Edgar Filing: DEVON ENERGY CORP/DE

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

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 March 31, 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 April 23, 2014, 407.9 million shares of common stock were outstanding.

DEVON ENERGY CORPORATION

FORM 10-Q

TABLE OF CONTENTS


Part I. Financial Information
Item 1. Financial Statements
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			26
Item 3. Quantitative and Qualitative Disclosures About Market Risk			40
Item 4. Controls and Procedures			40

Part II. Other Information
Item 1. Legal Proceedings			42
Item 1A. Risk Factors			42
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			42
Item 3. Defaults Upon Senior Securities			42
Item 4. Mine Safety Disclosures			42
Item 5. Other Information			42
Item 6. Exhibits			43

Signatures			44

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

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

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

Part I. Financial Information

Item 1. Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS


	Three Months Ended March 31,
	2014			2013
	(Unaudited) (In millions, except per share amounts)
Oil, gas and NGL sales	$	2,557		$	1,804
Oil, gas and NGL derivatives		(320	)		(320	)
Marketing and midstream revenues		1,488			487

Total operating revenues		3,725			1,971

Lease operating expenses		598			525
Marketing and midstream operating expenses		1,305			363
General and administrative expenses		211			150
Production and property taxes		137			113
Depreciation, depletion and amortization		739			704
Asset impairments		—			1,913
Restructuring costs		37			38
Other operating items		8			22

Total operating expenses		3,035			3,828

Operating income (loss)		690			(1,857	)
Net financing costs		112			103
Other nonoperating items		18			2

Earnings (loss) before income taxes		560			(1,962	)
Income tax expense (benefit)		231			(623	)

Net earnings (loss)		329			(1,339	)
Net earnings attributable to noncontrolling interests		5			—

Net earnings (loss) attributable to Devon	$	324		$	(1,339	)

Net earnings (loss) per share attributable to Devon:
Basic	$	0.80		$	(3.34	)
Diluted	$	0.79		$	(3.34	)
Comprehensive earnings (loss):
Net earnings (loss)	$	329		$	(1,339	)
Other comprehensive loss, net of tax:
Foreign currency translation		(298	)		(183	)
Pension and postretirement plans		3			4

Other comprehensive loss, net of tax		(295	)		(179	)

Comprehensive earnings (loss)	$	34		$	(1,518	)

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Three Months Ended March 31,
	2014			2013
	(Unaudited) (In millions)
Cash flows from operating activities:
Net earnings (loss)	$	329		$	(1,339	)
Adjustments to reconcile net earnings (loss) to net cash from operating activities:
Depreciation, depletion and amortization		739			704
Asset impairments		—			1,913
Deferred income tax expense (benefit)		208			(623	)
Derivatives and other financial instruments		307			305
Cash settlements on derivatives and financial instruments		(54	)		114
Other noncash charges		108			83
Net change in working capital		(152	)		(158	)
Change in long-term other assets		(88	)		(6	)
Change in long-term other liabilities		13			9

Net cash from operating activities		1,410			1,002

Cash flows from investing activities:
Acquisition of GeoSouthern		(5,935	)		—
Capital expenditures		(1,583	)		(1,926	)
Proceeds from property and equipment divestitures		142			29
Purchases of short-term investments		—			(871	)
Redemptions of short-term investments		—			1,988
Redemptions of long-term investments		57			1
Other		37			(3	)

Net cash from investing activities		(7,282	)		(782	)

Cash flows from financing activities:
Proceeds from borrowings of long-term debt, net of issuance costs		3,346			—
Net short-term debt borrowings		257			508
Long-term debt repayments		(1,577	)		—
Proceeds from stock option exercises		11			—
Dividends paid on common stock		(90	)		(81	)
Excess tax benefits related to share-based compensation		1			3
Distributions to noncontrolling interests		(100	)		—
Other		(4	)		—

Net cash from financing activities		1,844			430

Effect of exchange rate changes on cash		(11	)		(12	)

Net change in cash and cash equivalents		(4,039	)		638

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

Cash and cash equivalents at end of period	$	2,027		$	5,275

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	March 31,			December 31,
	2014			2013
	(Unaudited)
	(In millions, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	2,027		$	6,066
Accounts receivable		2,580			1,520
Other current assets		413			419

Total current assets		5,020			8,005

Property and equipment, at cost:
Oil and gas, based on full cost accounting:
Subject to amortization		79,399			73,995
Not subject to amortization		3,821			2,791

Total oil and gas		83,220			76,786
Other		8,801			6,195

Total property and equipment, at cost		92,021			82,981
Less accumulated depreciation, depletion and amortization		(54,592	)		(54,534	)

Property and equipment, net		37,429			28,447

Goodwill		9,155			5,858
Other long-term assets		1,161			567

Total assets	$	52,765		$	42,877

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,581		$	1,229
Revenues and royalties payable		1,529			786
Short-term debt		3,773			4,066
Other current liabilities		697			574

Total current liabilities		7,580			6,655

Long-term debt		11,739			7,956
Asset retirement obligations		2,218			2,140
Other long-term liabilities		933			834
Deferred income taxes		5,249			4,793
Stockholders’ equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 408 million and 406 million shares in 2014 and 2013, respectively		41			41
Additional paid-in capital		3,836			3,780
Retained earnings		15,644			15,410
Accumulated other comprehensive earnings		973			1,268

Total stockholders’ equity attributable to Devon		20,494			20,499
Noncontrolling interests		4,552			—

Total stockholders’ equity		25,046			20,499

Commitments and contingencies (Note 17)
Total liabilities and stockholders’ equity	$	52,765		$	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)
Three Months Ended March 31, 2014
Balance as of December 31, 2013		406	$	41	$	3,780		$	15,410		$	1,268		$	—		$	—		$	20,499
Net earnings		—		—		—			324			—			—			5			329
Other comprehensive loss, net of tax		—		—		—			—			(295	)		—			—			(295	)
Stock option exercises		—		—		11			—			—			—			—			11
Restricted stock grants, net of cancellations		2		—		—			—			—			—			—			—
Common stock repurchased		—		—		—			—			—			(3	)		—			(3	)
Common stock retired		—		—		(3	)		—			—			3			—			—
Common stock dividends		—		—		—			(90	)		—			—			—			(90	)
Share-based compensation		—		—		47			—			—			—			—			47
Share-based compensation tax benefits		—		—		1			—			—			—			—			1
Acquisition of noncontrolling interests		—		—		—			—			—			—			4,652			4,652
Distributions to noncontrolling interests		—		—		—			—			—			—			(100	)		(100	)
Other		—		—		—			—			—			—			(5	)		(5	)

