DEVON ENERGY CORP/DE - Quarter Report: 2014 June (Form 10-Q)

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended June 30, 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 þ 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 þ 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 þ

On July 23, 2014, 409.1 million shares of common stock were outstanding.

DEVON ENERGY CORPORATION

FORM 10-Q

TABLE OF CONTENTS


Part I. Financial Information
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			27
Item 3. Quantitative and Qualitative Disclosures About Market Risk			42
Item 4. Controls and Procedures			42

Part II. Other Information
Item 1. Legal Proceedings			44
Item 1A. Risk Factors			44
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			44
Item 3. Defaults Upon Senior Securities			44
Item 4. Mine Safety Disclosures			44
Item 5. Other Information			44
Item 6. Exhibits			45

Signatures			46

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						Six Months
	Ended June 30,						Ended June 30,
	2014			2013			2014			2013
	(Unaudited)
	(In millions, except per share amounts)
Oil, gas and NGL sales	$	2,679		$	2,222		$	5,236		$	4,026
Oil, gas and NGL derivatives		(399	)		366			(719	)		46
Marketing and midstream revenues		2,230			500			3,718			987

Total operating revenues		4,510			3,088			8,235			5,059

Lease operating expenses		582			559			1,180			1,084
Marketing and midstream operating expenses		2,006			382			3,311			745
General and administrative expenses		189			167			400			317
Production and property taxes		150			125			287			238
Depreciation, depletion and amortization		828			674			1,567			1,378
Asset impairments		—			40			—			1,953
Restructuring costs		5			8			42			46
Gains and losses on asset sales		(1,057	)		1			(1,072	)		—
Other operating items		33			32			56			55

Total operating expenses		2,736			1,988			5,771			5,816

Operating income (loss)		1,774			1,100			2,464			(757	)
Net financing costs		131			103			243			206
Other nonoperating items		89			—			107			2

Earnings (loss) before income taxes		1,554			997			2,114			(965	)
Income tax expense (benefit)		854			314			1,085			(309	)

Net earnings (loss)		700			683			1,029			(656	)
Net earnings attributable to noncontrolling interests		25			—			30			—

Net earnings (loss) attributable to Devon	$	675		$	683		$	999		$	(656	)

Net earnings (loss) per share attributable to Devon:
Basic	$	1.65		$	1.69		$	2.45		$	(1.63	)
Diluted	$	1.64		$	1.68		$	2.44		$	(1.63	)
Comprehensive earnings (loss):
Net earnings (loss)	$	700		$	683		$	1,029		$	(656	)
Other comprehensive earnings (loss), net of tax:
Foreign currency translation		292			(271	)		(6	)		(454	)
Pension and postretirement plans		5			5			8			9

Other comprehensive earnings (loss), net of tax		297			(266	)		2			(445	)

Comprehensive earnings (loss)		997			417			1,031			(1,101	)
Comprehensive earnings attributable to noncontrolling interests		25			—			30			—

Comprehensive earnings (loss) attributable to Devon	$	972		$	417		$	1,001		$	(1,101	)

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months
	Ended June 30,
	2014			2013
	(Unaudited)
	(In millions)
Cash flows from operating activities:
Net earnings (loss)	$	1,029		$	(656	)
Adjustments to reconcile net earnings (loss) to net cash from operating activities:
Depreciation, depletion and amortization		1,567			1,378
Gain on asset sales		(1,072	)		—
Asset impairments		—			1,953
Deferred income tax expense (benefit)		777			(441	)
Derivatives and other financial instruments		761			(103	)
Cash settlements on derivatives and financial instruments		(245	)		149
Other noncash charges		229			176
Net change in working capital		470			(128	)
Change in long-term other assets		(77	)		22
Change in long-term other liabilities		20			48

Net cash from operating activities		3,459			2,398

Cash flows from investing activities:
Acquisitions of property, equipment and businesses		(6,224	)		—
Capital expenditures		(3,341	)		(3,569	)
Proceeds from property and equipment divestitures		2,942			34
Purchases of short-term investments		—			(1,076	)
Redemptions of short-term investments		—			2,550
Redemptions of long-term investments		57			—
Other		84			82

Net cash from investing activities		(6,482	)		(1,979	)

Cash flows from financing activities:
Proceeds from borrowings of long-term debt, net of issuance costs		3,720			—
Net short-term debt repayments		(862	)		(1,495	)
Long-term debt repayments		(3,990	)		—
Proceeds from stock option exercises		83			1
Proceeds from issuance of subsidiary units		20			—
Dividends paid on common stock		(189	)		(170	)
Distributions to noncontrolling interests		(141	)		—
Other		9			5

Net cash from financing activities		(1,350	)		(1,659	)

Effect of exchange rate changes on cash		13			(34	)

Net change in cash and cash equivalents		(4,360	)		(1,274	)
Cash and cash equivalents at beginning of period		6,066			4,637

Cash and cash equivalents at end of period	$	1,706		$	3,363

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	June 30,			December 31,
	2014			2013
	(Unaudited)
	(In millions, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	1,706		$	6,066
Accounts receivable		2,301			1,520
Other current assets		385			419

Total current assets		4,392			8,005

Property and equipment, at cost:
Oil and gas, based on full cost accounting:
Subject to amortization		75,242			73,995
Not subject to amortization		3,984			2,791

Total oil and gas		79,226			76,786
Other		8,956			6,195

Total property and equipment, at cost		88,182			82,981
Less accumulated depreciation, depletion and amortization		(51,183	)		(54,534	)

Property and equipment, net		36,999			28,447

Goodwill		8,408			5,858
Other long-term assets		1,316			567

Total assets	$	51,115		$	42,877

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,529		$	1,229
Revenues and royalties payable		1,581			786
Short-term debt		475			4,066
Other current liabilities		1,094			574

Total current liabilities		4,679			6,655

Long-term debt		11,880			7,956
Asset retirement obligations		1,541			2,140
Other long-term liabilities		1,029			834
Deferred income taxes		5,927			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		3,943			3,780
Retained earnings		16,220			15,410
Accumulated other comprehensive earnings		1,270			1,268

Total stockholders’ equity attributable to Devon		21,474			20,499
Noncontrolling interests		4,585			—

Total stockholders’ equity		26,059			20,499

Commitments and contingencies (Note 17)
Total liabilities and stockholders’ equity	$	51,115		$	42,877

