Edgar Filing: DEVON ENERGY CORP/DE

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2014

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

Commission File Number 001-32318

DEVON ENERGY CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		73-1567067
(State of other jurisdiction of incorporation or organization)		(I.R.S. Employer identification No.)

333 West Sheridan Avenue, Oklahoma City, Oklahoma		73102-5015
(Address of principal executive offices)		(Zip code)

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

Former name, address and former fiscal year, if changed from last report: Not applicable

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

On October 22, 2014, 409.1 million shares of common stock were outstanding.

DEVON ENERGY CORPORATION

FORM 10-Q

TABLE OF CONTENTS


Part I. Financial Information			3
Item 1. Financial Statements			3
Consolidated Comprehensive Statements of Earnings			3
Consolidated Statements of Cash Flows			4
Consolidated Balance Sheets			5
Consolidated Statements of Stockholders’ Equity			6
Notes to Consolidated Financial Statements			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			28
Item 3. Quantitative and Qualitative Disclosures About Market Risk			44
Item 4. Controls and Procedures			44

Part II. Other Information			46
Item 1. Legal Proceedings			46
Item 1A. Risk Factors			46
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			46
Item 3. Defaults Upon Senior Securities			46
Item 4. Mine Safety Disclosures			46
Item 5. Other Information			46
Item 6. Exhibits			47

Signatures			48

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This report includes “forward-looking statements” as defined by the United States Securities and Exchange Commission (“SEC”). Such statements are those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare our December 31, 2013 reserve reports and other data in our possession or available from third parties. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, such as changes in the supply of and demand for oil, natural gas and natural gas liquids (“NGLs”) and related products and services; exploration or drilling programs; our ability to successfully complete mergers, acquisitions and divestitures; political or regulatory events; general economic and financial market conditions; and other risks and factors discussed in this report.

All subsequent written and oral forward-looking statements attributable to Devon Energy Corporation, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We assume no duty to update or revise our forward-looking statements based on new information, future events or otherwise.

Part I. Financial Information

Item 1. Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(Unaudited)
	(In millions, except per share amounts)

Oil, gas and NGL sales	$	2,588		$	2,341		$	7,824		$	6,367
Oil, gas and NGL derivatives		748			(141	)		29			(95	)
Marketing and midstream revenues		2,000			514			5,718			1,501

Total operating revenues		5,336			2,714			13,571			7,773

Lease operating expenses		584			600			1,764			1,684
Marketing and midstream operating expenses		1,781			383			5,092			1,128
General and administrative expenses		195			143			595			460
Production and property taxes		140			115			427			353
Depreciation, depletion and amortization		842			691			2,409			2,069
Asset impairments		—			7			—			1,960
Restructuring costs		2			4			44			50
Gains and losses on asset sales		—			11			(1,072	)		11
Other operating items		18			27			74			82

Total operating expenses		3,562			1,981			9,333			7,797

Operating income (loss)		1,774			733			4,238			(24	)
Net financing costs		116			100			359			306
Other nonoperating items		4			(6	)		111			(4	)

Earnings (loss) before income taxes		1,654			639			3,768			(326	)
Income tax expense (benefit)		613			210			1,698			(99	)

Net earnings (loss)		1,041			429			2,070			(227	)
Net earnings attributable to noncontrolling interests		25			—			55			—

Net earnings (loss) attributable to Devon	$	1,016		$	429		$	2,015		$	(227	)


Net earnings (loss) per share attributable to Devon:
Basic	$	2.48		$	1.06		$	4.94		$	(0.57	)
Diluted	$	2.47		$	1.05		$	4.91		$	(0.57	)

Comprehensive earnings (loss):
Net earnings (loss)	$	1,041		$	429		$	2,070		$	(227	)
Other comprehensive earnings (loss), net of tax:
Foreign currency translation		(279	)		173			(285	)		(281	)
Pension and postretirement plans		2			3			10			12

Other comprehensive earnings (loss), net of tax		(277	)		176			(275	)		(269	)

Comprehensive earnings (loss)		764			605			1,795			(496	)
Comprehensive earnings attributable to noncontrolling interests		25			—			55			—

Comprehensive earnings (loss) attributable to Devon	$	739		$	605		$	1,740		$	(496	)

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended September 30,
	2014			2013
	(Unaudited) (In millions)
Cash flows from operating activities:
Net earnings (loss)	$	2,070		$	(227	)
Adjustments to reconcile net earnings (loss) to net cash from operating activities:
Depreciation, depletion and amortization		2,409			2,069
Gains and losses on asset sales		(1,072	)		11
Asset impairments		—			1,960
Deferred income tax expense (benefit)		800			(181	)
Derivatives and other financial instruments		(43	)		65
Cash settlements on derivatives and financial instruments		(201	)		147
Other noncash charges		357			195
Net change in working capital		766			(104	)
Change in long-term other assets		(115	)		(28	)
Change in long-term other liabilities		47			92

Net cash from operating activities		5,018			3,999


Cash flows from investing activities:
Acquisitions of property, equipment and businesses		(6,255	)		—
Capital expenditures		(5,013	)		(5,219	)
Proceeds from property and equipment divestitures		5,202			316
Purchases of short-term investments		—			(1,076	)
Redemptions of short-term investments		—			3,419
Redemptions of long-term investments		57			—
Other		87			83

Net cash from investing activities		(5,922	)		(2,477	)


Cash flows from financing activities:
Proceeds from borrowings of long-term debt, net of issuance costs		4,158			—
Net short-term debt repayments		(1,318	)		(1,577	)
Long-term debt repayments		(4,265	)		—
Proceeds from stock option exercises		92			1
Proceeds from issuance of subsidiary units		72			—
Dividends paid on common stock		(287	)		(259	)
Distributions to noncontrolling interests		(187	)		—
Other		(4	)		5

Net cash from financing activities		(1,739	)		(1,830	)

Effect of exchange rate changes on cash		(15	)		(9	)

Net change in cash and cash equivalents		(2,658	)		(317	)

Cash and cash equivalents at beginning of period		6,066			4,637


Cash and cash equivalents at end of period	$	3,408		$	4,320

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	September 30, 2014			December 31, 2013
	(Unaudited)
	(In millions, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	3,408		$	6,066
Accounts receivable		2,009			1,520
Other current assets		556			419

Total current assets		5,973			8,005

Property and equipment, at cost:
Oil and gas, based on full-cost accounting:
Subject to amortization		73,733			73,995
Not subject to amortization		3,642			2,791

Total oil and gas		77,375			76,786
Other		9,204			6,195

Total property and equipment, at cost		86,579			82,981
Less accumulated depreciation, depletion and amortization		(51,410	)		(54,534	)

Property and equipment, net		35,169			28,447

Goodwill		8,310			5,858
Other long-term assets		1,387			567

Total assets	$	50,839		$	42,877


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,344		$	1,229
Revenues and royalties payable		1,455			786
Short-term debt		1,898			4,066
Income taxes payable		651			1
Other current liabilities		646			573

Total current liabilities		5,994			6,655

Long-term debt		10,161			7,956
Asset retirement obligations		1,348			2,140
Other long-term liabilities		926			834
Deferred income taxes		5,642			4,793
Stockholders’ equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 409 million and 406 million shares in 2014 and 2013, respectively		41			41
Additional paid-in capital		4,004			3,780
Retained earnings		17,138			15,410
Accumulated other comprehensive earnings		993			1,268

Total stockholders’ equity attributable to Devon		22,176			20,499
Noncontrolling interests		4,592			—

Total stockholders’ equity		26,768			20,499

Commitments and contingencies (Note 17)
Total liabilities and stockholders’ equity	$	50,839		$	42,877

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY


	Common Stock				Additional Paid-In			Retained			Accumulated Other Comprehensive			Treasury			Noncontrolling			Total Stockholders’
	Shares		Amount		Capital			Earnings			Earnings			Stock			Interests			Equity
	(Unaudited)
	(In millions)
Nine Months Ended September 30, 2014
Balance as of December 31, 2013		406	$	41	$	3,780		$	15,410		$	1,268		$	—		$	—		$	20,499
Net earnings		—		—		—			2,015			—			—			55			2,070
Other comprehensive loss, net of tax		—		—		—			—			(275	)		—			—			(275	)
Stock option exercises		1		—		92			—			—			—			—			92
Restricted stock grants, net of cancellations		2		—		—			—			—			—			—			—
Common stock repurchased		—		—		—			—			—			(6	)		—			(6	)
Common stock retired		—		—		(6	)		—			—			6			—			—
Common stock dividends		—		—		—			(287	)		—			—			—			(287	)
Share-based compensation		—		—		120			—			—			—			—			120
Share-based compensation tax benefits		—		—		1			—			—			—			—			1
Acquisition of noncontrolling interests		—		—		—			—			—			—			4,664			4,664
Subsidiary equity transactions		—		—		17			—			—			—			55			72
Distributions to noncontrolling interests		—		—		—			—			—			—			(187	)		(187	)
Other		—		—		—			—			—			—			5			5

Balance as of September 30, 2014		409	$	41	$	4,004		$	17,138		$	993		$	—		$	4,592		$	26,768


Nine Months Ended September 30, 2013
Balance as of December 31, 2012		406	$	41	$	3,688		$	15,778		$	1,771		$	—		$	—		$	21,278
Net loss		—		—		—			(227	)		—			—			—			(227	)
Other comprehensive loss, net of tax		—		—		—			—			(269	)		—			—			(269	)
Stock option exercises		—		—		1			—			—			—			—			1
Common stock repurchased		—		—		—			—			—			(9	)		—			(9	)
Common stock retired		—		—		(9	)		—			—			9			—			—
Common stock dividends		—		—		—			(259	)		—			—			—			(259	)
Share-based compensation		—		—		92			—			—			—			—			92
Share-based compensation tax benefits		—		—		5			—			—			—			—			5

Balance as of September 30, 2013		406	$	41	$	3,777		$	15,292		$	1,502		$	—		$	—		$	20,612

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.	Summary of Significant Accounting Policies

The accompanying unaudited financial statements and notes of Devon Energy Corporation (“Devon”) have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“U.S.”) have been omitted. The accompanying financial statements and notes should be read in conjunction with the financial statements and notes included in Devon’s 2013 Annual Report on Form 10-K.

The accompanying unaudited interim financial statements furnished in this report reflect all adjustments that are, in the opinion of management, necessary for a fair statement of Devon’s results of operations and cash flows for the three-month and nine-month periods ended September 30, 2014 and 2013 and Devon’s financial position as of September 30, 2014.

Basis of Presentation

The accompanying consolidated financial statements include the accounts of Devon and entities in which it holds a controlling interest. All intercompany transactions have been eliminated. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities, over which Devon has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for Devon’s proportionate share of earnings, losses and distributions. Investments accounted for using the equity method and cost method are reported as a component of other long-term assets.

As discussed more fully in Note 2, on March 7, 2014, Devon completed a business combination whereby Devon controls both EnLink Midstream Partners, LP (the “Partnership”) and its general partner entity, EnLink Midstream, LLC (“EnLink”). Devon controls both the Partnership’s and EnLink’s operations; therefore, the Partnership’s and EnLink’s accounts are included in Devon’s accompanying consolidated financial statements subsequent to the completion of the transaction. The portions of the Partnership’s and EnLink’s net earnings and stockholders’ equity not attributable to Devon’s controlling interest are shown separately as noncontrolling interests in the accompanying consolidated comprehensive statements of earnings and consolidated balance sheets.

Intangible Assets

EnLink’s long-term assets include intangible assets, consisting of customer relationships. These assets are amortized on a straight-line basis over the expected periods of benefits, which range from ten to twenty years.

Recently Issued Accounting Standards Not Yet Adopted

In May 2014, the FASB issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606). The update provides guidance concerning the recognition and measurement of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The update is effective for Devon beginning on January 1, 2017. The standard permits the use of either the retrospective or cumulative effect transition method. Devon has not yet selected a transition method and is evaluating the impact this standard will have on its consolidated financial statements and related disclosures.