Balance as of March 31, 2014		408	$	41	$	3,836		$	15,644		$	973		$	—		$	4,552		$	25,046

Three Months Ended March 31, 2013
Balance as of December 31, 2012		406	$	41	$	3,688		$	15,778		$	1,771		$	—		$	—		$	21,278
Net loss		—		—		—			(1,339	)		—			—			—			(1,339	)
Other comprehensive loss, net of tax		—		—		—			—			(179	)		—			—			(179	)
Common stock repurchased		—		—		—			—			—			(6	)		—			(6	)
Common stock retired		—		—		(6	)		—			—			6			—			—
Common stock dividends		—		—		—			(81	)		—			—			—			(81	)
Share-based compensation		—		—		32			—			—			—			—			32
Share-based compensation tax benefits		—		—		3			—			—			—			—			3

Balance as of March 31, 2013		406	$	41	$	3,717		$	14,358		$	1,592		$	—		$	—		$	19,708

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 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 periods ended March 31, 2014 and 2013 and Devon’s financial position as of March 31, 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 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 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 fifteen to twenty years.

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 purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to material change.

The following table summarizes the preliminary estimate of the purchase price and its allocation to the assets acquired and liabilities assumed (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

Partnership outstanding units:
Common units held by public unitholders		75.1
Preferred units held by third party⁽²⁾		17.1
Restricted units		0.4

Total		92.6
Partnership common unit price⁽³⁾	$	30.51

Partnership common units value	$	2,825

Partnership outstanding unit options value	$	4

Total fair value of noncontrolling interests⁽³⁾	$	2,829

Total consideration and fair value of noncontrolling interests	$	4,652

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

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

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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


Current assets	$	438
Property, plant and equipment, net		2,412
Intangible assets		427
Equity investment		222
Goodwill⁽¹⁾		3,420
Other long term assets		1
Current liabilities		514
Long-term debt		1,454
Deferred income taxes		199
Other long-term liabilities		101

Total consideration and fair value of noncontrolling interests	$	4,652

(1)

Goodwill was 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 purchase price allocation has been prepared on a preliminary basis and is subject to material change. 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		252
Proved properties		5,039
Unproved properties		1,010
Midstream assets		85
Current liabilities		445
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 and GeoSouthern’s operating revenues and net earnings included in Devon’s consolidated statements of earnings subsequent to the transactions described above.


	GeoSouthern		EnLink
	(In millions)
Total operating revenues	$	154	$	199
Total operating expenses		74		197

Operating income	$	80	$	2

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.


	Three Months Ended March 31,
	2014		2013
	(In millions)
Total operating revenues	$	4,372	$	2,548
Net earnings (loss)	$	347	$	(1,333	)
Noncontrolling interests	$	18	$	16
Net earnings (loss) attributable to Devon	$	329	$	(1,349	)
Net earnings (loss) per common share attributable to Devon	$	0.81	$	(3.30	)

Canadian Conventional Assets Divestiture

In November 2013, Devon announced plans to divest certain non-core properties located throughout Canada and the U.S. In the first quarter of 2014, Devon completed minor divestiture transactions for $142 million. On April 1, 2014, Devon sold the majority of its Canadian conventional assets to Canadian Natural Resources Limited for approximately $2.7 billion after taxes ($3.125 billion in Canadian dollars).

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 March 31, 2014, Devon did not hold any cash collateral from its counterparties.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Commodity Derivatives

As of March 31, 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)
Q2-Q4 2014		75,000	$	94.14		68,555	$	89.36	$	100.40		42,000	$	116.43
Q1-Q4 2015		65,750	$	90.10		—	$	—	$	—		28,000	$	116.43
Q1-Q4 2016		—	$	—		—	$	—	$	—		18,500	$	103.11


	Basis Swaps
Period	Index	Volume (Bbls/d)		Weighted Average Differential to WTI ($/Bbl)
Q2-Q4 2014	Western Canadian Select		9,236	$	(18.19	)

As of March 31, 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)
Q2-Q4 2014		800,000	$	4.42		460,000	$	4.03	$	4.51		500,000	$	5.00
Q1-Q4 2015		160,000	$	4.39		225,000	$	4.04	$	4.32		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)

Q2-Q4 2014

AECO

94,781

(0.52

)

Interest Rate Derivatives


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

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Foreign Currency Derivatives

As of March 31, 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

3,000

0.898

April 2014

Canadian Dollar

Sell

1,312

0.893

June 2014

Financial Statement Presentation

The following table presents the net gains and losses recognized in the accompanying comprehensive statements of earnings associated with derivative financial instruments. Net gains and losses associated with Devon’s commodity derivatives are presented in oil, gas and NGL derivatives in the accompanying comprehensive statements of earnings. Net gains and losses associated with 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 March 31,
	2014			2013
	(In millions)
Commodity derivatives	$	(320	)	$	(320	)
EnLink commodity derivatives		(1	)		—
Foreign currency derivatives		14			15

Net losses recognized in comprehensive statements of earnings	$	(307	)	$	(305	)

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


	Balance Sheet Caption	March 31, 2014		December 31, 2013
		(In millions)
Asset derivatives:
Commodity derivatives	Other current assets	$	—	$	75
Commodity derivatives	Other long-term assets		39		28
EnLink commodity derivatives	Other current assets		1		—
Interest rate derivatives	Other current assets		1		—

Total asset derivatives		$	41	$	103

Liability derivatives:
Commodity derivatives	Other current liabilities	$	205	$	58
Commodity derivatives	Other long-term liabilities		71		62
EnLink commodity derivatives	Other current liabilities		1		—
EnLink commodity derivatives	Other long-term liabilities		1		—
Interest rate derivatives	Other long-term liabilities		1		—
Foreign currency derivatives	Other current liabilities		32		1

Total liability derivatives		$	311	$	121

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 quarter of 2014 includes $1 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.


	Three Months Ended March 31,
	2014		2013
	(In millions)
Gross general and administrative expense	$	57	$	40
Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties	$	13	$	15
Related income tax benefit	$	7	$	6

Under its 2009 Long-Term Incentive Plan, as amended, Devon granted share-based awards to certain employees in the first quarter 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		2,829		$	61.02
Vested		(45	)	$	61.91
Forfeited		(96	)	$	59.84

Unvested at March 31, 2014		5,980		$	60.30

As of March 31, 2014, Devon’s unrecognized compensation cost related to unvested restricted stock awards and units was $279 million. Such cost is expected to be recognized over a weighted-average period of 2.7 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 March 31, 2014		475		$	59.20

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

As of March 31, 2014, Devon’s unrecognized compensation cost related to these awards was $12 million. Such cost is expected to be recognized over a weighted-average period of 1.9 years.