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY



											Accumulated
					Additional						Other									Total
	Common Stock				Paid-In			Retained			Comprehensive			Treasury			Noncontrolling			Stockholders’
	Shares		Amount		Capital			Earnings			Earnings			Stock			Interests			Equity
	(Unaudited)
	(In millions)
Six Months Ended June 30, 2014
Balance as of December 31, 2013		406	$	41	$	3,780		$	15,410		$	1,268		$	—		$	—		$	20,499
Net earnings		—		—		—			999			—			—			30			1,029
Other comprehensive earnings, net of tax		—		—		—			—			2			—			—			2
Stock option exercises		1		—		83			—			—			—			—			83
Restricted stock grants, net of cancellations		2		—		—			—			—			—			—			—
Common stock repurchased		—		—		—			—			—			(5	)		—			(5	)
Common stock retired		—		—		(5	)		—			—			5			—			—
Common stock dividends		—		—		—			(189	)		—			—			—			(189	)
Share-based compensation		—		—		84			—			—			—			—			84
Share-based compensation tax benefits		—		—		1			—			—			—			—			1
Subsidiary equity transactions		—		—		—			—			—			—			27			27
Acquisition of noncontrolling interests		—		—		—			—			—			—			4,664			4,664
Distributions to noncontrolling interests		—		—		—			—			—			—			(141	)		(141	)
Other		—		—		—			—			—			—			5			5

Balance as of June 30, 2014		409	$	41	$	3,943		$	16,220		$	1,270		$	—		$	4,585		$	26,059

Six Months Ended June 30, 2013
Balance as of December 31, 2012		406	$	41	$	3,688		$	15,778		$	1,771		$	—		$	—		$	21,278
Net loss		—		—		—			(656	)		—			—			—			(656	)
Other comprehensive loss, net of tax		—		—		—			—			(445	)		—			—			(445	)
Stock option exercises		—		—		1			—			—			—			—			1
Common stock repurchased		—		—		—			—			—			(9	)		—			(9	)
Common stock retired		—		—		(9	)		—			—			9			—			—
Common stock dividends		—		—		—			(170	)		—			—			—			(170	)
Share-based compensation		—		—		62			—			—			—			—			62
Share-based compensation tax benefits		—		—		5			—			—			—			—			5

Balance as of June 30, 2013		406	$	41	$	3,747		$	14,952		$	1,326		$	—		$	—		$	20,066

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 six-month periods ended June 30, 2014 and 2013 and Devon’s financial position as of June 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 in calendar year 2017. Devon 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		1.0	x

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		546
Equity investment		222
Goodwill⁽¹⁾		3,292
Other long term assets		1
Liabilities assumed:
Current liabilities		(515	)
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 assets and liabilities) 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 June 30, 2014				Six Months Ended June 30, 2014
	GeoSouthern		EnLink		GeoSouthern		EnLink
	(In millions)				(In millions)
Total operating revenues	$	586	$	771	$	740	$	970
Total operating expenses		312		765		386		962

Operating income	$	274	$	6	$	354	$	8

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.


	Six Months Ended June 30,
	2014		2013
	(In millions)
Total operating revenues	$	8,882	$	6,211
Net earnings (loss)	$	1,043	$	(635	)
Noncontrolling interests	$	43	$	28
Net earnings (loss) attributable to Devon	$	1,000	$	(663	)
Net earnings (loss) per common share attributable to Devon	$	2.45	$	(1.63	)

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) during the first six months of 2014. 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.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 June 30, 2014, Devon reached an agreement to sell its U.S. non-core assets for $2.3 billion to Linn Energy. The transaction with Linn Energy is expected to close in the third quarter of 2014. No gain or loss is expected to be recognized on the U.S. non-core asset divestiture.

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. As of June 30, 2014, Devon did not hold any cash collateral from its counterparties.

Commodity Derivatives

As of June 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)
Q3-Q4 2014		75,000	$	94.14		64,750	$	89.33	$	100.00		42,000	$	116.43
Q1-Q4 2015		100,492	$	90.95		27,000	$	89.14	$	97.84		28,000	$	116.43
Q1-Q4 2016		—	$	—		—	$	—	$	—		18,500	$	103.11

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


	Basis Swaps
Period	Index	Volume (Bbls/d)		Weighted Average Differential to WTI ($/Bbl)
Q3 2014	Western Canadian Select		30,000	$	(18.21	)

As of June 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 index.


	Price Swaps				Price Collars						Call Options Sold
Period	Volume (MMBtu/d)		Weighted Average Price ($/MMBtu)		Volume (MMBtu/d)		Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)		Volume (MMBtu/d)		Weighted Average Price ($/MMBtu)
Q3-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

Basis Swaps

Period

Index

Volume
(MMBtu/d)

Weighted Average Differential
to Henry Hub ($/MMBtu)

Q3-Q4 2014

AECO

94,781

(0.52

)

Interest Rate Derivatives

As of June 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 June 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

0.931

September 2014

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Financial Statement Presentation

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


	Three Months Ended June 30,					Six Months Ended June 30,
	2014			2013		2014			2013
	(In millions)
Commodity derivatives	$	(399	)	$	366	$	(719	)	$	46
EnLink commodity derivatives		(2	)		—		(3	)		—
Interest rate derivatives		1			—		1			—
Foreign currency derivatives		(54	)		42		(40	)		57

Net gains (losses) recognized in comprehensive statements of earnings	$	(454	)	$	408	$	(761	)	$	103

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


	Balance Sheet Caption	June 30, 2014		December 31, 2013
		(In millions)
Asset derivatives:
Commodity derivatives	Other current assets	$	6	$	75
Commodity derivatives	Other long-term assets		11		28
Interest rate derivatives	Other current assets		1		—

Total asset derivatives		$	18	$	103

Liability derivatives:
Commodity derivatives	Other current liabilities	$	386	$	58
Commodity derivatives	Other long-term liabilities		157		62
EnLink commodity derivatives	Other current liabilities		1		—
EnLink commodity derivatives	Other long-term liabilities		1		—
Foreign currency derivatives	Other current liabilities		5		1

Total liability derivatives		$	550	$	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 six months of 2014 includes $6 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.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


	Six Months Ended June 30,
	2014		2013
	(In millions)
Gross general and administrative expense	$	106	$	79
Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties	$	27	$	30
Related income tax benefit	$	13	$	12

Under its 2009 Long-Term Incentive Plan, as amended, Devon granted share-based awards to certain employees in the first six 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		3,343		$	63.18
Vested		(505	)	$	60.87
Forfeited		(521	)	$	60.62

Unvested at June 30, 2014		5,609		$	61.50

As of June 30, 2014, Devon’s unrecognized compensation cost related to unvested restricted stock awards and units was $255 million. Such cost is expected to be recognized over a weighted-average period of 2.6 years.

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 June 30, 2014		475		$	59.20

As of June 30, 2014, Devon’s unrecognized compensation cost related to these awards was $10 million. Such cost is expected to be recognized over a weighted-average period of 1.7 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

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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		(137	)	$	79.74

Unvested at June 30, 2014 ⁽¹⁾		1,496		$	70.90

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

As of June 30, 2014, Devon’s unrecognized compensation cost related to unvested units was $48 million. Such cost is expected to be recognized over a weighted-average period of 1.8 years.