2.	Acquisitions and Divestitures

Formation of EnLink Midstream, LLC and EnLink Midstream Partners, LP

On March 7, 2014, Devon, Crosstex Energy, Inc. and Crosstex Energy, LP (together with Crosstex Energy, Inc., “Crosstex”) completed a business combination to combine substantially all of Devon’s U.S. midstream assets with Crosstex’s assets to form a new midstream business. The new business consists of the Partnership and EnLink, a master limited partnership and a general partner entity, respectively, which are both publicly traded entities.

In exchange for a controlling interest in both EnLink and the Partnership, Devon contributed its equity interest in a newly formed Devon subsidiary, EnLink Midstream Holdings, LP (“EnLink Holdings”) and $100 million in cash. EnLink Holdings owns 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 each own 50 percent of EnLink Holdings.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The ownership of EnLink is approximately:

•

70% - Devon

•

30% - Public unitholders

The ownership of the Partnership is approximately:

•

52% - Devon

•

41% - Public unitholders

•

7% - EnLink

This business combination was accounted for using the acquisition method of accounting. Under the acquisition method of accounting, EnLink Holdings was the accounting acquirer because its parent company, Devon, obtained control of EnLink and the Partnership as a result of the business combination. Consequently, EnLink Holdings’ assets and liabilities retained their carrying values. Additionally, the Crosstex assets acquired and liabilities assumed by the Partnership and EnLink in the business combination, as well as EnLink’s noncontrolling interest in the Partnership, were recorded at their fair values which were measured as of the acquisition date, March 7, 2014. The excess of the purchase price over the estimated fair values of Crosstex’s net assets acquired was recorded as goodwill.

The following table summarizes the purchase price (in millions, except unit price).


Crosstex Energy, Inc. outstanding common shares:
Held by public shareholders		48.0
Restricted shares		0.4

Total subject to conversion		48.4
Exchange ratio		1.0x

Converted shares		48.4
Crosstex Energy, Inc. common share price ⁽¹⁾	$	37.60

Crosstex Energy, Inc. consideration	$	1,823
Fair value of noncontrolling interests in E2 ⁽²⁾	$	12

Total Crosstex Energy, Inc. consideration and fair value of noncontrolling interests	$	1,835

Partnership outstanding units:
Common units held by public unitholders		75.1
Preferred units held by third party⁽³⁾		17.1
Restricted units		0.4

Total		92.6
Partnership common unit price⁽⁴⁾	$	30.51

Partnership common units value	$	2,825
Partnership outstanding unit options value	$	4

Total fair value of noncontrolling interests in the Partnership⁽⁴⁾	$	2,829

Total consideration and fair value of noncontrolling interests	$	4,664

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(1)	The final purchase price is based on the fair value of Crosstex Energy Inc.’s common shares as of the closing date, March 7, 2014.

(2)	Represents the value of noncontrolling interests related to EnLink’s equity investment in E2 Energy Services, LLC and E2 Appalachian Compression, LLC (collectively “E2”).

(3)	The Partnership converted the preferred units to common units in February 2014.

(4)	The final purchase price is based on the fair value of the Partnership’s common shares as of the closing date, March 7, 2014.

The preliminary allocation of the purchase price is as follows (in millions):


Assets acquired:
Current assets	$	438
Property, plant and equipment, net		2,438
Intangible assets		547
Equity investment		222
Goodwill⁽¹⁾		3,292
Other long term assets		1
Liabilities assumed:
Current liabilities		(516	)
Long-term debt		(1,454	)
Deferred income taxes		(203	)
Other long-term liabilities		(101	)

Total consideration and fair value of noncontrolling interests	$	4,664

(1)

Goodwill is the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill is not amortized and is not deductible for tax purposes.

GeoSouthern Energy Acquisition

On November 20, 2013, Devon entered into a Purchase and Sale Agreement with GeoSouthern Energy Corporation (“GeoSouthern”) and a wholly owned subsidiary of GeoSouthern to acquire GeoSouthern’s interests in certain affiliates (the “Acquired Companies”) that own certain oil and gas properties, leasehold mineral interest and related assets located in the Eagle Ford Shale. On February 28, 2014, the GeoSouthern acquisition closed, and GeoSouthern transferred the Acquired Companies to Devon in exchange for the aggregate purchase price of approximately $6.0 billion. Devon funded the acquisition price with cash on hand and debt financing. In connection with the GeoSouthern acquisition, Devon acquired approximately 82,000 net acres located in DeWitt and Lavaca counties in south Texas. The transaction was accounted for using the acquisition method, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The following table summarizes the preliminary allocation of the purchase price to the assets acquired and liabilities assumed in the transaction (in millions).


Cash and cash equivalents	$	95
Other current assets		256
Proved properties		5,029
Unproved properties		1,008
Midstream assets		85
Current liabilities		(437	)
Long-term liabilities		(6	)

Net assets acquired	$	6,030

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

EnLink and GeoSouthern Operating Results

The following table presents EnLink’s (acquired Crosstex operations) and GeoSouthern’s operating revenues and net earnings included in Devon’s consolidated statements of earnings subsequent to the transactions described above.


	Three Months Ended September 30, 2014				Nine Months Ended September 30, 2014
	GeoSouthern		EnLink		GeoSouthern		EnLink
	(In millions)				(In millions)
Total operating revenues	$	634	$	700	$	1,374	$	1,670
Total operating expenses		322		692		708		1,654

Operating income	$	312	$	8	$	666	$	16

Pro Forma Financial Information

The following unaudited pro forma financial information has been prepared assuming both the EnLink formation and the GeoSouthern acquisition occurred on January 1, 2013. The pro forma information is not intended to reflect the actual results of operations that would have occurred if the business combination and acquisition had been completed at the dates indicated. In addition, they do not project Devon’s results of operations for any future period.


	Nine Months Ended September 30,
	2014		2013
	(In millions)
Total operating revenues	$	14,218	$	9,603

Net earnings (loss)	$	2,109	$	(192	)
Noncontrolling interests	$	68	$	32
Net earnings (loss) attributable to Devon	$	2,041	$	(224	)
Net earnings (loss) per common share attributable to Devon	$	4.98	$	(0.55	)

Partnership Acquisitions and Dropdowns

Effective November 1, 2014, the Partnership acquired Gulf Coast natural pipeline assets predominantly located in southern Louisiana for $235 million, subject to certain adjustments. Furthermore, in October 2014, the Partnership acquired equity interests in E2 Appalachian Compression, LLC and E2 Energy Services, LLC (together “E2”) from EnLink. The total consideration for the transaction was approximately $193 million, including a $163 million cash payment and 1.0 million Partnership units valued at $30 million based on the fair value of the Partnership’s units as of the closing date of the transaction.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Non-Core Asset Divestitures

In November 2013, Devon announced plans to divest certain non-core properties located throughout Canada and the U.S.

Canada

In the first quarter of 2014, Devon completed minor divestiture transactions for $142 million ($155 million Canadian dollars). In the second quarter of 2014, Devon sold conventional assets to Canadian Natural Resources Limited for $2.8 billion ($3.125 billion Canadian dollars).

Under full-cost accounting rules, sales or dispositions of oil and gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of gain or loss. However, if not recognizing a gain or loss on the disposition would otherwise significantly alter the relationship between a cost center’s capitalized costs and proved reserves, then a gain or loss must be recognized. The Canadian divestitures significantly altered such relationship. Therefore, Devon recognized gains totaling $1.1 billion ($0.6 billion after-tax) in 2014 associated with these transactions. These gains are included as a separate item in the accompanying consolidated comprehensive statements of earnings.

Included in the gain calculation noted above were asset retirement obligations of approximately $700 million assumed by the purchaser as well as the derecognition of approximately $700 million of goodwill allocated to the sold assets.

In conjunction with the divestitures noted above, Devon repatriated approximately $2.8 billion of proceeds to the U.S. in the second quarter of 2014. The proceeds were used to repay $0.7 billion of commercial paper and the $2.0 billion term loans that were drawn in the first quarter of 2014 to fund a portion of the GeoSouthern acquisition. Between collecting the divestiture proceeds and repatriating funds to the U.S., Devon recognized an $84 million foreign currency exchange loss and a $29 million foreign currency derivative loss. These losses are included in other nonoperating items in the accompanying consolidated comprehensive statements of earnings.

U.S.

On August 29, 2014, Devon sold its U.S. non-core assets to LINN Energy for $2.3 billion ($1.7 billion after-tax proceeds). Additionally, approximately $200 million of asset retirement obligations were assumed by LINN Energy. No gain or loss was recognized on the sale.

3.	Derivative Financial Instruments

Objectives and Strategies

Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility and typically include financial price swaps, basis swaps, costless price collars and call options. Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon periodically enters into foreign exchange forward contracts to manage its exposure to fluctuations in exchange rates. Additionally, EnLink manages its exposure to fluctuations in commodity prices by hedging the impact of market fluctuations.

Devon does not intend to hold or issue derivative financial instruments for speculative trading purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment.

Counterparty Credit Risk

By using derivative financial instruments, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are acceptable credit risks. It is Devon’s policy to enter into derivative contracts only with investment grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts contain provisions that provide for collateral payments, depending on levels of exposure and the credit rating of the counterparty.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

As of September 30, 2014, Devon held $31 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.

Commodity Derivatives

As of September 30, 2014, Devon had the following open oil derivative positions. The first table presents Devon’s oil derivatives that settle against the average of the prompt month NYMEX West Texas Intermediate futures price. The second table presents Devon’s oil derivatives that settle against the Western Canadian Select index.


	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)
Q4 2014		75,000	$	94.14		64,750	$	89.33	$	100.00		42,000	$	116.43
Q1-Q4 2015		106,736	$	91.22		31,500	$	89.67	$	97.84		28,000	$	116.43
Q1-Q4 2016		—	$	—		—	$	—	$	—		18,500	$	103.11


	Oil Basis Swaps
Period	Index	Volume (Bbls/d)		Weighted Average Differential to WTI ($/Bbl)
Q4 2014	Western Canadian Select		50,000	$	(17.40	)
Q1-Q4 2015	Western Canadian Select		14,890	$	(18.92	)

As of September 30, 2014, 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 and PEPL indices.


	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)
Q4 2014		800,000	$	4.42		460,000	$	4.03	$	4.51		500,000	$	5.00
Q1-Q4 2015		210,000	$	4.38		260,000	$	4.05	$	4.36		550,000	$	5.09
Q1-Q4 2016		—	$	—		—	$	—	$	—		400,000	$	5.00


	Natural Gas Basis Swaps
Period	Index	Volume (MMBtu/d)		Weighted Average Differential to Henry Hub ($/MMBtu)
Q4 2014	AECO		94,781	$	(0.52	)
Q1-Q4 2015	PEPL		100,000	$	(0.28	)

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Interest Rate Derivatives

As of September 30, 2014, Devon had the following open interest rate derivative positions:


Notional		Rate Received	Rate Paid	Expiration
(In millions)
$	100	Three Month LIBOR	0.92%	December 2016
$	100	1.76%	Three Month LIBOR	January 2019

Foreign Currency Derivatives

As of September 30, 2014, Devon had the following open foreign currency derivative positions:

Forward Contract

Currency

Contract Type

CAD Notional

Weighted
Average
Fixed Rate
Received

Expiration

(In millions)

(CAD-USD)

Canadian Dollar

Sell

1,312

0.899

December 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.


