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 ☑ No ☐

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

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

On ~~October 18, 2017, 525.5~~July 24, 2019, 404.2 million shares of common stock were outstanding.

Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon” and the “Company” refer to Devon Energy Corporation and its consolidated subsidiaries. All monetary values, other than per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified. In addition, the following are other abbreviations and definitions of certain terms used within this Quarterly Report on Form 10-Q:

“~~2015 Plan”~~ASC” means ~~the Devon Energy Corporation 2015 Long-Term Incentive Plan.~~Accounting Standards Codification.

“~~2017 Plan”~~ASR” means ~~the Devon Energy Corporation 2017 Long-Term Incentive Plan.~~an accelerated share-repurchase transaction with a financial institution to repurchase Devon’s common stock.

“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.

“Canada” means the division of Devon encompassing oil and gas properties located in Canada. On June 27, 2019, all of Devon’s Canadian operating assets and operations were divested. All dollar amounts associated with Canada are in U.S. dollars, unless stated otherwise.

“General Partner” means EnLink Midstream, LLC, the indirect general partner of ~~EnLink.~~EnLink, and, unless the context otherwise indicates, EnLink Midstream Manager, LLC, the managing member of EnLink Midstream, LLC.

“Senior Credit Facility” means Devon’s syndicated unsecured revolving line of ~~credit.~~credit, effective as of October 5, 2018.

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 and phrases “expects,” “believes,” “will,” “would,” “could,” “continue,” “may,” “aims,” “likely to be,” “intends,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. ~~Such forward-looking~~All statements, ~~are based on our examination~~other than statements of historical ~~operating trends,~~facts, included in this report that address activities, events or developments that Devon expects, believes or anticipates will or may occur in the ~~information used to prepare our December 31, 2016 reserve reports and other data in our possession or available from third parties.~~future are forward-looking statements. 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:

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.

											Accumulated																							Accumulated
					Additional			Retained			Other																	Additional						Other
	Common Stock				Paid-In			Earnings			Comprehensive		Treasury			Noncontrolling			Total			Common Stock						Paid-In			Retained			Comprehensive			Treasury			Noncontrolling			Total
	Shares		Amount		Capital			(Accumulated Deficit)			Earnings		Stock			Interests			Equity			Shares			Amount			Capital			Earnings			Earnings (Loss)			Stock			Interests			Equity
	(Unaudited)																					(Unaudited)
	(Millions)
Nine Months Ended September 30, 2017
Balance as of December 31, 2016		523	$	52	$	7,237		$	(1,646	)	$	284	$	—		$	4,448		$	10,375
Three Months Ended June 30, 2019
Balance as of March 31, 2019																							417		$	42		$	3,518		$	3,280		$	1,064		$	(47	)	$	—		$	7,857
Net earnings		—		—		—			1,218			—		—			59			1,277			—			—			—			495			—			—			—			495
Other comprehensive earnings, net of tax		—		—		—			—			13		—			—			13
Other comprehensive loss, net of tax																							—			—			—			—			(1,181	)		—			—			(1,181	)
Common stock repurchased																							—			—			—			—			—			(164	)		—			(164	)
Common stock retired																							(7	)		(1	)		(190	)		—			—			191			—			—
Common stock dividends																							—			—			—			(37	)		—			—			—			(37	)
Share-based compensation																							—			—			24			—			—			—			—			24
Balance as of June 30, 2019																							410		$	41		$	3,352		$	3,738		$	(117	)	$	(20	)	$	—		$	6,994
Three Months Ended June 30, 2018
Balance as of March 31, 2018																							526		$	53		$	7,269		$	473		$	1,122		$	(12	)	$	4,820		$	13,725
Net earnings (loss)																							—			—			—			(425	)		—			—			90			(335	)
Other comprehensive loss, net of tax																							—			—			—			—			(31	)		—			—			(31	)
Common stock repurchased																							—			(1	)		—			—			—			(444	)		—			(445	)
Common stock retired																							(11	)		(1	)		(433	)		—			—			434			—			—
Common stock dividends																							—			—			—			(42	)		—			—			—			(42	)
Share-based compensation																							—			—			53			—			—			—			—			53
Subsidiary equity transactions																							—			—			(1	)		—			—			—			41			40
Distributions to noncontrolling interests																							—			—			—			—			—			—			(117	)		(117	)
Balance as of June 30, 2018																							515		$	51		$	6,888		$	6		$	1,091		$	(22	)	$	4,834		$	12,848
Six Months Ended June 30, 2019
Balance as of December 31, 2018																							450		$	45		$	4,486		$	3,650		$	1,027		$	(22	)	$	—		$	9,186
Effect of adoption of lease accounting																							—			—			—			(19	)		—			—			—			(19	)
Net earnings																							—			—			—			178			—			—			—			178
Other comprehensive loss, net of tax																							—			—			—			—			(1,144	)		—			—			(1,144	)
Restricted stock grants, net of cancellations																							3			—			—			—			—			—			—			—
Common stock repurchased																							—			—			—			—			—			(1,206	)		—			(1,206	)
Common stock retired																							(43	)		(4	)		(1,204	)		—			—			1,208			—			—
Common stock dividends																							—			—			—			(71	)		—			—			—			(71	)
Share-based compensation																							—			—			70			—			—			—			—			70
Balance as of June 30, 2019																							410		$	41		$	3,352		$	3,738		$	(117	)	$	(20	)	$	—		$	6,994
Six Months Ended June 30, 2018
Balance as of December 31, 2017																							525		$	53		$	7,333		$	702		$	1,166		$	—		$	4,850		$	14,104
Net earnings (loss)																							—			—			—			(622	)		—			—			134			(488	)
Other comprehensive loss, net of tax																							—			—			—			—			(75	)		—			—			(75	)
Restricted stock grants, net of cancellations		1		1		—			—			—		—			—			1			3			—			—			—			—			—			—			—
Common stock repurchased		—		—		—			—			—		(43	)		—			(43	)		—			(1	)		—			—			—			(555	)		—			(556	)
Common stock retired		—		—		(43	)		—			—		43			—			—			(14	)		(1	)		(532	)		—			—			533			—			—
Common stock dividends		—		—		(95	)		—			—		—			—			(95	)		—			—			—			(74	)		—			—			—			(74	)
Share-based compensation		1		—		96			—			—		—			—			96			1			—			89			—			—			—			—			89
Subsidiary equity transactions		—		—		12			—			—		—			545			557			—			—			(2	)		—			—			—			69			67
Distributions to noncontrolling interests		—		—		—			—			—		—			(247	)		(247	)		—			—			—			—			—			—			(219	)		(219	)
Balance as of September 30, 2017		525	$	53	$	7,207		$	(428	)	$	297	$	—		$	4,805		$	11,934
Nine Months Ended September 30, 2016
Balance as of December 31, 2015		418	$	42	$	4,996		$	1,781		$	230	$	—		$	3,940		$	10,989
Net loss		—		—		—			(3,633	)		—		—			(391	)		(4,024	)
Other comprehensive earnings, net of tax		—		—		—			—			48		—			—			48
Restricted stock grants, net of cancellations		3		—		—			—			—		—			—			—
Common stock repurchased		—		—		—			—			—		(23	)		—			(23	)
Common stock retired		—		—		(23	)		—			—		23			—			—
Common stock dividends		—		—		(65	)		(125	)		—		—			—			(190	)
Common stock issued		103		10		2,117			—			—		—			—			2,127
Share-based compensation		—		—		142			—			—		—			—			142
Subsidiary equity transactions		—		—		320			—			—		—			896			1,216
Distributions to noncontrolling interests		—		—		—			—			—		—			(224	)		(224	)
Balance as of September 30, 2016		524	$	52	$	7,487		$	(1,977	)	$	278	$	—		$	4,221		$	10,061
Balance as of June 30, 2018																							515		$	51		$	6,888		$	6		$	1,091		$	(22	)	$	4,834		$	12,848