5. Asset Impairments

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


	Six Months Ended June 30, 2013
	Gross		Net of Taxes
	(In millions)
U.S. oil and gas assets	$	1,110	$	707
Canada oil and gas assets		843		632

Total asset impairments	$	1,953	$	1,339

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.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

6. Restructuring Costs

Canadian Divestitures

In the first six months of 2014, Devon recognized $42 million of employee related 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 June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(In millions)
Canada divestitures:
Employee related costs	$	5	$	—	$	42	$	—
Office consolidation:
Lease obligations and other		—		8		—		46

Restructuring costs	$	5	$	8	$	42	$	46

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		5			2			7
Changes due to office consolidation		(20	)		(1	)		(21	)
Changes due to offshore divestiture		(1	)		(1	)		(2	)

Balance as June 30, 2014	$	11		$	18		$	29

Balance as of December 31, 2012	$	52		$	9		$	61
Changes due to office consolidation		(7	)		11			4
Changes due to offshore divestiture		(1	)		(1	)		(2	)

Balance as of June 30, 2013	$	44		$	19		$	63

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Total income tax expense (benefit) (in millions)	$	854		$	314		$	1,085		$	(309	)

U.S. statutory income tax rate		35	%		35	%		35	%		(35	%)
Repatriations		16	%		—			12	%		—
State income taxes		—			1	%		1	%		(1	%)
Taxation on Canadian operations		4	%		(2	%)		2	%		6	%
Taxes on EnLink formation		—			—			2	%		—
Other		—			(2	%)		(1	%)		(2	%)

Effective income tax rate		55	%		32	%		51	%		(32	%)

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.

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.


				Common			Earnings (loss)
	Earnings (loss)			Shares			per Share
	(In millions, except per share amounts)
Three Months Ended June 30, 2014:
Net earnings attributable to Devon	$	675			408
Attributable to participating securities		(8	)		(4	)

Basic earnings per share		667			404		$	1.65
Dilutive effect of potential common shares issuable		—			2

Diluted earnings per share	$	667			406		$	1.64

Three Months Ended June 30, 2013:
Net earnings attributable to Devon	$	683			406
Attributable to participating securities		(5	)		(4	)

Basic earnings per share		678			402		$	1.69
Dilutive effect of potential common shares issuable		—			1

Diluted earnings per share	$	678			403		$	1.68

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


Six Months Ended June 30, 2014:
Net earnings attributable to Devon	$	999		408
Attributable to participating securities		(10	)	(4	)

Basic earnings per share		989		404		$	2.45
Dilutive effect of potential common shares issuable		—		2

Diluted earnings per share	$	989		406		$	2.44

Six Months Ended June 30, 2013:
Net loss attributable to Devon	$	(656	)	406
Attributable to participating securities		(1	)	(4	)

Basic loss per share		(657	)	402		$	(1.63	)
Dilutive effect of potential common shares issuable		—		—

Diluted loss per share	$	(657	)	402		$	(1.63	)

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 six-month periods ended June 30, 2014, 2.6 million shares and 3.4 million shares, respectively, were excluded from the diluted earnings per share calculations. During the three-month and six-month periods ended June 30, 2013, 7.6 million shares were excluded from the diluted earnings per share calculations.

9. Other Comprehensive Earnings

Components of other comprehensive earnings consist of the following:


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
		(In millions)
Foreign currency translation:
Beginning accumulated foreign currency translation	$	1,150		$	1,813		$	1,448		$	1,996
Change in cumulative translation adjustment		306			(284	)		(7	)		(475	)
Income tax benefit (expense)		(14	)		13			1			21

Ending accumulated foreign currency translation		1,442			1,542			1,442			1,542

Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits		(177	)		(221	)		(180	)		(225	)
Recognition of net actuarial loss and prior service cost in earnings⁽¹⁾		6			6			11			12
Income tax expense		(1	)		(1	)		(3	)		(3	)

Ending accumulated pension and postretirement benefits		(172	)		(216	)		(172	)		(216	)

Accumulated other comprehensive earnings, net of tax	$	1,270		$	1,326		$	1,270		$	1,326

(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).

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

10. Supplemental Information to Statements of Cash Flows


	Six Months Ended June 30,
	2014			2013
	(In millions)
Net change in working capital accounts:
Accounts receivable	$	(234	)	$	(300	)
Other current assets		(30	)		72
Accounts payable		45			56
Revenues and royalties payable		508			82
Other current liabilities		181			(38	)

Net change in working capital	$	470		$	(128	)

Interest paid (net of capitalized interest)	$	235		$	208
Income taxes paid (received)	$	113		$	(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.

11. Accounts Receivable

The components of accounts receivable include the following:


	June 30, 2014			December 31, 2013
	(In millions)
Oil, gas and NGL sales	$	1,022		$	851
Joint interest billings		468			447
Marketing and midstream revenues		773			172
Other		49			61

Gross accounts receivable		2,312			1,531
Allowance for doubtful accounts		(11	)		(11	)

Net accounts receivable	$	2,301		$	1,520

12. Goodwill

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


	June 30, 2014		December 31, 2013
	(In millions)
U.S.	$	2,618	$	2,618
Canada		2,096		2,838
EnLink		3,694		402

Total	$	8,408	$	5,858

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The changes to Devon’s goodwill during the first six 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.

13. Debt


	June 30, 2014			December 31, 2013
	(In millions)
Devon debt
Commercial paper	$	456		$	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		10,661			12,022

EnLink debt
Credit facilities		255			—
Other borrowings		24			—
2.70% due April 1, 2019		400			—
7.125% due June 1, 2022		197			—
4.40% due April 1, 2024		450			—
5.60% due April 1, 2044		350			—
Net premium on debentures and notes		18			—

Total EnLink debt		1,694			—

Total debt		12,355			12,022
Less amount classified as short-term debt⁽¹⁾		475			4,066

Total long-term debt	$	11,880		$	7,956

(1)

Short-term debt as of June 30, 2014 consists of $456 million of commercial paper and $19 million of EnLink’s 2022 senior notes, which were redeemed on July 20, 2014. 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

As of June 30, 2014, Devon had $456 million of outstanding commercial paper at an average rate of 0.24 percent.

Credit Lines

Devon has a $3.0 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). As of June 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 June 30, 2014, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 23.4 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. in June 2014.