	Comprehensive Statements of Earnings Caption	Three Months Ended September 30,					Nine Months Ended September 30,
	Comprehensive Statements of Earnings Caption	2014		2013			2014			2013
		(In millions)
Commodity derivatives	Oil, gas and NGL derivatives	$	748	$	(141	)	$	29		$	(95	)
EnLink commodity derivatives	Marketing and midstream revenues		1		—			(2	)		—
Interest rate derivatives	Other nonoperating items		—		1			1			1
Foreign currency derivatives	Other nonoperating items		55		(28	)		15			29

Net gains (losses) recognized in comprehensive statements of earnings		$	804	$	(168	)	$	43		$	(65	)

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


	Balance Sheet Caption	September 30, 2014		December 31, 2013
		(In millions)
Asset derivatives:
Commodity derivatives	Other current assets	$	231	$	75
Commodity derivatives	Other long-term assets		66		28
EnLink commodity derivatives	Other current assets		1		—
Interest rate derivatives	Other current assets		1		—
Foreign currency derivatives	Other current assets		11		—

Total asset derivatives		$	310	$	103

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


	Balance Sheet Caption	September 30, 2014		December 31, 2013
		(In millions)
Liability derivatives:
Commodity derivatives	Other current liabilities	$	30	$	58
Commodity derivatives	Other long-term liabilities		50		62
EnLink commodity derivatives	Other current liabilities		1		—
EnLink commodity derivatives	Other long-term liabilities		1		—
Interest rate derivatives	Other current liabilities		1		—
Interest rate derivatives	Other long-term liabilities		1		—
Foreign currency derivatives	Other current liabilities		—		1

Total liability derivatives		$	84	$	121

4.	Share-Based Compensation

The following table presents the effects of share-based compensation included in Devon’s accompanying comprehensive statements of earnings. Devon’s gross general and administrative expense for the first nine months of 2014 includes $11 million of unit-based compensation related to grants made under EnLink’s long-term incentive plans.

The vesting for certain share-based awards was accelerated in the first quarter of 2014 in conjunction with the divestiture of Devon’s Canadian conventional assets. 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.


	Nine Months Ended September 30,
	2014		2013
	(In millions)
Gross general and administrative expense	$	155	$	118
Share-based compensation expense capitalized pursuant to the full-cost method of accounting for oil and gas properties	$	40	$	44
Related income tax benefit	$	20	$	17

Under its 2009 Long-Term Incentive Plan, as amended, Devon granted share-based awards to certain employees in the first nine months of 2014. The following sections include information related to these awards.

Restricted Stock Awards and Units

The following table presents a summary of Devon’s unvested restricted stock awards and units.


	Restricted Stock Award & Units			Weighted Average Grant-Date Fair Value
	(In thousands)
Unvested at December 31, 2013		3,292		$	59.76
Granted		3,412		$	63.53
Vested		(558	)	$	60.65
Forfeited		(607	)	$	60.96

Unvested at September 30, 2014		5,539		$	61.73

As of September 30, 2014, Devon’s unrecognized compensation cost related to unvested restricted stock awards and units was $225 million. Such cost is expected to be recognized over a weighted-average period of 2.4 years.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Performance Based Restricted Stock Awards

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, 2013		316		$	56.25
Granted		234		$	61.33
Vested		(75	)	$	53.45

Unvested at September 30, 2014		475		$	59.20

As of September 30, 2014, Devon’s unrecognized compensation cost related to these awards was $7 million. Such cost is expected to be recognized over a weighted-average period of 1.4 years.

Performance Share Units

The following table presents a summary of the grant-date fair values of performance share units granted in 2014 and the related assumptions.


	2014
Grant-date fair value	$	70.18 - $81.05
Risk-free interest rate		0.54	%
Volatility factor		28.8	%
Contractual term (in years)		2.89

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, 2013		925		$	66.64
Granted		708		$	77.77
Forfeited		(147	)	$	77.25

Unvested at September 30, 2014 ⁽¹⁾		1,486		$	70.89

(1)	A maximum of 3.0 million common shares could be awarded based upon Devon’s final total shareholder return ranking.

As of September 30, 2014, Devon’s unrecognized compensation cost related to unvested units was $40 million. Such cost is expected to be recognized over a weighted-average period of 1.6 years.

5.	Asset Impairments

In the first nine months of 2013, Devon recognized asset impairments related to its oil and gas property and equipment as presented below.


	Nine Months Ended September 30, 2013
	Gross		Net of Taxes
	(In millions)
U.S. oil and gas assets	$	1,110	$	707
Canada oil and gas assets		843		632
Midstream assets		7		4

Total asset impairments	$	1,960	$	1,343

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Oil and Gas Impairments

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. 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.

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, bitumen and NGLs, which reduced proved reserve values.

Midstream Impairments

In the third quarter of 2013, Devon determined that the carrying amounts of certain midstream facilities located in south and east Texas were not recoverable from estimated future cash flows due to declining natural gas production. 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.

6.	Restructuring Costs

Canadian Divestitures

In the first nine months of 2014, Devon recognized $44 million of employee related and other costs associated with its Canadian non-core asset divestitures. Approximately $15 million of the employee related costs resulted from accelerated vesting of share-based grants, which are non-cash charges.

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 headquarters in Oklahoma City. As of December 31, 2013, Devon had completed this initiative and incurred $134 million of restructuring costs associated with the office consolidation.

Financial Statement Presentation

The schedule below summarizes restructuring costs presented in the accompanying comprehensive statements of earnings related to the Canadian divestitures and office consolidation.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(In millions)
Canada divestitures:
Employee related and other costs	$	2	$	—	$	44	$	—
Office consolidation:
Lease obligations and other		—		4		—		50

Restructuring costs	$	2	$	4	$	44	$	50

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The schedule below summarizes Devon’s restructuring liabilities.


	Other Current Liabilities			Other Long-Term Liabilities			Total
	(In millions)
Balance as of December 31, 2013	$	27		$	18		$	45
Changes due to Canadian divestitures		2			2			4
Changes due to office consolidation		(22	)		(1	)		(23	)
Changes due to offshore divestiture		(2	)		(1	)		(3	)

Balance as September 30, 2014	$	5		$	18		$	23


Balance as of December 31, 2012	$	52		$	9		$	61
Changes due to office consolidation		(16	)		11			(5	)
Changes due to offshore divestiture		(2	)		(1	)		(3	)

Balance as of September 30, 2013	$	34		$	19		$	53

7.	Income Taxes

The following table presents Devon’s total income tax expense (benefit) and a reconciliation of its effective income tax rate to the U.S. statutory income tax rate.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Total income tax expense (benefit) (in millions)	$	613		$	210		$	1,698		$	(99	)


U.S. statutory income tax rate		35	%		35	%		35	%		(35	%)
Repatriations		—			—			7	%		—
State income taxes		2	%		1	%		1	%		(3	%)
Taxation on Canadian operations		—			(5	%)		1	%		9	%
Taxes on EnLink formation		—			—			1	%		—
Other		—			2	%		—			(1	%)

Effective income tax rate		37	%		33	%		45	%		(30	%)

In the third quarter of 2014, Devon completed its U.S. non-core asset divestiture program. In conjunction with the divestiture closing, Devon recognized $543 million of current income tax expense. The current tax expense was entirely offset by the recognition of deferred tax benefits.

In the second quarter of 2014, Devon recognized $247 million of additional income tax expense related to the $2.8 billion of repatriations to the U.S. Prior to the repatriation, Devon had recognized a $143 million deferred income tax liability associated with the planned repatriation. When the repatriation was made, Devon retained a larger property basis in Canada than was previously estimated, resulting in the incremental tax in the second quarter.

In the first quarter of 2014, Devon recorded a $48 million deferred tax liability in conjunction with the formation of EnLink, which impacted the effective tax rate as reflected in the table above.

In the second quarter of 2013, Devon repatriated to the U.S. $2.0 billion of cash from its foreign subsidiaries. In conjunction with the repatriation, Devon recognized approximately $100 million of current income tax expense. The current expense was entirely offset by the recognition of deferred income tax benefits, which included the reduction of the deferred tax liability previously recognized for unremitted foreign earnings deemed not to be indefinitely reinvested.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

8.	Earnings (Loss) Per Share Attributable to Devon

The following table reconciles net earnings (loss) attributable to Devon 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)
Three Months Ended September 30, 2014:
Net earnings attributable to Devon	$	1,016			409
Attributable to participating securities		(11	)		(4	)

Basic earnings per share		1,005			405		$	2.48
Dilutive effect of potential common shares issuable		—			2

Diluted earnings per share	$	1,005			407		$	2.47


Three Months Ended September 30, 2013:
Net earnings attributable to Devon	$	429			406
Attributable to participating securities		(4	)		(4	)

Basic earnings per share		425			402		$	1.06
Dilutive effect of potential common shares issuable		—			1

Diluted earnings per share	$	425			403		$	1.05


Nine Months Ended September 30, 2014:
Net earnings attributable to Devon	$	2,015			408
Attributable to participating securities		(20	)		(4	)

Basic earnings per share		1,995			404		$	4.94
Dilutive effect of potential common shares issuable		—			2

Diluted earnings per share	$	1,995			406		$	4.91


Nine Months Ended September 30, 2013:
Net loss attributable to Devon	$	(227	)		406
Attributable to participating securities		(2	)		(4	)

Basic loss per share		(229	)		402		$	(0.57	)
Dilutive effect of potential common shares issuable		—			—

Diluted loss per share	$	(229	)		402		$	(0.57	)

Certain options to purchase shares of Devon’s common stock are excluded from the dilution calculation because the options are antidilutive. During the three-month and nine-month periods ended September 30, 2014, 1.1 million shares and 3.2 million shares, respectively, were excluded from the diluted earnings per share calculations. During the three-month and nine-month periods ended September 30, 2013, 7.5 million shares and 7.6 million shares, respectively, were excluded from the diluted earnings per share calculations.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

9.	Other Comprehensive Earnings

Components of other comprehensive earnings consist of the following:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In millions)
Foreign currency translation:
Beginning accumulated foreign currency translation	$	1,442		$	1,542		$	1,448		$	1,996
Change in cumulative translation adjustment		(299	)		182			(306	)		(294	)
Income tax benefit (expense)		20			(9	)		21			13

Ending accumulated foreign currency translation		1,163			1,715			1,163			1,715

Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits		(172	)		(216	)		(180	)		(225	)
Recognition of net actuarial loss and prior service cost in earnings⁽¹⁾		4			6			15			18
Income tax expense		(2	)		(3	)		(5	)		(6	)

Ending accumulated pension and postretirement benefits		(170	)		(213	)		(170	)		(213	)

Accumulated other comprehensive earnings, net of tax	$	993		$	1,502		$	993		$	1,502

(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 Note 15 for additional details).

10.

Supplemental Information to Statements of Cash Flows


	Nine Months Ended September 30,
	2014			2013
	(In millions)
Net change in working capital accounts:
Accounts receivable	$	(25	)	$	(287	)
Other current assets		(120	)		72
Accounts payable		(118	)		127
Income taxes payable		704			7
Revenues and royalties payable		381			56
Other current liabilities		(56	)		(79	)

Net change in working capital	$	766		$	(104	)


Interest paid (net of capitalized interest)	$	355		$	342
Income taxes paid (received)	$	214		$	(2	)

On March 7, 2014, Devon completed a business combination to form EnLink. With the exception of a $100 million cash payment to noncontrolling interests, the business combination was a non-monetary transaction. See Note 2 for additional details.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

11.

Accounts Receivable

The components of accounts receivable include the following:


	September 30, 2014			December 31, 2013
	(In millions)
Oil, gas and NGL sales	$	899		$	851
Joint interest billings		393			447
Marketing and midstream revenues		674			172
Other		54			61

Gross accounts receivable		2,020			1,531
Allowance for doubtful accounts		(11	)		(11	)

Net accounts receivable	$	2,009		$	1,520

12.

Goodwill

The table below provides a summary of Devon’s goodwill, by assigned reporting unit.


	September 30, 2014		December 31, 2013
	(In millions)
U.S.	$	2,618	$	2,618
Canada		1,997		2,838
EnLink		3,695		402

Total	$	8,310	$	5,858

The changes to Devon’s goodwill during the first nine months of 2014 relate to both EnLink and Canada. Included in the assets Devon contributed to EnLink Holdings was $402 million of goodwill. The additional EnLink goodwill of $3.3 billion represents the goodwill recognized on the EnLink transaction described in Note 2.

The decrease in Devon’s Canadian goodwill was primarily due to goodwill that was derecognized upon the asset divestitures described in Note 2.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

13.

