DEVON ENERGY CORP/DE - Quarter Report: 2016 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2016

o	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 or 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 o

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 o

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

Large accelerated filer	þ	Accelerated filer	o

Non-accelerated filer	o	Smaller reporting company	o

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

On July 20, 2016, 523.6 million shares of common stock were outstanding.

DEVON ENERGY CORPORATION

FORM 10-Q

TABLE OF CONTENTS

Part I. Financial Information
Item 1.	Financial Statements	6
	Consolidated Comprehensive Statements of Earnings	6
	Consolidated Statements of Cash Flows	7
	Consolidated Balance Sheets	8
	Consolidated Statements of Stockholders’ Equity	9
	Notes to Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	45

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

Signatures		48

DEFINITIONS

Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon” and the “Company” refer to Devon Energy Corporation and its consolidated subsidiaries. In addition, the following are other abbreviations and definitions of certain terms used within this Quarterly Report on Form 10-Q:

“ASU” means Accounting Standards Update.

“Bbl” or “Bbls” means barrel or barrels.

“Boe” means barrel of oil equivalent. Gas proved reserves and production are converted to Boe, at the pressure and temperature base standard of each respective state in which the gas is produced, at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of gas and oil. Bitumen and NGL proved reserves and production are converted to Boe on a one-to-one basis with oil.

“Btu” means British thermal units, a measure of heating value.

“Canada” means the division of Devon encompassing oil and gas properties located in Canada. All dollar amounts associated with Canada are in U.S. dollars.

“Canadian Plan” means Devon Canada Corporation Incentive Savings Plan.

“DD&A” means depreciation, depletion and amortization expenses.

“Devon Plan” means Devon Energy Corporation Incentive Savings Plan.

“E&P” means exploration and production activities.

“EnLink” means EnLink Midstream Partners, L.P., a master limited partnership.

“FASB” means Financial Accounting Standards Board.

“G&A” means general and administrative expenses.

“GAAP” means U.S. generally accepted accounting principles.

“General Partner” means EnLink Midstream, LLC, the indirect general partner of EnLink.

“Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.

“LIBOR” means London Interbank Offered Rate.

“LOE” means lease operating expenses.

“MBbls” means thousand barrels.

“MBoe” means thousand Boe.

“Mcf” means thousand cubic feet.

“MMBoe” means million Boe.

“MMBtu” means million Btu.

“MMcf” means million cubic feet.

“N/M” means not meaningful.

“NGL” or “NGLs” means natural gas liquids.

“NYMEX” means New York Mercantile Exchange.

“OPIS” means Oil Price Information Service.

“SEC” means United States Securities and Exchange Commission.

“Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit.

“TSR” means total shareholder return.

“U.S.” means United States of America.

“VEX” means Victoria Express Pipeline and related truck terminal and storage assets.

“WTI” means West Texas Intermediate.

“/d” means per day.

“/gal” means per gallon.

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This report includes “forward-looking statements” as defined by the SEC. Such statements include those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions, and are often identified by use of the words “expects,” “believes,” “will,” “would,” “could,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare our December 31, 2015 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, including, but not limited to:

the volatility of oil, gas and NGL prices, including the currently depressed commodity price environment;

uncertainties inherent in estimating oil, gas and NGL reserves;

the extent to which we are successful in acquiring and discovering additional reserves;

the uncertainties, costs and risks involved in exploration and development activities;

risks related to our hedging activities;

counterparty credit risks;

regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters;

risks relating to our indebtedness;

our ability to successfully complete mergers, acquisitions and divestitures;

the extent to which insurance covers any losses we may experience;

our limited control over third parties who operate some of our oil and gas properties;

midstream capacity constraints and potential interruptions in production;

competition for leases, materials, people and capital;

cyberattacks targeting our systems and infrastructure; and

any of the other risks and uncertainties discussed in this report, our 2015 Annual Report on Form 10-K and our other filings with the SEC.

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

Part I. Financial Information

Item 1. Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS

	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2016			2015			2016			2015
	(Unaudited)
	(Millions, except per share amounts)
Oil, gas and NGL sales	$	1,085		$	1,587		$	1,910		$	2,926
Oil, gas and NGL derivatives		(142	)		(282	)		(109	)		12
Marketing and midstream revenues		1,545			2,088			2,813			3,720
Total operating revenues		2,488			3,393			4,614			6,658
Lease operating expenses		416			562			860			1,115
Marketing and midstream operating expenses		1,338			1,863			2,404			3,302
General and administrative expenses		147			212			341			463
Production and property taxes		75			116			153			224
Depreciation, depletion and amortization		484			814			1,026			1,744
Asset impairments		1,497			4,168			4,532			9,628
Restructuring and transaction costs		24			—			271			—
Other operating items		4			21			24			40
Total operating expenses		3,985			7,756			9,611			16,516
Operating loss		(1,497	)		(4,363	)		(4,997	)		(9,858	)
Net financing costs		163			125			327			242
Other nonoperating items		85			(9	)		106			3
Loss before income taxes		(1,745	)		(4,479	)		(5,430	)		(10,103	)
Income tax benefit		(182	)		(1,686	)		(399	)		(3,721	)
Net loss		(1,563	)		(2,793	)		(5,031	)		(6,382	)
Net earnings (loss) attributable to noncontrolling interests		7			23			(405	)		33
Net loss attributable to Devon	$	(1,570	)	$	(2,816	)	$	(4,626	)	$	(6,415	)
Net loss per share attributable to Devon:
Basic	$	(3.04	)	$	(6.94	)	$	(9.33	)	$	(15.81	)
Diluted	$	(3.04	)	$	(6.94	)	$	(9.33	)	$	(15.81	)
Comprehensive loss:
Net loss	$	(1,563	)	$	(2,793	)	$	(5,031	)	$	(6,382	)
Other comprehensive earnings (loss), net of tax:
Foreign currency translation		3			44			26			(258	)
Pension and postretirement plans		5			3			9			7
Other comprehensive earnings (loss), net of tax		8			47			35			(251	)
Comprehensive loss		(1,555	)		(2,746	)		(4,996	)		(6,633	)
Comprehensive earnings (loss) attributable to noncontrolling interests		7			23			(405	)		33
Comprehensive loss attributable to Devon	$	(1,562	)	$	(2,769	)	$	(4,591	)	$	(6,666	)

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2016			2015			2016			2015
	(Unaudited)
	(Millions)
Cash flows from operating activities:
Net loss	$	(1,563	)	$	(2,793	)	$	(5,031	)	$	(6,382	)
Adjustments to reconcile net loss to net cash from operating activities:
Depreciation, depletion and amortization		484			814			1,026			1,744
Asset impairments		1,497			4,168			4,532			9,628
Deferred income tax benefit		(179	)		(1,593	)		(386	)		(3,640	)
Derivatives and other financial instruments		223			305			417			(125	)
Cash settlements on derivatives and financial instruments		(44	)		464			(148	)		1,183
Other noncash charges		88			41			21			266
Net change in working capital		(153	)		(189	)		45			26
Change in long-term other assets		(40	)		18			13			159
Change in long-term other liabilities		22			(134	)		(5	)		(110	)
Net cash from operating activities		335			1,101			484			2,749
Cash flows from investing activities:
Capital expenditures		(489	)		(1,432	)		(1,238	)		(3,149	)
Acquisitions of property, equipment and businesses		(11	)		(13	)		(1,638	)		(417	)
Divestitures of property and equipment		191			6			209			8
Other		(26	)		(8	)		(27	)		(5	)
Net cash from investing activities		(335	)		(1,447	)		(2,694	)		(3,563	)
Cash flows from financing activities:
Borrowings of long-term debt, net of issuance costs		450			2,094			846			3,051
Repayments of long-term debt		(290	)		(1,034	)		(549	)		(1,521	)
Net short-term debt repayments		—			(778	)		(626	)		(763	)
Issuance of common stock		—			—			1,469			—
Sale of subsidiary units		—			85			—			654
Issuance of subsidiary units		49			2			776			4
Dividends paid on common stock		(33	)		(98	)		(158	)		(197	)
Distributions to noncontrolling interests		(74	)		(65	)		(147	)		(118	)
Other		(2	)		4			(2	)		(8	)
Net cash from financing activities		100			210			1,609			1,102
Effect of exchange rate changes on cash		(12	)		3			14			(43	)
Net change in cash and cash equivalents		88			(133	)		(587	)		245
Cash and cash equivalents at beginning of period		1,635			1,858			2,310			1,480
Cash and cash equivalents at end of period	$	1,723		$	1,725		$	1,723		$	1,725

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

		June 30, 2016			December 31, 2015
		(Unaudited)
	(Millions, except share data)
ASSETS
Current assets:
Cash and cash equivalents		$	1,723		$	2,310
Accounts receivable			1,167			1,105
Assets held for sale			728			—
Other current assets			364			606
Total current assets			3,982			4,021
Property and equipment, at cost:
Oil and gas, based on full cost accounting:
Subject to amortization			80,066			78,190
Not subject to amortization			3,798			2,584
Total oil and gas			83,864			80,774
Midstream and other			10,243			10,380
Total property and equipment, at cost			94,107			91,154
Less accumulated depreciation, depletion and amortization			(77,292	)		(72,086	)
Property and equipment, net			16,815			19,068
Goodwill			4,159			5,032
Other long-term assets			2,288			1,330
Total assets		$	27,244		$	29,451
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	545		$	906
Revenues and royalties payable			819			763
Short-term debt			350			976
Liabilities held for sale			205			—
Other current liabilities			1,010			650
Total current liabilities			2,929			3,295
Long-term debt			12,357			12,056
Asset retirement obligations			1,473			1,370
Other long-term liabilities			1,011			853
Deferred income taxes			555			888
Stockholders’ equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 524 million and 418 million shares in 2016 and 2015, respectively			52			42
Additional paid-in capital			7,500			4,996
Retained earnings (accumulated deficit)			(2,970	)		1,781
Accumulated other comprehensive earnings			265			230
Total stockholders’ equity attributable to Devon			4,847			7,049
Noncontrolling interests			4,072			3,940
Total stockholders’ equity			8,919			10,989
Commitments and contingencies (Note 19)
Total liabilities and stockholders’ equity		$	27,244		$	29,451

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

											Accumulated
					Additional			Retained			Other									Total
	Common Stock				Paid-In			Earnings			Comprehensive			Treasury			Noncontrolling			Stockholders’
	Shares		Amount		Capital			(Accumulated Deficit)			Earnings			Stock			Interests			Equity
	(Unaudited)
	(Millions)
Six Months Ended June 30, 2016
Balance as of December 31, 2015		418	$	42	$	4,996		$	1,781		$	230		$	—		$	3,940		$	10,989
Net loss		—		—		—			(4,626	)		—			—			(405	)		(5,031	)
Other comprehensive earnings, net of tax		—		—		—			—			35			—			—			35
Restricted stock grants, net of cancellations		3		—		—			—			—			—			—			—
Common stock repurchased		—		—		—			—			—			(21	)		—			(21	)
Common stock retired		—		—		(21	)		—			—			21			—			—
Common stock dividends		—		—		(33	)		(125	)		—			—			—			(158	)
Common stock issued		103		10		2,117			—			—			—			—			2,127
Share-based compensation		—		—		123			—			—			—			—			123
Subsidiary equity transactions		—		—		318			—			—			—			684			1,002
Distributions to noncontrolling interests		—		—		—			—			—			—			(147	)		(147	)
Balance as of June 30, 2016		524	$	52	$	7,500		$	(2,970	)	$	265		$	—		$	4,072		$	8,919
Six Months Ended June 30, 2015
Balance as of December 31, 2014		409	$	41	$	4,088		$	16,631		$	779		$	—		$	4,802		$	26,341
Net earnings (loss)		—		—		—			(6,415	)		—			—			33			(6,382	)
Other comprehensive loss, net of tax		—		—		—			—			(251	)		—			—			(251	)
Stock option exercises		—		—		4			—			—			—			—			4
Restricted stock grants, net of cancellations		2		—		—			—			—			—			—			—
Common stock repurchased		—		—		—			—			—			(23	)		—			(23	)
Common stock retired		—		—		(23	)		—			—			23			—			—
Common stock dividends		—		—		—			(197	)		—			—			—			(197	)
Share-based compensation		—		—		89			—			—			—			—			89
Subsidiary equity transactions		—		—		578			—			—			—			111			689
Distributions to noncontrolling interests		—		—		—			—			—			—			(118	)		(118	)
Other		—		—		—			(1	)		—			—			—			(1	)
Balance as of June 30, 2015		411	$	41	$	4,736		$	10,018		$	528		$	—		$	4,828		$	20,151

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 interim financial statements and notes of Devon have been prepared pursuant to the rules and regulations of the SEC. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been omitted. The accompanying unaudited interim financial statements and notes should be read in conjunction with the financial statements and notes included in Devon’s 2015 Annual Report on Form 10-K.