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 ~~2016~~2018 Annual Report on Form ~~10-K.~~10-K.

The accompanying unaudited interim financial statements ~~furnished~~ in this report reflect all adjustments that are, in the opinion of management, necessary for a fair statement of Devon’s results of operations and cash flows for the three-month and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018 and Devon’s financial position as of ~~September~~June 30, ~~2017.~~2019. As further discussed in Note 18, Devon sold its Canadian operations on June 27, 2019 and its ownership interests in EnLink and the General Partner on July 18, 2018. Activity relating to Devon’s Canadian operations and EnLink and the General Partner are classified as discontinued operations within Devon’s consolidated comprehensive statements of earnings and consolidated statements of cash flows. The associated assets and liabilities of Devon’s Canadian operations are presented as assets and liabilities associated with discontinued operations on the consolidated balance sheets.

Subsequent to the sale of Devon’s Canadian business in 2019 discussed in Note 18, Devon’s oil and gas exploration and production activities are solely focused in the U.S. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of its business. With the reclassification of Devon’s Canadian operations to discontinued operations and assets and liabilities associated with discontinued operations, Devon now has one reporting segment, which is reflected in the consolidated financial statements.

The following table presents revenue from contracts with customers that are disaggregated based on the type of good.

In January ~~2017,~~2019, Devon adopted ASU ~~2016-09,~~ ~~Compensation – Stock Compensation~~2016-02, Leases (Topic ~~718)~~842), ~~Improvements to Employee Share-Based Payment Accounting. Its objective is to simplify several aspects of~~using the ~~accounting~~ modified retrospective method. See Note 14for ~~share-based payments, including income taxes when awards vest or are settled, statutory withholding and forfeitures.~~ As the result of adoption, Devon made certain income tax presentation changes, most notably prospectively presenting excess tax benefits and deficiencies in the consolidated comprehensive statements of earnings and as operating cash flows in the consolidated statements of cash flows. ~~Devon also retrospectively applied the new cash flow statement guidance dictating the presentation of shares exchanged for tax-withholding purposes as a financing activity. The~~further discussion regarding Devon’s adoption of the ~~new guidance did not materially impact the consolidated financial statements for the nine months ended September 30, 2017~~leases standard.

The SEC released Final Rule No. 33 -10532, Disclosure Update and Simplification, which amends various SEC disclosure requirements determined to be redundant, duplicative, overlapping, outdated or ~~previously reported financial information but could have a more material future impact.~~

~~In January 2017, the FASB issued ASU 2017-04,~~ ~~Intangibles – Goodwill And Other (Topic 350)~~, ~~Simplifying the Test for Goodwill Impairment~~ ~~("ASU 2017-04"). ASU 2017-04 simplifies the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount~~superseded as part of ~~step two~~the SEC’s ongoing disclosure effectiveness initiative. The rule was effective November 5, 2018. The rule amended numerous SEC rules, items and forms covering a diverse group of topics. Devon has implemented these required changes which generally reduced or eliminated disclosures. Devon adopted the ~~goodwill impairment test. Under ASU 2017-04, an entity should perform its goodwill impairment test by comparing~~requirement of presenting current and comparative quarterly stockholders’ equity roll forwards in the ~~fair value~~first quarter of 2019.

The SEC released Final Rule Release No. 33-10618, FAST Act Modernization and Simplification of Regulation S-K, which amends Regulation S-K to modernize and simplify certain disclosure requirements in a reporting unit with its carrying amount. An impairment charge should be recognized for the amount by which the carrying amount exceeds the reporting unit's fair value. However, the impairment loss recognized shouldmanner that reduces costs and burdens on registrants while continuing to provide all material information to investors. The rule became effective May 2, 2019. The rule amended numerous SEC rules, items and forms covering a diverse group of topics, primarily focusing on reducing or eliminating disclosures. Other than presentation, this adoption did not exceed the total amount of goodwill allocated to that reporting unit. ASU 2017-04 is effective for annual reporting periods beginning after December 15, 2019, including any interim impairment tests within those annual periods, with early application for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. In January 2017, Devon elected to early adopt ASU 2017-04, and the adoption had nohave a material impact on ~~the~~Devon’s consolidated financial statements. ~~Devon will perform future goodwill impairment tests according to ASU 2017-04.~~

The FASB issued ASU ~~2014-09,~~ ~~Revenue from Contracts with Customers~~2018-13, Fair Value Measurement (Topic ~~606)~~820): Changes to the Disclosure Requirements for Fair Value Measurement. This ASU will ~~supersede the revenue recognition~~eliminate, add and modify certain disclosure requirements ~~in Topic 605,~~ ~~Revenue Recognition~~ ~~and industry-specific guidance in Subtopic 932-605,~~ ~~Extractive Activities – Oil and Gas – Revenue Recognition. This~~for fair value measurement. The 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,~~January 1, 2020, with early adoption permitted ~~in 2017. Devon has not early adopted this ASU.~~for either the entire standard or only the provisions that eliminate or modify requirements. The ASU ~~is required~~requires the additional disclosure requirements to be adopted using ~~either~~a retrospective approach. Devon is currently evaluating the ~~retrospective transition method, which requires restating previously reported results or~~provisions of this ASU and assessing the ~~cumulative effect (modified retrospective) transition method, which utilizes a cumulative-effect adjustment to retained earnings~~impact it may have on its disclosures in the ~~period of adoption~~notes to ~~account for prior period effects rather than restating previously reported results. Devon intends to use~~ the ~~cumulative effect transition method and does not anticipate this ASU will have a material impact on its balance sheet or related~~ consolidated statements of earnings, equity or cash flows. However, Devon continues to evaluate the “gross versus net” presentation of certain revenues and associated expenses in its consolidated statements of earnings. Any presentation changes would have no impact on operating income, earnings or cash flows. Devon does not expect significant changes to its annual disclosures; however, Devon’s quarterly disclosures will expand upon adoption of this ASU. Devon has implemented a process to gather and provide the quarterly disclosures required by the ASU.