Debt


	September 30, 2014			December 31, 2013
	(In millions)

Devon debt
Commercial paper	$	—		$	1,317
5.625% due January 15, 2014		—			500
Floating rate due December 15, 2015		500			500
2.40% due July 15, 2016		500			500
Floating rate due December 15, 2016		350			350
1.20% due December 15, 2016		650			650
1.875% due May 15, 2017		750			750
8.25% due July 1, 2018		125			125
2.25% due December 15, 2018		750			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 Devon debt		10,205			12,022

EnLink debt
Credit facilities		451			—
Other borrowings		27			—
2.70% due April 1, 2019		400			—
7.125% due June 1, 2022		163			—
4.40% due April 1, 2024		450			—
5.60% due April 1, 2044		350			—
Net premium on debentures and notes		13			—

Total EnLink debt		1,854			—

Total debt		12,059			12,022
Less amount classified as short-term debt⁽¹⁾		1,898			4,066

Total long-term debt	$	10,161		$	7,956

(1)

Short-term debt as of September 30, 2014 consists of $1.9 billion of senior notes that Devon intends to redeem in the fourth quarter of 2014 prior to their scheduled maturity date. The redemption includes the 2.4% $500 million senior note due 2016, the 1.2% $650 million senior note due 2016 and the 1.875% $750 million senior note due 2017 plus unpaid interest and a make-whole premium. The debt will be repaid with funds received as part of the divestiture program discussed in Note 2.

Short-term debt as of December 31, 2013 consists of $2.25 billion of senior notes issued in conjunction with the GeoSouthern acquisition, $1.3 billion of commercial paper and $500 million of senior notes due January 15, 2014. Subsequent to the close of the GeoSouthern acquisition the $2.25 billion of senior notes were reclassified to long-term debt.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Commercial Paper

During the nine months ended September 30, 2014, Devon has reduced commercial paper borrowings by $1.3 billion primarily utilizing divestiture proceeds. As of September 30, 2014, Devon had no outstanding commercial paper borrowings.

Credit Lines

Devon has a $3.0 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). As of September 30, 2014, 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. As of September 30, 2014, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 22.7 percent.

Term Loans

In December 2013, in conjunction with the GeoSouthern acquisition, Devon entered into a term loan agreement with a group of major financial institutions. In February 2014, Devon drew $2.0 billion of term loans to finance, in part, the GeoSouthern acquisition and to pay transaction costs. The term loans were repaid on June 30, 2014 with the Canadian divestiture proceeds that were repatriated to the U.S.

EnLink Debt

The table below summarizes the fair value of EnLink’s debt as of March 7, 2014, the formation date of EnLink. The premiums are being amortized using the effective interest method. EnLink’s debt is non-recourse to Devon.


	March 7, 2014 Fair Value of Debt		Effective Rate of Debt
	(In millions)
8.875% due February 15, 2018 (principal of $725 million) ⁽¹⁾	$	760		7.7	%
7.125% due June 1, 2022 (principal of $197 million)		226		5.3	%
Credit facilities		468

Total long-term debt	$	1,454

(1)	The 2018 senior notes were redeemed on April 18, 2014.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The Partnership has a $1.0 billion unsecured revolving credit facility, which includes a $500 million letter of credit subfacility. As of September 30, 2014, there were $14.0 million in outstanding letters of credit and $371.0 million outstanding borrowings under the $1.0 billion credit facility, leaving $615.0 million available for future borrowing.

The $1.0 billion credit facility will mature on the fifth anniversary of the initial funding date, which was March 7, 2014, unless EnLink requests, and the requisite lenders agree, to extend it pursuant to its terms. The credit facility contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of consolidated indebtedness to EnLink’s consolidated EBITDA (as defined in the credit facility, which definition includes projected EnLink EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If EnLink consummates one or more acquisitions in which the aggregate purchase price is $50 million or more, the maximum allowed ratio of consolidated indebtedness to EnLink’s consolidated EBITDA will increase to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters.

EnLink also has a $250 million revolving credit facility, which includes a $125 million letter of credit subfacility, as well as an additional credit agreement in association with E2 Energy Services LLC under which EnLink can borrow up to $30 million. As of September 30, 2014, EnLink’s outstanding borrowings under the $250 million credit facility were $81 million and $26 million in association with the E2 Energy Services LLC credit agreement. Additionally, as of September 30, 2014, E2 Services had certain promissory notes outstanding related to its vehicle fleet in the amount of $0.4 million due in increments through July 2017.

The $250 million credit facility will mature on March 7, 2019. The credit facility contains certain financial, operational and legal covenants. The financial covenants will be tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter, and include (i) maintaining a maximum consolidated leverage ratio (as defined in the credit facility, but generally computed as the ratio of consolidated funded indebtedness to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) of 4.00 to 1.00, provided that the maximum consolidated leverage ratio is 4.50 to 1.00 during an acquisition period (as defined in the credit facility) and (ii) maintaining a minimum consolidated interest coverage ratio (as defined in the credit facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) of 2.50 to 1.00 at all times prior to the occurrence of an investment grade event (as defined in the credit facility).

14.

Asset Retirement Obligations

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


	Nine Months Ended September 30,
	2014			2013
	(In millions)
Asset retirement obligations as of beginning of period	$	2,228		$	2,095
Liabilities incurred		79			88
Liabilities settled		(38	)		(46	)
Revision of estimated obligation		75			104
Liabilities assumed by others		(949	)		(15	)
Accretion expense on discounted obligation		70			86
Foreign currency translation adjustment		(55	)		(44	)

Asset retirement obligations as of end of period		1,410			2,268
Less current portion		62			107

Asset retirement obligations, long-term	$	1,348		$	2,161

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

During the first nine months of 2014, Devon reduced its asset retirement obligations $949 million for those obligations that were assumed by the purchasers of Devon’s Canadian and U.S. non-core oil and gas properties.

15.

Retirement Plans

The following table presents the components of net periodic benefit cost for Devon’s pension and postretirement benefit plans.


	Pension Benefits												Postretirement Benefits
	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013			2014			2013			2014			2013		2014			2013
	(In millions)
Service cost	$	7		$	9		$	22		$	27		$	—		$	—	$	—		$	—
Interest cost		14			13			41			39			—			—		—			1
Expected return on plan assets		(13	)		(16	)		(40	)		(47	)		—			—		—			—
Amortization of prior service cost ⁽¹⁾		1			1			3			3			(1	)		—		(1	)		—
Net actuarial loss (gain)⁽¹⁾		4			5			14			16			—			—		(1	)		(1	)

Net periodic benefit cost ⁽²⁾	$	13		$	12		$	40		$	38		$	(1	)	$	—	$	(2	)	$	—

(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.

16.

Stockholders’ Equity

Dividends

Devon paid common stock dividends of $287 million and $259 million in the first nine months of 2014 and 2013, respectively. The quarterly cash dividend was $0.20 per share in the first quarter of 2013. Devon increased the dividend rate to $0.22 per share in the second quarter of 2013 and to $0.24 per share in the second quarter of 2014.

Subsidiary equity transactions

In May 2014, the Partnership entered into an Equity Distribution Agreement (the “EDA”) with BMO Capital Markets Corp. (“BMO”). Pursuant to the terms of the EDA, the Partnership may from time to time through BMO, as its sales agent, sell common units representing limited partner interests having an aggregate offering price of up to $75 million.

Through September 30, 2014, the Partnership sold an aggregate of 2.4 million common units under the EDA, generating net proceeds of approximately $72 million. The Partnership used the net proceeds for general partnership purposes, including working capital, capital expenditures and repayments of indebtedness.

Distributions to noncontrolling interests

In conjunction with the formation of EnLink in the first quarter of 2014, Devon made a payment of $100 million to noncontrolling interests. Further, EnLink distributed $87 million to its non-Devon unitholders during the first nine months of 2014.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

17.

Commitments and Contingencies

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

Royalty Matters

Numerous oil and 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 oil, natural gas and NGLs produced and sold. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.

Environmental Matters

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

Other Matters

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

18.

Fair Value Measurements

The following tables provide carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other current payables and accrued expenses included in the accompanying balance sheets approximated fair value at September 30, 2014 and December 31, 2013. Therefore, such financial assets and liabilities are not presented in the following tables.


							Fair Value Measurements Using:
	Carrying Amount			Total Fair Value			Level 1 Inputs		Level 2 Inputs			Level 3 Inputs
	(In millions)
September 30, 2014 assets (liabilities):
Cash equivalents	$	2,876		$	2,876		$	1,745	$	1,131		$	—
Commodity derivatives	$	297		$	297		$	—	$	297		$	—
Commodity derivatives	$	(80	)	$	(80	)	$	—	$	(80	)	$	—
EnLink commodity derivatives	$	1		$	1		$	—	$	1		$	—
EnLink commodity derivatives	$	(2	)	$	(2	)	$	—	$	(2	)	$	—
Interest rate derivatives	$	1		$	1		$	—	$	1		$	—
Interest rate derivatives	$	(2	)	$	(2	)	$	—	$	(2	)	$	—
Foreign currency derivatives	$	11		$	11		$	—	$	11		$	—
Debt	$	(12,059	)	$	(13,410	)	$	—	$	(13,410	)	$	—
Capital lease obligations	$	(21	)	$	(21	)	$	—	$	(21	)	$	—

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


							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	)	$	—

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

Level 1 Fair Value Measurements

Cash equivalents — Amounts consist primarily of U.S. and Canadian treasury securities and money market investments. The fair value approximates the carrying value.

Level 2 Fair Value Measurements

Cash equivalents — 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 debt are estimated based on rates available for debt with similar terms and maturity. The fair value of Devon’s commercial paper and EnLink’s credit facility is the carrying value.

Capital lease obligations — The fair value was calculated using inputs from third-party banks.

Level 3 Fair Value Measurements

Long-term investments — Devon’s long-term investments as of December 31, 2013 consisted entirely of auction rate securities. In the first quarter of 2014, Devon redeemed all these securities for approximately $57 million, or $5 million below their carrying value.

19.

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 U.S. and Canadian segments are both primarily engaged in oil and gas exploration and production activities.

With the formation of EnLink in the first quarter of 2014, Devon considers EnLink to be an operating segment that is distinct from its existing operating segments. EnLink’s operations consist of midstream assets and operations located across the U.S. Additionally, EnLink has a management team that is primarily responsible for capital and resource allocation decisions. Therefore, EnLink is presented as a separate reporting segment. For the reporting periods prior to the formation of EnLink, Devon has reclassified, from its U.S. segment to the EnLink segment, all asset-level amounts related to the midstream assets that it contributed to EnLink Holdings.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


	U.S.		Canada			EnLink		Eliminations			Total
	(In millions)
Three Months Ended September 30, 2014:
Revenues from external customers	$	4,199	$	481		$	656	$	—		$	5,336
Intersegment revenues	$	—	$	—		$	199	$	(199	)	$	—
Depreciation, depletion and amortization	$	655	$	113		$	74	$	—		$	842
Interest expense	$	95	$	20		$	14	$	(11	)	$	118
Earnings (loss) before income taxes	$	1,461	$	109		$	84	$	—		$	1,654
Income tax expense (benefit)	$	557	$	38		$	18	$	—		$	613
Net earnings (loss)	$	904	$	71		$	66	$	—		$	1,041
Net earnings attributable to noncontrolling interests	$	—	$	—		$	25	$	—		$	25
Net earnings (loss) attributable to Devon	$	904	$	71		$	41	$	—		$	1,016
Capital expenditures	$	1,213	$	335		$	207	$	—		$	1,755

Three Months Ended September 30, 2013:
Revenues from external customers	$	1,687	$	791		$	236	$	—		$	2,714
Intersegment revenues	$	—	$	—		$	342	$	(342	)	$	—
Depreciation, depletion and amortization	$	444	$	199		$	48	$	—		$	691
Interest expense	$	94	$	20		$	—	$	(10	)	$	104
Asset impairments	$	7	$	—		$	—	$	—		$	7
Earnings (loss) before income taxes	$	366	$	219		$	54	$	—		$	639
Income tax expense (benefit)	$	141	$	50		$	19	$	—		$	210
Net earnings (loss)	$	225	$	169		$	35	$	—		$	429
Capital expenditures	$	1,219	$	437		$	37	$	—		$	1,693