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

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

The Partnership has a $1.0 billion unsecured revolving credit facility, which includes a $500 million letter of credit subfacility. As of June 30, 2014, there were $14.1 million in outstanding letters of credit and $160.0 million outstanding borrowings under the $1.0 billion credit facility, leaving $825.9 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 $20 million. On April 9, 2014, the credit agreement was amended to increase the borrowing capacity to $30 million. As of June 30, 2014, EnLink’s outstanding borrowings under the $250 million credit facility were $95 million and $23 million in association with the E2 Energy Services LLC credit agreement. Additionally, as of June 30, 2014, E2 Services had certain promissory notes outstanding related to its vehicle fleet in the amount of $0.5 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.


	Six Months Ended June 30,
	2014			2013
	(In millions)
Asset retirement obligations as of beginning of period	$	2,228		$	2,095
Liabilities incurred		64			67
Liabilities settled		(22	)		(40	)
Revision of estimated obligation		69			105
Liabilities assumed by others		(731	)		(4	)
Accretion expense on discounted obligation		50			57
Foreign currency translation adjustment		(26	)		(72	)

Asset retirement obligations as of end of period		1,632			2,208
Less current portion		91			87

Asset retirement obligations, long-term	$	1,541		$	2,121

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

During the first six months of 2014, Devon reduced its asset retirement obligations approximately $700 million for those obligations that were assumed by the purchasers of Devon’s Canadian 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						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2014			2013			2014			2013			2014			2013			2014			2013
	(In millions)
Service cost	$	8		$	9		$	15		$	18		$	—		$	—		$	—		$	—
Interest cost		13			13			27			26			—			1			—			1
Expected return on plan assets		(14	)		(16	)		(27	)		(31	)		—			—			—			—
Amortization of prior service cost ⁽¹⁾		1			1			2			2			—			—			—			—
Net actuarial loss (gain)⁽¹⁾		6			6			10			11			(1	)		(1	)		(1	)		(1	)

Net periodic benefit cost ⁽²⁾	$	14		$	13		$	27		$	26		$	(1	)	$	—		$	(1	)	$	—

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

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

16. Stockholders’ Equity

Dividends

Devon paid common stock dividends of $189 million and $170 million in the first six 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.

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 $41 million to its non-Devon unitholders during the first six months of 2014.

Issuance of subsidiary units

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

Through June 30, 2014, the Partnership sold an aggregate of 0.6 million common units under the EDA, generating proceeds of approximately $20 million. The Partnership used the net proceeds for general partnership purposes, including working capital, capital expenditures and repayments of indebtedness.

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 June 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)
June 30, 2014 assets (liabilities):
Cash equivalents	$	1,201		$	1,201		$	59	$	1,142		$	—
Commodity derivatives	$	17		$	17		$	—	$	17		$	—
Commodity derivatives	$	(543	)	$	(543	)	$	—	$	(543	)	$	—
EnLink commodity derivatives	$	(2	)	$	(2	)	$	—	$	(2	)	$	—
Interest rate derivatives	$	1		$	1		$	—	$	1		$	—
Foreign currency derivatives	$	(5	)	$	(5	)	$	—	$	(5	)	$	—
Debt	$	(12,355	)	$	(13,885	)	$	—	$	(13,885	)	$	—
Capital lease obligations	$	22		$	22		$	—	$	22		$	—
December 31, 2013 assets (liabilities):
Cash equivalents	$	5,305		$	5,305		$	4,191	$	1,114		$	—
Long-term investments	$	62		$	62		$	—	$	—		$	62

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


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 all 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 June 30, 2014:
Revenues from external customers	$	3,252		$	506		$	752	$	—		$	4,510
Intersegment revenues	$	—		$	—		$	175	$	(175	)	$	—
Depreciation, depletion and amortization	$	642		$	112		$	74	$	—		$	828
Interest expense	$	108		$	22		$	14	$	(11	)	$	133
Earnings before income taxes	$	362		$	1,109		$	83	$	—		$	1,554
Income tax expense	$	378		$	458		$	18	$	—		$	854
Net earnings (loss)	$	(16	)	$	651		$	65	$	—		$	700
Noncontrolling interests	$	1		$	—		$	24	$	—		$	25
Net earnings (loss) attributable to Devon	$	(17	)	$	651		$	41	$	—		$	675
Capital expenditures	$	1,432		$	278		$	216	$	—		$	1,926

Three Months Ended June 30, 2013:
Revenues from external customers	$	2,127		$	722		$	239	$	—		$	3,088
Intersegment revenues	$	—		$	—		$	349	$	(349	)	$	—
Depreciation, depletion and amortization	$	419		$	209		$	46	$	—		$	674
Interest expense	$	94		$	23		$	—	$	(9	)	$	108
Asset impairments	$	—		$	40		$	—	$	—		$	40
Earnings before income taxes	$	849		$	102		$	46	$	—		$	997
Income tax expense	$	277		$	20		$	17	$	—		$	314
Net earnings	$	572		$	82		$	29	$	—		$	683
Capital expenditures	$	1,087		$	356		$	53	$	—		$	1,496

Six Months Ended June 30, 2014:
Revenues from external customers	$	5,868		$	1,190		$	1,177	$	—		$	8,235
Intersegment revenues	$	—		$	—		$	473	$	(473	)	$	—
Depreciation, depletion and amortization	$	1,139		$	306		$	122	$	—		$	1,567
Interest expense	$	208		$	41		$	19	$	(20	)	$	248
Earnings before income taxes	$	758		$	1,201		$	155	$	—		$	2,114
Income tax expense	$	564		$	479		$	42	$	—		$	1,085
Net earnings	$	194		$	722		$	113	$	—		$	1,029
Net earnings attributable to noncontrolling interests	$	1		$	—		$	29	$	—		$	30
Net earnings attributable to Devon	$	193		$	722		$	84	$	—		$	999
Property and equipment, net	$	25,606		$	7,009		$	4,384	$	—		$	36,999
Total assets	$	30,631		$	11,224		$	9,379	$	(119	)	$	51,115
Capital expenditures	$	8,535		$	720		$	284	$	—		$	9,539

Six Months Ended June 30, 2013:
Revenues from external customers	$	3,346		$	1,261		$	452	$	—		$	5,059
Intersegment revenues	$	—		$	—		$	663	$	(663	)	$	—
Depreciation, depletion and amortization	$	843		$	444		$	91	$	—		$	1,378
Interest expense	$	190		$	42		$	—	$	(14	)	$	218
Asset impairments	$	1,110		$	843		$	—	$	—		$	1,953
Earnings (loss) before income taxes	$	(270	)	$	(778	)	$	83	$	—		$	(965	)
Income tax expense (benefit)	$	(131	)	$	(208	)	$	30	$	—		$	(309	)
Net earnings (loss)	$	(139	)	$	(570	)	$	53	$	—		$	(656	)
Capital expenditures	$	2,258		$	940		$	136	$	—		$	3,334