Performance Share Units

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


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

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


	Performance Share Units			Weighted Average Grant-Date Fair Value
	(In thousands)
Unvested at December 31, 2013		925		$	66.64
Granted		708		$	77.77
Forfeited		(100	)	$	79.74

Unvested at March 31, 2014 ⁽¹⁾		1,533		$	70.92

(1)	A maximum of 3.1 million common shares could be awarded based upon Devon’s final total shareholder return ranking.

As of March 31, 2014, Devon’s unrecognized compensation cost related to unvested units was $63 million. Such cost is expected to be recognized over a weighted-average period of 2.1 years

5. Asset Impairments

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


	Three Months Ended March 31, 2013
	Gross		Net of Taxes
	(In millions)
U.S. oil and gas assets	$	1,110	$	707
Canada oil and gas assets		803		601

Total asset impairments	$	1,913	$	1,308

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 quarter of 2014, Devon recognized $37 million of estimated employee related costs associated with its Canadian non-core asset divestitures. Approximately $14 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 March 31,
	2014		2013
	(In millions)
Canada divestitures:
Employee related costs	$	37	$	—
Office consolidation:
Lease obligations and other		—		38

Restructuring costs	$	37	$	38

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		21			2			23
Changes due to office consolidation		(20	)		(1	)		(21	)

Balance as of March 31, 2014	$	28		$	19		$	47

Balance as of December 31, 2012	$	52		$	9		$	61
Changes due to office consolidation		1			9			10

Balance as of March 31, 2013	$	53		$	18		$	71

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

7. Other Operating Items

The components of other operating items in the accompanying consolidated statements of earnings include the following:


	Three Months Ended March 31,
	2014			2013
	(In millions)
Accretion of asset retirement obligations		29			28
Gain on sale of assets		(15	)		(1	)
Other		(6	)		(5	)

Other operating items	$	8		$	22

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 March 31, 2014:
Net earnings attributable to Devon	$	324			407
Attributable to participating securities		(2	)		(4	)

Basic earnings per share		322			403		$	0.80
Dilutive effect of potential common shares issuable		—			2

Diluted earnings per share	$	322			405		$	0.79

Three Months Ended March 31, 2013:
Net loss attributable to Devon	$	(1,339	)		406
Attributable to participating securities		(1	)		(4	)

Basic loss per share		(1,340	)		402		$	(3.34	)
Dilutive effect of potential common shares issuable		—			—

Diluted loss per share	$	(1,340	)		402		$	(3.34	)

Certain options to purchase shares of Devon’s common stock are excluded from the dilution calculation because the options are antidilutive. These excluded options totaled 6.3 million shares and 7.7 million shares during the three-month periods ended March 31, 2014 and 2013, respectively.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

9. Other Comprehensive Earnings

Components of other comprehensive earnings consist of the following:


	Three Months Ended March 31,
	2014			2013
	(In millions)
Foreign currency translation:
Beginning accumulated foreign currency translation	$	1,448		$	1,996
Change in cumulative translation adjustment		(313	)		(191	)
Income tax benefit		15			8

Ending accumulated foreign currency translation		1,150			1,813

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

Ending accumulated pension and postretirement benefits		(177	)		(221	)

Accumulated other comprehensive earnings, net of tax	$	973		$	1,592

(1)	These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of general and administrative expenses on the accompanying comprehensive statements of earnings (see Note 15 for additional details).

10. Supplemental Information to Statements of Cash Flows


	Three Months Ended March 31,
	2014			2013
	(In millions)
Net change in working capital accounts:
Accounts receivable	$	(455	)	$	(122	)
Other current assets		(27	)		(1	)
Accounts payable		20			83
Revenues and royalties payable		391			3
Other current liabilities		(81	)		(121	)

Net change in working capital	$	(152	)	$	(158	)

Interest paid (net of capitalized interest)	$	137		$	139
Income taxes paid (received)	$	38		$	(11	)

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

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

11. Accounts Receivable

The components of accounts receivable include the following:


	March 31, 2014			December 31, 2013
	(In millions)
Oil, gas and NGL sales	$	1,185		$	851
Joint interest billings		537			447
Marketing and midstream revenues		793			172
Other		76			61

Gross accounts receivable		2,591			1,531
Allowance for doubtful accounts		(11	)		(11	)

Net accounts receivable	$	2,580		$	1,520

12. Goodwill

The table below provides a summary of Devon’s goodwill, by assigned reporting unit. The changes to Devon’s goodwill in the first quarter of 2014 largely relate to EnLink. Included in the assets Devon contributed to EnLink Holdings was $402 million of goodwill, which is in the table below. The additional EnLink goodwill of $3.4 billion represents the goodwill recognized on the EnLink transaction described in Note 2. The decrease in Devon’s Canadian goodwill was primarily due to changes in the exchange rate between the United States dollar and the Canadian dollar, as well as goodwill removed in conjunction with minor asset divestitures.


	March 31,		December 31,
	2014		2013
	(In millions)
U.S.	$	2,618	$	2,618
Canada		2,715		2,838
EnLink		3,822		402

Total	$	9,155	$	5,858

13. Debt


	March 31, 2014		December 31, 2013
	(In millions)
Devon debt
Commercial paper	$	1,575	$	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
Term loan due February 28, 2017		1,000		—
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
Term loan due February 28, 2019		1,000		—
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

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


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		13,780			12,022

EnLink debt
Credit facilities		103			—
Other borrowings		15
8.875% due February 15, 2018		189			—
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		28			—

Total EnLink debt		1,732			—

Total debt		15,512			12,022
Less amount classified as short-term debt⁽¹⁾		3,773			4,066

Total long-term debt	$	11,739		$	7,956

(1)

March 31, 2014 short-term debt consists of $2.0 billion term loan drawn in conjunction with the GeoSouthern acquisition, $1.6 billion of commercial paper and the EnLink $189 million senior note along with the associated $9 million premium, which was redeemed on April 18, 2014. December 31, 2013 short-term debt 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.