The accompanying unaudited interim financial statements furnished in this report reflect all adjustments that are, in the opinion of management, necessary for a fair statement of Devon’s results of operations and cash flows for the three-month and six-month periods ended June 30, 2016 and 2015 and Devon’s financial position as of June 30, 2016.

Recently Issued Accounting Standards

The FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. Its objective is to simplify several aspects of the accounting for share-based payments, including accounting for income taxes when awards vest or are settled, statutory withholding and accounting for forfeitures. Classification of these aspects on the statement of cash flows is also addressed. This ASU is effective for Devon beginning January 1, 2017. Devon is evaluating the impact this ASU will have on its consolidated financial statements and related disclosures and does not plan on early adopting.

The FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This ASU will supersede the revenue recognition requirements in Topic 605, Revenue Recognition and industry-specific guidance in Subtopic 932-605, Extractive Activities – Oil and Gas – Revenue Recognition. This ASU provides guidance concerning the recognition and measurement of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14, Revenue from Contracts with Customers – Deferral of the Effective Date, to annual and interim periods beginning in 2018, with early adoption permitted in 2017. The ASU is required to be adopted using either the retrospective transition method, which requires restating previously reported results or the cumulative effect (modified retrospective) transition method, which utilizes a cumulative-effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. Devon intends to use the cumulative effect transition method and is evaluating the impact this ASU will have on its consolidated financial statements and related disclosures. Devon does not plan on early adopting.

The FASB issued ASU 2016-02, Leases (Topic 842). This ASU will supersede the lease requirements in Topic 840, Leases. Its objective is to increase transparency and comparability among organizations. This ASU provides guidance requiring lessees to recognize most leases on their balance sheet. Lessor accounting does not significantly change from Topic 840, except for some changes made to align with Topic 606. This ASU is effective for Devon beginning January 1, 2019 and will be applied using a modified retrospective transition method, which requires applying the new guidance to leases that exist or are entered into after the beginning of the earliest period in the financial statements. Early adoption is permitted. Devon is evaluating the impact this ASU will have on its consolidated financial statements and related disclosures and does not plan on early adopting.

2.	Acquisitions and Divestitures

Devon Acquisitions

On January 7, 2016, Devon acquired approximately 80,000 net acres and assets in the STACK play for approximately $1.5 billion, subject to certain adjustments. Devon funded the acquisition with $847 million of cash and $659 million of common equity shares. The allocation of the purchase price at June 30, 2016 was approximately $1.3 billion to unproved properties and approximately $200 million to proved properties.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

EnLink Acquisitions

On January 7, 2016, EnLink acquired Anadarko Basin gathering and processing midstream assets, along with dedicated acreage service rights and service contracts, for approximately $1.5 billion, subject to certain adjustments. EnLink funded the acquisition with approximately $215 million of General Partner common units and approximately $800 million of cash, primarily funded with the issuance of EnLink preferred units. The remaining $500 million of the purchase price is to be paid within one year with the option to defer $250 million of the final payment 24 months from the close date. The first $250 million of undiscounted future installment payment is reported in other current liabilities in the accompanying consolidated balance sheets with the remaining $250 million payment reported in other long-term liabilities. The accretion of the discount is reported within net financing costs in the accompanying consolidated comprehensive statement of earnings. A preliminary allocation of the purchase price at June 30, 2016 was $1.0 billion to intangible assets and $420 million to property and equipment.

On August 1, 2016, EnLink formed a joint venture to operate and expand its midstream assets in the Delaware Basin. The joint venture is initially owned 50.1% by EnLink and 49.9% by the joint venture partner. EnLink contributed approximately $230 million of existing assets to the joint venture and committed an additional $285 million in capital to fund potential future development projects and potential acquisitions. The joint venture partner committed an aggregate of approximately $400 million of capital, including an initial contribution of approximately $115 million, and granted to EnLink call rights beginning in 2021 to acquire increasing portions of the joint venture partner’s interest.

Devon Asset Divestitures

In December 2015, Devon announced its intent to divest certain non-core upstream assets in the U.S. and its interest in the Access Pipeline in Canada. Proceeds from these divestitures are expected to be used primarily for debt repayment and to support capital investment in Devon’s core resource plays.

On June 30, 2016, Devon sold its Mississippian assets for $200 million, subject to certain adjustments. Estimated proved reserves associated with these assets were approximately 11 MMBoe, or less than 1% of total U.S. proved reserves. Under full cost accounting rules, sales or dispositions of oil and gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of a gain or loss. No gain or loss was recognized on the sale of the Mississippian assets.

During the second quarter of 2016, Devon entered into definitive agreements to divest approximately $1.8 billion of non-core assets located primarily in east Texas, the Anadarko Basin and the Midland Basin to five separate purchasers. Through August 3, 2016, Devon has closed approximately $1.2 billion of the announced asset divestitures. Devon expects to close the remaining transactions in the third quarter of 2016. Devon is evaluating whether the impact of these divestitures will result in an adjustment to its capitalized costs or in the recognition of a gain in the consolidated statement of earnings.

As of June 30, 2016, Devon held approximately $95 million in cash related to the pending transactions. The cash deposits are restricted until the closing of the transactions. As a result, Devon has classified these amounts in other current assets and other current liabilities in the accompanying consolidated balance sheet.

Assets held for sale

In July 2016, Devon reached an agreement to sell its interest in the Access Pipeline for $1.1 billion ($1.4 billion Canadian dollars). The transaction is expected to close in the third quarter of 2016. As of June 30, 2016, Devon’s Access Pipeline assets and liabilities were classified as held for sale. Upon this classification change, Devon ceased recording depreciation on Access Pipeline. Based on the contracted sales price, no fair value adjustment to the carrying value of these assets and liabilities was warranted at June 30, 2016, and Devon expects to recognize a gain of approximately $400 million to $600 million upon the closing of the sale. Under the terms of the related transportation agreement, Devon’s Canadian thermal-oil acreage is dedicated to Access Pipeline for an initial term of 25 years. A market-based toll will be applied to production from Devon’s thermal-oil projects.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 to hedge future prices received. Additionally, Devon and EnLink periodically enter into derivative financial instruments with respect to a portion of their oil, gas and NGL marketing activities. These commodity derivative financial instruments 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 and foreign exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar exchange rates. As of June 30, 2016, Devon did not have any open foreign exchange contracts.

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.

As of December 31, 2015, Devon’s other current assets in the accompanying consolidated balance sheet included $236 million of accrued settlements that it received in January 2016.

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 generally contain provisions that provide for collateral payments, if Devon’s or its counterparty’s credit rating falls below certain credit rating levels.

As of December 31, 2015, Devon held $75 million of cash collateral which represented the estimated fair value of certain derivative positions in excess of Devon’s credit guidelines. The collateral is reported in other current liabilities in the accompanying consolidated balance sheets.

Commodity Derivatives

As of June 30, 2016, 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 WTI futures price. The second table presents Devon’s oil derivatives that settle against the respective indices noted within the table.

	Price Swaps				Price Collars						Call Options Sold
Period	Volume (Bbls/d)		Weighted Average Price ($/Bbl)		Volume (Bbls/d)		Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)		Volume (Bbls/d)		Weighted Average Price ($/Bbl)
Q3 2016		33,000	$	48.37		65,000	$	40.37	$	46.91		18,500	$	55.00
Q4 2016		30,000	$	48.58		20,000	$	40.85	$	50.85		18,500	$	55.00
Q1-Q4 2017		2,623	$	51.79		7,248	$	47.21	$	57.21		—	$	—

	Oil Basis Swaps
Period	Index	Volume (Bbls/d)		Weighted Average Differential to WTI ($/Bbl)
Q3-Q4 2016	Western Canadian Select		41,500	$	(13.43	)
Q3-Q4 2016	West Texas Sour		5,000	$	(0.53	)
Q3-Q4 2016	Midland Sweet		13,000	$	0.25

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

As of June 30, 2016, 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 respective indices noted within the table.

	Price Swaps				Price Collars						Call Options Sold
Period	Volume (MMBtu/d)		Weighted Average Price ($/MMBtu)		Volume (MMBtu/d)		Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)		Volume (MMBtu/d)		Weighted Average Price ($/MMBtu)
Q3 2016		140,000	$	2.78		105,000	$	2.57	$	2.85		400,000	$	2.80
Q4 2016		155,000	$	2.83		275,000	$	2.70	$	2.90		400,000	$	2.80
Q1-Q4 2017		79,397	$	3.00		42,411	$	2.96	$	3.26		—	$	—

	Natural Gas Basis Swaps
Period	Index	Volume (MMBtu/d)		Weighted Average Differential to Henry Hub ($/MMBtu)
Q3-Q4 2016	Panhandle Eastern Pipe Line		175,000	$	(0.34	)
Q3-Q4 2016	El Paso Natural Gas		125,000	$	(0.12	)
Q3-Q4 2016	Houston Ship Channel		30,000	$	0.11
Q3-Q4 2016	Transco Zone 4		70,000	$	0.01
Q1-Q4 2017	Panhandle Eastern Pipe Line		150,000	$	(0.34	)
Q1-Q4 2017	El Paso Natural Gas		80,000	$	(0.13	)
Q1-Q4 2017	Houston Ship Channel		35,000	$	0.06
Q1-Q4 2017	Transco Zone 4		205,000	$	0.03

As of June 30, 2016, Devon had the following open NGL derivative positions. Devon’s NGL positions settle against the average of the prompt month OPIS Mont Belvieu, Texas index.

		Price Swaps				Price Collars
Period	Product	Volume (Bbls/d)		Weighted Average Price ($/Bbl)		Volume (Bbls/d)		Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)
Q3-Q4 2016	Ethane		6,000	$	9.34		10,500	$	8.20	$	9.46
Q3-Q4 2016	Propane		—	$	—		5,000	$	19.61	$	21.71

As of June 30, 2016, EnLink had the following open derivative positions associated with gas processing and fractionation. EnLink’s NGL derivative positions settle by purity product against the average of the prompt month OPIS Mont Belvieu, Texas index. EnLink’s natural gas derivatives settle against the Henry Hub Gas Daily index.

Period	Product	Volume (Total)			Weighted Average Price Paid	Weighted Average Price Received
Q3 2016-Q4 2016	Ethane		273	MBbls	$0.29/gal	Index
Q3 2016-Q2 2017	Propane		557	MBbls	Index	$0.72/gal
Q3 2016-Q2 2017	Normal Butane		122	MBbls	Index	$0.58/gal
Q3 2016-Q2 2017	Natural Gasoline		66	MBbls	Index	$0.95/gal
Q3 2016-Q2 2017	Natural Gas		7,082	MMBtu/d	Index	$2.86/MMbtu
Q4 2016	Condensate		50	MBbls	Index	$40.20/bbl

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Interest Rate Derivatives

As of June 30, 2016, Devon had the following open interest rate derivative positions:

Notional		Rate Received		Rate Paid		Expiration
(Millions)
$	100	Three Month LIBOR			0.92%	December 2016
$	750	Three Month LIBOR			2.98%	December 2048 ⁽¹⁾
$	100		1.76%	Three Month LIBOR		January 2019

(1)	Mandatory settlement in December 2018.