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 six-month periods ended June 30, 2014, compared to the three-month and six-month periods ended June 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 June 30,							Six Months Ended June 30,
	2014		2013		Change			2014		2013			Change
	($ in millions, except per share amounts)
Net earnings (loss) attributable to Devon	$	675	$	683		-1	%	$	999	$	(656	)		+252	%
Adjusted earnings attributable to Devon⁽¹⁾	$	574	$	491		+17	%	$	1,121	$	761			+47	%
Earnings (loss) per share attributable to Devon	$	1.64	$	1.68		-2	%	$	2.44	$	(1.63	)		+249	%
Adjusted earnings per share attributable to Devon⁽¹⁾	$	1.40	$	1.21		+16	%	$	2.74	$	1.87			+46	%
Production (MBoe/d)		667		698		-4	%		679		692			-2	%
Realized price per Boe	$	44.12	$	35.00		+26	%	$	42.61	$	32.13			+33	%
Adjusted operating income per Boe⁽²⁾	$	28.69	$	22.05		+30	%	$	27.05	$	20.13			+34	%
Operating cash flow	$	2,049	$	1,396		+47	%	$	3,459	$	2,398			+44	%
Capitalized costs	$	1,926	$	1,496		+29	%	$	9,539	$	3,334			+186	%
Shareholder distributions	$	99	$	88		+11	%	$	189	$	170			+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, commodity derivatives settlements and marketing and midstream operations, less expenses for lease operations, marketing and midstream operations, general and administrative, production and property taxes and net financing costs, with the result divided by total production.

During the three-month and six-month periods ended June 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 results were driven primarily by increases in oil and gas prices, liquids volumes and oil and gas realizations. These factors also contributed to higher operating cash flow which caused our cash flow deficit to narrow considerably in 2014.

During the first six months of 2014, we made significant progress toward three strategic initiatives that are 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 over 7 MMBoe from our Eagle Ford development, with oil accounting for over 60% of our production from the play.

On March 7, 2014, we, Crosstex Energy, Inc. and Crosstex Energy, L.P. (collectively “Crosstex”) 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 are nearing completion of 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). This divestiture included approximately 170 MMBoe of proved reserves. Production associated with the divested properties was approximately 79 MBoe/d, including 357 MMcf/d of natural gas in the first quarter of 2014. Additionally, on June 30, 2014, we reached an agreement with Linn Energy to sell our U.S. non-core assets for $2.3 billion. This transaction is expected to close in the third quarter of 2014.

In the second quarter, we repatriated $2.8 billion to the U.S. from the Canadian divestiture. We used those proceeds, cash on hand and free cash flow generated during the quarter to reduce debt balances by $3.2 billion.

Results of Operations

Oil, Gas and NGL Production


	Three Months Ended June 30,							Six Months Ended June 30,
	2014		2013		Change			2014		2013		Change
Oil (MBbls/d)
Anadarko Basin		11		9		+24	%		10		9		+17	%
Barnett Shale		2		2		-13	%		2		2		+5	%
Eagle Ford		40		—		N/M			25		—		N/M
Mississippian-Woodford Trend		9		3		+162	%		9		3		+240	%
Permian Basin		55		46		+21	%		55		43		+28	%
Rockies		8		8		-0	%		8		7		+8	%
Other		3		3		+0	%		3		3		+0	%

U.S. core and emerging properties		128		71		+79	%		112		67		+68	%
Canada		25		29		-9	%		26		28		-8	%

Total core and emerging properties		153		100		+54	%		138		95		+45	%
Non-core properties		4		16		-73	%		10		17		-42	%

Total		157		116		+36	%		148		112		+32	%

Bitumen (MBbls/d)
Canada		52		53		-3	%		52		54		-4	%
Gas (MMcf/d)
Anadarko Basin		309		281		+10	%		295		275		+7	%
Barnett Shale		932		1,040		-10	%		931		1,049		-11	%
Eagle Ford		86		—		N/M			54		—		N/M
Mississippian-Woodford Trend		28		8		+239	%		28		7		+320	%
Permian Basin		134		106		+26	%		128		97		+31	%
Rockies		67		79		-15	%		68		77		-11	%
Other		135		164		-18	%		137		162		-15	%

U.S. core and emerging properties		1,691		1,678		+1	%		1,641		1,667		-2	%
Canada		23		32		-26	%		23		35		-37	%

Total core and emerging properties		1,714		1,710		+0	%		1,664		1,702		-2	%
Non-core properties		217		730		-70	%		397		730		-46	%

Total		1,931		2,440		-21	%		2,061		2,432		-15	%

NGLs (MBbls/d)
Anadarko Basin		31		24		+26	%		30		24		+23	%
Barnett Shale		55		54		+3	%		55		53		+3	%
Eagle Ford		10		—		N/M			7		—		N/M
Mississippian-Woodford Trend		5		1		+553	%		5		1		+893	%
Permian Basin		18		13		+37	%		17		13		+33	%
Rockies		1		2		-59	%		1		1		-24	%
Other		10		11		-9	%		10		11		-9	%

U.S. core and emerging properties		130		105		+24	%		125		103		+21	%
Non-core properties		6		17		-63	%		11		18		-38	%

Total		136		122		+12	%		136		121		+12	%

Combined (MBoe/d)
Anadarko Basin		93		80		+16	%		89		79		+13	%
Barnett Shale		212		230		-7	%		212		230		-8	%
Eagle Ford		65		—		N/M			41		—		N/M
Mississippian-Woodford Trend		18		5		+236	%		19		4		+335	%
Permian Basin		95		76		+25	%		93		72		+30	%
Rockies		21		24		-14	%		21		22		-5	%
Other		35		41		-15	%		36		41		-12	%

U.S. core and emerging properties		539		456		+18	%		511		448		+14	%
Canada		81		87		-6	%		81		88		-8	%

Total core and emerging properties		620		543		+14	%		592		536		+10	%
Non-core properties		47		155		-70	%		87		156		-44	%