Commercial Paper

As of March 31, 2014, Devon had $1.6 billion of outstanding commercial paper at an average rate of 0.23 percent.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Credit Lines

Devon has a $3.0 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). As of March 31, 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 March 31, 2014, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 28.3 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. Under the term loan agreement, $1.0 billion of the term loans have a maturity of three years, and the remaining $1.0 billion have a maturity of five years (the “5-Year Loans”). The 5-Year Loans will provide for the partial amortization of principal during the last two years that they are outstanding. Loans outstanding under the term loan agreement, at Devon’s election, bear interest at various fixed rate options for periods up to six months. Such rates are generally less than the prime rate. However, Devon may elect to borrow at the prime rate.

Devon intends to repay the $2.0 billion term loans in the second quarter of 2014 using Canadian divestiture proceeds that will be repatriated to the U.S. Accordingly, amounts outstanding under the term loans have been classified as short-term debt in the consolidated balance sheet as of March 31, 2014.

EnLink Debt

Senior Notes

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)	$	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)

Credit Facilities

The Partnership has a $1.0 billion unsecured revolving credit facility, which includes a $500 million letter of credit subfacility. As of March 31, 2014, there were no borrowings under the $1.0 billion credit facility.

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. As of March 31, 2014, EnLink’s outstanding borrowings under the $250 million credit facility was $103 million and $15 million in association with the E2 Energy Services LLC credit agreement.

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.


	Three Months Ended March 31,
	2014			2013
	(In millions)
Asset retirement obligations as of beginning of period	$	2,228		$	2,095
Liabilities incurred		45			43
Liabilities settled		(14	)		(28	)
Revision of estimated obligation		69			63
Liabilities assumed by others		(9	)		(4	)
Accretion expense on discounted obligation		29			28
Foreign currency translation adjustment		(51	)		(26	)

Asset retirement obligations as of end of period		2,297			2,171
Less current portion		79			79

Asset retirement obligations, long-term	$	2,218		$	2,092

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

15. Retirement Plans

The following table presents the components of net periodic benefit cost for Devon’s pension and postretirement benefit plans. Net periodic benefit costs for the postretirement benefit plans were $0 for all periods presented below.


	Pension Benefits
	Three Months Ended March 31,
	2014			2013
	(In millions)
Service cost	$	7		$	9
Interest cost		14			13
Expected return on plan assets		(13	)		(15	)
Amortization of prior service cost ⁽¹⁾		1			1
Net actuarial loss ⁽¹⁾		4			5

Net periodic benefit cost ⁽²⁾	$	13		$	13

(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 $90 million and $81 million in the first three 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.

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’s largest exposure for such matters relates to royalties associated with Devon’s operations in New Mexico. Devon expects to mediate or go to trial before the end of 2014 as ordered by the court in the first quarter of 2014. 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.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 March 31, 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)
March 31, 2014 assets (liabilities):
Cash equivalents	$	1,227		$	1,227		$	99	$	1,128		$	—
Commodity derivatives	$	39		$	39		$	—	$	39		$	—
Commodity derivatives	$	(276	)	$	(276	)	$	—	$	(276	)	$	—
EnLink commodity derivatives	$	1		$	1		$	—	$	1		$	—
EnLink commodity derivatives	$	(2	)	$	(2	)	$	—	$	(2	)	$	—
Interest rate derivatives	$	1		$	1		$	—	$	1		$	—
Interest rate derivatives	$	(1	)	$	(1	)	$	—	$	(1	)	$	—
Foreign currency derivatives	$	(32	)	$	(32	)	$	—	$	(32	)	$	—
Debt	$	(15,512	)	$	(16,811	)	$	—	$	(16,811	)	$	—
Obligations under capital lease	$	23		$	23		$	—	$	23		$	—
December 31, 2013 assets (liabilities):
Cash equivalents	$	5,305		$	5,305		$	4,191	$	1,114		$	—
Long-term investments	$	62		$	62		$	—	$	—		$	62
Commodity derivatives	$	103		$	103		$	—	$	103		$	—
Commodity derivatives	$	(120	)	$	(120	)	$	—	$	(120	)	$	—
Foreign currency derivatives	$	(1	)	$	(1	)	$	—	$	(1	)	$	—
Debt	$	(12,022	)	$	(12,908	)	$	—	$	(12,908	)	$	—

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

Level 1 Fair Value Measurements

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

Level 2 Fair Value Measurements

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

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

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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.

Obligations under capital leases — The fair value of obligations under capital leases 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 United States. 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 March 31, 2014:
Revenues from external customers	$	2,616		$	684		$	425	$	—		$	3,725
Intersegment revenues	$	—		$	—		$	298	$	(298	)	$	—
Depreciation, depletion and amortization	$	497		$	194		$	48	$	—		$	739
Interest expense	$	100		$	19		$	5	$	(9	)	$	115
Earnings before income taxes	$	396		$	92		$	72	$	—		$	560
Income tax expense	$	186		$	21		$	24	$	—		$	231
Net earnings	$	210		$	71		$	48	$	—		$	329
Net earnings attributable to noncontrolling interests	$	—		$	—		$	5	$	—		$	5
Net earnings attributable to Devon	$	210		$	71		$	43	$	—		$	324
Property and equipment, net	$	24,857		$	8,369		$	4,203	$	—		$	37,429
Total assets	$	30,085		$	13,384		$	9,354	$	(58	)	$	52,765
Capital expenditures	$	7,089		$	442		$	82	$	—		$	7,613

Three Months Ended March 31, 2013:
Revenues from external customers	$	1,219		$	539		$	213	$	—		$	1,971
Intersegment revenues	$	—		$	—		$	314	$	(314	)	$	—
Depreciation, depletion and amortization	$	424		$	235		$	45	$	—		$	704
Interest expense	$	96		$	19		$	—	$	(5	)	$	110
Asset impairments	$	1,110		$	803		$	—	$	—		$	1,913
Earnings before income taxes	$	(1,119	)	$	(880	)	$	37	$	—		$	(1,962	)
Income tax benefit	$	(408	)	$	(228	)	$	13	$	—		$	(623	)
Net earnings (loss)	$	(711	)	$	(652	)	$	24	$	—		$	(1,339	)
Capital expenditures	$	1,171		$	584		$	83	$	—		$	1,838

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 period ended March 31, 2014, compared to the three-month period ended March 31, 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 March 31,
	2014		2013			Change
	($ in millions, except per share amounts)
Net earnings (loss) attributable to Devon	$	324	$	(1,339	)		+124	%
Adjusted earnings attributable to Devon⁽¹⁾	$	547	$	270			+103	%
Earnings (loss) per share attributable to Devon	$	0.79	$	(3.34	)		+76	%
Adjusted earnings per share attributable to Devon⁽¹⁾	$	1.34	$	0.66			+102	%
Production (MBoe/d)		690.9		686.9			+1	%
Realized price per Boe	$	41.13	$	29.18			+41	%
Adjusted operating income per Boe⁽²⁾	$	25.47	$	18.06			+41	%
Operating cash flow	$	1,410	$	1,002			+41	%
Capitalized costs	$	7,613	$	1,838			+314	%
Shareholder distributions	$	90	$	81			+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 interest, with the result divided by total production.