Financial Statement Presentation

The following table presents the net gains and losses by derivative financial instrument type followed by the corresponding individual consolidated comprehensive statements of earnings caption.

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(Millions)
Commodity derivatives:
Oil, gas and NGL derivatives	$	(142	)	$	(282	)	$	(109	)	$	12
Marketing and midstream revenues		(6	)		—			(6	)		2
Interest rate derivatives:
Other nonoperating items		(71	)		1			(143	)		2
Foreign currency derivatives:
Other nonoperating items		(4	)		(24	)		(159	)		109
Net gains (losses) recognized	$	(223	)	$	(305	)	$	(417	)	$	125

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheet caption.

	June 30, 2016		December 31, 2015
	(Millions)
Commodity derivative assets:
Other current assets	$	14	$	34
Other long-term assets		2		1
Interest rate derivative assets:
Other current assets		1		1
Other long-term assets		2		1
Foreign currency derivative assets:
Other current assets		—		8
Total derivative assets	$	19	$	45

Commodity derivative liabilities:
Other current liabilities	$	104	$	14
Other long-term liabilities		7		4
Interest rate derivative liabilities:
Other long-term liabilities		166		22
Foreign currency derivative liabilities:
Other current liabilities		—		8
Total derivative liabilities	$	277	$	48

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 consolidated comprehensive statements of earnings. Gross G&A expense for the first six months of 2016 and 2015 includes $12 million and $18 million, respectively, 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 2016 in conjunction with the reduction of workforce described in Note 6. For the six months ended June 30, 2016, approximately $67 million of associated expense for these accelerated awards is included in restructuring and transaction costs in the accompanying consolidated comprehensive statements of earnings.

	Six Months Ended June 30,
	2016		2015
	(Millions)
Gross G&A for share-based compensation	$	80	$	127
Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties	$	21	$	31
Related income tax benefit	$	2	$	26

Under its approved long-term incentive plan, Devon granted share-based awards to certain employees in the first six months of 2016. The following table presents a summary of Devon’s unvested restricted stock awards and units, performance-based restricted stock awards and performance share units granted under the plan.

	Restricted Stock					Performance-Based					Performance
	Awards and Units					Restricted Stock Awards					Share Units
	Awards and Units			Weighted Average Grant-Date Fair Value		Awards			Weighted Average Grant-Date Fair Value		Units			Weighted Average Grant-Date Fair Value
	(Thousands, except fair value data)
Unvested at 12/31/15		4,738		$	62.49		434		$	60.48		1,859		$	76.17
Granted		4,299		$	19.46		330		$	19.22		1,388		$	10.41
Vested		(2,051	)	$	62.50		(102	)	$	62.55		(602	)	$	63.37
Forfeited		(121	)	$	50.58		—		$	—		(7	)	$	81.67
Unvested at 6/30/16		6,865		$	35.74		662		$	39.57		2,638	⁽¹⁾	$	46.52

(1)	A maximum of 5.3 million common shares could be awarded based upon Devon’s final TSR ranking relative to Devon’s peer group established under applicable award agreements.

The following table presents the assumptions related to the performance share units granted in 2016, as indicated in the previous summary table.

	2016
Grant-date fair value	$	9.24	—	$	10.61
Risk-free interest rate					0.94	%
Volatility factor					37.7	%
Contractual term (years)					2.83

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table presents a summary of the unrecognized compensation cost and the related weighted average recognition period associated with unvested awards and units as of June 30, 2016.

			Performance-Based
	Restricted Stock		Restricted Stock		Performance
	Awards and Units		Awards		Share Units
Unrecognized compensation cost (millions)	$	170	$	8	$	34
Weighted average period for recognition (years)		2.6		2.5		1.8

EnLink Share-Based Awards

The following table presents a summary of the unrecognized compensation cost and the related weighted average recognition period associated with the General Partner’s and EnLink’s unvested restricted incentive units and performance units as of June 30, 2016.

	General Partner				EnLink
	Restricted		Performance		Restricted		Performance
	Incentive Units		Units		Incentive Units		Units
Unrecognized compensation cost (millions)	$	19	$	4	$	19	$	4
Weighted average period for recognition (years)	1.7			2.0	1.8			2.0

5.	Asset Impairments

The following table presents the components of asset impairments recognized by Devon.

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(Millions)
U.S. oil and gas assets	$	885	$	4,167	$	2,493	$	9,625
Canada oil and gas assets		612		—		1,166		—
EnLink goodwill		—		—		873		—
Other assets		—		1		—		3
Total asset impairments	$	1,497	$	4,168	$	4,532	$	9,628

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% 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 from declines in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from significant decreases in the 12-month average trailing prices for oil, bitumen, gas and NGLs, which significantly reduced proved reserves values and, to a lesser degree, proved reserves.

EnLink Goodwill Impairments

In the first quarter of 2016, Devon recognized goodwill impairments related to EnLink’s business. Additional information regarding the impairments is discussed in Note 13.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

6.	Restructuring and Transaction Costs

The following table summarizes restructuring and transaction costs presented in the accompanying consolidated comprehensive statement of earnings.

	June 30, 2016
	Three Months Ended		Six Months Ended
	(Millions)
2016 reduction in workforce:
Employee-related costs	$	2	$	236
Lease obligations		17		17
Asset impairments		3		3
Transaction costs		2		15
Restructuring and transaction costs	$	24	$	271

The following table summarizes Devon’s restructuring liabilities.

	Other			Other
	Current			Long-term
	Liabilities			Liabilities			Total
	(Millions)
Balance as of December 31, 2015	$	13		$	63		$	76
Changes due to 2016 workforce reductions		107			13			120
Changes related to prior years' restructurings		3			(6	)		(3	)
Balance as June 30, 2016	$	123		$	70		$	193

Balance as of December 31, 2014	$	13		$	7		$	20
Changes related to prior years' restructurings		(3	)		(2	)		(5	)
Balance as of June 30, 2015	$	10		$	5		$	15

Reduction in Workforce

In the first six months of 2016, Devon recognized $236 million in employee-related costs associated with a reduction in workforce that was made in response to the depressed commodity price environment. Of these employee-related costs, approximately $67 million resulted from accelerated vesting of share-based grants, which are noncash charges. Additionally, approximately $30 million resulted from estimated defined benefit settlements. These cash and noncash charges included estimates for employees released from service during the first six months of 2016, as well as amounts based on the number of employees expected to be impacted by certain of its non-core asset divestitures. Devon expects to complete these pending divestitures in the third quarter of 2016.

As a result of the reduction in workforce and asset divestitures, Devon ceased using certain office space that was subject to non-cancellable operating lease arrangements. Consequently, Devon recognized $17 million of restructuring costs that represent the present value of its future obligations under the leases. Additionally, Devon recognized $3 million of asset impairment charges for leasehold improvements and furniture associated with the office space it ceased using.

Transaction Costs

In the first six months of 2016, Devon and EnLink recognized transaction costs primarily associated with the closing of the acquisitions discussed in Note 2.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

7.	Income Taxes

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Total income tax benefit (millions)	$	(182	)	$	(1,686	)	$	(399	)	$	(3,721	)

U.S. statutory income tax rate		(35	%)		(35	%)		(35	%)		(35	%)
Deferred tax asset valuation allowance		27	%		0	%		24	%		0	%
Non-deductible goodwill impairment		0	%		0	%		6	%		0	%
Taxation on Canadian operations		3	%		1	%		2	%		1	%
State income taxes		(2	%)		(2	%)		(1	%)		(2	%)
Other		(3	%)		(2	%)		(3	%)		(1	%)
Effective income tax rate		(10	%)		(38	%)		(7	%)		(37	%)

Devon estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the quarter in which they occur.

At December 31, 2015, Devon recorded a 100%, or $967 million, valuation allowance against the U.S. deferred tax assets that largely resulted from the full cost impairments recognized during 2015. Through the first six months of 2016, Devon provided an additional $1.3 billion valuation allowance against the U.S. deferred tax assets due to its continued financial losses incurred largely by the additional full cost impairments.

In the first quarter of 2016, EnLink recorded a goodwill impairment of approximately $873 million. This impairment is not deductible for purposes of calculating income tax and therefore has an impact on the effective tax rate.

Devon and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. Devon’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. Devon is under audit in the U.S. and various foreign jurisdictions as part of its normal course of business.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

8.	Net Loss Per Share Attributable to Devon

The following table reconciles net loss attributable to Devon and weighted-average common shares outstanding used in the calculations of basic and diluted net loss per share.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
	(Millions, except per share amounts)
Net loss:
Net loss attributable to Devon	$	(1,570	)	$	(2,816	)	$	(4,626	)	$	(6,415	)
Attributable to participating securities		(1	)		(1	)		(1	)		(2	)
Basic and diluted loss	$	(1,571	)	$	(2,817	)	$	(4,627	)	$	(6,417	)
Common shares:
Common shares outstanding - total		524			411			502			411
Attributable to participating securities		(6	)		(5	)		(6	)		(5	)
Common shares outstanding - basic		518			406			496			406
Dilutive effect of potential common shares issuable		—			—			—			—
Common shares outstanding - diluted		518			406			496			406
Net loss per share attributable to Devon:
Basic	$	(3.04	)	$	(6.94	)	$	(9.33	)	$	(15.81	)
Diluted	$	(3.04	)	$	(6.94	)	$	(9.33	)	$	(15.81	)
Antidilutive options ⁽¹⁾		3			3			3			4

(1)	Amounts represent options to purchase shares of Devon’s common stock that are excluded from the diluted net loss per share calculations because the options are antidilutive.

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						Six Months Ended
		June 30,						June 30,
		2016			2015			2016			2015
	(Millions)
Foreign currency translation:
Beginning accumulated foreign currency translation		$	447		$	681		$	424		$	983
Change in cumulative translation adjustment			2			60			53			(277	)
Income tax benefit (expense)			1			(16	)		(27	)		19
Ending accumulated foreign currency translation			450			725			450			725
Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits			(190	)		(200	)		(194	)		(204	)
Recognition of net actuarial loss and prior service cost in earnings ⁽¹⁾			8			5			13			11
Income tax expense			(3	)		(2	)		(4	)		(4	)
Ending accumulated pension and postretirement benefits			(185	)		(197	)		(185	)		(197	)
Accumulated other comprehensive earnings, net of tax		$	265		$	528		$	265		$	528

(1)	These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of G&A on the accompanying consolidated comprehensive statements of earnings. See Note 16 for additional details.

10.	Supplemental Information to Statements of Cash Flows

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(Millions)
Net change in working capital accounts, net of assets and liabilities assumed:
Accounts receivable	$	(140	)	$	36		$	6		$	440
Income taxes receivable		(14	)		(9	)		101			416
Other current assets		(107	)		87			144			(6	)
Accounts payable		(30	)		(87	)		(151	)		(102	)
Revenues and royalties payable		95			53			(6	)		(183	)
Other current liabilities		43			(269	)		(49	)		(539	)
Net change in working capital	$	(153	)	$	(189	)	$	45		$	26
Interest paid (net of capitalized interest)	$	174		$	112		$	289		$	230
Income taxes paid (received)	$	5		$	84		$	(123	)	$	(330	)

Devon’s acquisition of certain STACK assets during the first three months of 2016 included the noncash issuance of Devon common stock. See Note 2 for additional details.