The FASB issued ASU ~~2016-02,~~ ~~Leases (Topic 842)~~2018-15, Intangibles, Goodwill and Other Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract. This ASU will ~~supersede~~require a customer in a cloud computing arrangement (i.e., hosting arrangement) that is a service contract to follow the ~~lease requirements~~internal-use software guidance in ~~Topic 840,~~ ~~Leases. Its objective~~ASC 350-40 to determine which implementation costs to capitalize as assets or expense as incurred. Capitalized implementation costs related to a hosting arrangement that 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, excepta service contract will be amortized over the term of the hosting arrangement, beginning when the module or component of the hosting arrangement is ready for ~~some changes made to align with new revenue recognition requirements.~~its intended use. This ASU is effective for ~~Devon~~annual and interim periods beginning January 1, ~~2019 and will be~~2020, with early adoption permitted. Entities have the option to adopt the ASU using either a retrospective approach or a prospective approach applied ~~using a modified retrospective transition method, which requires applying the new guidance~~ to ~~leases that exist or are entered into~~all implementation costs incurred after the ~~beginning~~date of the ~~earliest period in the financial statements. Early adoption is permitted, but Devon does not plan to early adopt.~~adoption. Devon is incurrently evaluating the ~~process~~provisions of ~~evaluating contracts~~this ASU and ~~gathering the necessary terms and data elements for purposes of determining~~assessing the impact ~~this ASU will~~it may have on its consolidated financial ~~statements~~statements.

In February 2019, Devon announced its intent to separate its Canadian business and ~~related disclosures. Recently,~~Barnett Shale assets from the ~~FASB~~ ~~issued~~ ~~Proposed Accounting Standards Update (ASU) No. 2017-290,~~ ~~Leases (Topic 842)~~Company, based on authorizations provided by its Board of Directors. On June 27, 2019, Devon completed the sale of all of its operating assets and operations in Canada to Canadian Natural Resources Limited for proceeds, net of purchase price adjustments, of $2.6 billion ($3.4 billion Canadian dollars), ~~Land Easement Practical Expedient for Transition to Topic 842~~and recognized a pre-tax gain of $189 million ($460 million, net of tax). ~~This proposed ASU~~ ~~would permit an entity not to apply Topic 842 to land easements and rights-of-way that exist or expired before the effective date of Topic 842 and that were not previously assessed under Topic 840.~~An entity would continue to apply its current accounting policy for accounting for land easements that existed before the effective date of Topic 842. Once an entity adopts Topic 842, it would apply that Topic prospectively to all new (or modified) land easements and rights-of-way to determine whether the arrangement should be accounted for asAs a ~~lease.~~ ~~For Devon, these contracts represent a relatively small percentage~~part of the ~~aggregate value of contracts being evaluated but represent a significant number of contracts.~~

Based on continuing research, Devon estimates a large number of contracts and data elements must be gathered and reviewed to ensure proper accounting of these contracts once this ASU is effective. Devon anticipates the adoption of this standard will significantly impact its consolidated financial statements, systems, processes and controls and is evaluating technology requirements and solutions needed to comply with the requirements of this ASU.

~~The FASB issued ASU No. 2017-07,~~ ~~Compensation – Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.~~ ~~This ASU will~~ require entities to present the service cost component of net periodic benefit cost in the same line item as other employee compensation costs and present the other components of net periodic benefit cost outside of operating income in the statement of earnings. Only the service cost component of net periodic benefit cost is eligible for capitalization. This ASU is effective for Devon beginning January 1, 2018, and presentation changes in the statement of earnings will be applied retrospectively, while service cost component capitalization will be applied prospectively. Upon adoption of this ASU, Devon will reclassify $7 million, $14 million and $16transaction, $436 million of non-service cost components of net periodic benefit costs for 2017, 2016 and 2015, respectively, as other nonoperating items. Such amounts are currently classified in Devon’s G&A. No other changes upon adopting this ASU are expected to be material.

asset retirement obligations were assumed by Canadian Natural Resources Limited. In ~~January 2016, Devon acquired approximately 80,000 net acres (unaudited) and assets in~~aggregate, the STACK play for approximately $1.5 billion. Devon funded the acquisition with $849 million of cash, after adjustments, and $659 million of common equity shares. The purchase price allocation was approximately $1.3 billion to unproved properties and approximately $200 million to proved properties.

In May 2017, Devon announced a program to divest approximately $1 billion of upstream assets. The non-core assets identified for monetization include select portions of the Barnett Shale focused primarily in and around Johnson County and other properties located principally within Devon’s U.S. resource base. Through September 30, 2017, Devon completed divestiture transactions totaling approximately $400 million, before purchase price adjustments. Estimatedtotal estimated proved reserves associated with these assets were approximately 400 MMBoe, or 21% of total proved reserves. In conjunction with the Canadian divestiture, Devon recognized $273 million of restructuring and asset impairment related charges. These costs relate to personnel, office lease abandonment and a firm transportation agreement abandonment. Additional information on these discontinued operations can be found in Note 18.

Devon is evaluating multiple methods of separation for the Barnett Shale assets, including a potential sale, potential mergers or spin-off. As of June 30, 2019, Devon does not currently have any indications that it would recognize an impairment upon separating its Barnett Shale assets as they are long-lived assets that are held for use. This conclusion is based on probability-weighted computations applied to the separation methods currently under evaluation. As of June 30, 2019, Devon’s carrying value of its Barnett Shale net assets (property and equipment, asset retirement obligations and estimated allocated goodwill) was approximately $1.4 billion. Should Devon enter into a transaction that causes Devon to cease having control, such as a cash sale or exchange for a noncontrolling interest in another entity or combination thereof, Devon would recognize a gain or loss based on the value of the proceeds and/or equity interests as compared to the carrying value. Devon anticipates reporting all information for its Barnett Shale assets as discontinued operations in 2019 when all the requisite criteria are met for such financial statement presentation.

In the first quarter of 2019, Devon received proceeds of approximately $300 million and recognized a $44 million net gain on asset dispositions, primarily from sales of non-core assets in the Permian Basin. In aggregate, the total estimated proved reserves associated with these divested assets were approximately 25 MMBoe, or less than 1%2% of total U.S. proved reserves. As of December

31, 2018, assets and liabilities associated with these divested assets were classified as held for sale in the accompanying consolidated balance sheet.

During the second quarter of ~~2016,~~2018, Devon ~~divested non-core~~sold a portion of its Barnett Shale assets, primarily located in Johnson County for ~~approximately $200~~$553 million. Estimated proved reserves associated with these assets were ~~less than 1%~~approximately 10% of total ~~U.S.~~ proved reserves.