During the three-month period ended March 31, 2014, our adjusted earnings, adjusted earnings per share and adjusted operating income per Boe all increased compared to 2013. The improved 2014 results were driven primarily by increases in oil and gas prices, liquids volumes and oil realizations. These factors also contributed to higher adjusted operating cash flow, which when combined with a reduction in capital expenditures, excluding the GeoSouthern acquisition, caused our cash flow deficit to narrow considerably in 2014.

During the first quarter 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, during the month of March 2014, our Eagle Ford assets produced 49 MBoe/d, including 31 MBbls/d of oil.

Additionally, 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, on April 1, 2014, we sold the majority of our Canadian conventional assets to Canadian Natural Resources Limited for approximately $2.7 billion after taxes ($3.125 billion in Canadian dollars). This divestiture included approximately 170 MMBoe of proved reserves. Production associated with the divested properties was approximately 79.0 MBoe/d, including 357 MMcf/d of natural gas. We expect to repatriate the divestiture proceeds to the U.S. in the second quarter of 2014 to repay borrowings used to fund a portion of the GeoSouthern acquisition.

Results of Operations

Oil, Gas and NGL Production


	Three Months Ended March 31,
	2014		2013		Change
Oil (MBbls/d)
Anadarko Basin		9.3		8.5		+10	%
Barnett Shale		2.3		1.8		+29	%
Eagle Ford		10.8		—		N/M
Mississippian-Woodford Trend		9.5		2.0		+366	%
Permian Basin		55.1		40.4		+36	%
Rockies		8.0		6.7		+21	%
Other		2.5		3.3		- 27	%

U.S. core and emerging properties		97.5		62.7		+56	%
Canadian heavy oil		26.3		28.5		- 7	%

Total core and emerging properties		123.8		91.2		+36	%
Non-core properties		14.6		16.8		- 13	%

Total		138.4		108.0		+28	%

Bitumen (MBbls/d)
Canadian heavy oil		51.7		54.3		- 5	%
Gas (MMcf/d)
Anadarko Basin		281.2		270.1		+4	%
Barnett Shale		931.0		1,057.3		- 12	%
Eagle Ford		21.8		—		N/M
Mississippian-Woodford Trend		28.0		5.1		+453	%
Permian Basin		121.0		87.9		+38	%
Rockies		64.8		79.9		- 19	%
Other		139.7		159.9		- 13	%

U.S. core and emerging properties		1,587.5		1,660.2		- 4	%
Canadian heavy oil		19.4		20.6		- 6	%

Total core and emerging properties		1,606.9		1,680.8		- 4	%
Non-core properties		585.2		743.2		- 21	%

Total		2,192.1		2,424.0		- 10	%

NGLs (MBbls/d)
Anadarko Basin		29.2		24.4		+19	%
Barnett Shale		55.1		53.1		+4	%
Eagle Ford		2.6		—		N/M
Mississippian-Woodford Trend		4.7		0.2		+2114	%
Permian Basin		16.2		12.6		+29	%
Rockies oil		0.9		0.8		+20	%
Other		10.4		10.5		0	%

U.S. core and emerging properties		119.1		101.6		+17	%
Non-core properties		16.3		18.9		- 14	%

Total		135.4		120.5		+12	%

Combined (MBoe/d)
Anadarko Basin		85.3		77.9		+10	%
Barnett Shale		212.6		231.1		- 8	%
Eagle Ford		17.0		—		N/M
Mississippian-Woodford Trend		18.9		3.1		+510	%
Permian Basin		91.4		67.6		+35	%
Rockies		19.7		20.7		- 5	%
Other		36.4		40.6		- 11	%

U.S. core and emerging properties		481.3		441.0		+9	%
Canadian heavy oil		81.2		86.2		- 6	%

Total core and emerging properties		562.5		527.2		+7	%
Non-core properties		128.4		159.7		- 20	%

Total		690.9		686.9		+1	%

Oil, Gas and NGL Pricing


	Three Months Ended March 31,
	2014 ⁽¹⁾		2013 ⁽¹⁾		Change
Oil (per Bbl)
U.S.	$	91.66	$	87.45		+5	%
Canada	$	71.26	$	57.12		+25	%
Total	$	86.24	$	76.08		+13	%
Bitumen (per Bbl)
Canada	$	54.99	$	28.42		+93	%
Gas (per Mcf)
U.S.	$	4.33	$	2.81		+54	%
Canada	$	4.14	$	3.02		+37	%
Total	$	4.30	$	2.85		+51	%
NGLs (per Bbl)
U.S.	$	29.66	$	26.28		+13	%
Canada	$	51.80	$	47.33		+9	%
Total	$	31.15	$	28.04		+11	%
Combined (per Boe)
U.S.	$	39.44	$	28.32		+39	%
Canada	$	46.71	$	31.59		+48	%
Total	$	41.13	$	29.18		+41	%

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

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 March 31, 2014 and 2013.


	Three Months Ended March 31,
	Oil		Bitumen			Gas			NGLs		Total
	(In millions)
2013 sales	$	739	$	140		$	621		$	304	$	1,804
Change due to volumes		209		(8	)		(61	)		38		178
Change due to prices		127		124			286			38		575

2014 sales	$	1,075	$	256		$	846		$	380	$	2,557

Upstream sales increased $178 million in the first quarter of 2014 due to a 20 percent increase in our liquids production, partially offset by a 10 percent decline in our gas production. As a result of continued development of our oil properties, primarily in the Permian Basin, Mississippian-Woodford Trend and in our recently acquired Eagle Ford Shale properties, oil sales increased $209 million. Additionally, our NGL sales increased $38 million primarily as a result of continued drilling in the liquids-rich gas portions of the Cana-Woodford, Mississippian-Woodford Trend, Permian Basin and Eagle Ford. These increases were partially offset by declines in our dry gas production, which resulted in a $61 million decrease in sales. Bitumen sales decreased $8 million primarily due to higher royalties on our Jackfish thermal heavy oil projects in Canada.