Total		667		698		-4	%		679		692		-2	%

Oil, Gas and NGL Pricing


	Three Months Ended June 30,							Six Months Ended June 30,
	2014 ⁽¹⁾		2013 ⁽¹⁾		Change			2014 ⁽¹⁾		2013 ⁽¹⁾		Change
Oil (per Bbl)
U.S.	$	95.71	$	91.56		+5	%	$	93.96	$	89.64		+5	%
Canada	$	76.60	$	72.47		+6	%	$	73.48	$	64.76		+13	%
Total	$	92.59	$	85.02		+9	%	$	89.64	$	80.73		+11	%
Bitumen (per Bbl)
Canada	$	65.88	$	53.90		+22	%	$	60.47	$	41.10		+47	%
Gas (per Mcf)
U.S.	$	4.19	$	3.49		+20	%	$	4.26	$	3.15		+35	%
Canada ⁽²⁾	$	1.56	$	3.44		-55	%	$	3.97	$	3.24		+23	%
Total	$	4.15	$	3.48		+19	%	$	4.23	$	3.17		+34	%
NGLs (per Bbl)
U.S.	$	25.22	$	24.80		+2	%	$	27.34	$	25.53		+7	%
Canada	$	—	$	43.68		N/M		$	50.17	$	45.54		+10	%
Total	$	25.13	$	26.29		-4	%	$	28.11	$	27.16		+4	%
Combined (per Boe)
U.S.	$	41.06	$	32.19		+28	%	$	40.30	$	30.29		+33	%
Canada	$	65.96	$	43.02		+53	%	$	53.26	$	37.34		+43	%
Total	$	44.12	$	35.00		+26	%	$	42.61	$	32.13		+33	%

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

(2)

The reported Canadian gas volumes include 19 and 27 MMcf per day for the second quarter of 2014 and 2013, respectively, and 29 and 28 MMcf per day for the first six months of 2014 and 2013, respectively, 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 June 30, 2014 and 2013.


	Three Months Ended June 30,
	Oil		Bitumen			Gas			NGLs			Total
	(In millions)
2013 sales	$	897	$	260		$	773		$	292		$	2,222
Change due to volumes		323		(8	)		(161	)		33			187
Change due to prices		108		57			119			(14	)		270

2014 sales	$	1,328	$	309		$	731		$	311		$	2,679

Upstream sales increased $187 million due to volumes in the second quarter of 2014. The primary driver of the increase results from a 79% increase in our U.S. core and emerging oil production. Such growth results 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 $33 million of additional sales. These production additions were partially offset by the impacts of our Canadian divestitures, which were the primary driver of our 21% decrease in gas production. Bitumen sales decreased due to volumes as a result of higher royalties on our Jackfish heavy oil project in Canada.

Upstream sales increased $270 million due to prices in the second quarter of 2014, primarily due to a 26% increase in our realized price without hedges. Oil and bitumen sales were the most significantly impacted with an increase of $166 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. Gas sales increased $119 million largely due to higher North American regional index prices upon which our gas sales are based. NGL sales decreased $14 million as a result of lower NGL prices at Mont Belvieu, Texas.

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


	Six Months Ended June 30,
	Oil		Bitumen			Gas			NGLs		Total
	(In millions)
2013 sales	$	1,636	$	400		$	1,394		$	596	$	4,026
Change due to volumes		528		(16	)		(213	)		71		370
Change due to prices		239		181			396			24		840

2014 sales	$	2,403	$	565		$	1,577		$	691	$	5,236

Upstream sales increased $370 million due to volumes during the first six months of 2014. The primary driver of the increase results from a 68% increase in our U.S. core and emerging oil production. Such growth results 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 $71 million of additional sales. These production additions were partially offset by the impacts of our Canadian divestitures, which were the primary driver of our 15% decrease in gas production. Bitumen sales decreased due to volumes as a result of higher royalties on our Jackfish heavy oil project in Canada.

Upstream sales increased $840 million due to prices during the first six months of 2014, primarily due to a 33% increase in our realized price without hedges. Oil and bitumen sales were the most significantly impacted with an increase of $420 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. Gas sales increased $396 million largely due to higher North American regional index prices upon which our gas sales are based. NGL sales increased $24 million as a result of higher NGL prices at Mont Belvieu, Texas.

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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In millions)
Cash settlements:
Oil derivatives	$	(79	)	$	29		$	(115	)	$	61
Gas derivatives		(29	)		(17	)		(93	)		36
NGL derivatives		—			2			—			3

Total cash settlements		(108	)		14			(208	)		100

Gains (losses) on fair value changes:
Oil derivatives		(320	)		43			(409	)		(104	)
Gas derivatives		29			308			(102	)		52
NGL derivatives		—			1			—			(2	)

Total gains (losses) on fair value changes		(291	)		352			(511	)		(54	)

Oil, gas and NGL derivatives	$	(399	)	$	366		$	(719	)	$	46


	Three Months Ended June 30, 2014
	Oil (Per Bbl)			Bitumen (Per Bbl)		Gas (Per Mcf)			NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	92.59		$	65.88	$	4.15		$	25.13	$	44.12
Cash settlements of hedges⁽¹⁾		(5.54	)		—		(0.16	)		—		(1.78	)

Realized price, including cash settlements	$	87.05		$	65.88	$	3.99		$	25.13	$	42.34


	Three Months Ended June 30, 2013
	Oil (Per Bbl)			Bitumen (Per Bbl)		Gas (Per Mcf)			NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	85.02		$	53.90	$	3.48		$	26.29	$	35.00
Cash settlements of hedges⁽¹⁾		2.82			—		(0.07	)		0.10		0.23

Realized price, including cash settlements	$	87.84		$	53.90	$	3.41		$	26.39	$	35.23


	Six Months Ended June 30, 2014
	Oil (Per Bbl)			Bitumen (Per Bbl)		Gas (Per Mcf)			NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	89.64		$	60.47	$	4.23		$	28.11	$	42.61
Cash settlements of hedges⁽¹⁾		(4.31	)		—		(0.25	)		—		(1.70	)

Realized price, including cash settlements	$	85.33		$	60.47	$	3.98		$	28.11	$	40.91


	Six Months Ended June 30, 2013
	Oil (Per Bbl)			Bitumen (Per Bbl)		Gas (Per Mcf)			NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	80.73		$	41.10	$	3.17		$	27.16	$	32.13
Cash settlements of hedges⁽¹⁾		3.05			—		0.08			0.11		0.80

Realized price, including cash settlements	$	83.78		$	41.10	$	3.25		$	27.27	$	32.93

(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 incurred a net loss of $399 million and generated a net gain of $366 million in the second quarter of 2014 and 2013, respectively. Including the cash settlements discussed above, our commodity derivatives incurred a net loss of $719 million and generated a net gain of $46 million in the first six months of 2014 and 2013, respectively.

Marketing and Midstream Revenues and Operating Expenses


	Three Months Ended June 30,									Six Months Ended June 30,
	2014			2013			Change			2014			2013			Change
	($ in millions)
Operating revenues	$	2,230		$	500			+344	%	$	3,718		$	987			+276	%
Product purchases		(1,934	)		(334	)		+479	%		(3,188	)		(647	)		+393	%
Operations and maintenance expenses		(72	)		(48	)		+50	%		(123	)		(98	)		+26	%

Operating profit	$	224		$	118			+90	%	$	407		$	242			+68	%

During the second quarter and first six months of 2014, marketing and midstream operating profit increased $106 million and $165 million, respectively, primarily due to higher prices and volumes. Of the $106 million increase for the three months ended June 30, $93 million was attributable to EnLink’s operations. Of the $165 million increase for the six months ended June 30, $140 million was related to EnLink’s operations. EnLink’s Oklahoma segment, which includes the Cana plant and gathering system, was the largest driver of 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 the increases noted above.