Nine Months Ended September 30, 2014:
Revenues from external customers	$	10,067	$	1,671		$	1,833	$	—		$	13,571
Intersegment revenues	$	—	$	—		$	672	$	(672	)	$	—
Depreciation, depletion and amortization	$	1,794	$	419		$	196	$	—		$	2,409
Interest expense	$	303	$	61		$	33	$	(31	)	$	366
Earnings (loss) before income taxes	$	2,219	$	1,310		$	239	$	—		$	3,768
Income tax expense (benefit)	$	1,121	$	517		$	60	$	—		$	1,698
Net earnings (loss)	$	1,098	$	793		$	179	$	—		$	2,070
Net earnings attributable to noncontrolling interests	$	1	$	—		$	54	$	—		$	55
Net earnings (loss) attributable to Devon	$	1,097	$	793		$	125	$	—		$	2,015
Property and equipment, net	$	23,764	$	6,882		$	4,523	$	—		$	35,169
Total assets	$	30,533	$	10,895		$	9,528	$	(117	)	$	50,839
Capital expenditures	$	9,748	$	1,055		$	491	$	—		$	11,294

Nine Months Ended September 30, 2013:
Revenues from external customers	$	5,033	$	2,052		$	688	$	—		$	7,773
Intersegment revenues	$	—	$	—		$	1,005	$	(1,005	)	$	—
Depreciation, depletion and amortization	$	1,287	$	643		$	139	$	—		$	2,069
Interest expense	$	284	$	62		$	—	$	(24	)	$	322
Asset impairments	$	1,117	$	843		$	—	$	—		$	1,960
Earnings (loss) before income taxes	$	96	$	(559	)	$	137	$	—		$	(326	)
Income tax expense (benefit)	$	10	$	(158	)	$	49	$	—		$	(99	)
Net earnings (loss)	$	86	$	(401	)	$	88	$	—		$	(227	)
Capital expenditures	$	3,477	$	1,377		$	173	$	—		$	5,027

December 31, 2013:
Property and equipment, net	$	18,201	$	8,478		$	1,768	$	—		$	28,447
Total assets	$	27,080	$	13,560		$	2,237	$	—		$	42,877

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis addresses material changes in our results of operations and capital resources and uses for the three-month and nine-month periods ended September 30, 2014, compared to the three-month and nine-month periods ended September 30, 2013 and in our financial condition and liquidity since December 31, 2013. For information regarding our critical accounting policies and estimates, see our 2013 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Overview of 2014 Results

Key components of our financial performance are summarized below.


	Three Months Ended September 30,							Nine Months Ended September 30,
	2014		2013		Change			2014		2013			Change
	($ in millions, except per share amounts)
Net earnings (loss) attributable to Devon	$	1,016	$	429		+137	%	$	2,015	$	(227	)		+988	%
Adjusted earnings attributable to Devon⁽¹⁾	$	552	$	526		+5	%	$	1,673	$	1,287			+30	%
Earnings (loss) per share attributable to Devon	$	2.47	$	1.05		+135	%	$	4.91	$	(0.57	)		+961	%
Adjusted earnings per share attributable to Devon⁽¹⁾	$	1.34	$	1.29		+4	%	$	4.08	$	3.16			+29	%
Production (MBoe/d)		671		691		-3	%		676		692			-2	%
Realized price per Boe	$	41.92	$	36.84		+14	%	$	42.38	$	33.71			+26	%
Adjusted operating income per Boe⁽²⁾	$	29.42	$	24.44		+20	%	$	29.51	$	21.47			+37	%
Operating cash flow	$	1,559	$	1,601		-3	%	$	5,018	$	3,999			+25	%
Capitalized costs	$	1,755	$	1,693		+4	%	$	11,294	$	5,027			+125	%
Shareholder distributions	$	98	$	89		+10	%	$	287	$	259			+11	%

(1)

Adjusted earnings and adjusted earnings per share attributable to Devon are financial measures not prepared in accordance with accounting principles generally accepted in the U.S. (GAAP). For a description of adjusted earnings and adjusted earnings per share attributable to Devon, as well as reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 2.

(2)	Computed as revenues from commodity sales and marketing and midstream operations, less expenses for lease operations, marketing and midstream operations, cash-based general and administrative, production and property taxes and net financing costs, with the result divided by total production.

During the three-month and nine-month periods ended September 30, 2014, our adjusted earnings, adjusted earnings per share and adjusted operating income per Boe all increased compared to the same periods in 2013. The improved 2014 quarterly results were driven primarily by increases in production from our retained properties, particularly liquids volumes, combined with higher gas price realizations. These same factors along with higher oil price realizations also drove higher earnings and operating cash flow for the nine-month period.

In November 2013, we announced three strategic portfolio transformation initiatives that were focused on building value per share. On February 28, 2014, we closed the GeoSouthern acquisition and acquired GeoSouthern’s Eagle Ford Shale assets and operations in south Texas for approximately $6.0 billion. This acquisition included approximately 250 MMBoe of proved reserves. Additionally, since closing the transaction, we have produced approximately 15 MMBoe from our Eagle Ford development, with oil accounting for approximately 60% of our production from the play.

On March 7, 2014, we completed a transaction to combine substantially all of our U.S. midstream assets with Crosstex’s assets to form a new midstream business referred to as EnLink. This transaction, including Devon’s controlling ownership of EnLink, is described more fully in “Part I. Financial Information – Item 1. Financial Statements – Note 2” in this report. The results of operations from our assets contributed to EnLink are included in our consolidated financial statements for all periods presented. Additionally, the results of operations for all assets contributed to EnLink are included in our consolidated financial statements subsequent to the completion of the transaction. The portions of EnLink’s net earnings and stockholders’ equity not attributable to Devon’s controlling interest are shown separately as noncontrolling interests in our consolidated comprehensive statements of earnings and consolidated balance sheets.

Finally, we have completed our non-core divestiture program. On April 1, 2014, we sold Canadian conventional assets to Canadian Natural Resources Limited for $2.8 billion ($3.125 billion Canadian dollars), and on August 29, 2014, we sold U.S. non-core assets to LINN Energy for $2.3 billion. In less than one year, we have transformed our portfolio by the completion of an accretive Eagle Ford acquisition, the innovative creation of EnLink Midstream and the sale of our non-core properties.

In conjunction with the Canadian divestiture, we repatriated $2.8 billion to the U.S. from Canada in the second quarter of 2014. These proceeds, as well as the LINN divestiture proceeds, along with cash on hand and free cash flow generated during the year, are being used to reduce debt balances. In October 2014, we announced the redemption of $1.9 billion in senior notes. This redemption includes all of our outstanding 2.4% senior notes due 2016, 1.2% senior notes due 2016 and 1.875% senior notes due 2017. Upon redemption in November 2014, this represents the completion of our debt repayment plan associated with our portfolio transformation.

Results of Operations

Oil, Gas and NGL Production


	Three Months Ended September 30,							Nine Months Ended September 30,
	2014		2013		Change			2014		2013		Change
Oil (MBbls/d)
Anadarko Basin		10		10		+7	%		10		9		+14	%
Barnett Shale		2		2		-4	%		2		2		+2	%
Eagle Ford		46		—		N/M			32		—		N/M
Mississippian-Woodford Trend		10		5		+77	%		9		4		+158	%
Permian Basin		56		49		+15	%		55		45		+23	%
Rockies		10		8		+23	%		9		8		+14	%
Other		2		3		-33	%		4		2		+100	%

U.S. core and emerging properties		136		77		+77	%		121		70		+71	%
Canada		27		27		-3	%		26		28		-7	%

Total core and emerging properties		163		104		+56	%		147		98		+49	%
Non-core properties		3		15		-83	%		7		16		-55	%

Total		166		119		+38	%		154		114		+34	%

Bitumen (MBbls/d)
Canada		53		46		+17	%		52		51		+2	%
Gas (MMcf/d)
Anadarko Basin		323		297		+9	%		304		282		+8	%
Barnett Shale		896		1,009		-11	%		920		1,036		-11	%
Eagle Ford		107		—		N/M			72		—		N/M
Mississippian-Woodford Trend		32		14		+131	%		29		9		+222	%
Permian Basin		136		109		+25	%		130		101		+29	%
Rockies		66		76		-12	%		66		79		-17	%
Other		130		151		-14	%		135		159		-15	%

U.S. core and emerging properties		1,690		1,656		+2	%		1,656		1,666		-1	%
Canada		26		17		+56	%		24		29		-19	%

Total core and emerging properties		1,716		1,673		+3	%		1,680		1,695		-1	%
Non-core properties		138		710		-81	%		311		720		-57	%

Total		1,854		2,383		-22	%		1,991		2,415		-18	%

NGLs (MBbls/d)
Anadarko Basin		34		24		+39	%		32		25		+28	%
Barnett Shale		54		57		-4	%		55		54		+1	%
Eagle Ford		14		—		N/M			9		—		N/M
Mississippian-Woodford Trend		6		1		+414	%		5		1		+628	%
Permian Basin		19		15		+29	%		18		13		+31	%
Rockies		1		1		+46	%		1		1		+33	%
Other		10		12		-17	%		9		11		-18	%

U.S. core and emerging properties		138		110		+27	%		129		105		+23	%
Non-core properties		5		19		-74	%		9		19		-51	%

Total		143		129		+11	%		138		124		+12	%

Combined (MBoe/d)
Anadarko Basin		98		83		+17	%		92		80		+15	%
Barnett Shale		205		226		-9	%		209		228		-8	%
Eagle Ford		78		—		N/M			54		—		N/M
Mississippian-Woodford Trend		21		9		+136	%		19		6		+233	%
Permian Basin		98		82		+20	%		95		75		+26	%
Rockies		22		23		-4	%		22		23		-4	%
Other		34		39		-13	%		35		41		-15	%

U.S. core and emerging properties		556		462		+20	%		526		453		+16	%
Canada		84		76		+10	%		82		84		-2	%

Total core and emerging properties		640		538		+19	%		608		537		+13	%
Non-core properties		31		153		-80	%		68		155		-56	%

Total		671		691		-3	%		676		692		-2	%

Oil, Gas and NGL Pricing


	Three Months Ended September 30,							Nine Months Ended September 30,
	2014 ⁽¹⁾		2013 ⁽¹⁾		Change			2014 ⁽¹⁾		2013 ⁽¹⁾		Change
Oil (per Bbl)
U.S.	$	90.23	$	101.40		-11	%	$	92.55	$	93.94		-1	%
Canada	$	71.07	$	87.25		-19	%	$	72.76	$	72.07		+1	%
Total	$	87.20	$	96.90		-10	%	$	88.75	$	86.41		+3	%
Bitumen (per Bbl)
Canada	$	63.34	$	73.74		-14	%	$	61.45	$	50.93		+21	%
Gas (per Mcf)
U.S.	$	3.61	$	3.08		+17	%	$	4.04	$	3.13		+29	%
Canada ⁽²⁾	$	0.76	$	2.67		-72	%	$	3.80	$	3.05		+25	%
Total	$	3.57	$	3.00		+19	%	$	4.02	$	3.11		+29	%
NGLs (per Bbl)
U.S.	$	25.82	$	24.36		+6	%	$	26.80	$	25.12		+7	%
Canada	$	63.46	$	48.48		+31	%	$	50.57	$	46.54		+9	%
Total	$	25.90	$	26.23		-1	%	$	27.34	$	26.83		+2	%
Combined (per Boe)
U.S.	$	38.90	$	32.72		+19	%	$	39.81	$	31.12		+28	%
Canada	$	63.23	$	49.65		+27	%	$	55.85	$	41.29		+35	%
Total	$	41.92	$	36.84		+14	%	$	42.38	$	33.71		+26	%

(1)	The prices presented exclude any effects due to oil, gas and NGL derivatives.