Upstream sales increased $575 million in the first quarter of 2014, primarily due to a 41 percent increase in our realized price without hedges. Gas sales were the most significantly impacted with an increase of $286 million, largely due to higher North American regional index prices upon which our gas sales are based. Oil and bitumen sales increased $251 million due to prices and realizations. Additionally, NGL sales increased $38 million as a result of an 11 percent increase in our realized price without hedges. The largest contributors to the higher liquids prices were an increase in the average NYMEX West Texas Intermediate index price and tighter bitumen and heavy oil differentials as well as higher NGL prices in the Mont Belvieu, Texas index.

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 March 31,
	2014			2013
	(In millions)
Cash settlements:
Oil derivatives	$	(36	)	$	32
Gas derivatives		(64	)		53
NGL derivatives		—			1

Total cash settlements		(100	)		86

Losses on fair value changes:
Oil derivatives		(89	)		(147	)
Gas derivatives		(131	)		(256	)
NGL derivatives		—			(3	)

Total losses on fair value changes		(220	)		(406	)

Oil, gas and NGL derivatives	$	(320	)	$	(320	)


	Three Months Ended March 31, 2014
	Oil (Per Bbl)			Bitumen (Per Bbl)		Gas (Per Mcf)			NGLs (Per Bbl)			Boe (Per Boe)
Realized price without hedges	$	86.24		$	54.99	$	4.30		$	31.15		$	41.13
Cash settlements of hedges ⁽¹⁾		(2.88	)		—		(0.33	)		(0.02	)		(1.61	)

Realized price, including cash settlements	$	83.36		$	54.99	$	3.97		$	31.13		$	39.52


	Three Months Ended March 31, 2013
	Oil (Per Bbl)			Bitumen (Per Bbl)		Gas (Per Mcf)			NGLs (Per Bbl)			Boe (Per Boe)
Realized price without hedges	$	76.08		$	28.42	$	2.85		$	28.04		$	29.18
Cash settlements of hedges ⁽¹⁾		3.29			—		0.24			0.13			1.39

Realized price, including cash settlements	$	79.37		$	28.42	$	3.09		$	28.17		$	30.57

(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 net losses of $320 million during both the first three months of 2014 and 2013.

Marketing and Midstream Revenues and Operating Expenses


	Three Months Ended March 31,
	2014			2013			Change
	($ in millions)
Operating revenues	$	1,488		$	487			+205	%
Product purchases		(1,254	)		(313	)		+301	%
Operations and maintenance expenses		(51	)		(50	)		+2	%

Operating profit	$	183		$	124			+47	%

During the first three months of 2014, marketing and midstream operating profit increased $59 million, primarily due to higher prices and volumes. Of the $59 million increase, $47 million is attributable 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 relates 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 associated marketing revenues increased approximately $830 million while product purchases increased approximately $810 million in the comparative periods. The higher marketing revenues and product purchases are primarily due to new commitments we have entered into to secure capacity on downstream oil pipelines.

Lease Operating Expenses (“LOE”)


	Three Months Ended March 31,
	2014		2013		Change
LOE ($ in millions):
U.S.	$	344	$	288		+20	%
Canada		254		237		+7	%

Total	$	598	$	525		+14	%

LOE per Boe:
U.S.	$	7.20	$	6.32		+14	%
Canada	$	17.58	$	14.59		+20	%
Total	$	9.61	$	8.49		+13	%

LOE increased $1.12 per Boe during the first three months of 2014. The largest contributor to the higher unit cost relates to our Canadian operations. The higher Canadian unit costs largely result from higher Canadian royalties paid in the first quarter of 2014. As Canadian royalties increase, our net production volumes decrease, causing upward pressure on our per-unit operating costs. Improved price realizations, particularly related to our thermal heavy oil operations, resulted in higher royalties in the first quarter of 2014. Additionally, Jackfish 1 reached payout in the second quarter of 2013, contributing to higher royalties post payout. Besides an increase in Canadian royalties, upward cost pressures at Jackfish and Lloydminster also contributed to the higher per unit costs in Canada. The higher unit cost in the U.S. was primarily related to our liquids production growth, particularly in the Permian Basin and Rockies, 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 March 31,
	2014			2013			Change
	($ in millions)
Gross G&A	$	331		$	283			+17	%
Capitalized G&A		(83	)		(99	)		- 16	%
Reimbursed G&A		(37	)		(34	)		+7	%

Net G&A	$	211		$	150			+41	%

Net G&A per Boe	$	3.40		$	2.43			+40	%

Net G&A and net G&A per Boe increased during the first three months of 2014 largely due to higher employee compensation and benefits, $22 million in one-time costs related to the EnLink and GeoSouthern transactions and lower capitalized G&A. 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 March 31,
	2014			2013			Change
	($ in millions)
Production	$	87		$	60			+44	%
Property and other		50			53			-5	%

Production and property taxes	$	137		$	113			+21	%

Percentage of oil, gas and NGL sales:
Production		3.40	%		3.35	%		+1	%
Property and other		1.95	%		2.92	%		- 33	%

Total		5.35	%		6.27	%		- 15	%

Production and property taxes as a percentage of oil, gas and NGL sales, decreased during the first three months of 2014, primarily due to ad valorem and other taxes that do not change in direct correlation with oil, gas and NGL sales, as well as higher Canadian revenues with no associated production taxes.

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


	Three Months Ended March 31,
	2014		2013		Change
DD&A ($ in millions):
Oil & gas properties	$	659	$	627		+5	%
Other properties		80		77		+4	%

Total	$	739	$	704		+5	%

DD&A per Boe:
Oil & gas properties	$	10.59	$	10.13		+5	%
Other properties		1.30		1.25		+4	%

Total	$	11.89	$	11.38		+4	%

DD&A from our oil and gas properties increased during the first three months of 2014 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 effect of the asset impairments recognized in the first quarter of 2013.

Asset Impairments


	Three Months Ended March 31, 2013
	Gross		Net of Taxes
	(In millions)
U.S. oil and gas assets	$	1,110	$	707
Canada oil and gas assets		803		601

Total asset impairments	$	1,913	$	1,308

Oil and Gas Impairments

Under the full-cost method of accounting, capitalized costs of oil and gas properties are subject to a quarterly full-cost ceiling test. 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.