EnLink’s acquisition of Anadarko Basin gathering and processing midstream assets during the first quarter of 2016 included noncash issuance of General Partner common units. See Note 2 for additional details. During the first six months of 2015, EnLink’s acquisitions included $360 million of noncash equity issuance.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

11.	Accounts Receivable

Components of accounts receivable include the following:

	June 30, 2016			December 31, 2015
	(Millions)
Oil, gas and NGL sales	$	440		$	362
Joint interest billings		107			211
Marketing and midstream revenues		552			520
Other		83			30
Gross accounts receivable		1,182			1,123
Allowance for doubtful accounts		(15	)		(18	)
Net accounts receivable	$	1,167		$	1,105

12.	Other Current Liabilities

Components of other current liabilities include the following:

	June 30, 2016		December 31, 2015
	(Millions)
Installment payment - see Note 2	$	236	$	—
Accrued interest payable		150		149
Restructuring liabilities		123		13
Other		501		488
Other current liabilities	$	1,010	$	650

13.	Goodwill and Other Intangible Assets

Goodwill

Devon performs an annual impairment test of goodwill at October 31, or more frequently if events or changes in circumstances indicate that the carrying value of a reporting unit may not be recoverable. Sustained weakness in the overall energy sector driven by low commodity prices, together with a decline in EnLink’s unit price, caused a change in circumstances warranting an interim impairment test of EnLink’s reporting units in the first quarter of 2016. Based on that test, EnLink recorded a noncash goodwill impairment of $873 million. This consisted of a full impairment charge of $93 million related to its Crude and Condensate reporting unit and partial impairment to its Texas and General Partner reporting units of $473 million and $307 million, respectively.

Other Intangible Assets

The following table presents other intangible assets reported in other long-term assets in the accompanying consolidated balance sheets. See Note 2 for discussion of changes in other intangible assets resulting from EnLink acquisitions during the first six months of 2016.

	June 30, 2016			December 31, 2015
	(Millions)
Customer relationships	$	1,779		$	745
Accumulated amortization		(112	)		(55	)
Net intangibles	$	1,667		$	690

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The weighted-average amortization period for other intangible assets is 14 years. Amortization expense for intangibles was approximately $30 million and $18 million for the three months ended June 30, 2016 and 2015, respectively and $58 million and $30 million for six months ended June 30, 2016 and 2015, respectively. The remaining amortization expense is estimated to be $117 million each of the next five years.

14.

Debt

A summary of debt is as follows:

		June 30, 2016			December 31, 2015
	(Millions)
Devon debt:
Commercial paper		$	—		$	626
Debentures and notes			9,425			9,425
Net discount on debentures and notes			(27	)		(28	)
Debt issuance costs			(55	)		(57	)
Total Devon debt			9,343			9,966
EnLink debt:
Credit facilities			712			414
Debentures and notes			2,663			2,663
Net premium on debentures and notes			11			13
Debt issuance costs			(22	)		(24	)
Total EnLink debt			3,364			3,066
Total debt			12,707			13,032
Less amount classified as short-term debt⁽¹⁾			350			976
Total long-term debt		$	12,357		$	12,056

(1)	Short-term debt as of June 30, 2016 consists of $350 million of floating rate due on December 15, 2016. Short-term debt as of December 31, 2015 consists of $626 million of commercial paper and $350 million floating rate due on December 15, 2016.

As of January 1, 2016, Devon adopted ASU 2015-03, Interest – Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. This ASU requires debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than as an asset. As a result of the adoption, Devon reclassified unamortized debt issuance costs of $81 million as of December 31, 2015 from other long-term assets to a reduction of long-term debt on the consolidated balance sheets.

Commercial Paper

During the six months ended June 30, 2016, Devon reduced commercial paper borrowings by $626 million. As of June 30, 2016, Devon had no outstanding commercial paper borrowings.

Credit Lines

Devon has a $3.0 billion Senior Credit Facility. As of June 30, 2016, there were $66 million in outstanding letters of credit and 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%. Under the terms of the credit agreement, total capitalization is adjusted to add back noncash financial write-downs such as full cost ceiling impairments or goodwill impairments. As of June 30, 2016, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 23.1%.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

EnLink Debt

All of EnLink’s and the General Partner’s debt is non-recourse to Devon.

EnLink has a $1.5 billion unsecured revolving credit facility. As of June 30, 2016, there were $11 million in outstanding letters of credit and $697 million in outstanding borrowings at an average rate of 2.12% under the $1.5 billion credit facility. The General Partner has a $250 million secured revolving credit facility. As of June 30, 2016, the General Partner had $15 million in outstanding borrowings at an average rate of 4.25%. EnLink and the General Partner were in compliance with all financial covenants in their respective credit facilities as of June 30, 2016.

In July 2016, EnLink issued $500 million of 4.85% unsecured senior notes due 2026. EnLink intends to use the net proceeds to repay outstanding borrowings under its revolving credit facility and for general partnership purposes.

15.	Asset Retirement Obligations

The following table presents the changes in Devon’s asset retirement obligations.

	Six Months Ended June 30,
	2016			2015
	(Millions)
Asset retirement obligations as of beginning of period	$	1,414		$	1,399
Liabilities incurred and assumed through acquisitions		15			33
Liabilities settled and divested		(51	)		(31	)
Revision of estimated obligation		70			61
Accretion expense on discounted obligation		39			38
Foreign currency translation adjustment		30			(45	)
Asset retirement obligations as of end of period		1,517			1,455
Less current portion		44			64
Asset retirement obligations, long-term	$	1,473		$	1,391

During the first six months of 2016, Devon reduced its asset retirement obligation by $35 million for those obligations that were assumed by the purchasers of certain Devon non-core upstream U.S. assets.

16.	Retirement Plans

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

	Pension Benefits												Postretirement Benefits
	Three Months Ended						Six Months Ended						Three Months Ended					Six Months Ended
	June 30,						June 30,						June 30,					June 30,
	2016			2015			2016			2015			2016		2015			2016			2015
	(Millions)
Service cost	$	3		$	8		$	9		$	16		$	—	$	—		$	—		$	—
Interest cost		11			13			23			26			—		—			—			—
Expected return on plan assets		(13	)		(15	)		(26	)		(30	)		—		—			—			—
Amortization of prior service cost ⁽¹⁾		1			1			1			2			—		(1	)		(1	)		(1	)
Net actuarial loss ⁽¹⁾		7			5			13			10			—		—			—			—
Net periodic benefit cost ⁽²⁾	$	9		$	12		$	20		$	24		$	—	$	(1	)	$	(1	)	$	(1	)

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(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 G&A in the accompanying consolidated comprehensive statements of earnings.

17.	Stockholders’ Equity

Common Stock Issued

In January 2016, Devon issued approximately 23 million shares of common stock in conjunction with the STACK asset acquisition discussed in Note 2.

In February 2016, Devon issued 79 million shares of common stock to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were $1.5 billion.

Dividends

The table below summarizes the dividends Devon paid on its common stock.

	Amount		Rate
	(Millions)		(Per Share)
Quarter Ended 2016:
First quarter 2016	$	125	$	0.24
Second quarter 2016		33	$	0.06
Total year-to-date	$	158
Quarter Ended 2015:
First quarter 2015	$	99	$	0.24
Second quarter 2015		98	$	0.24
Total year-to-date	$	197

In response to the depressed commodity price environment, Devon reduced its quarterly dividend to $0.06 per share in the second quarter of 2016.

18.	Noncontrolling Interests

Subsidiary Equity Transactions

During the first quarter of 2016, EnLink issued common units in conjunction with the acquisition discussed in Note 2. In addition, during the first six months of 2016, EnLink issued approximately 3 million common units for net proceeds of $52 million. As a result of these transactions, Devon’s ownership interest in EnLink decreased from 28% at December 31, 2015 to 24% at June 30, 2016, excluding the interest held by the General Partner. Additionally, as a result of the transaction described in Note 2, Devon’s ownership in the General Partner decreased from 70% to 64% during the same time period. The net gains and losses and related income taxes resulting from these transactions have been recorded as an adjustment to equity, with the change in ownership reflected as an adjustment to noncontrolling interests.

Distributions to Noncontrolling Interests

EnLink and the General Partner distributed $147 million and $118 million to non-Devon unitholders during the first six months of 2016 and 2015, respectively.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

19.	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 is also involved in governmental agency proceedings and is subject to related contracts and regulatory controls in the ordinary course of business, some that may lead to additional royalty claims. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.

Environmental Matters

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

Other Matters

Devon is involved in other various 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.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

20.	Fair Value Measurements

The following table provides 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 consolidated balance sheets approximated fair value at June 30, 2016 and December 31, 2015. Therefore, such financial assets and liabilities are not presented in the following table. Additionally, the fair values of oil and gas assets, goodwill and other intangible assets and related impairments are measured as of the impairment date using Level 3 inputs. More information on these items is provided in Note 5 and Note 13.

								Fair Value Measurements Using:
		Carrying			Total Fair			Level 1		Level 2			Level 3
		Amount			Value			Inputs		Inputs			Inputs
	(Millions)
June 30, 2016 assets (liabilities):
Cash equivalents		$	1,241		$	1,241		$	1,163	$	78		$	—
Commodity derivatives		$	16		$	16		$	—	$	16		$	—
Commodity derivatives		$	(111	)	$	(111	)	$	—	$	(111	)	$	—
Interest rate derivatives		$	3		$	3		$	—	$	3		$	—
Interest rate derivatives		$	(166	)	$	(166	)	$	—	$	(166	)	$	—
Debt		$	(12,707	)	$	(12,901	)	$	—	$	(12,901	)	$	—
Installment payment		$	(447	)	$	(452	)	$	—	$	(452	)	$	—
Capital lease obligations		$	(12	)	$	(12	)	$	—	$	(12	)	$	—

December 31, 2015 assets (liabilities):
Cash equivalents		$	1,871		$	1,871		$	1,471	$	400		$	—
Commodity derivatives		$	35		$	35		$	—	$	35		$	—
Commodity derivatives		$	(18	)	$	(18	)	$	—	$	(18	)	$	—
Interest rate derivatives		$	2		$	2		$	—	$	2		$	—
Interest rate derivatives		$	(22	)	$	(22	)	$	—	$	(22	)	$	—
Foreign currency derivatives		$	8		$	8		$	—	$	8		$	—
Foreign currency derivatives		$	(8	)	$	(8	)	$	—	$	(8	)	$	—
Debt		$	(13,032	)	$	(11,927	)	$	—	$	(11,927	)	$	—
Capital lease obligations		$	(17	)	$	(16	)	$	—	$	(16	)	$	—

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

Level 1 Fair Value Measurements

Cash equivalents – Amounts consist primarily of money market investments. The fair value approximates the carrying value.

Level 2 Fair Value Measurements

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

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

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

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Installment payment – The fair value of the EnLink installment payment as of June 30, 2016 was based on Level 2 inputs from third-party market quotations.

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

21.	Segment Information

Devon manages its operations through distinct operating segments, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian E&P operating segment is reported as a separate reporting segment primarily due to the significant differences between the U.S. and Canadian regulatory environments. Devon’s U.S. and Canadian segments are both primarily engaged in oil and gas E&P activities.

Devon considers EnLink, combined with the General Partner, to be an operating segment that is distinct from the U.S. and Canadian operating segments. EnLink’s operations consist of midstream assets and operations located across the U.S. Additionally, EnLink has a management team that is primarily responsible for capital and resource allocation decisions. Therefore, EnLink is presented as a separate reporting segment.

