31, 2010			1,696				346				2,042
December 31, 2011			1,875				348				2,223
December 31, 2012			1,829				294				2,123
December 31, 2013			1,947				315				2,262
Proved developed-producing reserves as of:
December 31, 2010			1,557				314				1,871
December 31, 2011			1,746				323				2,069
December 31, 2012			1,743				278				2,021
December 31, 2013			1,857				297				2,154
Proved undeveloped reserves as of:
December 31, 2010			411				420				831
December 31, 2011			403				379				782
December 31, 2012			407				433				840
December 31, 2013			258				443				701

(1)	Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Bitumen and natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Proved Undeveloped Reserves

The following table presents the changes in Devon’s total proved undeveloped reserves during 2013 (in MMBoe).

		U.S.				Canada				Total
Proved undeveloped reserves as of December 31, 2012			407				433				840
Extensions and discoveries			57				38				95
Revisions due to prices			1				(10	)			(9	)
Revisions other than price			(91	)			13				(78	)
Conversion to proved developed reserves			(116	)			(31	)			(147	)
Proved undeveloped reserves as of December 31, 2013			258				443				701

At December 31, 2013, Devon had 701 MMBoe of proved undeveloped reserves. This represents a 17 percent decrease as compared to 2012 and represents 24 percent of total proved reserves. Drilling and development activities increased Devon’s proved undeveloped reserves 95 MMBoe and resulted in the conversion of 147 MMBoe, or 18 percent, of the 2012 proved undeveloped reserves to proved developed reserves. Costs incurred related to the development and conversion of Devon’s proved undeveloped reserves were $1.9 billion for 2013. Additionally, revisions other than price decreased Devon’s proved undeveloped reserves 78 MMBoe primarily due to evaluations of certain U.S. onshore dry-gas areas, which Devon does not expect to develop in the next five years. The largest revisions relate to the dry-gas areas in the Cana-Woodford Shale in western Oklahoma, Carthage in east Texas and the Barnett Shale in north Texas.

A significant amount of Devon’s proved undeveloped reserves at the end of 2013 related to its Jackfish operations. At December 31, 2013 and 2012, Devon’s Jackfish proved undeveloped reserves were 441 MMBoe and 429 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their 35,000 barrel daily facility capacity. Processing plant capacity is controlled by factors such as total steam processing capacity, steam-oil ratios and air quality discharge permits. As a result, these reserves are classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends though the year 2031.

Price Revisions

2013 – Reserves increased 94 MMBoe primarily due to higher gas prices. Of this increase, 43 MMBoe related to the Barnett Shale and 19 MMBoe related to the Rocky Mountain area.

2012 – Reserves decreased 171 MMBoe primarily due to lower gas prices. Of this decrease, 100 MMBoe related to the Barnett Shale and 25 MMBoe related to the Rocky Mountain area.

2011 – Reserves decreased 21 MMBoe due to lower gas prices and higher oil prices. The higher oil prices increased Devon’s Canadian royalty burden, which reduced Devon’s oil reserves.

Revisions Other Than Price

Total revisions other than price for 2013, 2012 and 2011 primarily related to Devon’s evaluation of certain dry gas regions, with the largest revisions being made in the Cana-Woodford Shale, Barnett Shale and Carthage area.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Extensions and Discoveries

2013 – Of the 261 MMBoe of extensions and discoveries, 76 MMBoe related to the Permian Basin in west Texas and southeast New Mexico, 54 MMBoe related to the Barnett Shale, 42 MMBoe related to the Anadarko Basin, 38 MMBoe related to Jackfish in northeast Alberta, Canada and 32 MMBoe related to the Mississippian-Woodford Trend in north Oklahoma.

The 2013 extensions and discoveries included 175 MMBoe related to additions from Devon’s infill drilling activities, including 23 MMBoe at the Cana-Woodford Shale, 54 MMBoe at the Barnett Shale, 38 MMBoe at Jackfish, 33 MMBoe at the Permian Basin and 20 MMBoe at the Mississippian-Woodford Trend.

2012 – Of the 449 MMBoe of extensions and discoveries, 151 MMBoe related to the Cana-Woodford Shale, 95 MMBoe related to the Barnett Shale, 72 MMBoe related to the Permian Basin, 67 MMBoe related to Jackfish, 16 MMBoe related to the Rocky Mountain area and 18 MMBoe related to the Granite Wash area.

The 2012 extensions and discoveries included 229 MMBoe related to additions from Devon’s infill drilling activities, including 134 MMBoe at the Cana-Woodford Shale and 82 MMBoe at the Barnett Shale.

2011 – Of the 421 MMBoe of extensions and discoveries, 162 MMBoe related to the Cana-Woodford Shale, 115 MMBoe related to the Barnett Shale, 39 MMBoe related to the Permian Basin, 30 MMBoe related to Jackfish, 19 MMBoe related to the Rocky Mountain area and 17 MMBoe related to the Granite Wash area.

The 2011 extensions and discoveries included 168 MMBoe related to additions from Devon’s infill drilling activities, including 80 MMBoe at the Cana-Woodford Shale and 77 MMBoe at the Barnett Shale.

Standardized Measure

The tables below reflect Devon’s standardized measure of discounted future net cash flows from its proved reserves.