Net Financing Costs


	Three Months Ended March 31,
	2014			2013			Change
	($ in millions)
Interest based on debt outstanding	$	125		$	118			+7	%
Capitalized interest		(16	)		(11	)		+53	%
Other fees and expenses		6			3			+70	%

Interest expense		115			110			+4	%
Interest income		(3	)		(7	)		- 70	%

Net financing costs	$	112		$	103			+9	%

Net financing costs increased during the first three months of 2014 primarily due to higher average debt borrowings along with a decrease in interest income due to a decline in short-term investments and cash equivalents. The additional borrowings primarily relate to funding of the GeoSouthern acquisition.

Restructuring Costs


	Three Months Ended March 31,
	2014		2013
	(In millions)
Canadian divestitures	$	37	$	—
Office consolidation		—		38

Restructuring costs	$	37	$	38

Canadian Divestitures

In the first quarter of 2014, we recognized $37 million of estimated employee related costs associated with our Canadian non-core asset divestitures. Approximately $14 million of the employee related costs resulted from accelerated vesting of share-based grants, which are non-cash charges.

Office Consolidation

In the first quarter of 2013, we incurred $38 million of restructuring costs associated with the consolidation of our U.S. personnel into one location in Oklahoma City. This amount includes $23 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 $9 million of asset impairment charges for leasehold improvements and furniture associated with the office consolidation.

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 March 31,
	2014			2013
Total income tax expense (benefit) (in millions)	$	231		$	(623	)

U.S. statutory income tax rate		35	%		(35	%)
State income taxes		1	%		(1	%)
Taxation on Canadian operations		(3	%)		4	%
Deferred taxes on formation of EnLink		9	%		—
Other		(1	%)		—

Effective income tax rate		41	%		(32	%)

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 2014, we expect to repatriate to the U.S. the after-tax Canadian conventional asset divestiture proceeds of approximately $2.7 billion. Our consolidated balance sheets at December 31, 2013 and March 31, 2014 include the deferred tax liability related to this planned repatriation.

Capital Resources, Uses and Liquidity

Sources and Uses of Cash

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


	Three Months Ended March 31,
	2014			2013
	(In millions)
Operating cash flow	$	1,410		$	1,002
GeoSouthern acquisition, net of cash received		(5,935	)		—
Capital expenditures		(1,583	)		(1,926	)
Distributions to noncontrolling interests		(100	)		—
Distributions to Devon shareholders		(90	)		(81	)
Debt activity, net		2,026			508
Divestitures of property and equipment		142			29
Other		91			(11	)

Net change in cash and short-term investments	$	(4,039	)	$	(479	)

Cash and short-term investments at end of period	$	2,027		$	6,501

Operating Cash Flow

Net cash provided by operating activities (“operating cash flow”) was a significant source of capital in the first three months of 2014. Our operating cash flow increased 41 percent during 2014 primarily due to higher commodity prices, higher oil realizations and production growth, partially offset by higher expenses.

During the first three months of 2014 and 2013, our operating cash flow funded approximately 90 percent and 50 percent, respectively, of our capital expenditures, excluding the approximately $6.0 billion GeoSouthern acquisition. Leveraging our liquidity, we used cash balances and debt to fund the remainder of our cash-based capital expenditures.

Capital Expenditures

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


	Three Months Ended March 31,
	2014		2013
	(In millions)
Development	$	1,149	$	1,327
Exploration		106		198
GeoSouthern acquisition - oil and gas		5,850		—
Other acquisitions		22		31

Subtotal		7,127		1,556
Capitalized G&A and interest		79		92

Total oil and gas		7,206		1,648
Midstream		193		219
GeoSouthern acquisition - midstream		85		—
Corporate and other		34		59

Total capital expenditures	$	7,518	$	1,926

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 $7.2 billion and $1.6 billion in the first three months of 2014 and 2013, respectively. The increase in capital spending was due to the approximately $6.0 billion GeoSouthern acquisition. Excluding this acquisition, exploration and development capital spending decreased 18 percent in the first three months of 2014, primarily due to a decline in new venture acreage acquisitions and 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. Historically, our midstream capital expenditures have largely been impacted by our oil and gas drilling activities. However, in the future, our midstream capital expenditures will be impacted primarily by EnLink’s operations, as well as by our oil and gas drilling activities.

Debt Activity, Net

During the first three months of 2014, we increased our debt borrowings a net amount of $2.0 billion, which primarily related to additional borrowings used to fund a portion of the GeoSouthern acquisition cost. We also utilized net commercial paper borrowings of $257 million to fund capital expenditures in excess of our operating cash flow. Our debt decreased $500 million due to repayment of senior notes due on January 15, 2014. Additionally, our debt increased $1.7 billion in the first quarter of 2014 in connection with the EnLink transaction, which closed on March 7, 2014. This increase solely arises because we control EnLink and, therefore, consolidate EnLink’s accounts, including its debt, with Devon’s. EnLink’s debt is non-recourse to Devon.

During the first three months of 2013, we utilized net commercial paper borrowings of $508 million to fund capital expenditures in excess of our operating cash flow.

Distributions to Devon shareholders

The following table summarizes our common stock dividends (amounts in millions) during the first three months of 2014 and 2013. In the second quarter of 2013, we increased our quarterly dividend to $0.22 per share.


	Three Months Ended March 31,
	2014				2013
	Amount		Per Share		Amount		Per Share
Dividends	$	90	$	0.22	$	81	$	0.20

Distributions to noncontrolling interests

In conjunction with the formation of EnLink, we paid $100 million to holders of EnLink’s publicly traded units in the first quarter of 2014.

Divestitures

In November 2013, we announced plans to divest certain non-core properties located throughout Canada and the U.S. In the first quarter of 2014, we completed minor divestiture transactions and received proceeds of $142 million.

Liquidity

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

Operating Cash Flow

Our operating cash flow is sensitive to many variables, the most volatile of which are the prices of the oil, gas and NGLs we produce. We expect operating cash flow to continue to be our primary source of liquidity. To mitigate some of the risk inherent in prices, we have utilized various derivative financial instruments to set minimum and maximum prices on a portion of our 2014 production. The key terms to our open oil, gas and NGL derivative financial instruments as of March 31, 2014 are presented in “Part I. Financial Information – Item 1. Financial Statements – Note 3” in this report.

Credit Availability

As of March 31, 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 March 31, 2014, we had $1.6 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 March 31, 2014, we were in compliance with this covenant with a debt-to-capitalization ratio of 28.3 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. As of March 31, 2014, there were no borrowings under the $1.0 billion credit facility, and there was $103 million borrowed under the $250 million credit facility and $15 million borrowed in association with the E2 Energy Services LLC credit facility.