	U.S.			Canada			EnLink			Eliminations			Total
	(Millions)
Three Months Ended June 30, 2016:
Revenues from external customers	$	1,365		$	266		$	857		$	—		$	2,488
Intersegment revenues	$	—		$	—		$	176		$	(176	)	$	—
Depreciation, depletion and amortization	$	256		$	103		$	125		$	—		$	484
Interest expense	$	108		$	33		$	47		$	(23	)	$	165
Asset impairments	$	885		$	612		$	—		$	—		$	1,497
Restructuring and transaction costs	$	19		$	4		$	1		$	—		$	24
Loss before income taxes	$	(1,097	)	$	(647	)	$	(1	)	$	—		$	(1,745	)
Income tax benefit	$	(6	)	$	(174	)	$	(2	)	$	—		$	(182	)
Net earnings (loss)	$	(1,091	)	$	(473	)	$	1		$	—		$	(1,563	)
Net earnings attributable to noncontrolling interests	$	1		$	—		$	6		$	—		$	7
Net loss attributable to Devon	$	(1,092	)	$	(473	)	$	(5	)	$	—		$	(1,570	)
Capital expenditures, including acquisitions	$	284		$	29		$	139		$	—		$	452

Three Months Ended June 30, 2015:
Revenues from external customers	$	1,930		$	360		$	1,103		$	—		$	3,393
Intersegment revenues	$	—		$	—		$	171		$	(171	)	$	—
Depreciation, depletion and amortization	$	595		$	121		$	98		$	—		$	814
Interest expense	$	88		$	23		$	26		$	(11	)	$	126
Asset impairments	$	4,168		$	—		$	—		$	—		$	4,168
Earnings (loss) before income taxes	$	(4,498	)	$	(36	)	$	55		$	—		$	(4,479	)
Income tax expense (benefit)	$	(1,736	)	$	40		$	10		$	—		$	(1,686	)
Net earnings (loss)	$	(2,762	)	$	(76	)	$	45		$	—		$	(2,793	)
Net earnings attributable to noncontrolling interests	$	1		$	—		$	22		$	—		$	23
Net earnings (loss) attributable to Devon	$	(2,763	)	$	(76	)	$	23		$	—		$	(2,816	)
Capital expenditures, including acquisitions	$	887		$	146		$	158		$	—		$	1,191

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

	U.S.			Canada			EnLink			Eliminations			Total
	(Millions)
Six Months Ended June 30, 2016:
Revenues from external customers	$	2,667		$	383		$	1,564		$	—		$	4,614
Intersegment revenues	$	—		$	—		$	359		$	(359	)	$	—
Depreciation, depletion and amortization	$	567		$	212		$	247		$	—		$	1,026
Interest expense	$	215		$	67		$	91		$	(43	)	$	330
Asset impairments	$	2,493		$	1,166		$	873		$	—		$	4,532
Restructuring and transaction costs	$	255		$	10		$	6		$	—		$	271
Loss before income taxes	$	(3,162	)	$	(1,396	)	$	(872	)	$	—		$	(5,430	)
Income tax benefit	$	(11	)	$	(382	)	$	(6	)	$	—		$	(399	)
Net loss	$	(3,151	)	$	(1,014	)	$	(866	)	$	—		$	(5,031	)
Net earnings (loss) attributable to noncontrolling interests	$	1		$	—		$	(406	)	$	—		$	(405	)
Net loss attributable to Devon	$	(3,152	)	$	(1,014	)	$	(460	)	$	—		$	(4,626	)
Property and equipment, net	$	7,823		$	2,832		$	6,160		$	—		$	16,815
Total assets	$	12,856		$	4,283		$	10,162		$	(57	)	$	27,244
Capital expenditures, including acquisitions	$	2,177		$	110		$	684		$	—		$	2,971

Six Months Ended June 30, 2015:
Revenues from external customers	$	4,189		$	581		$	1,888		$	—		$	6,658
Intersegment revenues	$	—		$	—		$	327		$	(327	)	$	—
Depreciation, depletion and amortization	$	1,307		$	248		$	189		$	—		$	1,744
Interest expense	$	175		$	48		$	45		$	(23	)	$	245
Asset impairments	$	9,628		$	—		$	—		$	—		$	9,628
Earnings (loss) before income taxes	$	(9,986	)	$	(208	)	$	91		$	—		$	(10,103	)
Income tax expense (benefit)	$	(3,729	)	$	(13	)	$	21		$	—		$	(3,721	)
Net earnings (loss)	$	(6,257	)	$	(195	)	$	70		$	—		$	(6,382	)
Net earnings attributable to noncontrolling interests	$	1		$	—		$	32		$	—		$	33
Net earnings (loss) attributable to Devon	$	(6,258	)	$	(195	)	$	38		$	—		$	(6,415	)
Property and equipment, net	$	15,852		$	6,422		$	5,550		$	—		$	27,824
Total assets	$	21,897		$	7,637		$	11,103		$	(111	)	$	40,526
Capital expenditures, including acquisitions	$	2,231		$	370		$	672		$	—		$	3,273

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

The following discussion and analysis addresses material changes in our results of operations and capital resources and uses for the three-month and six-month periods ended June 30, 2016 compared to the three-month and six-month periods ended June 30, 2015 and in our financial condition and liquidity since December 31, 2015. For information regarding our critical accounting policies and estimates, see our 2015 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Overview of 2016 Results

Key components of our financial performance are summarized below.

	Three Months Ended June 30,									Six Months Ended June 30, ⁽⁴⁾
	2016			2015			Change			2016			2015			Change
	(Millions, except per share amounts)
Net loss attributable to Devon	$	(1,570	)	$	(2,816	)		+44	%	$	(4,626	)	$	(6,415	)		+28	%
Net loss per share attributable to Devon	$	(3.04	)	$	(6.94	)		+56	%	$	(9.33	)	$	(15.81	)		+41	%
Core earnings (loss) attributable to Devon⁽¹⁾	$	33		$	320			- 90	%	$	(216	)	$	409			- 153	%
Core earnings (loss) per share attributable to Devon ⁽¹⁾	$	0.06		$	0.78			- 92	%	$	(0.44	)	$	0.99			- 144	%
Core production (MBoe/d) ⁽²⁾		545			547			0	%		563			553			+2	%
Total production (MBoe/d)		644			674			- 4	%		665			679			- 2	%
Realized price per Boe ⁽³⁾	$	18.50		$	25.86			- 28	%	$	15.78		$	23.80			- 34	%
Operating cash flow	$	335		$	1,101			- 70	%	$	484		$	2,749			- 82	%
Capitalized costs, including acquisitions	$	452		$	1,191			- 62	%	$	2,971		$	3,273			- 9	%
Shareholder and noncontrolling interests distributions	$	107		$	163			- 34	%	$	305		$	315			- 3	%
Cash and cash equivalents										$	1,723		$	1,725			0	%
Total debt										$	12,707		$	11,964			+6	%

(1)

Core earnings (loss) and core earnings (loss) per share attributable to Devon are financial measures not prepared in accordance with GAAP. For a description of core earnings (loss) and core earnings (loss) per share attributable to Devon, as well as reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 2.

(2)	Core production is comprised of production in our key operating areas as outlined in our “Oil, Gas and NGL Production” table in this Item 2.

(3)	Excludes any impact of oil, gas and NGL derivatives.

(4)	Except for balance sheet amounts, which are presented as of June 30.

During the first six months of 2016, commodity prices continued to be volatile. The WTI oil price has ranged from approximately $30/Bbl to $50/Bbl and NYMEX Henry Hub natural gas prices have ranged from approximately $1.75/Mcf to $3.00/Mcf in 2016. As compared to the first quarter of 2016, we have seen moderate improvements in the commodity price environment; however, commodity prices are substantially lower than the second quarter of 2015. Despite the improvements over the first quarter of 2016, relatively low prices remained a challenge for us and the upstream energy sector. In spite of this, we have continued to execute on our strategy and position our company for long-term success. To that end, we have taken financial and operational steps during 2016 by making prudent investments and upgrades to our portfolio of assets, bringing the value of certain non-core oil and gas assets forward through divestiture, further optimizing our production operations to minimize production declines and controlling costs to strengthen our balance sheet. Specifically, we had several key achievements:

Expanded our position in the STACK by acquiring approximately 80,000 net acres and assets for $1.5 billion.

Reduced exploratory and developmental capital investment by 69% as compared to the first six months of 2015.

Raised net proceeds of $1.5 billion in an offering of our common stock.

Entered into agreements totaling $3.2 billion to sell non-core assets across our portfolio, surpassing the top end of our guidance range. These agreements include our non-core Mississippian, east Texas, Anadarko Basin and Midland Basin assets, bringing total E&P non-core transactions to $2.1 billion. Subsequent to quarter-end, we entered into an agreement to sell our interest in the Access Pipeline for $1.1 billion.

Raised 2016 production guidance for core assets by 3%.

Reduced LOE by $28 million or 6% as compared to the first quarter of 2016 and by $146 million or 26% compared to the second quarter of 2015.

Reduced gross G&A by $67 million as compared to the first quarter of 2016, primarily through cost reduction initiatives resulting from our February 2016 workforce reduction, the full benefits of which have yet to be realized. Through the first six months of 2016, our gross G&A is approximately $200 million lower than the same time period in 2015. The reductions are expected to decrease gross G&A costs by approximately $400 million on an annualized basis.

Exited the second quarter of 2016 with $4.6 billion of liquidity, consisting of $1.7 billion of cash and $2.9 billion of capacity on our Senior Credit Facility. We have managed our debt maturity schedule to provide maximum flexibility with near-term liquidity; we have no major long-term debt maturities until December 2018.

In conjunction with the workforce reduction and transactions discussed above, we incurred $271 million of restructuring and transaction costs in the first six months of 2016. Additionally, during the first six months of 2016, we recognized $4.5 billion of asset impairments related to the continued depressed prices for commodities. While these impairments significantly impacted our earnings, they had no effect on our operating cash flow or debt covenants.

Results of Operations

Oil, Gas and NGL Production

	Three Months Ended June 30,								Six Months Ended June 30,
	2016		2015		Change			2016			2015		Change
Oil (MBbls/d)
Barnett Shale		1		1		- 27	%			1		1		- 31	%
Delaware Basin		36		41		- 14	%			36		37		- 2	%
Eagle Ford		41		67		- 38	%			50		71		- 29	%
Rockies Oil		15		16		- 6	%			16		14		+14	%
STACK		17		6		+190	%			16		6		+185	%
Heavy Oil		22		25		- 13	%			24		26		- 9	%
Core assets		132		156		- 16	%			143		155		- 8	%
Other assets ⁽¹⁾		28		41		- 31	%			29		41		- 29	%
Total		160		197		- 19	%			172		196		- 12	%
Bitumen (MBbls/d)
Heavy Oil		99		73		+36	%			100		75		+34	%
Gas (MMcf/d)
Barnett Shale		739		805		- 8	%			744		816		- 9	%
Delaware Basin		99		75		+33	%			91		70		+30	%
Eagle Ford		103		146		- 29	%			124		144		- 14	%
Rockies Oil		31		41		- 26	%			31		40		- 21	%
STACK		267		221		+21	%			277		226		+23	%
Heavy Oil		28		20		+38	%			22		24		- 11	%
Core assets		1,267		1,308		- 3	%			1,289		1,320		- 2	%
Other assets⁽¹⁾		260		319		- 18	%			265		316		- 16	%
Total		1,527		1,627		- 6	%			1,554		1,636		- 5	%
NGLs (MBbls/d)
Barnett Shale		43		49		- 14	%			42		50		- 15	%
Delaware Basin		13		10		+32	%			12		9		+38	%
Eagle Ford		17		24		- 27	%			21		23		- 11	%
STACK		29		16		+79	%			29		19		+51	%
Rockies Oil		1		1		- 11	%			1		1		+16	%
Core assets		103		100		+3	%			105		102		+3	%
Other assets⁽¹⁾		28		34		- 18	%			29		34		- 15	%
Total		131		134		- 2	%			134		136		- 1	%
Combined (MBoe/d)
Barnett Shale		167		185		- 10	%			168		188		- 11	%
Delaware Basin		65		64		+2	%			64		58		+10	%
Eagle Ford		75		114		- 34	%			91		118		- 23	%
Rockies Oil		21		24		- 12	%			22		22		+3	%
STACK		91		59		+54	%			91		62		+46	%
Heavy Oil		126		101		+24	%			127		105		+21	%
Core assets		545		547		- 0	%			563		553		+2	%
Other assets ⁽¹⁾		99		127		- 22	%			102		126		- 19	%
Total		644		674		- 4	%			665		679		- 2	%

(1)	Other assets are located primarily in the Midland Basin, east Texas, Granite Wash and Mississippian-Lime areas.