		Year Ended December 31, 2013
		U.S.				Canada				Total
		(In millions)
Future cash inflows		$	61,983			$	33,305			$	95,288
Future costs:
Development			(5,448	)			(5,308	)			(10,756	)
Production			(26,663	)			(15,709	)			(42,372	)
Future income tax expense			(9,046	)			(2,327	)			(11,373	)
Future net cash flow			20,826				9,961				30,787
10% discount to reflect timing of cash flows			(10,346	)			(4,700	)			(15,046	)
Standardized measure of discounted future net cash flows		$	10,480			$	5,261			$	15,741

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

		Year Ended December 31, 2012
		U.S.				Canada				Total
		(In millions)
Future cash inflows		$	55,297			$	33,570			$	88,867
Future costs:
Development			(6,556	)			(6,211	)			(12,767	)
Production			(24,265	)			(16,611	)			(40,876	)
Future income tax expense			(6,542	)			(1,992	)			(8,534	)
Future net cash flow			17,934				8,756				26,690
10% discount to reflect timing of cash flows			(9,036	)			(4,433	)			(13,469	)
Standardized measure of discounted future net cash flows		$	8,898			$	4,323			$	13,221

		Year Ended December 31, 2011
		U.S.				Canada				Total
		(In millions)
Future cash inflows		$	69,305			$	36,786			$	106,091
Future costs:
Development			(6,817	)			(4,678	)			(11,495	)
Production			(26,217	)			(15,063	)			(41,280	)
Future income tax expense			(11,432	)			(3,763	)			(15,195	)
Future net cash flow			24,839				13,282				38,121
10% discount to reflect timing of cash flows			(13,492	)			(6,785	)			(20,277	)
Standardized measure of discounted future net cash flows		$	11,347			$	6,497			$	17,844

Future cash inflows, development costs and production costs were computed using the same assumptions for prices and costs that were used to estimate Devon’s proved oil and gas reserves at the end of each year. For 2013 estimates, Devon’s future realized prices were assumed to be $88.19 per barrel of oil, $47.44 per barrel of bitumen, $3.10 per Mcf of gas and $26.28 per barrel of natural gas liquids. Of the $10.8 billion of future development costs as of the end of 2013, $1.9 billion, $1.5 billion and $0.7 billion are estimated to be spent in 2014, 2015 and 2016, respectively.

Future development costs include not only development costs, but also future asset retirement costs. Included as part of the $10.8 billion of future development costs are $2.7 billion of future asset retirement costs. The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The principal changes in Devon’s standardized measure of discounted future net cash flows are as follows:

		Year Ended December 31,
		2013				2012				2011
		(In millions)
Beginning balance		$	13,221			$	17,844			$	16,352
Net changes in prices and production costs			3,018				(9,889	)			1,875
Oil, bitumen, gas and NGL sales, net of production costs			(5,613	)			(4,388	)			(5,811	)
Changes in estimated future development costs			399				(1,094	)			(440	)
Extensions and discoveries, net of future development costs			4,047				4,669				3,714
Purchase of reserves			14				18				57
Sales of reserves in place			(44	)			(25	)			(2	)
Revisions of quantity estimates			(1,040	)			162				(228	)
Previously estimated development costs incurred during the period			1,986				1,321				1,302
Accretion of discount			1,940				1,420				2,248
Other, primarily changes in timing and foreign exchange rates			(583	)			113				(294	)
Net change in income taxes			(1,604	)			3,070				(929	)
Ending balance		$	15,741			$	13,221			$	17,844

23.	Supplemental Quarterly Financial Information (Unaudited)

Following is a summary of Devon’s unaudited interim results of operations.

		2013
		First Quarter				Second Quarter				Third Quarter				Fourth Quarter				Full Year
		(In millions, except per share amounts)
Operating revenues		$	1,971			$	3,088			$	2,714			$	2,624			$	10,397
Earnings (loss) before income taxes		$	(1,962	)		$	997			$	639			$	475			$	149
Net earnings (loss)		$	(1,339	)		$	683			$	429			$	207			$	(20	)
Basic net earnings (loss) per common share:
Net earnings (loss)		$	(3.34	)		$	1.69			$	1.06			$	0.51			$	(0.06	)
Diluted net earnings (loss) per common share:
Net earnings (loss)		$	(3.34	)		$	1.68			$	1.05			$	0.51			$	(0.06	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

		2012
		First Quarter				Second Quarter				Third Quarter				Fourth Quarter				Full Year
		(In millions, except per share amounts)
Operating revenues		$	2,495			$	2,561			$	1,865			$	2,580			$	9,501
Earnings (loss) from continuing operations before income taxes		$	611			$	734			$	(1,161	)		$	(501	)		$	(317	)
Earnings (loss) from continuing operations		$	414			$	477			$	(719	)		$	(357	)		$	(185	)
Loss from discontinued operations			(21	)			—				—				—				(21	)
Net earnings (loss)		$	393			$	477			$	(719	)		$	(357	)		$	(206	)
Basic net earnings (loss) per common share:
Earnings (loss) from continuing operations		$	1.03			$	1.18			$	(1.80	)		$	(0.89	)		$	(0.47	)
Loss from discontinued operations			(0.06	)			—				—				—				(0.05	)
Net earnings (loss)		$	0.97			$	1.18			$	(1.80	)		$	(0.89	)		$	(0.52	)
Diluted net earnings (loss) per common share:
Earnings (loss) from continuing operations		$	1.03			$	1.18			$	(1.80	)		$	(0.89	)		$	(0.47	)
Loss from discontinued operations			(0.06	)			—				—				—				(0.05	)
Net earnings (loss)		$	0.97			$	1.18			$	(1.80	)		$	(0.89	)		$	(0.52	)

Earnings (Loss) from Continuing Operations

The first quarter of 2013 includes U.S. and Canadian asset impairments totaling $1.9 billion ($1.3 billion after income taxes, or $3.25 per diluted share).

The fourth quarter of 2012 includes U.S. and Canadian asset impairments totaling $0.9 billion ($0.6 billion after income taxes, or $1.46 per diluted share).

The third quarter of 2012 includes U.S. asset impairments totaling $1.1 billion ($0.7 billion after income taxes, or $1.78 per diluted share).

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