(2)

The reported Canadian gas volumes include 14 and 18 MMcf per day for the third quarter of 2014 and 2013, respectively, and 24 MMcf per day for the first nine months of 2014 and 2013, that are produced from certain of our leases and then transported to our Jackfish operations where the gas is used as fuel. However, the revenues and expenses related to this consumed gas are eliminated in our consolidated financial results. With the sale of the vast majority of the Canadian gas business in the second quarter of 2014, the impact of the eliminated gas revenues more significantly impacts our gas price.

Commodity Sales

The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between the three months ended September 30, 2014 and 2013.


	Three Months Ended September 30,
	Oil			Bitumen			Gas			NGLs			Total
	(In millions)
2013 sales	$	1,064		$	309		$	658		$	310		$	2,341
Change due to volumes		410			53			(146	)		35			352
Change due to prices		(148	)		(51	)		98			(4	)		(105	)

2014 sales	$	1,326		$	311		$	610		$	341		$	2,588

Oil, gas and NGL sales increased $352 million due to volumes in the third quarter of 2014. The primary driver of the increase resulted from a 77% increase in our U.S. core and emerging oil production. Such growth resulted from our recently acquired Eagle Ford Shale properties and the continued development of our Permian Basin and Mississippian-Woodford Trend properties. In addition, we continue to grow our NGL production from these plays, which resulted in $35 million of additional sales. These production additions were partially offset by the impacts of our non-core asset divestitures, which were the primary drivers of our 22% decrease in gas production. Bitumen sales increased $53 million due to continued development of our Jackfish thermal heavy oil project in Canada, including Jackfish 3 which had first sales in the third quarter of 2014.

Oil, gas and NGL sales decreased $105 million due to prices in the third quarter of 2014, primarily due to a 10% and 14% decrease in our realized price without hedges for oil and bitumen sales, respectively. The $199 million decrease in oil and bitumen sales due to prices is due to lower average NYMEX West Texas Intermediate index prices and larger bitumen and heavy oil differentials. The decrease was offset by increased gas sales of $98 million largely due to higher North American regional index prices upon which our gas sales are based.

The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between the nine months ended September 30, 2014 and 2013.


	Nine Months Ended September 30,
	Oil		Bitumen		Gas			NGLs		Total
	(In millions)
2013 sales	$	2,700	$	709	$	2,052		$	906	$	6,367
Change due to volumes		931		17		(360	)		107		695
Change due to prices		98		150		495			19		762

2014 sales	$	3,729	$	876	$	2,187		$	1,032	$	7,824

Oil, gas and NGL sales increased $695 million due to volumes during the first nine months of 2014. The primary driver of the increase resulted from a 71% increase in our U.S. core and emerging oil production. Such growth resulted from our recently acquired Eagle Ford Shale properties and the continued development of our Permian Basin and Mississippian-Woodford Trend properties. In addition, we continue to grow our NGL production from these plays, which resulted in $107 million of additional sales. These production additions were partially offset by the impacts of our non-core asset divestitures, which were the primary driver of our 18% decrease in gas production. Bitumen sales increased $17 million due to continued development of our Jackfish thermal heavy oil project in Canada, including Jackfish 3 which had first sales in the third quarter of 2014.

Oil, gas and NGL sales increased $762 million due to prices during the first nine months of 2014, primarily due to a 26% increase in our realized price without hedges. Gas sales were the most significantly impacted with an increase of $495 million, largely due to higher North American regional index prices upon which our gas sales are based. Oil and bitumen sales increased $248 million, largely due to higher prices and realizations resulting from a higher average NYMEX West Texas Intermediate index price and tighter bitumen and heavy oil differentials.

Oil, Gas and NGL Derivatives

A summary of our open commodity derivative positions is included in Note 3 to the financial statements included in “Item 1. Consolidated Financial Statements” of this report. The following tables provide financial information associated with our commodity derivatives. The first table presents the cash settlements and fair value gains and losses recognized as components of our revenues. The subsequent tables present our oil, bitumen, gas and NGL prices with, and without, the effects of the cash settlements. The prices do not include the effects of fair value gains and losses.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In millions)
Cash settlements:
Oil derivatives	$	(22	)	$	(60	)	$	(137	)	$	1
Gas derivatives		26			53			(67	)		89
NGL derivatives		—			—			—			3

Total cash settlements		4			(7	)		(204	)		93

Gains (losses) on fair value changes:
Oil derivatives		642			(113	)		233			(217	)
Gas derivatives		102			(18	)		—			34
NGL derivatives		—			(3	)		—			(5	)

Total gains (losses) on fair value changes		744			(134	)		233			(188	)


Oil, gas and NGL derivatives	$	748		$	(141	)	$	29		$	(95	)


	Three Months Ended September 30, 2014
	Oil (Per Bbl)			Bitumen (Per Bbl)		Gas (Per Mcf)		NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	87.20		$	63.34	$	3.57	$	25.90	$	41.92
Cash settlements of hedges⁽¹⁾		(1.42	)		—		0.15		0.01		0.07

Realized price, including cash settlements	$	85.78		$	63.34	$	3.72	$	25.91	$	41.99


	Three Months Ended September 30, 2013
	Oil (Per Bbl)			Bitumen (Per Bbl)		Gas (Per Mcf)		NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	96.90		$	73.74	$	3.00	$	26.23	$	36.84
Cash settlements of hedges⁽¹⁾		(5.51	)		—		0.24		0.02		(0.12	)

Realized price, including cash settlements	$	91.39		$	73.74	$	3.24	$	26.25	$	36.72


	Nine Months Ended September 30, 2014
	Oil (Per Bbl)			Bitumen (Per Bbl)		Gas (Per Mcf)			NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	88.75		$	61.45	$	4.02		$	27.34	$	42.38
Cash settlements of hedges⁽¹⁾		(3.25	)		—		(0.12	)		—		(1.11	)

Realized price, including cash settlements	$	85.50		$	61.45	$	3.90		$	27.34	$	41.27


	Nine Months Ended September 30, 2013
	Oil (Per Bbl)		Bitumen (Per Bbl)		Gas (Per Mcf)		NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	86.41	$	50.93	$	3.11	$	26.83	$	33.71
Cash settlements of hedges⁽¹⁾		0.04		—		0.14		0.08		0.50

Realized price, including cash settlements	$	86.45	$	50.93	$	3.25	$	26.91	$	34.21

(1)	Cash settlements of oil hedges include settlements from our Western Canadian Select basis swaps presented in Note 3 to the financial statements included in “Item 1. Consolidated Financial Statements” of this report.

Cash settlements as presented in the tables above represent realized gains or losses related to various commodity derivatives. In addition to cash settlements, we also recognize fair value changes on our commodity derivatives in each reporting period. The changes in fair value result from new positions and settlements that occur during each period, as well as the relationships between contract prices and the associated forward curves. Including the cash settlements discussed above, our commodity derivatives generated a net gain of $748 million and incurred a net loss of $141 million in the third quarter of 2014 and 2013, respectively. Including the cash settlements discussed above, our commodity derivatives generated a net gain of $29 million and incurred a net loss $95 million in the first nine months of 2014 and 2013, respectively.

Marketing and Midstream Revenues and Operating Expenses


	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Change			2014			2013			Change
	($ in millions)
Operating revenues	$	2,000		$	514			+289	%	$	5,718		$	1,501			+281	%
Product purchases		(1,709	)		(331	)		+416	%		(4,897	)		(978	)		+401	%
Operations and maintenance expenses		(72	)		(52	)		+39	%		(195	)		(150	)		+30	%

Operating profit	$	219		$	131			+68	%	$	626		$	373			+68	%

During the third quarter and first nine months of 2014, marketing and midstream operating profit increased $88 million and $253 million, respectively, primarily due to higher prices and volumes. The entire $88 million increase for the three months ended September 30 was attributable to EnLink’s operations. Of the $253 million increase for the nine months ended September 30, $228 million was related to EnLink’s operations. EnLink’s Texas segment, which includes the Bridgeport facility, was the largest driver of the increase, while higher fees also contributed to the increase. The remaining increase in operating profit related to Devon’s marketing activities.

Besides the impact to our overall operating profit, Devon’s marketing activities were the primary driver of the increases in both operating revenues and product purchases. The higher marketing revenues and product purchases are primarily due to commitments we have entered into to secure capacity on downstream oil pipelines. Marketing activities of EnLink also contributed to these increases.

Lease Operating Expenses (“LOE”)


	Three Months Ended September 30,							Nine Months Ended September 30,
	2014		2013		Change			2014		2013		Change
LOE ($ in millions):
U.S.	$	410	$	333		+23	%	$	1,163	$	928		+25	%
Canada		174		267		-35	%		601		756		-21	%

Total	$	584	$	600		-3	%	$	1,764	$	1,684		+5	%

LOE per Boe:
U.S.	$	7.58	$	6.91		+10	%	$	7.50	$	6.60		+14	%
Canada	$	22.78	$	17.32		+32	%	$	20.34	$	15.70		+30	%
Total	$	9.47	$	9.45		+0	%	$	9.56	$	8.92		+7	%

Our absolute LOE changed largely as a result of our portfolio transformation initiatives, including our March 2014 purchase of GeoSouthern’s Eagle Ford assets and our 2014 divestitures of non-core properties in the U.S. and Canada. Higher volumes from development of our Eagle Ford assets, as well as our Permian assets, caused U.S. LOE to increase. This increase was partially offset by the decrease resulting from the U.S. divestitures. The Canadian divestitures were the primary cause of the decrease in Canadian LOE.

LOE per Boe remained flat during the third quarter and increased 7% during the first nine months of 2014. The largest contributor to the higher unit cost related to our Canadian operations. The higher Canadian unit costs largely resulted from the divestiture of the conventional assets in the second quarter of 2014 which resulted in lower total volumes while retaining the relatively higher-cost thermal heavy oil operations. Additionally, higher Jackfish royalties paid in 2014 also contributed

to higher Canadian unit costs. As Canadian royalties increase, our net production volumes decrease, causing upward pressure on our per-unit operating costs. The higher unit cost in the U.S. was primarily related to our liquids production growth, particularly in the Permian Basin, Mississippian-Woodford Trend and Eagle Ford, where projects generate higher revenues but generally require a higher cost to produce per unit than our gas projects. Additionally, we experienced upward pressures on costs in certain operating areas, which also contributed to the higher LOE per Boe.

General and Administrative Expenses (“G&A”)


	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Change			2014			2013			Change
	($ in millions)
Gross G&A	$	320		$	266			+20	%	$	967		$	836			+16	%
Capitalized G&A		(94	)		(88	)		+7	%		(268	)		(271	)		-1	%
Reimbursed G&A		(31	)		(35	)		-11	%		(104	)		(105	)		-1	%

Net G&A	$	195		$	143			+36	%	$	595		$	460			+29	%


Net G&A per Boe	$	3.16		$	2.25			+40	%	$	3.22		$	2.44			+32	%

Net G&A and net G&A per Boe increased during the third quarter and first nine months of 2014 largely due to higher employee compensation and benefits and $22 million in one-time costs in the first quarter of 2014 related to the EnLink and GeoSouthern transactions. The higher employee compensation and benefits costs were primarily related to share-based awards, which cause our G&A to be higher in the quarter in which our annual share-based grant is made. The grant related to our 2013 compensation cycle was made in the first quarter of 2014. The grant related to our 2012 compensation cycle was made in the fourth quarter of 2012. Additionally, higher employee severance costs in 2014, as well as expansion of our workforce as a part of growing production operations at certain of our key areas, also contributed to the increase.

Production and Property Taxes


	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Change			2014			2013			Change
	($ in millions)
Production	$	97		$	70			+40	%	$	288		$	201			+43	%
Property and other		43			45			-6	%		139			152			-9	%

Production and property taxes	$	140		$	115			+22	%	$	427		$	353			+21	%


Percentage of oil, gas and NGL sales:
Production		3.8	%		3.0	%		+27	%		3.7	%		3.1	%		+17	%
Property and other		1.6	%		1.9	%		-20	%		1.8	%		2.4	%		-26	%

Total		5.4	%		4.9	%		+11	%		5.5	%		5.5	%		-1	%

Production and property taxes increased during the third quarter and first nine months of 2014 primarily due to an increase in our U.S. revenues, on which the majority of our production taxes are assessed.