~~In the third quarter of 2016,~~ The transaction resulted in ~~several separate transactions~~an adjustment to Devon’s capitalized costs with different purchasers, Devon divested non-core upstream assets located in east Texas, the Anadarko Basin and the Midland Basin for approximately $1.7 billion. Estimated proved reserves associated with these assets were approximately 146 MMBoe, or approximately 9% of total U.S. proved reserves.

~~Proceeds from the transactions were used primarily for debt repayment and to support capital investment in Devon’s core resource plays.~~

~~The divestiture transactions that closed~~no gain recognized in the ~~third quarter~~consolidated statement of 2016 significantly altered the costs and reserves relationship of Devon’s U.S. cost center. Therefore, Devon recognized a $1.4 billion gain in the third quarter of 2016 associated with these divestitures. A summary of the gain computation follows.

earnings. In January 2016, EnLink acquired Anadarko Basin gathering and processing midstream assets, along with dedicated acreage service rights and service contracts, for approximately $1.4 billion. The purchase price allocation was $1.0 billion to intangible assets and approximately $400 million to property and equipment. EnLink funded the acquisition with approximately $215 million of General Partner common units and approximately $800 million of cash, primarily fundedconjunction with the ~~issuance of EnLink preferred units. The remaining $500~~divestiture, Devon settled certain gas processing contracts and recognized an approximately $40 million ofsettlement expense, which is included in asset dispositions within the ~~purchase price was 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 installment payment of $250 million was paid in~~ ~~January 2017. The remaining $250 million payment is reported in other current liabilities in the accompanying~~ consolidated ~~balance sheets. The accretion of the discount is reported within net financing costs in the accompanying consolidated comprehensive~~ statement of earnings.

In August 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 $244 million of existing non-monetary assets to the joint venture and committed an additional $262 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 initial cash contributions of approximately $138 million, and granted EnLink call rights beginning in 2021 to acquire increasing portions of the joint venture partner’s interest.

D~~uring the first quarter of 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million.~~

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~~enters into derivative financial instruments with respect to a portion of ~~their~~its oil, gas and NGL marketing activities. These commodity derivative financial instruments include financial price swaps, basis swaps and costless price collars. 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.~~volatility. As of ~~September~~June 30, ~~2017,~~2019, Devon did not have any open ~~foreign exchange~~interest rate swap 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.

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 ~~September~~June 30, ~~2017,~~2019, Devon had the following open oil derivative positions. The first ~~table presents~~two tables present Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The ~~second~~third table presents Devon’s oil derivatives that settle against the respective indices noted within the table.

As of ~~September~~June 30, ~~2017,~~2019, 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.

As of ~~September~~June 30, ~~2017,~~2019, 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.

As of September 30, 2017, EnLink had the following open derivative positions associated with gas processing and fractionation. EnLink’s NGL positions settle by purity product against the average of the prompt month OPIS Mont Belvieu, Texas index.

~~As of September 30, 2017, Devon had the following open interest rate derivative positions:~~

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.

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

In the second quarter of 2017, Devon’s stockholders approved the 2017 Plan. The 2017 Plan replaces the 2015 Plan. From the effective date of the 2017 Plan, no further awards may be made under the 2015 Plan, and awards previously granted will continue to be governed by the terms of the respective award documents. Subject to the terms of the 2017 Plan, awards may be made for a total of 33.5 million shares of Devon common stock, plus the number of shares available for issuance under the 2015 Plan (including shares subject to outstanding awards under the 2015 Plan that are transferred to the 2017 Plan in accordance with its terms). The 2017 Plan authorizes the Compensation Committee, which consists of independent, non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards or units, Canadian restricted stock units, performance units and stock appreciation rights to eligible employees. The 2017 Plan also authorizes the grant of nonqualified stock options, restricted stock awards or units and stock appreciation rights to non-employee directors. To calculate the number of shares that may be granted in awards under the 2017 Plan, options and stock appreciation rights represent one share and other awards represent 2.3 shares.

The ~~following~~ table below presents the ~~effects of~~ share-based compensation expense included in Devon’s accompanying consolidated comprehensive statements of earnings. Gross G&A expense for the first nine months of 2017 and 2016 includes $28 million and $18 million, respectively, of unit-based compensation related to grants made under EnLink’s long-term incentive plans.

Under its approved long-term incentive plan, Devon granted share-based awards to certain employees in the first ~~nine~~six months of ~~2017.~~2019. 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.

The following table presents the assumptions related to the performance share units granted in ~~2017,~~2019, as indicated in the previous summary table.

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 ~~September~~June 30, ~~2017.~~2019.

During the ~~General Partner~~first six months of 2018, Devon impaired certain non-core acreage in the U.S. that it no longer intends to pursue for exploration opportunities, resulting in unproved impairments of $61 million. Unproved impairments are included in exploration expenses in the consolidated comprehensive statements of earnings.

During the second quarter of 2018, Devon recognized $109 million of proved asset impairments relating to U.S. non-core assets no longer in its development plans and ~~EnLink issued restricted incentive units as bonus payments to officers~~approximately $45 million of non-oil and ~~certain employees. The combined grant fair value was $10 million,~~gas asset impairments.

During the first quarter of ~~2017 due~~2019, Devon announced workforce reductions and other initiatives designed to ~~the awards vesting immediately.~~

~~The following table presents a summary of the unrecognized compensation~~enhance its operational focus and cost ~~and the related weighted average recognition period associated~~structure in conjunction with the ~~General Partner’s and EnLink’s unvested restricted incentive units and performance units as~~portfolio transformation announcement further discussed in Note 2. As a result, Devon recognized $63 million of ~~September 30, 2017.~~

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 onrestructuring expenses during the first ~~day~~six months of ~~each of the previous 12 months.~~

~~The oil and gas impairments in 2016~~2019. Of these expenses, $24 million 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.

~~In the first quarter of 2016, EnLink recognized goodwill impairments. See Note 12 for additional details.~~

accelerated vesting of share-based grants, which are noncash charges. Additionally, $5 million resulted from settlements of defined retirement benefits.

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

~~In the first nine months of 2016,~~ 2018, Devon recognized ~~$229~~$85 million in ~~employee-related costs associated with a reduction in workforce.~~personnel related restructuring expenses related to workforce reductions. Of these ~~employee-related costs, approximately $60~~expenses, $26 million resulted from accelerated vesting of share-based grants, which are noncash charges. Additionally, ~~approximately $30~~$15 million resulted from estimated settlements of defined retirement benefits.

~~As a result of~~Devon anticipates recognizing additional restructuring charges in 2019 primarily when the ~~reduction of workforce, Devon ceased using certain office space that was subject to non-cancellable operating lease arrangements. Devon recognized restructuring costs that represent the present value~~separation of its ~~future obligations under the leases and impairment charges for leasehold improvements and furniture associated with the office space it ceased using.~~Barnett Shale assets is completed.

~~Transaction Costs~~The following table summarizes Devon’s restructuring liabilities.