Oil, Gas and NGL Pricing

	Three Months Ended June 30,							Six Months Ended June 30,
	2016 ⁽¹⁾		2015 ⁽¹⁾		Change			2016 ⁽¹⁾		2015 ⁽¹⁾		Change
Oil (per Bbl)
U.S.	$	41.56	$	52.52		- 21	%	$	34.70	$	47.74		- 27	%
Canada	$	27.62	$	42.60		- 35	%	$	19.86	$	35.57		- 44	%
Total	$	39.64	$	51.25		- 23	%	$	32.64	$	46.11		- 29	%
Bitumen (per Bbl)
Canada	$	21.40	$	34.38		- 38	%	$	14.73	$	27.39		- 46	%
Gas (per Mcf)
U.S.	$	1.40	$	2.13		- 34	%	$	1.47	$	2.29		- 36	%
NGLs (per Bbl)
U.S.	$	10.14	$	10.31		- 2	%	$	8.46	$	9.85		- 14	%
Combined (per Boe)
U.S.	$	17.68	$	24.18		- 27	%	$	15.89	$	22.93		- 31	%
Canada	$	21.85	$	35.33		- 38	%	$	15.33	$	28.56		- 46	%
Total	$	18.50	$	25.86		- 28	%	$	15.78	$	23.80		- 34	%

(1)	Prices presented exclude any effects of 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 and six months ended June 30, 2016 and 2015.

	Three Months Ended June 30,
	Oil			Bitumen			Gas			NGLs			Total
	(Millions)
2015 sales	$	917		$	228		$	316		$	126		$	1,587
Change due to volumes		(174	)		83			(19	)		(2	)		(112	)
Change due to prices		(168	)		(118	)		(102	)		(2	)		(390	)
2016 sales	$	575		$	193		$	195		$	122		$	1,085

	Six Months Ended June 30,
	Oil			Bitumen			Gas			NGLs			Total
	(Millions)
2015 sales	$	1,634		$	371		$	678		$	243		$	2,926
Change due to volumes		(193	)		128			(30	)		(2	)		(97	)
Change due to prices		(421	)		(231	)		(233	)		(34	)		(919	)
2016 sales	$	1,020		$	268		$	415		$	207		$	1,910

Oil, gas and NGL sales decreased due to a change in production volumes during the second quarter and the first six months of 2016. While continued development of our Delaware Basin and our enhanced positions in the STACK drove production increases, these increases were more than offset by reduced completion activity in the Eagle Ford and natural production declines in the Barnett Shale and in our non-core properties. Additionally, our bitumen production increased primarily due to Jackfish 3 exceeding nameplate capacity in the first six months of 2016.

Oil, bitumen, gas and NGL sales decreased in the second quarter and the first six months of 2016 due to significant price decreases for all commodities. The decrease in oil and bitumen sales resulted from lower average WTI crude oil index prices, which were 26% lower than the first six months of 2015. The decreases in gas and NGL sales were due to lower North American regional index prices upon which our gas sales are based and lower NGL prices at the Mont Belvieu, Texas hub.

Oil, Gas and NGL Derivatives

A summary of our open commodity derivative positions is included in Note 3 to the financial statements included in “Part I. Financial Information – Item 1. Financial Statements” of this report. The following tables provide financial information associated with our oil, gas and NGL hedges. 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, gas and NGL prices with, and without, the effects of the cash settlements. The prices do not include the effects of fair value gains and losses.

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(Millions)
Cash settlements:
Oil derivatives	$	(61	)	$	394		$	(61	)	$	911
Gas derivatives		32			86			51			162
NGL derivatives		(2	)		—			(2	)		—
Total cash settlements		(31	)		480			(12	)		1,073
Gains (losses) on fair value changes:
Oil derivatives		(28	)		(667	)		(30	)		(948	)
Gas derivatives		(77	)		(95	)		(61	)		(113	)
NGL derivatives		(6	)		—			(6	)		—
Total losses on fair value changes		(111	)		(762	)		(97	)		(1,061	)
Oil, gas and NGL derivatives	$	(142	)	$	(282	)	$	(109	)	$	12

	Three Months Ended June 30, 2016
	Oil			Bitumen		Gas		NGLs			Boe
	(Per Bbl)			(Per Bbl)		(Per Mcf)		(Per Bbl)			(Per Boe)
Realized price without hedges	$	39.64		$	21.40	$	1.40	$	10.14		$	18.50
Cash settlements of hedges		(4.17	)		—		0.24		(0.25	)		(0.53	)
Realized price, including cash settlements	$	35.47		$	21.40	$	1.64	$	9.89		$	17.97

	Three Months Ended June 30, 2015
	Oil			Bitumen		Gas		NGLs			Boe
	(Per Bbl)			(Per Bbl)		(Per Mcf)		(Per Bbl)			(Per Boe)
Realized price without hedges	$	51.25		$	34.38	$	2.13	$	10.31		$	25.86
Cash settlements of hedges		22.04			—		0.58		—			7.83
Realized price, including cash settlements	$	73.29		$	34.38	$	2.71	$	10.31		$	33.69

	Six Months Ended June 30, 2016
	Oil			Bitumen		Gas		NGLs			Boe
	(Per Bbl)			(Per Bbl)		(Per Mcf)		(Per Bbl)			(Per Boe)
Realized price without hedges	$	32.64		$	14.73	$	1.47	$	8.46		$	15.78
Cash settlements of hedges		(1.94	)		—		0.18		(0.13	)		(0.10	)
Realized price, including cash settlements	$	30.70		$	14.73	$	1.65	$	8.33		$	15.68

	Six Months Ended June 30, 2015
	Oil			Bitumen		Gas		NGLs			Boe
	(Per Bbl)			(Per Bbl)		(Per Mcf)		(Per Bbl)			(Per Boe)
Realized price without hedges	$	46.11		$	27.39	$	2.29	$	9.85		$	23.80
Cash settlements of hedges		25.69			—		0.55		—			8.72
Realized price, including cash settlements	$	71.80		$	27.39	$	2.84	$	9.85		$	32.52

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 oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationships between contract prices and the associated forward curves. Including the cash settlements discussed above, our oil, gas

and NGL derivatives incurred net losses in the second quarter of 2016 and 2015. Including the cash settlements discussed above, our oil, gas and NGL derivatives incurred a net loss in the first six months of 2016 and generated a net gain in the first six months of 2015.

Marketing and Midstream Revenues and Operating Expenses

	Three Months Ended June 30,									Six Months Ended June 30,
	2016			2015			Change			2016			2015			Change
	(Millions)
Operating revenues	$	1,545		$	2,088			- 26	%	$	2,813		$	3,720			- 24	%
Product purchases		(1,248	)		(1,762	)		- 29	%		(2,227	)		(3,110	)		- 28	%
Operations and maintenance expenses		(90	)		(101	)		- 11	%		(177	)		(192	)		- 8	%
Operating profit	$	207		$	225			- 8	%	$	409		$	418			- 2	%

Devon profit	$	(4	)	$	15	- 127	%	$	(19	)	$	13	- 246	%
EnLink profit		211			210	+0	%		428			405	+6	%
Total profit	$	207		$	225	- 8	%	$	409		$	418	- 2	%

The overall decrease in marketing and midstream margin in the second quarter of 2016 was primarily due to lower margins on Devon’s downstream marketing commitments. The overall decrease in the marketing and midstream margin in the six months ended period was due to lower margins on Devon’s downstream marketing commitments partially offset by EnLink’s acquisition activity in 2015 and the first quarter of 2016.

Lease Operating Expenses

	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Change			2016		2015		Change
	(Millions, except per Boe amounts)
LOE:
U.S.	$	295	$	402		- 27	%	$	638	$	812		- 21	%
Canada		121		160		- 24	%		222		303		- 27	%
Total	$	416	$	562		- 26	%	$	860	$	1,115		- 23	%

LOE per Boe:
U.S.	$	6.25	$	7.71		- 19	%	$	6.52	$	7.81		- 16	%
Canada	$	10.58	$	17.35		- 39	%	$	9.58	$	15.95		- 40	%
Total	$	7.09	$	9.16		- 23	%	$	7.11	$	9.07		- 22	%

LOE and LOE per Boe decreased during the second quarter and the first six months of 2016 primarily due to our well optimization and cost reduction initiatives and changes in the Canadian to U.S. foreign exchange rate. Our cost reduction initiatives have been primarily focused on reducing costs associated with water disposal, power and fuel, compression and workovers.

Upon closing the Access Pipeline divestiture discussed in Note 2 in “Part I. Financial Information – Item 1. Financial Statements,” we expect LOE to increase approximately $35 million to $40 million in the last six months of 2016 as a result of our transportation commitment on the pipeline.

General and Administrative Expenses

	Three Months Ended June 30,									Six Months Ended June 30,
	2016			2015			Change			2016			2015			Change
	(Millions)
Gross G&A	$	225		$	344			- 35	%	$	517		$	719			- 28	%
Capitalized G&A		(56	)		(101	)		- 45	%		(129	)		(195	)		- 34	%
Reimbursed G&A		(22	)		(31	)		- 29	%		(47	)		(61	)		- 23	%
Net G&A	$	147		$	212			- 30	%	$	341		$	463			- 26	%

Gross G&A and capitalized G&A decreased during the second quarter and the first six months of 2016 largely due to lower Devon employee costs resulting from recent workforce reductions, as discussed in Note 6 in “Part I. Financial Information – Item 1. Financial Statements,” and other cost reduction initiatives. Reimbursed G&A decreased primarily due to a reduction in drilling activity in response to the decline in commodity prices.

Production and Property Taxes

	Three Months Ended June 30,									Six Months Ended June 30,
	2016			2015			Change			2016			2015			Change
	(Millions)
Production	$	38		$	59			- 36	%	$	71		$	112			- 37	%
Property and other		37			57			- 35	%		82			112			- 28	%
Production and property taxes	$	75		$	116			- 35	%	$	153		$	224			- 32	%

Percentage of oil, gas and NGL sales:
Production		3.5	%		3.7	%		- 6	%		3.7	%		3.8	%		- 3	%
Property and other		3.4	%		3.6	%		- 4	%		4.3	%		3.9	%		+11	%
Total		6.9	%		7.3	%		- 5	%		8.0	%		7.7	%		+4	%

Production taxes decreased during the second quarter and the first six months of 2016 on an absolute dollar basis primarily due to a decrease in our U.S. revenues, on which the majority of our production taxes are assessed. Furthermore, property and other taxes decreased from the prior year primarily as a result of lower property value assessments from the local taxing authorities across our key operating areas. Property taxes do not change in direct correlation with the decline in oil, gas and NGL sales, and are generally determined based on the valuation of the underlying assets.

Depreciation, Depletion and Amortization

	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Change			2016		2015		Change
	(Millions, except per Boe amounts)
DD&A:
Oil and gas properties	$	313	$	675		- 54	%	$	691	$	1,475		- 53	%
Other assets		171		139		+23	%		335		269		+25	%
Total	$	484	$	814		- 41	%	$	1,026	$	1,744		- 41	%
DD&A per Boe:
Oil and gas properties	$	5.33	$	11.00		- 52	%	$	5.71	$	12.00		- 52	%

DD&A from our oil and gas properties decreased in the second quarter and the first six months of 2016 compared to the second quarter and the first six months of 2015 largely due to lower DD&A rates, as a result of the oil and gas asset impairments recognized in 2015 and the first quarter of 2016. Other DD&A increased primarily due to EnLink’s acquisitions in 2016 and 2015.

Asset Impairments

We recognized asset impairments during the second quarter and the first six months of 2016 and 2015. For further discussion, see Note 5 in “Part I. Financial Information – Item 1. Financial Statements” of this report.