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


	Three Months Ended September 30,							Nine Months Ended September 30,
	2014		2013		Change			2014		2013		Change
DD&A ($ in millions):
Oil & gas properties	$	733	$	611		+20	%	$	2,111	$	1,833		+15	%
Other assets		109		80		+39	%		298		236		+27	%

Total	$	842	$	691		+22	%	$	2,409	$	2,069		+16	%


	Three Months Ended September 30,							Nine Months Ended September 30,
	2014		2013		Change			2014		2013		Change
DD&A per Boe:
Oil & gas properties	$	11.87	$	9.62		+23	%	$	11.43	$	9.70		+18	%
Other assets		1.78		1.25		+43	%		1.62		1.25		+29	%

Total	$	13.65	$	10.87		+26	%	$	13.05	$	10.95		+19	%

DD&A from our oil and gas properties increased in both 2014 periods largely due to higher DD&A rates. The higher rates resulted from our oil and gas drilling and development activities and the GeoSouthern acquisition, which were partially offset by the asset impairments recognized in the first quarter of 2013 and the non-core asset divestitures. Other DD&A increased in both periods primarily due to the EnLink transaction.

Asset Impairments


	Nine Months Ended September 30, 2013
	Gross		Net of Taxes
	($ in millions)
U.S. oil and gas assets	$	1,110	$	707
Canada oil and gas assets		843		632
Midstream assets		7		4

Total asset impairments	$	1,960	$	1,343

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. The oil and gas asset 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, bitumen and NGLs, which reduced proved reserve values.

Midstream Impairments

In the third quarter of 2013, we determined that the carrying amounts of certain midstream facilities located in south and east Texas were not recoverable from estimated future cash flows due to declining natural gas production. Consequently, the assets were written down to their estimated fair values, which were determined using discounted cash flow models.

Restructuring Costs


	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(In millions)
Canadian divestitures	$	2	$	—	$	44	$	—
Office consolidation		—		4		—		50

Restructuring costs	$	2	$	4	$	44	$	50

Canadian Divestitures

In the nine months ended September 30, 2014, we recognized $44 million of employee related and other costs associated with our Canadian non-core asset divestitures. Approximately $15 million of the employee related costs resulted from accelerated vesting of share-based grants, which are non-cash charges.

Office Consolidation

In the nine months ended September 30, 2013, we incurred $50 million of restructuring costs associated with the consolidation of our U.S. personnel into one location in Oklahoma City. This amount includes $25 million related to office space that is subject to non-cancellable operating lease agreements that we ceased using as a part of the office consolidation. We also recognized $6 million of asset impairment charges for leasehold improvements and furniture associated with the office consolidation.

Gains On Asset Sales

In conjunction with the divestiture of our Canadian non-core properties, we recognized gains in the first and second quarters of 2014. Under full-cost accounting rules, sales or dispositions of oil and gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of gain or loss. However, if not recognizing a gain or loss on the disposition would otherwise significantly alter the relationship between a cost center’s capitalized costs and proved reserves, then a gain or loss must be recognized. Our Canadian divestitures significantly altered such relationship. Therefore, we recognized a total gain of $1.1 billion ($0.6 billion after-tax) during the first nine months of 2014.

Net Financing Costs


	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Change			2014			2013			Change
	($ in millions)
Interest based on debt outstanding	$	133		$	116			+15	%	$	399		$	350			+14	%
Capitalized interest		(21	)		(15	)		+33	%		(56	)		(38	)		+45	%
Other fees and expenses		6			3			+97	%		23			10			+134	%

Interest expense	$	118		$	104			+13	%	$	366		$	322			+14	%
Interest income		(2	)		(4	)		-45	%		(7	)		(16	)		-57	%

Net financing costs	$	116		$	100			+16	%	$	359		$	306			+18	%

Net financing costs increased during the third quarter and first nine months of 2014 primarily due to higher average fixed-rate borrowings resulting from the EnLink and GeoSouthern transactions.

Income Taxes

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Total income tax expense (benefit) (in millions)	$	613		$	210		$	1,698		$	(99	)


U.S. statutory income tax rate		35	%		35	%		35	%		(35	%)
Repatriations		—			—			7	%		—
State income taxes		2	%		1	%		1	%		(3	%)
Taxation on Canadian operations		—			(5	%)		1	%		9	%
Taxes on EnLink formation		—			—			1	%		—
Other		—			2	%		—			(1	%)

Effective income tax rate		37	%		33	%		45	%		(30	%)

In the third quarter of 2014, we completed our U.S. non-core asset divestiture program. In conjunction with the divestiture closing, we recognized $543 million of current income tax expense. The current tax expense was entirely offset by the recognition of deferred tax benefits.

In the second quarter of 2014, we recognized $247 million of additional income tax expense related to the $2.8 billion of repatriations to the U.S. Prior to the repatriation, we had recognized a $143 million deferred income tax liability associated with the planned repatriation. When the repatriation was made, we retained a larger property basis in Canada than was previously estimated, resulting in the incremental tax in the second quarter.

In the first quarter of 2014, we recorded a $48 million deferred tax liability in conjunction with the formation of EnLink, which impacted our effective tax rate as reflected in the table above.

In the second quarter of 2013, we repatriated to the U.S. $2.0 billion of cash from our foreign subsidiaries. In conjunction with the repatriation, we recognized approximately $100 million of current income tax expense. The current expense was entirely offset by the recognition of deferred income tax benefits, which included the reduction of the deferred tax liability previously recognized for unremitted foreign earnings deemed not to be indefinitely reinvested.

Net Income Attributable to Noncontrolling Interests

Our net income attributable to noncontrolling interests for the three and nine months ended September 30, 2014 relate to public ownership interests in EnLink Midstream Partners, LP (ENLK) and EnLink Midstream, LLC (ENLC). Public ownership in ENLK consisted of a 41% limited partnership interest. Public ownership in ENLC consisted of a 30% limited partnership interest.

Capital Resources, Uses and Liquidity

Sources and Uses of Cash

The following table presents the major changes in our cash and cash equivalents.


	Nine Months Ended September 30,
	2014			2013
	(In millions)
Operating cash flow	$	5,018		$	3,999
Divestitures of property and equipment		5,202			316
Capital expenditures		(5,013	)		(5,219	)
Acquisitions of property, equipment and businesses		(6,255	)		—
Debt activity, net		(1,425	)		(1,577	)
Distributions to Devon shareholders		(287	)		(259	)
Distributions to noncontrolling interests		(187	)		—
Stock option proceeds		92			1
Proceeds from issuance of subsidiary units		72			—
Other		125			79

Net change in cash and short-term investments	$	(2,658	)	$	(2,660	)

Cash and cash equivalents at end of period	$	3,408		$	4,320

Operating Cash Flow

Net cash provided by operating activities (“operating cash flow”) was a significant source of capital in the first nine months of 2014. Our operating cash flow increased 25 percent year-over-year primarily due to higher commodity prices and liquids production growth, partially offset by higher expenses and approximately $700 million of current tax associated with the U.S. and Canada non-core divestitures.

Excluding the $6.3 billion attributable to the GeoSouthern and other acquisitions, our operating cash flow funded our capital expenditures during the first nine months of 2014 and funded approximately 80 percent of our capital expenditures during the first nine months of 2013. Leveraging our liquidity, we used cash balances, short term debt and divestiture proceeds to fund the remainder of our 2013 cash-based capital expenditures.

Divestitures

In November 2013, we announced plans to divest certain non-core properties located throughout Canada and the U.S. In the first nine months of 2014, we completed these divestiture transactions and received proceeds totaling $5.2 billion ($4.5 billion after-tax).

Capital Expenditures

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


	Nine Months Ended September 30,
	2014		2013
	(In millions)
Development	$	3,560	$	3,640
Exploration		193		693

Total oil and gas development and exploration		3,753		4,333
Capitalized G&A and interest		260		301

Total oil and gas		4,013		4,634
Acquisitions of property, equipment and businesses		6,255		—
Midstream		419		353
Corporate and other		93		30

Devon capital expenditures		10,780		5,017
EnLink		488		202

Total capital expenditures	$	11,268	$	5,219

Our capital expenditures consist of amounts related to our oil and gas exploration and development operations, midstream operations, other corporate activities and EnLink growth and maintenance activities. The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties, which totaled $10.1 billion and $4.6 billion in the first nine months of 2014 and 2013, respectively. The increase in capital spending was primarily due to the GeoSouthern acquisition. Excluding this acquisition, exploration and development capital spending decreased 14 percent in the first nine months of 2014, primarily due to utilization of the drilling carries in 2014 from our Sinopec and Sumitomo joint venture arrangements.

Capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas gathering systems and oil pipelines. Our midstream capital expenditures are largely impacted by our oil and gas drilling activities.

Debt Activity, Net

During the first nine months of 2014, we decreased our net debt borrowings $1.4 billion. The decrease was the net impact of repaying our $500 million senior notes upon maturity, reducing commercial paper balances $1.3 billion primarily with repatriated Canadian divestiture proceeds and EnLink net borrowings of $400 million.

During the first nine months of 2013, we repatriated $2.0 billion of foreign earnings to the U.S. and repaid a portion of outstanding commercial paper borrowings. The repayment resulted in a net repayment of $1.6 billion for the first nine months of 2013.

Distributions to Devon shareholders

The following table summarizes our common stock dividends (amounts in millions) during the first nine months of 2014 and 2013. In the second quarter of 2014, we increased our quarterly dividend to $0.24 per share.


	Nine Months Ended September 30,
	2014				2013
	Amount		Per Share		Amount		Per Share
Dividends	$	287	$	0.70	$	259	$	0.64

Distributions to noncontrolling interests

In conjunction with the formation of EnLink in the first quarter of 2014, we made a payment of $100 million to noncontrolling interests. Further, EnLink distributed $87 million to its non-Devon unitholders during the first nine months of 2014.

Stock option proceeds

During the first nine months of 2014, we received $92 million from stock option proceeds.

Proceeds from issuance of subsidiary units

During the nine months ended September 30, 2014, ENLK sold 2.4 million limited partner units to the public, raising net proceeds of $72 million.

Liquidity

Historically, our primary sources of capital and liquidity have been our operating cash flow, asset divestiture proceeds and cash on hand. Additionally, we maintain revolving lines of credit and a commercial paper program, which can be accessed as needed to supplement operating cash flow and cash balances. Other available sources of capital and liquidity include debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC. We estimate the combination of these sources of capital will continue to be adequate to fund future capital expenditures, debt repayments and other contractual commitments. The following sections discuss changes to our liquidity subsequent to filing our 2013 Annual Report on Form 10-K.

Operating Cash Flow

Our operating cash flow is sensitive to many variables, the most volatile of which are the prices of the oil, gas and NGLs we produce. We expect operating cash flow to continue to be our primary source of liquidity. To mitigate some of the risk inherent in prices, we have utilized various derivative financial instruments to set minimum and maximum prices on a portion of our 2014 production. The key terms to our open oil, gas and NGL derivative financial instruments as of September 30, 2014 are presented in “Part I. Financial Information – Item 1. Financial Statements – Note 3” in this report.

Credit Availability

As of September 30, 2014, we had $3.0 billion of available capacity under our syndicated, unsecured revolving line of credit (the “Senior Credit Facility”), net of letters of credit outstanding. This credit facility supports our $3.0 billion commercial paper program. At September 30, 2014, we had no outstanding commercial paper borrowings.

The Senior Credit Facility contains only one material financial covenant. This covenant requires us to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65 percent. As of September 30, 2014, we were in compliance with this covenant with a debt-to-capitalization ratio of 22.7 percent.

The Partnership has a $1.0 billion unsecured revolving credit facility, which includes a $500 million letter of credit subfacility. EnLink also has a $250 million revolving credit facility, which includes a $125 million letter of credit subfacility, as well as an additional credit agreement in association with E2 Energy Services LLC under which EnLink can borrow up to $30 million. As of September 30, 2014, there was $371 million borrowed under the $1.0 billion credit facility, and there was $81 million borrowed under the $250 million credit facility and $26 million borrowed in association with the E2 Energy Services LLC credit facility.