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

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

Devon estimates its annual effective income tax rate ~~in recording~~to record 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.

~~Throughout 2016 and through~~In the second quarter of 2019, the deferred tax asset representing Devon’s U.S. state net operating loss that is subject to a valuation allowance increased by $11 million from the first ~~nine months~~quarter of ~~2017, Devon continued to maintain a 100%~~2019. The corresponding increase in the valuation allowance against ~~its U.S.~~the state net operating loss resulted in a deferred tax assets resulting from prior year cumulative financial losses largely due to full cost impairments. Furthermore, a partial allowance continues to be held against certain Canadian segment deferred tax assets.

~~Devon provided an additional $796 million to the U.S. segment valuation allowance~~expense, which is included within state income taxes in the first nine months of 2016 based on the financial loss recorded during the period. Also, during the third quarter of 2016, Devon’s Canadian segment recorded a $71 million partial valuation allowance. Devon reduced its U.S. segment valuation allowance by $348 million in the first nine months of 2017 based on the financial income recorded during the period.table above.

~~Also in~~In the table above, the “other” effect is primarily composed of permanent differences for which dollar amounts do not increase or decrease in relation to the change in pre-tax earnings. Generally, such items have an insignificant impact on ~~our~~Devon’s effective income tax rate. However, these items ~~have~~had a more noticeable impact to ~~our~~the rate in the ~~third quarter~~first six months of ~~2017~~2019 due to ~~lower~~the low relative ~~earnings~~net loss during the period. ~~During the third quarter of 2017, “other” is primarily related to the taxation of foreign earnings and other financing items.~~

In the first quarter of 2016, EnLink recorded goodwill impairments totaling $873 million. These impairments are not deductible for purposes of calculating income tax and, therefore, have an impact on the effective tax rate.

Devon is under audit in the U.S. and various foreign jurisdictions as part of its normal course of business. The timing of resolution of income tax examinations is uncertain as are the amounts and timing of tax payments that are part of any audit settlement process. Devon believes that within the next 12 months it is reasonably possible that certain tax examinations will be resolved by settlement with the taxing authorities.

Through the first six months of 2018, Devon maintained a 100% valuation allowance against its U.S. deferred tax assets resulting from prior year cumulative financial losses, oil and gas impairments, and significant net operating losses for U.S. federal and state income tax. However, upon closing the EnLink divestiture in the third quarter of 2018, Devon reassessed its position and determined that a full valuation allowance against its U.S. deferred tax assets was no longer necessary, maintaining only valuation allowances against certain deferred tax assets, including certain tax credits and state net operating losses.

On June 27, 2019, Devon completed the sale of all of its Canadian operating assets. Devon’s foreign earnings have not been considered indefinitely reinvested since the announcement of the plan to separate the assets in the first quarter of 2019. As the separation took the form of an asset sale and Devon has retained certain non-operating obligations to be settled over time, Devon has not recorded a deferred tax asset or corresponding valuation allowance related to its Canadian investment.

As the sale of all of its Canadian operating assets closed during the second quarter of 2019, Devon has recorded materially all tax impacts related to the Canadian business in discontinued operations. Additional information on these discontinued operations can be found in Note 18.

The following table reconciles net earnings (loss) ~~attributable to Devon~~from continuing operations and weighted-average common shares outstanding used in the calculations of basic and diluted net earnings (loss) per ~~share.~~share from continuing operations.

~~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 the noncash issuance of General Partner common units. Additionally, EnLink’s formation of a joint venture during the third quarter of 2016 included non-monetary asset contributions. See Note 2 for additional details.

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 noncash goodwill impairment of $873 million in the first quarter of 2016. This consisted of a full impairment charge of $93 million related to EnLink’s Crude and Condensate reporting unit and partial impairments to EnLink’s Texas and General Partner reporting units of $473 million and $307 million, respectively.

~~During the third quarter of 2016, Devon derecognized $197 million of goodwill in conjunction with the upstream oil and gas asset divestitures discussed in Note 2.~~

The following table presents ~~other intangible assets reported in other long-term assets in~~ the ~~accompanying consolidated balance sheets.~~aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas activities.

The weighted-average amortization period for other intangible assets is 15 years. Amortization expense for intangibles was $37 million and $29 million for the three months ended September 30, 2017 and 2016, respectively, and $96 million and $87 million for the nine months ended September 30, 2017 and 2016, respectively. The remaining amortization expense is estimated to be $123 million for each of the next five years.

Devon has a $3.0 billion Senior Credit Facility. As of ~~September~~June 30, ~~2017,~~2019, Devon had ~~$59 million in outstanding letters of credit under the Senior Credit Facility. There were~~ no outstanding borrowings under the Senior Credit Facility ~~at September 30, 2017.~~and had issued $3 million in outstanding letters of credit under this 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 ~~September~~June 30, ~~2017,~~2019, Devon was in compliance with this covenant with a debt-to-capitalization ratio of ~~18.9%~~23.4%.

In connection with the closing of the sale of its Canadian business, Devon reallocated and terminated all Canadian commitments under the Senior Credit Facility in accordance with the terms of the credit agreement governing the Senior Credit Facility. The termination of the Canadian subfacility was effective as of June 27, 2019, and such termination did not decrease the $3.0 billion in total revolving commitments under, or otherwise modify the terms of, the Senior Credit Facility.

In January 2019, Devon repaid the $162 million of 6.30% senior notes at maturity.

In the ~~third~~first quarter of ~~2016,~~2018, Devon completed tender offers to repurchase ~~$1.2 billion~~$807 million in aggregate principal amount of debt securities, using ~~proceeds from~~cash on hand. This included $384 million of the ~~asset divestitures discussed in Note 2.~~7.875% senior notes due September 30, 2031 and $423 million of the 7.95% senior notes due April 15, 2032. Devon recognized a $312 million loss on early retirement of debt, ~~primarily~~ consisting of ~~$82~~$304 million in cash retirement costs and ~~other fees.~~$8 million of noncash charges. These costs, along with other ~~minimal noncash~~ charges associated with retiring the debt, are included in net financing costs in the consolidated comprehensive statements of earnings.

~~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 September 30, 2017, there were $9 million in outstanding letters of credit and no outstanding borrowings under the $1.5 billion credit facility. The General Partner has a $250 million secured revolving credit facility. As of September 30, 2017, the General Partner had $74 million in outstanding borrowings at an average rate of 3.2%. EnLink and the General Partner were in compliance with all financial covenants in their respective credit facilities as of September 30, 2017.

In the second quarter of 2017, EnLink issued $500 million of 5.45% unsecured senior notes due in 2047. The proceeds were used to repay outstanding borrowings under its revolving credit facility and for general partnership purposes. Additionally, in the second quarter of 2017, EnLink redeemed its $163 million 7.125% senior unsecured notes due in 2022. EnLink redeemed the notes at 103.6% of the principal amount, plus accrued unpaid interest, for aggregate cash consideration of $174 million, which resulted in a gain on extinguishment of debt of $9 million during the second quarter of 2017. The gain is included in net financing costs in the consolidated comprehensive statement of earnings.