Restructuring and Transaction Costs

During the first six months of 2016, we recognized restructuring costs of $256 million as a result of the workforce reductions, which were driven by our cost reduction initiatives and anticipated divestitures of non-core properties. These restructuring costs include estimated employee-related cash and non-cash severance costs afforded under the terms of our severance policy. When estimating these costs, certain assumptions were made with respect to the timing of employee terminations and the number of employees that may receive employment offers from the purchasers of our divested assets. Based on the percentage of employees receiving offers from purchasers through the date of this report, we do not expect to incur significant additional severance costs related to the pending divestiture transactions. In addition, we incurred lease obligation costs due to non-cancellable operating lease agreements and asset impairments related to the vacated office space. See Note 6 in “Part I. Financial Information – Item 1. Financial Statements” of this report.

During the first six months of 2016, we recognized transaction costs of $15 million, primarily associated with the closing of the acquisitions discussed in Note 2 in “Part I. Financial Information – Item 1. Financial Statements” of this report.

Net Financing Costs

	Three Months Ended June 30,									Six Months Ended June 30,
	2016			2015			Change			2016			2015			Change
	(Millions)
Interest based on debt outstanding	$	163		$	136			+19	%	$	324		$	266			+21	%
Capitalized interest		(18	)		(15	)		+16	%		(35	)		(29	)		+20	%
Interest accretion on deferred installment		13			—		N/M				26			—		N/M
Other fees and expenses		7			5			+26	%		15			8			+81	%
Interest expense		165			126			+30	%		330			245			+34	%
Interest income		(2	)		(1	)		+19	%		(3	)		(3	)		- 25	%
Net financing costs	$	163		$	125			+30	%	$	327		$	242			+35	%

Net financing costs increased during the second quarter and the first six months of 2016 primarily due to an increase in Devon and EnLink fixed-rate borrowings and accretion of future installment payments related to EnLink acquisition activity in the first quarter of 2016. For further discussion of the accretion of future installment payments, see Note 2 in “Part I. Financial Information – Item 1. Financial Statements.”

As discussed in “Liquidity” in this Item 2. we anticipate using a portion of divestiture proceeds for debt repayment. Upon repayment of outstanding debt, and excluding one-time costs we expect to incur upon retirement, we would expect a decline in net financing costs in future reporting periods. The extent of the decline will be largely dependent upon the timing of closing the divestiture transactions, as well as the amount and timing of debt retired. As such, we are unable to estimate the magnitude of the impact of debt repayments on net financing costs at this time.

Income Taxes

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Total income tax benefit (millions)	$	(182	)	$	(1,686	)	$	(399	)	$	(3,721	)
Effective income tax rate		(10	%)		(38	%)		(7	%)		(37	%)

For further discussion of our income tax benefit, see Note 7 in “Part I. Financial Information – Item 1. Financial Statements.”

Capital Resources, Uses and Liquidity

Sources and Uses of Cash

The following table presents the major changes in our cash and cash equivalents for the six months ended June 30, 2016 and 2015.

		Devon						EnLink						Consolidated
		2016			2015			2016			2015			2016			2015
	(Millions)
Operating cash flow		$	180		$	2,472		$	304		$	277		$	484		$	2,749
Issuance of common stock			1,469			—			—			—			1,469			—
Divestitures of property and equipment			208			8			1			—			209			8
Capital expenditures			(950	)		(2,800	)		(288	)		(349	)		(1,238	)		(3,149	)
Acquisitions of property, equipment and businesses			(847	)		(92	)		(791	)		(325	)		(1,638	)		(417	)
Debt activity, net			(627	)		(30	)		298			797			(329	)		767
Shareholder and noncontrolling interests distributions			(158	)		(197	)		(147	)		(118	)		(305	)		(315	)
EnLink and General Partner distributions			133			137			(133	)		(137	)		—			—
EnLink dropdowns			—			171			—			(171	)		—			—
Issuance of subsidiary units			—			—			776			4			776			4
Sale of subsidiary units			—			654			—			—			—			654
Effect of exchange rate and other			13			(82	)		(28	)		26			(15	)		(56	)
Net change in cash and cash equivalents		$	(579	)	$	241		$	(8	)	$	4		$	(587	)	$	245
Cash and cash equivalents at end of period		$	1,713		$	1,653		$	10		$	72		$	1,723		$	1,725

Operating Cash Flow

Net cash provided by operating activities decreased 82% primarily due to lower commodity prices and the impact of cash settlements associated with our commodity derivatives during 2015.

Excluding payments made for acquisitions, our consolidated operating cash flow funded 39% and 87% of our capital expenditures during the first six months of 2016 and 2015, respectively. In 2016, leveraging our liquidity, we also used cash balances and proceeds from our common stock offering to fund our acquisitions and capital expenditures.

Issuance of Common Stock

In February 2016, we issued 79 million shares of our common stock to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were approximately $1.5 billion.

Divestitures of Property and Equipment

On June 30, 2016, we sold our non-core Mississippian assets for approximately $200 million. For further discussion, see Note 2 in “Part 1. Financial Information – Item 1. Financial Statements.”

Capital Expenditures and Acquisitions of Property, Equipment and Businesses

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

	Six Months Ended June 30,
	2016		2015
	(Millions)
Oil and gas	$	932	$	2,711
Midstream		4		29
Corporate and other		14		60
Devon capital expenditures		950		2,800
EnLink capital expenditures		288		349
Total capital expenditures	$	1,238	$	3,149
Devon acquisitions	$	847	$	92
EnLink acquisitions		791		325
Total acquisitions	$	1,638	$	417

Capital expenditures consist of amounts related to our oil and gas exploration and development operations, midstream operations, other corporate activities and EnLink growth and maintenance activities. The vast majority of Devon’s capital expenditures are for the acquisition, drilling and development of oil and gas properties. In response to lower commodity prices, Devon’s 2016 capital program is designed to be substantially lower than 2015, evidenced by a 69% decrease in exploration and development costs from the first six months of 2015 as well as a 53% decrease from the last six months of 2015 to the first six months of 2016.

Capital expenditures for Devon’s and EnLink’s midstream operations are primarily for the construction and expansion of oil and gas gathering facilities and pipelines. Midstream capital expenditures are largely impacted by oil and gas drilling and development activities.

Acquisition capital for the first six months of 2016 primarily consisted of Devon’s acquisition of assets in the STACK play for approximately $1.5 billion and EnLink’s acquisition of Anadarko Basin gathering and processing midstream assets for $1.5 billion. Approximately $847 million and $800 million, respectively, was paid in cash at the closings with the remainder of the purchase prices funded with equity consideration and debt. For additional information, see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Debt Activity, Net

During the first six months of 2016, we reduced our debt by $329 million. The decrease was primarily due to reducing our commercial paper balances by $626 million partially offset by EnLink’s increased credit facility borrowings to fund acquisitions and growth capital expenditures.

In June 2015, we issued $750 million of 5.0% senior notes. The proceeds were used to repay the aggregate principal amount of our December 15, 2015 floating rate senior notes, as well as outstanding commercial paper balances. Our net debt borrowings during the first six months of 2015 increased $767 million, which was primarily due to EnLink borrowings made to fund acquisitions and dropdowns.

Shareholder and Noncontrolling Interests Distributions

The following table summarizes our common stock dividends during the first six months of 2016 and 2015. In the second quarter of 2016, we decreased our quarterly dividend to $0.06 per share.

	Amount		Rate
	(Millions)		(Per Share)
Quarter Ended 2016:
First quarter 2016	$	125	$	0.24
Second quarter 2016		33	$	0.06
Total year-to-date	$	158
Quarter Ended 2015:
First quarter 2015	$	99	$	0.24
Second quarter 2015		98	$	0.24
Total year-to-date	$	197

EnLink and the General Partner distributed $147 million and $118 million to non-Devon unitholders during the first six months of 2016 and 2015, respectively.

EnLink and General Partner Distributions

Devon received $133 million and $137 million in distributions from EnLink and the General Partner during the first six months of 2016 and 2015, respectively.

EnLink Dropdowns

In the second quarter of 2015, Devon received $171 million in cash from EnLink in exchange for VEX.

Issuance of Subsidiary Units

In February 2016, as part of its acquisition of Anadarko Basin gathering and processing midstream assets, EnLink issued 50 million preferred units in a private placement generating proceeds of approximately $725 million. Also in conjunction with this acquisition, the General Partner issued 15.6 million of common units with an aggregate value of $215 million. Additionally, during the first six months of 2016, EnLink issued 3 million common units for net proceeds of $52 million.

Sale of Subsidiary Units

In March 2015, we conducted an underwritten secondary public offering of 23 million common units representing limited partner interests in EnLink, raising proceeds of $569 million, net of underwriting discount. In April 2015, as part of the secondary public offering, underwriters fully exercised their option to purchase an additional 3.4 million common units, raising $85 million of net proceeds.

Liquidity

Historically, our primary sources of capital and liquidity have been our operating cash flow and cash on hand. Additionally, we maintain a commercial paper program, supported by our revolving line of credit, which can be accessed as needed to supplement operating cash flow and cash balances. Available sources of capital and liquidity include, among others, debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC, as well as the sale of a portion of our common units representing interests in our investment in EnLink and the General Partner. The most significant source of liquidity in 2016 will come from proceeds related to our asset divestitures. Through August 3, 2016 we have closed approximately $1.2 billion of the announced asset divestitures. We expect to close the remaining transactions in the third quarter of 2016. 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.

Operating Cash Flow

Our operating cash flow is sensitive to many variables, the most volatile of which are the prices of the oil, bitumen, gas and NGLs we produce and sell. Our consolidated operating cash flow decreased 82% in the first six months of 2016 compared to the first six months of 2015 as a result of the significant decreases in commodity prices, as well as in the settlement value of our hedge contracts. In spite of this decline, we expect operating cash flow to continue to be a key source of liquidity as we adjust our capital program in response to lower commodity prices. Additionally, we anticipate utilizing divestiture proceeds and our credit availability to provide additional liquidity as needed.

To mitigate some of the risk inherent in prices, we utilize various derivative financial instruments to protect a portion of our production against downside price risk. For additional information, see Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Capital Expenditures

With the success of the non-core asset divestitures discussed below, we increased our estimated capital program spending $200 million. Excluding acquisitions and EnLink, our 2016 capital expenditures are expected to range from $1.4 billion to $1.6 billion, including $1.1 billion to $1.3 billion for our oil and gas capital program.

Credit Availability

As of June 30, 2016, we had $66 million in outstanding letters of credit and no outstanding borrowings under our $3.0 billion Senior Credit Facility. This credit facility supports our $3.0 billion commercial paper program. At June 30, 2016, we had no outstanding commercial paper borrowings.

The Senior Credit Facility contains only one material financial covenant. This covenant requires us to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65%. As of June 30, 2016, we were in compliance with this covenant with a debt-to-capitalization ratio of 23.1%.

EnLink has a $1.5 billion unsecured revolving credit facility, and the General Partner has a $250 million secured revolving credit facility. As of June 30, 2016, there were $11 million in outstanding letters of credit and $697 million in outstanding borrowings under the $1.5 billion credit facility, and the General Partner had $15 million in outstanding borrowings under the $250 million credit facility.

Asset Divestitures

In December 2015, we announced our intent to divest our interest in the Access Pipeline and certain non-core upstream assets targeting total proceeds of $2 billion to $3 billion. During the second quarter of 2016, we closed the divestiture of our Mississippian assets for approximately $200 million. Additionally, in June 2016, we entered into definitive agreements to sell the remaining upstream assets in the U.S. for approximately $1.8 billion. Subsequent to the end of the second quarter, we entered into a definitive agreement to sell our 50% ownership interest in the Access Pipeline for approximately $1.1 billion. The remaining transactions have or are expected to close in the third quarter of 2016 and will conclude our divestitures with expected proceeds of approximately $3.2 billion, surpassing the top end of our guidance range. We anticipate using a portion of these asset divestiture proceeds for debt repayment in the second half of 2016.