Asset Divestitures

On April 1, 2014, we sold the majority of our Canadian conventional assets to Canadian Natural Resources Limited for approximately $2.7 billion after taxes ($3.125 billion in Canadian dollars). In the second quarter of 2014, we plan to repatriate the sale proceeds into the U.S. and repay the $2.0 billion term loan that funded a portion of the GeoSouthern acquisition cost.

Contractual Obligations

A summary of our contractual obligations as of March 31, 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)	$	15,504	$	3,773	$	2,000	$	2,325	$	7,406
Interest expense (2)		8,143		553		1,087		975		5,528
Purchase obligations (3)		6,216		643		1,817		1,756		2,000
Operational agreements (4)		5,555		721		1,770		1,694		1,370
Asset retirement obligations (5)		1,574		46		79		77		1,372
Drilling and facility obligations (6)		372		337		27		2		6
Lease obligations (7)		277		33		72		61		111
Other (8)		298		133		67		45		53

Total	$	37,939	$	6,239	$	6,919	$	6,935	$	17,846

(1)	Debt amounts represent scheduled maturities of our debt obligations at March 31, 2014, excluding $8 million of net premiums included in the carrying value of debt.

(2)	Interest expense represents the scheduled cash payments 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. The operational agreements in the table above are as of March 31, 2014 but have been adjusted for the agreements transferred to Canadian Natural Resources Limited as a part of the sale of the Canadian conventional assets in April 2014.Operational agreements include approximately $2.2 billion of obligations between Devon and EnLink. The terms of the contracts with EnLink are summarized in the following table.


Contract	Contract Terms (Years)		Minimum Gathering Volume Commitment (MMcf/d)		Minimum Processing Volume Commitment (MMcf/d)		Minimum Volume Commitment Term (Years)		Annual Rate Escalators
Bridgeport gathering and processing contract		10		850		650		5		CPI
East Johnson County gathering contract		10		125		—		5		CPI
Northridge gathering and processing contract		10		40		40		5		CPI
Cana gathering and processing contract		10		330		330		5		CPI

(5)

Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. The obligations in the table above are as of March 31, 2014 but have been adjusted for the estimated obligations transferred to Canadian Natural Resources Limited as a part of the sale of the Canadian conventional assets in April 2014.

(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 $227 million related to uncertain tax positions. The “other” in the table above as of March 31, 2014 has been adjusted for the obligations transferred to Canadian Natural Resources Limited as a part of the sale of the Canadian conventional assets in April 2014.

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 March 31, 2014, we had $2.7 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 quarter of 2014 relate to our Canadian divestiture program and amounts excluded for the first quarter 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 March 31,
	2014			2013
	(In millions, except per share amounts)
Net earnings (loss) attributable to Devon (GAAP)	$	324		$	(1,339	)
Adjustments (net of taxes):
Derivatives and other financial instruments		221			213
Cash settlements on derivatives and financial instruments		(64	)		64
Deferred income taxes on formation of EnLink		48			—
Restructuring costs		28			24
Gain on sale of assets		(10	)		—
Asset impairments		—			1,308

Adjusted earnings attributable to Devon (Non-GAAP)	$	547		$	270

Earnings (loss) per share attributable to Devon (GAAP)	$	0.79		$	(3.34	)
Adjustments (net of taxes):
Derivatives and other financial instruments		0.54			0.53
Cash settlements on derivatives and financial instruments		(0.16	)		0.16
Deferred income taxes on formation of EnLink		0.12			—
Restructuring costs		0.07			0.06
Gain on sale of assets		(0.02	)		—
Asset impairments		—			3.25

Adjusted earnings per share attributable to Devon (Non-GAAP)	$	1.34		$	0.66

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 nine months of 2014, as well as 2015 and 2016. The key terms to our open oil, gas and NGL derivative financial instruments as of March 31, 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 March 31, 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	$	(269	)	$	235
Oil derivatives	$	(597	)	$	539

Interest Rate Risk

At March 31, 2014, we had total debt outstanding of $15.5 billion. Of this amount, $11.0 billion bears fixed interest rates averaging 4.9 percent. The remaining $4.5 billion of debt is comprised of commercial paper borrowings that bear interest rates averaging 0.23 percent and floating rate debt that at March 31, 2014 had rates averaging 1.3 percent. Our commercial paper borrowings typically have maturities between 1 and 90 days.

As of March 31, 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 March 31, 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 March 31, 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 March 31, 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 March 31, 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 March 31, 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

In conjunction with the formation of EnLink in the first quarter of 2014, we implemented additional internal controls related to EnLink’s financial amounts included in our consolidated financial statements. Except for these changes, there were no other 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 first quarter of 2014.


Period	Total Number of Shares Purchased⁽¹⁾		Average Price Paid per Share
January 1 – January 31		22,626	$	59.73
February 1 – February 28		14,873	$	61.68
March 1 – March 31		7,054	$	65.80

Total		44,553	$	61.34

(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 18,600 shares of our common stock in the first 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. Eligible Canadian employees purchased approximately 700 shares of our common stock in the first quarter of 2014, at then-prevailing stock prices, that they held through their ownership in the Canadian Plan. 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.

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 Incentive Savings Plan, as amended and restated effective January 1, 2013.

10.2		Devon Energy Corporation Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Incentive Savings Plan.

10.3		Devon Energy Corporation Amendment 2014-2, executed March 7, 2014, to the Devon Energy Corporation Incentive Savings Plan.

10.4		Devon Energy Corporation Amendment 2014-3, executed March 19, 2014, to the Devon Energy Corporation Incentive Savings Plan.

10.5		Devon Energy Corporation Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan.

10.6		Devon Energy Corporation Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Benefit Restoration Plan.

10.7		Devon Energy Corporation Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Defined Contribution Restoration Plan.

10.8		Devon Energy Corporation Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental Contribution Plan.

10.9		Devon Energy Corporation Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental Retirement Income Plan.

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 Incentive Savings Plan, as amended and restated effective January 1, 2013.

10.2		Devon Energy Corporation Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Incentive Savings Plan.

10.3		Devon Energy Corporation Amendment 2014-2, executed March 7, 2014, to the Devon Energy Corporation Incentive Savings Plan.

10.4		Devon Energy Corporation Amendment 2014-3, executed March 19, 2014, to the Devon Energy Corporation Incentive Savings Plan.

10.5		Devon Energy Corporation Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan.

10.6		Devon Energy Corporation Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Benefit Restoration Plan.

10.7		Devon Energy Corporation Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Defined Contribution Restoration Plan.

10.8		Devon Energy Corporation Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental Contribution Plan.

10.9		Devon Energy Corporation Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental Retirement Income Plan.

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