Devon adopted ASU No. 2016-02, Leases (Topic 842), as of January 1, 2019, using the modified retrospective transition approach. ASC 842 supersedes the previous lease accounting requirements in ASC 840 and requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. ASC 842 establishes a right-of-use model that requires a lessee to recognize a right-of-use asset and lease liability on the balance sheet for all leases with a term longer than 12 months. At adoption, using the modified retrospective transition approach, Devon recorded right-of-use lease assets of $394 million and lease liabilities of $380 million. Additionally, Devon recorded a $24 million before tax, $19 million net of tax, cumulative-effect adjustment to reduce retained earnings. Comparative periods have been presented in accordance with ASC Topic 840 and do not include any retrospective adjustments to reflect the adoption of Topic 842. Excluding land easements and rights-of-way, all leases that existed at January 1, 2019 or were entered into or modified thereafter, are accounted for under Topic 842. Devon elected the practical expedient provided in the standard that allows the new guidance to be applied prospectively to all new or modified land easements and rights-of-way. Devon also elected a policy not to recognize right-of-use assets and lease liabilities related to short-term leases with terms of 12 months or less. Additionally, Devon elected to account for lease components separately from the nonlease components.

Devon made certain significant assumptions and judgments in determining its right-of-use asset and lease liability balances. First is the determination of whether a contract contains a lease. Devon considered the presence of an identified asset that is physically distinct, and for which the supplier does not have substantive substitution rights and whether Devon has the right to control the underlying asset. Second, Devon assessed lease terms and considered whether Devon is reasonably certain to extend leases or exercise purchase options. Certain of Devon’s leases include one or more options to renew, with renewal terms that can extend the lease term for additional years. Certain leases also include options to purchase the leased property. For options to renew or purchase that Devon

is reasonably certain to exercise, these costs are recognized as part of the right-of-use assets and lease liabilities. Third, significant judgments have been made in determining discount rates. Devon estimates discount rates using market rates that approximate collateralized borrowings over the remaining term of Devon’s lease payments.

Devon’s right-of-use operating lease assets are for certain leases related to real estate, drilling rigs and other equipment related to the exploration, development and production of oil and gas. Devon’s right-of-use financing lease assets are related to real estate. Certain of Devon’s lease agreements include variable payments based on usage or rental payments adjusted periodically for inflation. Devon’s lease agreements do not contain any material residual value guarantees or restrictive covenants.

The following table presents Devon’s right-of-use assets and lease liabilities as of June 30, 2019.

The following table presents Devon’s additional lease information for the three and six months ended June 30, 2019.

The following table presents Devon’s maturity analysis as of June 30, 2019 for leases expiring in each of the next 5 years and thereafter.

Devon rents or subleases certain real estate to third parties. The following table presents Devon’s expected lease income as of June 30, 2019 for each of the next 5 years and thereafter.

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

During the first ~~quarter~~six months of ~~2017,~~2019, Devon reduced its ~~estimated~~ asset retirement obligations by ~~$184~~$63 million, primarily due to changes in the ~~assumed inflation rate~~future cost estimates and retirement dates for its oil and gas assets.

During the ~~first nine months~~second quarter of ~~2016,~~2018, Devon reduced its asset retirement ~~obligation~~obligations by ~~$285~~$34 million for those obligations that were assumed by purchasers of certain ~~upstream U.S.~~Barnett Shale assets. ~~See~~ For additional information, see Note 2 ~~for additional details.~~.

The following table presents the components of net periodic benefit cost for Devon’s pension ~~and~~benefits plan. There was $1 million of net periodic benefit credit for postretirement benefit ~~plans.~~plans for all periods presented below.

~~(2) Net periodic benefit cost is a component of G&A in the accompanying consolidated comprehensive statements of earnings.~~

In ~~January 2016,~~March 2018, Devon ~~issued approximately 23 million shares~~announced a share repurchase program to buy up to $1.0 billion of its common ~~stock~~stock. In June 2018, in conjunction with the ~~STACK asset acquisition discussed~~announced divestiture of its investment in ~~Note 2.~~

EnLink and the General Partner, Devon increased its program by an additional $3.0 billion. In February ~~2016, Devon issued 79 million shares~~2019, Devon’s Board of Directors authorized an expansion of the share repurchase program by an additional $1.0 billion, bringing the total to $5.0 billion. The share repurchase program expires December 31, 2019.

The table below provides information regarding purchases of Devon’s common stock tothat were made during 2018 and the ~~public, inclusive~~first six months of ~~10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were $1.5 billion.~~2019 (shares in thousands).

~~In response to the depressed commodity price environment,~~ Devon ~~reduced~~raised its quarterly dividend by 12.5%, to ~~$0.06~~$0.09 per share, beginning in the second quarter of ~~2016.~~2019. In the second quarter of 2018, Devon increased the quarterly dividend rate from $0.06 to $0.08 per share.

On May 29, 2019, Devon announced it had entered into an agreement to sell ~~common units through~~all of its ~~“at~~operating assets and operations in Canada to Canadian Natural Resources Limited. Devon concluded that the ~~market” equity offering programs.~~ transaction was a strategic shift and met the requirements of assets held for sale and discontinued operations upon the authorization to enter the agreement by Devon’s Board of Directors. As part of its assessment, Devon considered the following: 1) Devon is exiting its entire heavy oil and Canadian operations; 2) Devon’s Canadian operations is a separate reportable segment and is a component of Devon’s business; and 3) the transaction resulted in a material reduction in total assets, revenues, net earnings and total proved reserves. As a result, Devon has classified the results of operations and cash flows related to its Canadian operations as discontinued operations on its consolidated financial statements. Additionally, Devon ceased depreciation and amortization for all plant, property and equipment and intangible assets classified as assets held for sale on the date the sales agreement was approved by the Board of Directors.

On June 27, 2019, Devon completed the sale of its Canadian business for $2.6 billion ($3.4 billion Canadian dollars), net of purchase price adjustments, and recognized a pre-tax gain of $189 million ($460 million net of tax, primarily due to a significant deferred tax benefit). Current (cash) income tax associated with the sale was approximately $110 million.The disposition of all of Devon’s Canadian operating assets resulted in Devon releasing its historical cumulative foreign currency translation adjustment of $1.2 billion from accumulated other comprehensive earnings to be included within the gain computation. The historical cumulative foreign currency translation portion of the gain is not taxable. Additionally, $370 million of the Canadian cash balance is restricted for funding certain tax and other obligations related to the Canadian business and is classified as cash restricted for discontinued operations on the consolidated balance sheets.