EnLink Capital Resources and Expenditures

In January 2016, EnLink acquired additional gathering and processing midstream assets in the Anadarko Basin for approximately $1.5 billion in cash and equity, subject to certain adjustments. The first installment of $1.02 billion for the acquisition was paid at closing, and the final installment of $500 million is due no later than the first anniversary of the closing date, with the option to defer $250 million of the final installment up to 24 months following the closing date.

Debt Ratings

We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales, near-term and long-term production growth opportunities and capital allocation challenges. In February 2016, our credit rating was revised by Standard & Poor’s Financial Services from BBB+ with a negative outlook to BBB with a stable outlook. In March 2016, Fitch Ratings affirmed our BBB+ rating but revised our outlook from

stable to negative. In July 2016, Moody’s Investor Service revised our senior unsecured rating from Ba2 with negative outlook to a stable outlook.

There are no “rating triggers” in any of our or EnLink’s contractual debt obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. However, these downgrades could adversely impact our and EnLink’s interest rate on any credit facility borrowings and the ability to economically access debt markets in the future.

Contractual Obligations

As discussed in Note 2 in “Part 1. Financial Information – Item 1. Financial Statements” of this report, we reached an agreement to sell our 50% interest in the Access Pipeline. Under the terms of the agreement, we dedicated our thermal-oil acreage to Access Pipeline for an initial term of 25 years. Upon closing of the transaction in the third quarter of 2016, we expect our annualized LOE to increase approximately $100 million.

Critical Accounting Estimates

Full Cost Method of Accounting and Proved Reserves

Under the full cost method of accounting, sales or dispositions of oil and gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of a gain or loss. The determination of whether a gain or loss is to be recognized is dependent upon whether the disposition significantly alters the relationship between capitalized costs and proved reserves, the conclusion of which involves a significant amount of judgment. We are evaluating whether the pending non-core oil and gas property divestiture transactions discussed in Note 2 in “Part 1. Financial Information – Item 1. Financial Statements” of this report will result in the recognition of a gain. The final determination will largely depend on factors such as how and whether the disposal transactions are aggregated.

We perform a full cost ceiling impairment test each quarter for our U.S. and Canadian oil and gas properties. The ceiling tests for the first six months of 2016 resulted in recognizing ceiling impairments on our U.S. and Canadian properties totaling $3.7 billion.

Depending on the relationship between our capitalized costs and calculated full cost ceiling at the time of the most recent ceiling test performed, uncertain future prices limit our ability to predict and measure potential future full cost impairments. However, because the ceiling test computation uses a 12-month trailing price to determine future cash flows, we can typically predict when circumstances will result in future impairments that are material, particularly in the next one to two quarters. However, due to the nature of estimating future cash flows, measuring any potential impairments is more difficult.

Based on prices from the last nine months of the trailing 12-month average and the short-term pricing outlook for the third quarter of 2016 and an assumption that we complete the Access Pipeline divestiture in the third quarter, we expect to recognize an additional Canadian full cost impairment in the third quarter of 2016. We expect the impairment on our Canadian oil and gas properties to approximate amounts recognized in the first and second quarter of 2016. As discussed above, we are currently evaluating the accounting impact of the U.S. divestiture transactions, which would impact the amount of any impairment recorded on our U.S. full cost pool. Our full cost impairments have no effect on liquidity or capital resources. However, they adversely affect our results of operations in the period recognized.

Goodwill

We test goodwill for impairment annually at October 31, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Sustained weakness in the overall energy sector driven by low commodity prices, together with a decline in the EnLink unit price, caused a change in circumstances warranting an interim impairment test for EnLink’s reporting units.

The goodwill assessment is performed at the reporting unit level and primarily utilizes a discounted cash flow analysis, supplemented by a market approach analysis in the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples and estimated future cash flows, including volume forecasts and estimated operating and G&A costs. In estimating cash flows, current and historical market information, among other factors, are incorporated.

Using the fair value approaches described above, in the first quarter of 2016 it was determined that the estimated fair value of EnLink’s Texas, General Partner and Crude and Condensate reporting units were less than their carrying amounts, primarily due to changes in assumptions related to commodity prices and discount rates. Through the analysis, a goodwill impairment loss of $473

million, $307 million and $93 million for EnLink’s Texas, General Partner and Crude and Condensate reporting units, respectively, was recognized in the first quarter of 2016.

As of March 31, 2016, the goodwill allocated to the Crude and Condensate reporting unit was fully impaired. Other than those mentioned above, no other goodwill impairment was identified or recorded for the remaining reporting units as a result of the interim goodwill assessment, as their estimated fair values were in excess of carrying values. However, the fair value of EnLink’s Texas and General Partner reporting units are not substantially in excess of their carrying value. The fair value of the Texas and General Partner reporting units approximates their carrying values after considering the impairment loss above and, as of June 30, 2016, $230 million and $1.1 billion of goodwill remains allocated to the reporting units, respectively.

Our impairment determinations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual future results are not consistent with these assumptions and estimates, or the assumptions and estimates change due to new information, we may be exposed to additional goodwill impairment charges, which would be recognized in the period in which we would determine that the carrying value exceeds fair value. We would expect that a prolonged or sustained period of lower commodity prices would adversely affect the estimate of future operating results, which could result in future goodwill impairments for other reporting units due to the potential impact on the cash flows of our operations.

The goodwill impairment has no effect on liquidity or capital resources. However, it adversely affects net earnings in the period recognized.

Income Taxes

The amount of income taxes recorded requires interpretations of complex rules and regulations of federal, state, provincial and foreign tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. At December 31, 2015, we recorded a 100% valuation allowance against the U.S. deferred tax assets that largely resulted from the full cost impairments recognized during 2015. As a result of the continued financial losses in the second quarter of 2016, we continued to have a 100% valuation allowance against our U.S. deferred tax assets as of June 30, 2016.

The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. Material changes to our income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of other pending matters.

Non-GAAP Measures

We make reference to “core earnings (loss) attributable to Devon” and “core earnings (loss) per share attributable to Devon” in “Overview of 2016 Results” in this Item 2. that are not required by or presented in accordance with GAAP. These non-GAAP measures are not alternatives to GAAP measures, and should not be considered in isolation or as a substitute for analysis of our results reported under GAAP. Core earnings (loss) attributable to Devon, as well as the per share amount, represent net earnings excluding certain noncash and other 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. Amounts excluded for the second quarter and first six months of 2016 relate to derivatives and financial instrument fair value changes, noncash asset impairments (including an impairment of goodwill), deferred tax asset valuation allowance and restructuring and transaction costs. Amounts excluded for the second quarter and first six months of 2015 relate to derivatives and financial instrument fair value changes and noncash asset impairments. 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.

Below are reconciliations of our core earnings (loss) and core earnings (loss) per share attributable to Devon to their comparable GAAP measures.

	Three Months Ended June 30,												Six Months Ended June 30,
	Before Tax			After Tax			After Noncontrolling Interests			Per Share			Before Tax			After Tax			After Noncontrolling Interests			Per Share
	(Millions, except per share amounts)
2016
Loss attributable to Devon (GAAP)	$	(1,745	)	$	(1,563	)	$	(1,570	)	$	(3.04	)	$	(5,430	)	$	(5,031	)	$	(4,626	)	$	(9.33	)
Adjustments:
Fair value changes in financial instruments and foreign currency		205			134			130			0.25			217			94			89			0.18
Restructuring and transaction costs		24			16			16			0.03			271			174			172			0.34
Deferred tax asset valuation allowance		—			467			467			0.91			—			1,275			1,275			2.57
Asset impairments		1,497			990			990			1.91			4,532			3,290			2,874			5.80
Core earnings (loss) attributable to Devon (Non-GAAP)	$	(19	)	$	44		$	33		$	0.06		$	(410	)	$	(198	)	$	(216	)	$	(0.44	)
2015
Loss attributable to Devon (GAAP)	$	(4,479	)	$	(2,793	)	$	(2,816	)	$	(6.94	)	$	(10,103	)	$	(6,382	)	$	(6,415	)	$	(15.81	)
Adjustments:
Fair value changes in financial instruments and foreign currency		761			490			490			1.20			1,079			711			711			1.75
Asset impairments		4,168			2,646			2,646			6.52			9,628			6,113			6,113			15.05
Core earnings attributable to Devon (Non-GAAP)	$	450		$	343		$	320		$	0.78		$	604		$	442		$	409		$	0.99

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

As of June 30, 2016, we have commodity derivatives that pertain to a portion of our production for the last six months of 2016, as well as 2017. The key terms to our open oil, gas and NGL derivative financial instruments are presented in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

The fair values of our commodity derivatives are largely determined by the forward curves of the relevant price indices. At June 30, 2016, a 10% 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
	(Millions)
Gain (loss):
Gas derivatives	$	(56	)	$	49
Oil derivatives	$	(90	)	$	81
NGL derivatives	$	(5	)	$	5
Processing and fractionation derivatives	$	(4	)	$	4

Interest Rate Risk

At June 30, 2016, we had total debt of $12.7 billion. Of this amount, $11.6 billion bears fixed interest rates averaging 5.4%, and approximately $1.1 billion is comprised of floating rate debt with interest rates averaging 1.9%.

As of June 30, 2016, we had open interest rate swap positions that are presented in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” 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% change in these forward curves would not have materially impacted our balance sheet at June 30, 2016.

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% unfavorable change in the Canadian-to-U.S. dollar exchange rate would not have materially impacted our June 30, 2016 balance sheet.

Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, some of our subsidiaries hold Canadian-dollar cash and engage in 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.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

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

Based on their evaluation, our principal executive and principal financial officers have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of June 30, 2016 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.

Changes in Internal Control Over Financial Reporting

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

PART II. Other Information

Item 1. Legal Proceedings

We are involved in various legal proceedings incidental to our business. However, to our knowledge as of the date of this report, there were no material pending legal proceedings to which we are a party or to which any of our property is subject.

Devon Gas Services, L.P., a wholly owned subsidiary of the Company, is currently in negotiations with the Environmental Protection Agency with respect to alleged noncompliance with the leak detection and repair requirements of Environmental Protection Agency regulations promulgated under the Clean Air Act at its Beaver Creek Gas Plant located near Riverton, Wyoming. Although management cannot predict the outcome of settlement negotiations, the resolution of this matter may result in a fine or penalty in excess of $100,000.

Item 1A. Risk Factors

There have been no material changes to the information included in Item 1A. “Risk Factors” in our 2015 Annual Report on Form 10-K.

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

The following table provides information regarding purchases of our common stock that were made by us during the second quarter of 2016.

Period	Total Number of Shares Purchased ⁽¹⁾		Average Price Paid per Share
April 1 - April 30		3,729	$	31.40
May 1 - May 31		229,199	$	33.30
June 1 - June 30		41,763	$	36.32
Total		274,691	$	33.74

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

Under the Devon Plan, eligible employees may purchase shares of our common stock through an investment in the Devon Stock Fund, which is administered by an independent trustee. Eligible employees purchased approximately 16,400 shares of our common stock in the second quarter of 2016, 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 Devon Plan through open-market purchases.

Similarly, eligible Canadian employees may purchase shares of our common stock through an investment in the Canadian Plan, which is administered by an independent trustee, Sun Life Assurance Company of Canada. Shares sold under the Canadian Plan were acquired through open-market purchases. These shares and any interest in the Canadian Plan were offered and sold in reliance on the exemptions for offers and sales of securities made outside of the U.S., including under Regulation S for offers and sales of securities to employees pursuant to an employee benefit plan established and administered in accordance with the law of a country other than the U.S. In the second quarter of 2016, there were no shares purchased by Canadian employees.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

Item 6. Exhibits

Exhibit Number		Description

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

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

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

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

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB		XBRL Taxonomy Extension Labels Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

SIGNATURES

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

				DEVON ENERGY CORPORATION

Date: August 3, 2016				/s/ Jeremy D. Humphers
				Jeremy D. Humphers
				Senior Vice President and Chief Accounting Officer

INDEX TO EXHIBITS

Exhibit Number	Description

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