Lease Operating Expenses (“LOE”)


	Three Months Ended June 30,							Six Months Ended June 30,
	2014		2013		Change			2014		2013		Change
LOE ($ in millions):
U.S.	$	409	$	307		+33	%	$	753	$	595		+26	%
Canada		173		252		-31	%		427		489		-13	%

Total	$	582	$	559		+4	%	$	1,180	$	1,084		+9	%

LOE per Boe:
U.S.	$	7.68	$	6.54		+17	%	$	7.46	$	6.43		+16	%
Canada	$	23.15	$	15.25		+52	%	$	19.48	$	14.92		+31	%
Total	$	9.58	$	8.80		+9	%	$	9.60	$	8.65		+11	%

LOE per Boe increased 9% and 11% during the second quarter and first six months of 2014, respectively. 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. The higher unit cost in the U.S. was primarily related to our liquids production growth, particularly in the Permian Basin and Mississippian-Woodford Trend, where projects 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 June 30,									Six Months Ended June 30,
	2014			2013			Change			2014			2013			Change
	($ in millions)
Gross G&A	$	316		$	287			+10	%	$	647		$	570			+14	%
Capitalized G&A		(91	)		(85	)		+8	%		(174	)		(183	)		-5	%
Reimbursed G&A		(36	)		(35	)		+3	%		(73	)		(70	)		+5	%

Net G&A	$	189		$	167			+13	%	$	400		$	317			+26	%

Net G&A per Boe	$	3.11		$	2.63			+18	%	$	3.25		$	2.53			+29	%

Net G&A and net G&A per Boe increased during the second quarter and first six 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 June 30,									Six Months Ended June 30,
	2014			2013			Change			2014			2013			Change
	($ in millions)
Production	$	104		$	71			+46	%	$	191		$	131			+45	%
Property and other		46			54			-14	%		96			107			-10	%

Production and property taxes	$	150		$	125			+20	%	$	287		$	238			+21	%

Percentage of oil, gas and NGL sales:
Production		3.9	%		3.2	%		+21	%		3.7	%		3.3	%		+12	%
Property and other		1.7	%		2.4	%		-29	%		1.8	%		2.6	%		-28	%

Total		5.6	%		5.6	%		-0	%		5.5	%		5.9	%		-7	%

Production and property taxes increased during the second quarter and first six 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 June 30,							Six Months Ended June 30,
	2014		2013		Change			2014		2013		Change
DD&A ($ in millions):
Oil & gas properties	$	719	$	595		+21	%	$	1,378	$	1,222		+13	%
Other assets		109		79		+37	%		189		156		+21	%

Total	$	828	$	674		+23	%	$	1,567	$	1,378		+14	%

DD&A per Boe:
Oil & gas properties	$	11.85	$	9.37		+26	%	$	11.21	$	9.75		+15	%
Other assets		1.78		1.25		+43	%		1.54		1.25		+23	%

Total	$	13.63	$	10.62		+28	%	$	12.75	$	11.00		+16	%

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. Other DD&A increased in both periods primarily due to the EnLink transaction.

Asset Impairments


	Six Months Ended June 30, 2013
	Gross		Net of Taxes
	(In millions)
U.S. oil and gas assets	$	1,110	$	707
Canada oil and gas assets		843		632

Total asset impairments	$	1,953	$	1,339

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.

Restructuring Costs


	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(In millions)
Canadian divestitures	$	5	$	—	$	42	$	—
Office consolidation		—		8		—		46

Restructuring costs	$	5	$	8	$	42	$	46

Canadian Divestitures

In the six months ended June 30, 2014, we recognized $42 million of employee related 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 six months ended June 30, 2013, we incurred $46 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, in the first six months of 2014 we recognized gains on conventional asset divestitures. 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 six months of 2014.

Net Financing Costs


	Three Months Ended June 30,									Six Months Ended June 30,
	2014			2013			Change			2014			2013			Change
	($ in millions)
Interest based on debt outstanding	$	141		$	116			+21	%	$	266		$	234			+14	%
Capitalized interest		(19	)		(12	)		+53	%		(35	)		(23	)		+53	%
Other fees and expenses		11			4			+249	%		17			7			+162	%

Interest expense	$	133		$	108			+25	%	$	248		$	218			+14	%
Interest income		(2	)		(5	)		-46	%		(5	)		(12	)		-61	%

Net financing costs	$	131		$	103			+28	%	$	243		$	206			+19	%

Net financing costs increased during the second quarter and first six months of 2014 primarily due to higher average debt 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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Total income tax expense (benefit) (in millions)	$	854		$	314		$	1,085		$	(309	)

U.S. statutory income tax rate		35	%		35	%		35	%		(35	%)
Repatriations		16	%		—			12	%		—
State income taxes		—			1	%		1	%		(1	%)
Taxation on Canadian operations		4	%		(2	%)		2	%		6	%
Taxes on EnLink formation		—			—			2	%		—
Other		—			(2	%)		(1	%)		(2	%)

Effective income tax rate		55	%		32	%		51	%		(32	%)

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.

Capital Resources, Uses and Liquidity

Sources and Uses of Cash

The following table presents the major changes in our cash and short-term investments.


	Six Months Ended June 30,
	2014			2013
	(In millions)
Operating cash flow	$	3,459		$	2,398
Divestitures of property and equipment		2,942			34
Capital expenditures		(3,341	)		(3,569	)
Acquisitions of property, equipment and businesses		(6,224	)		—
Debt activity, net		(1,132	)		(1,495	)
Distributions to Devon shareholders		(189	)		(170	)
Distributions to noncontrolling interests		(141	)		—
Other		266			54

Net change in cash and short-term investments	$	(4,360	)	$	(2,748	)

Cash and short-term investments at end of period	$	1,706		$	4,232

Operating Cash Flow

Net cash provided by operating activities (“operating cash flow”) was a significant source of capital in the first six months of 2014. Our operating cash flow increased 44 percent during 2014 primarily due to higher commodity prices, higher oil realizations and liquids production growth, partially offset by higher expenses.

Excluding the $6.2 billion attributable to the GeoSouthern and other acquisitions, our operating cash flow funded our capital expenditures during the first six months of 2014 and funded approximately 67 percent of our capital expenditures during the first six months of 2013. Leveraging our liquidity, we used cash balances and debt 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 six months of 2014, we completed our Canadian divestiture transactions and received proceeds totaling $2.9 billion. Additionally, in the second quarter of 2014, we reached an agreement to sell our U.S. non-core assets for $2.3 billion to Linn Energy.