In conjunction with the sale of Devon’s Canadian business, Devon recognized $273 million of restructuring and asset impairment related charges. Canadian Natural Resources Limited has reimbursed Devon for approximately $50 million of these restructuring costs, under the terms of the disposition agreement. Along with certain tax obligations, these costs will be funded with the restricted cash described above. These charges consist of $154 million related to a firm transportation agreement abandonment and $55 million related to office lease abandonment and related asset impairment charges. Cash payments for the abandonment charges total approximately $6 million per quarter. Additionally, there are $64 million of employee related costs, including approximately $40 million of noncash accelerated vesting of employee stock awards. As mentioned above, Canadian Natural Resources Limited reimbursed the Company for approximately $50 million of these costs pursuant to the disposition agreement and Devon expects to fund the remaining costs in the second half of 2019.

Prior to the second quarter of 2019, Devon’s Canadian business maintained a valuation allowance against certain capital loss carryforwards and net operating losses. As a result of the sale of all of Devon’s Canadian operating assets and the lack of future forecasted income, all but approximately $34 million of the Canadian deferred tax assets have been offset with a valuation allowance.

As announced on June 27, 2019, Devon utilized a portion of the sales proceeds to early retire its $500 million of the 4.00% senior notes due July 15, 2021 and $1.0 billion of the 3.25% senior notes due May 15, 2022. Devon expects to recognize a loss on the early retirement of these notes in the third quarter of ~~2017,~~ 2019 consisting of $52 million in cash retirement costs and $6 million of noncash charges.

On June 6, 2018, Devon announced that it had entered into ~~additional equity distribution agreements~~an agreement to sell ~~up to $600 million~~its aggregate ownership interests in common units through its programs. Future common units that EnLink issues will be issued under the new equity distribution agreement. During the first nine months of 2017, EnLink issued and sold 5 million common units through its programs and generated $92 million in net proceeds.

~~In September 2017, EnLink issued 400,000 preferred units through an underwritten public offering for net proceeds of approximately $394 million.~~

During the first nine months of 2016, EnLink issued and sold 7 million common units for net proceeds of $110 million. In conjunction with its acquisition of Anadarko Basin gathering and processing midstream assets during the first quarter of 2016, EnLink issued preferred units as discussed in Note 2.

As of September 30, 2017, Devon’s ownership interest in EnLink was 23%, excluding the interest held by the General Partner. Devon’s controlling ownership interest in the General Partner as of September 30, 2017 was 64%. 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.

EnLink and the General Partner ~~distributed $247 million~~for $3.125 billion. Upon entering into the agreement to sell its ownership interest in June 2018, Devon concluded that the transaction was a strategic shift and ~~$224 million~~met the requirements of assets held for sale and discontinued operations. As a result, Devon classified the results of operations and cash flows related to ~~non-Devon unitholders during~~EnLink and the General Partner as discontinued operations on its consolidated financial statements.

On July 18, 2018, Devon completed the sale of its aggregate ownership interests in EnLink and the General Partner for $3.125 billion and recognized a gain of approximately $2.6 billion ($2.2 billion after-tax). Current (cash) income tax associated with the transaction was approximately $12 million. The vast majority of the tax effect relates to deferred tax expense offset by the valuation allowance adjustment.

As part of the sale agreement, Devon extended its fixed-fee gathering and processing contracts with respect to the Bridgeport and Cana plants with EnLink through 2029. Although the agreements were extended to 2029, the minimum volume commitments for the Bridgeport and Cana plants expired at the end of 2018. Devon has minimum volume commitments for gathering and processing of 77-128 MMcf/d with EnLink at the Chisholm plant through early 2021.

Prior to the divestment of Devon’s aggregate ownership of EnLink and the General Partner, certain activity between Devon and EnLink were eliminated in consolidation. Subsequent to the divestment, all activity related to EnLink represent third-party transactions and are no longer eliminated in consolidation.

During the first ~~nine~~six months of ~~2017~~2019, Devon had net outflows of approximately $280 million with EnLink, which primarily related to gathering and ~~2016, respectively.~~processing expenses. These net outflows represent gross cash amounts and not net working interest amounts.

The following table presents the amounts reported in the consolidated comprehensive statements of earnings as discontinued operations.

The following table presents the carrying amounts of the assets and liabilities associated with discontinued operations on the consolidated balance sheets. The assets and liabilities associated with discontinued operations at June 30, 2019 and December 31, 2018 are primarily related to the divestiture of Devon’s Canadian business. Included within assets and liabilities associated with discontinued operations at December 31, 2018 are $197 million of assets and $69 million of liabilities related to the divestiture of non-core upstream Permian Basin assets which closed in January 2019 as further discussed in Note 2.

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 likely 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.~~estimates.

Numerous oil and natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. ~~The~~Devon is currently named as a defendant in a number of such lawsuits, including some lawsuits in which the plaintiffs seek to certify classes of similarly situated plaintiffs. Among the allegations typically asserted in these suits ~~allege~~are claims that ~~the producers and related parties~~Devon 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 royalty audits 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.

Devon is subject to certain ~~environmental, health and safety~~ laws and regulations ~~including with respect~~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.

Beginning in 2013, various parishes in Louisiana filed suit against more than 100 oil and gas companies, including Devon, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused substantial environmental contamination, subsidence and other environmental damages to land and

water bodies located in the coastal zone of Louisiana. The plaintiffs seek, among other things, the payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. Although Devon cannot predict the ultimate outcome of these matters, Devon is vigorously defending against these claims.

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.

The following table provides carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. ~~None of the items below are measured using Level 3 inputs.~~ The carrying values of cash, cash restricted for discontinued operations, accounts receivable, other current receivables, accounts payable, other current payables, ~~and~~ accrued expenses and lease liabilities included in the accompanying consolidated balance sheets approximated fair value at ~~September~~June 30, ~~2017~~2019 and December 31, ~~2016.~~2018, as applicable. 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 12, respectively.

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

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

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

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

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

~~Installment payment~~ ~~– The fair value of the EnLink installment payment 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.~~

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.

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

The following discussion and analysis addresses material changes in our results of operations ~~and capital resources and uses~~ for the three-month and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2019 compared to ~~the three-month and nine-month~~previous periods ~~ended September 30, 2016~~ and in our financial condition and liquidity since December 31, ~~2016.~~2018. For information regarding our critical accounting policies and estimates, see our ~~2016~~2018 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Key components of our sequential quarter financial performance are summarized below.

~~During~~We have made significant progress in our transition to “New Devon” - a U.S. oil growth company. We closed on the first nine months of 2017, we generated solid operating results with our three-fold strategy of operating in North America’s best resource plays, delivering superior execution and maintaining a high degree of financial strength. Led by our development in the STACK, we continued to improve our 90-day initial production rates. With investments in proprietary data tools, predictive analytics and artificial intelligence, we are delivering industry-leading, initial-rate well productivity performance and improving the performancesale of our ~~established wells. Even though~~Canadian operations and are making progress in separating our ~~2017 production volumes~~Barnett Shale assets from the Company. We are using the proceeds from the separation of these assets to maintain target debt levels as well as return cash to our shareholders. As we continue to execute on our strategic objectives of funding high-return projects, generating free cash flow, maintaining financial strength and returning cash to shareholders, we have ~~declined from 2016 due to reduced capital investment, we estimate our highest-margin U.S. oil production from retained assets will exit 2017 at levels approximately 20% higher than year-end 2016.~~already achieved the following accomplishments in 2019.