Partnership Acquisitions

Effective November 1, 2014, the Partnership acquired Gulf Coast natural gas pipeline assets predominantly located in southern Louisiana for $235 million, subject to certain adjustments.

Contractual Obligations

A summary of our contractual obligations as of September 30, 2014, is provided in the following table.


	Payments Due by Period
	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
	(In millions)
Debt ⁽¹⁾	$	12,066	$	1,900	$	850	$	1,353	$	7,963
Interest expense ⁽²⁾		7,693		493		970		903		5,327
Purchase obligations ⁽³⁾		5,620		201		1,751		1,755		1,913
Operational agreements ⁽⁴⁾		5,588		530		1,843		1,740		1,475
Asset retirement obligations ⁽⁵⁾		1,410		62		102		101		1,145
Drilling and facility obligations ⁽⁶⁾		327		118		91		112		6
Lease obligations ⁽⁷⁾		240		10		67		57		106
Other ⁽⁸⁾		247		14		109		45		79

Total	$	33,191	$	3,328	$	5,783	$	6,066	$	18,014

(1)	Debt amounts represent scheduled maturities of our debt obligations at September 30, 2014, excluding $7 million of net discounts included in the carrying value of debt.

(2)	Interest expense represents the scheduled obligations on long-term, fixed-rate debt and an estimate of our floating-rate debt.

(3)

Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at our heavy oil projects in Canada. We have entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in our ability to obtain condensate could negatively affect our ability to transport heavy oil at these locations. Our 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 our internal estimate of future condensate market prices.

(4)

Operational agreements represent commitments to transport or process certain volumes of oil, gas and NGLs for a fixed fee. We have entered into these agreements to aid the movement of our production to downstream markets. Operational agreements include approximately $2.1 billion of obligations between us and EnLink. The terms of the contracts with EnLink are summarized in the following table.

Minimum

Gathering

Processing

Volume

Contract

Volume

Commitment

Annual

Terms

Commitment

Term

Rate

Contract

(Years)

(MMcf/d)

(Years)

Escalators

Bridgeport gathering and processing contract

850

650

CPI

East Johnson County gathering contract

125

—

CPI

Northridge gathering and processing contract ^(a)

CPI

Cana gathering and processing contract

330

CPI

(a)

On August 29, 2014, we assigned the 10-year gathering and processing agreement to LINN Energy, in connection with our divestiture of certain non-core assets. Such assignment will be effective as of December 1, 2014. Accordingly, beginning on December 1, 2014, LINN Energy will perform our obligations under the agreement, which remains in full force and effect.

(5)	Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs.

(6)	Drilling and facility obligations represent contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction.

(7)	Lease obligations consist primarily of non-cancelable leases for office space and equipment used in our daily operations.

(8)	These amounts include $207 million related to uncertain tax positions.

Critical Accounting Estimates

Devon conducts its annual goodwill impairment test in the fourth quarter each year. As of the date of our last goodwill impairment test, the fair values of our U.S. and Canadian reporting units exceeded their related carrying values. The fair value of our U.S. reporting unit substantially exceeded its carrying value. However, the fair value of our Canadian reporting unit is not substantially in excess of its carrying value. The fair value of our Canadian reporting unit exceeded its carrying value by approximately 11 percent. As of September 30, 2014, we had $2.0 billion of goodwill allocated to the Canadian reporting unit. Significant decreases to our stock price, decreases in commodity prices, negative deviations from projected Canadian reporting unit earnings or unfavorable changes in reserves could result in a goodwill impairment charge. A goodwill impairment charge would have no effect on liquidity or capital resources. However, it would adversely affect our results of operations in that period.

Non-GAAP Measures

We make reference to “adjusted earnings attributable to Devon” and “adjusted earnings per share attributable to Devon” in “Overview of 2014 Results” in this Item 2 that are not required by or presented in accordance with GAAP. These non-GAAP measures should not be considered as alternatives to GAAP measures. Adjusted earnings attributable to Devon, as well as the per share amount, represent net earnings excluding certain non-cash or non-recurring items that are typically excluded by securities analysts in their published estimates of our financial results. Our non-GAAP measures are typically used as a quarterly performance measure. Items may appear to be recurring while comparing on an annual basis. In the below table, restructuring costs were incurred in each period. However, these costs relate to different restructuring programs. Amounts excluded for the first nine months of 2014 relate to our divestiture programs, repatriation of proceeds to the U.S. and deferred income tax on the formation of EnLink. Amounts excluded for the first nine months of 2013 relate to our office consolidation and asset impairments. For more information on our restructuring programs see Note 6 to the financial statements included in this report. We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates published by securities analysts. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers.

Adjusted Earnings and Adjusted Earnings Per Share Attributable to Devon

Below are reconciliations of our adjusted earnings and earnings per share attributable to Devon to their comparable GAAP measures.


	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013		2014			2013
	(In millions, except per share amounts)
Net earnings (loss) attributable to Devon (GAAP)	$	1,016		$	429	$	2,015		$	(227	)
Adjustments (net of taxes):
Derivatives and other financial instruments		(469	)		88		(16	)		62
Cash settlements on derivatives and financial instruments		3			2		(129	)		77

Net derivatives and financial instruments		(466	)		90		(145	)		139
Investment in EnLink deferred income tax		—			—		48			—
Restructuring costs		2			3		34			32
Current tax on property divestiture		543			—		543			—
Deferred tax on property divestiture		(543	)		—		(543	)		—
Gain on asset sales and related repatriation		—			—		(279	)		—
Asset impairments		—			4		—			1,343

Adjusted earnings attributable to Devon (Non-GAAP)	$	552		$	526	$	1,673		$	1,287


Earnings (loss) per share (GAAP)	$	2.47		$	1.05	$	4.91		$	(0.57	)
Adjustments (net of taxes):
Derivatives and other financial instruments		(1.14	)		0.21		(0.04	)		0.15
Cash settlements on derivatives and financial instruments		0.01			0.01		(0.31	)		0.18

Net derivatives and financial instruments		(1.13	)		0.22		(0.35	)		0.33
Investment in EnLink taxes		—			—		0.12			—
Restructuring costs		—			0.01		0.08			0.08
Current tax on property divestiture		1.32			—		1.32			—
Deferred tax on property divestiture		(1.32	)		—		(1.32	)		—
Gain on asset sales and related repatriation		—			—		(0.68	)		—
Asset impairments		—			0.01		—			3.32

Adjusted earnings per share (Non-GAAP)	$	1.34		$	1.29	$	4.08		$	3.16

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

We have commodity derivatives that pertain to a portion of our production for the last three months of 2014, as well as 2015 and 2016. The key terms to our open oil, gas and NGL derivative financial instruments as of September 30, 2014 are presented in “Part I. Financial Information – Item 1. Financial Statements – Note 3” in this report.

The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At September 30, 2014, a 10 percent change in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by the following amounts:


	10% Increase			10% Decrease
	(In millions)
Gain (loss):
Gas derivatives	$	(144	)	$	133
Oil derivatives	$	(518	)	$	520

Interest Rate Risk

At September 30, 2014, we had total debt outstanding of $12.1 billion. Of this amount, $10.8 billion bears fixed interest rates averaging 4.8 percent. The remaining $1.3 billion of debt is comprised of floating rate debt that at September 30, 2014 had rates averaging 1.2 percent.

As of September 30, 2014, we had open interest rate swap positions that are presented in “Part I. Financial Information – Item 1. Financial Statements – Note 3” in this report. The fair values of our interest rate swaps are largely determined by estimates of the forward curves of the 3 month LIBOR rate. A 10 percent change in these forward curves would not have materially impacted our balance sheet at September 30, 2014.

Foreign Currency Risk

Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. A 10 percent unfavorable change in the Canadian-to-U.S. dollar exchange rate would not materially impact our September 30, 2014 balance sheet.

Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, one of these foreign subsidiaries holds Canadian-dollar cash and engages in short-term intercompany loans with Canadian subsidiaries that are based in Canadian dollars. The value of the Canadian-dollar cash and intercompany loans increases or decreases from the remeasurement of the cash and loans into the U.S. dollar functional currency. Additionally, at September 30, 2014, we held foreign currency exchange forward contracts to hedge exposures to fluctuations in exchange rates on the Canadian-dollar cash and intercompany loans. The increase or decrease in the value of the forward contracts is offset by the increase or decrease to the U.S. dollar equivalent of the Canadian-dollar cash and intercompany loans. Based on the amount of the cash and intercompany loans as of September 30, 2014, a 10 percent change in the foreign currency exchange rates would not have materially impacted our balance sheet.

Item 4.

Controls and Procedures

Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that material information relating to Devon, including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to other members of senior management and the Board of Directors.

Based on their evaluation, our principal executive and principal financial officers have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of September 30, 2014, to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. Other Information

Item 1. Legal Proceedings

There have been no material changes to the information included in Item 3. “Legal Proceedings” in our 2013 Annual Report on Form 10-K.

Item 1A. Risk Factors

There have been no material changes to the information included in Item 1A. “Risk Factors” in our 2013 Annual Report on Form 10-K.

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

The following table provides information regarding purchases of our common stock that were made by us during the third quarter of 2014.


Period	Total Number of Shares Purchased⁽¹⁾		Average Price Paid per Share

July 1 - July 31		1,311	$	76.32
August 1 - August 31		1,375	$	74.16
September 1 - September 30		11,087	$	70.43

Total		13,773	$	71.36

(1)	Share repurchases represent shares received by us from employees and directors for the payment of personal income tax withholding on restricted stock vesting and stock option exercises.

Under the Devon Energy Corporation Incentive Savings Plan (the “Plan”), eligible employees may purchase shares of our common stock through an investment in the Devon Stock Fund (the “Stock Fund”), which is administered by an independent trustee. Eligible employees purchased approximately 13,500 shares of our common stock in the third quarter of 2014, at then-prevailing stock prices, that they held through their ownership in the Stock Fund. We acquired the shares of our common stock sold under the Plan through open-market purchases.

Similarly, under the Devon Canada Corporation Savings Plan (the “Canadian Plan”), eligible Canadian employees may purchase shares of our common stock through an investment in the Canadian Plan, which is administered by an independent trustee, Sun Life Assurance Company of Canada. Shares sold under the Canadian Plan were acquired through open-market purchases. These shares and any interest in the Canadian Plan were offered and sold in reliance on the exemptions for offers and sales of securities made outside of the U.S., including under Regulation S for offers and sales of securities to employees pursuant to an employee benefit plan established and administered in accordance with the law of a country other than the U.S. In the third quarter of 2014, there were no shares purchased by Canadian employees.

Item 3.

Defaults Upon Senior Securities

Not applicable.

Item 4.

Mine Safety Disclosures

Not applicable.

Item 5.

Other Information

Not applicable.

Item 6.

Exhibits

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


Exhibit Number		Description

10.1		Extension Agreement dated as of October 17, 2014 to the Credit Agreement dated as of October 24, 2012, among Registrant, as U.S. Borrower, Devon NEC Corporation and Devon Canada Corporation, as Canadian Borrowers, Devon Financing Company, L.L.C., the consenting lenders, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender with respect to the extension of the maturity date from October 24, 2018 to October 24, 2019.

31.1		Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB		XBRL Taxonomy Extension Labels Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

SIGNATURES

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


				DEVON ENERGY CORPORATION

Date: November 5, 2014				/s/ Jeremy D. Humphers
				Jeremy D. Humphers
				Senior Vice President and Chief Accounting Officer

INDEX TO EXHIBITS


Exhibit Number		Description

10.1		Extension Agreement dated as of October 17, 2014 to the Credit Agreement dated as of October 24, 2012, among Registrant, as U.S. Borrower, Devon NEC Corporation and Devon Canada Corporation, as Canadian Borrowers, Devon Financing Company, L.L.C., the consenting lenders, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender with respect to the extension of the maturity date from October 24, 2018 to October 24, 2019.

31.1		Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB		XBRL Taxonomy Extension Labels Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document