Capital Expenditures

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


	Six Months Ended June 30,
	2014		2013
	(In millions)
Development	$	2,406	$	2,510
Exploration		162		403

Total oil and gas development and exploration		2,568		2,913
Capitalized G&A and interest		164		172

Total oil and gas		2,732		3,085
Acquisitions of property, equipment and businesses		6,224		—
Midstream		231		228
Corporate and other		61		99

Devon capital expenditures		9,248		3,412
EnLink		317		157

Total capital expenditures	$	9,565	$	3,569

Our capital expenditures consist of amounts related to our oil and gas exploration and development operations, our midstream operations and other corporate activities. The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties, which totaled $8.9 billion and $3.1 billion in the first six 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 12 percent in the first six 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 six months of 2014, we decreased our net debt borrowings $1.1 billion. The decrease was the net impact of repaying our $500 million senior notes upon maturity, reducing commercial paper balances $862 million primarily with repatriated Canadian divestiture proceeds and EnLink borrowings of $235 million.

During the first six months of 2013, we repatriated $2.0 billion of foreign earnings to the U.S. and repaid outstanding commercial paper borrowings. The repayment resulted in a net repayment of $1.5 billion in the first six months of 2013.

Distributions to Devon shareholders

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


	Six Months Ended June 30,
	2014				2013
	Amount		Per Share		Amount		Per Share
Dividends	$	189	$	0.46	$	170	$	0.42

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 $41 million to its non-Devon unitholders during the first six months of 2014.

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 June 30, 2014 are presented in “Part I. Financial Information – Item 1. Financial Statements – Note 3” in this report.

Credit Availability

As of June 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. We also have access to $3.0 billion of short-term credit under our commercial paper program. At June 30, 2014, we had $0.5 billion of commercial paper borrowings outstanding.

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 June 30, 2014, we were in compliance with this covenant with a debt-to-capitalization ratio of 23.4 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 $20 million. On April 9, 2014, the E2 credit agreement was amended to increase the borrowing capacity to $30.0 million. As of June 30, 2014, there was $160 million borrowed under the $1.0 billion credit facility, and there was $95 million borrowed under the $250 million credit facility and $23 million borrowed in association with the E2 Energy Services LLC credit facility.

Asset Divestitures

In the second quarter of 2014, we reached an agreement to sell our U.S. non-core assets for $2.3 billion to Linn Energy. This transaction is expected to close in the third quarter of 2014.

Contractual Obligations

A summary of our contractual obligations as of June 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)	$	12,357	$	475	$	2,750	$	2,254	$	6,878
Interest expense (2)		7,895		523		1,021		923		5,428
Purchase obligations (3)		5,973		438		1,781		1,756		1,998
Operational agreements (4)		5,528		634		1,783		1,706		1,405
Asset retirement obligations (5)		1,632		56		132		113		1,331
Drilling and facility obligations (6)		189		163		18		2		6
Lease obligations (7)		269		25		72		61		111
Other (8)		353		183		72		45		53

Total	$	34,196	$	2,497	$	7,629	$	6,860	$	17,210

(1)	Debt amounts represent scheduled maturities of our debt obligations at June 30, 2014, excluding $2 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 Devon 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

CPI

Cana gathering and processing contract

330

CPI

(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 $221 million related to uncertain tax positions.

Critical Accounting Estimates

Devon conducts its annual goodwill impairment test as of October 31 each year. At October 31, 2013, 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. As of October 31, 2013, the fair value of our Canadian reporting unit exceeded its carrying value by approximately 11 percent. As of June 30, 2014, we had $2.1 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 six months of 2014 relate to our Canadian divestiture program and amounts excluded for the first six months of 2013 relate to our office consolidation. 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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In millions, except per share amounts)
Net earnings (loss) attributable to Devon (GAAP)	$	675		$	683		$	999		$	(656	)
Adjustments (net of taxes):
Derivatives and other financial instruments		249			(240	)		453			(27	)
Cash settlements on derivatives and financial instruments		(68	)		12			(132	)		76

Net derivatives and financial instruments		181			(228	)		321			49
Investment in EnLink deferred income tax		—			—			48			—


Restructuring costs		4			5			32			29
Gain on asset sales and related repatriation		(286	)		—			(279	)		—
Asset impairments		—			31			—			1,339

Adjusted earnings attributable to Devon (Non-GAAP)	$	574		$	491		$	1,121		$	761

Earnings (loss) per share (GAAP)	$	1.64		$	1.68		$	2.44		$	(1.63	)
Adjustments (net of taxes):
Derivatives and other financial instruments		0.62			(0.58	)		1.10			(0.07	)
Cash settlements on derivatives and financial instruments		(0.17	)		0.03			(0.32	)		0.19

Net derivatives and financial instruments		0.45			(0.55	)		0.78			0.12
Investment in EnLink taxes		—			—			0.12			—
Restructuring costs		0.01			0.01			0.08			0.07
Gain on asset sales and related repatriation		(0.70	)		—			(0.68	)		—
Asset impairments		—			0.07			—			3.31

Adjusted earnings per share (Non-GAAP)	$	1.40		$	1.21		$	2.74		$	1.87

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 six months of 2014, as well as 2015 and 2016. The key terms to our open oil, gas and NGL derivative financial instruments as of June 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 June 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	$	(223	)	$	192
Oil derivatives	$	(727	)	$	645

Interest Rate Risk

At June 30, 2014, we had total debt outstanding of $12.4 billion. Of this amount, $10.8 billion bears fixed interest rates averaging 4.8 percent. The remaining $1.6 billion of debt is comprised of commercial paper borrowings that bear interest rates averaging 0.24 percent and floating rate debt that at June 30, 2014 had rates averaging 1.3 percent. Our commercial paper borrowings typically have maturities between 1 and 90 days.

As of June 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 June 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 June 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 June 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 June 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 June 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 second quarter of 2014.


Period	Total Number of Shares Purchased⁽¹⁾		Average Price Paid per Share
April 1 – April 30		20,756	$	69.22
May 1 – May 31		7,844	$	72.29
June 1 – June 30		3,820	$	77.95

Total		32,420	$	70.99

(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 12,300 shares of our common stock in the second 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. We acquired the shares sold under the Canadian Plan 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 second 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		Devon Energy Corporation Non-Qualified Deferred Compensation Plan, Amended and Restated effective as of April 15, 2014.

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.

INDEX TO EXHIBITS


Exhibit Number		Description

10.1		Devon Energy Corporation Non-Qualified Deferred Compensation Plan, Amended and Restated effective as of April 15, 2014.

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