~~Compared to 2016, commodity prices increased significantly and were the primary driver for improvements in Devon’s operating margins, earnings and cash flow during the first nine months of 2017.~~ We exited the ~~third~~second quarter of ~~2017~~2019 with liquidity comprised of ~~$2.8~~$3.8 billion of cash, inclusive of $370 million of cash restricted for discontinued operations, and ~~$2.9~~$3.0 billion of available credit under our Senior Credit Facility. WeAfter completing the $1.5 billion of early retirement of debt in July 2019, we have no ~~significant~~outstanding debt maturities until ~~2021. At September 30, 2017, we also had~~2025. We currently have approximately ~~65%~~75% of our ~~remaining 2017 forecasted~~expected oil and gas production ~~hedged at~~protected with hedges for the remainder of 2019. These contracts consist of collars and swaps based off the WTI oil benchmark and the Henry Hub natural gas index. Additionally, we have entered into regional basis swaps in an ~~average floor~~effort to protect price realizations across our portfolio.

The following graphs, discussion and ~~approximately 66%~~analysis are intended to provide an understanding of our ~~remaining 2017 forecasted natural gas production hedged at an average floor price~~results of ~~$3.10/MMBtu. We~~operations and current financial condition. Specifically, the graph below shows the change in net earnings from the three months ended March 31, 2019 to the three months ended June 30, 2019. The material changes are ~~building our 2018 and 2019 hedge positions at similar prices.~~further discussed by category on the following pages.

~~We expect to further enhance our financial strength with our announced $1 billion~~

* Other includes asset ~~divestiture program.~~ dispositions, restructuring and transaction costs and other expenses.

The ~~planned divestitures include select portions~~graph below presents the drivers of the ~~Barnett Shale focused primarily~~upstream operations change presented above, with additional details and discussion of the drivers following the graph.

Upstream Operations

Field-Level Cash Margin

The table below presents the field-level cash margin for each of our operating areas. Field-level cash margin is computed as oil, gas and NGL revenues less production expenses and is not prepared in ~~and around Johnson County and other properties located principally within Devon’s~~accordance with GAAP. A reconciliation to the comparable GAAP measures is found in “Non-GAAP Measures” in this Item 2.

	Q2 2019		$ per BOE		Q1 2019		$ per BOE
Field-level cash margin (non-GAAP)
Delaware Basin	$	267	$	24.46	$	234	$	24.39
STACK		177	$	15.77		203	$	18.27
Powder River Basin		60	$	31.79		50	$	27.02
Eagle Ford		120	$	26.63		129	$	28.53
Other		15	$	22.67		13	$	21.39
New Devon		639	$	21.88		629	$	22.71
U.S. divest assets		41	$	4.38		74	$	7.62
Total	$	680	$	17.63	$	703	$	18.80

Production Volumes

	Q2 2019		% of Total			Q1 2019		Change
Oil (MBbls/d)
Delaware Basin		67		46	%		60		+12	%
STACK		31		21	%		32		- 4	%
Powder River Basin		15		11	%		15		- 1	%
Eagle Ford		23		16	%		25		- 4	%
Other		6		4	%		6		+0	%
New Devon		142		98	%		138		+3	%
U.S. divest assets		3		2	%		4		- 35	%
Total		145		100	%		142		+2	%

	Q2 2019		% of Total			Q1 2019		Change
Gas (MMcf/d)
Delaware Basin		158		16	%		146		+9	%
STACK		313		32	%		333		- 6	%
Powder River Basin		22		2	%		18		+20	%
Eagle Ford		81		8	%		83		- 3	%
Other		1		0	%		1		+1	%
New Devon		575		58	%		581		- 1	%
U.S. divest assets		423		42	%		439		- 4	%
Total		998		100	%		1,020		- 2	%

	Q2 2019		% of Total			Q1 2019		Change
NGLs (MBbls/d)
Delaware Basin		27		24	%		23		+16	%
STACK		40		36	%		35		+14	%
Powder River Basin		2		1	%		2		+2	%
Eagle Ford		12		11	%		12		+7	%
Other		1		1	%		1		+5	%
New Devon		82		73	%		73		+13	%
U.S. divest assets		30		27	%		31		- 2	%
Total		112		100	%		104		+9	%

	Q2 2019		% of Total			Q1 2019		Change
Combined (MBoe/d)
Delaware Basin		120		28	%		107		+12	%
STACK		124		29	%		123		+0	%
Powder River Basin		21		5	%		21		+2	%
Eagle Ford		49		12	%		50		- 1	%
Other		7		2	%		7		- 1	%
New Devon		321		76	%		308		+4	%
U.S. divest assets		103		24	%		108		- 4	%
Total		424		100	%		416		+2	%

Continued growth in the Delaware Basin drove production increases for New Devon in the second quarter of 2019 compared to the first quarter of 2019. These production gains were slightly offset by lower production volumes associated with the U.S. ~~resource base. Through September 30, 2017, we have closed non-core divestitures totaling approximately $400 million under this program.~~divest assets.

Field Prices

	Q2 2019			Realization		Q1 2019		Change
Oil (per Bbl)
WTI index	$	59.85				$	54.88		+9	%
Realized price, unhedged	$	57.09			95%	$	51.83		+10	%
Cash settlements	$	(0.41	)			$	3.63
Realized price, with hedges	$	56.68			95%	$	55.46		+2	%

	Q2 2019		Realization		Q1 2019			Change
Gas (per Mcf)
Henry Hub index	$	2.64			$	3.15			- 16	%
Realized price, unhedged	$	1.61		61%	$	2.53			- 36	%
Cash settlements	$	0.20			$	(0.17	)
Realized price, with hedges	$	1.81		69%	$	2.36			- 23	%

	Q2 2019		Realization		Q1 2019		Change
NGLs (per Bbl)
Mont Belvieu blended index ⁽¹⁾	$	19.05			$	22.94		- 17	%
Realized price, unhedged	$	14.79		78%	$	18.64		- 21	%
Cash settlements	$	1.03			$	0.48
Realized price, with hedges	$	15.82		83%	$	19.12		- 17	%

(1)Based upon composition of our NGL barrel.

	Q2 2019		Q1 2019		Change
Combined (per Boe)
Realized price, unhedged	$	27.24	$	28.58		- 5	%
Cash settlements	$	0.60	$	0.93
Realized price, with hedges	$	27.84	$	29.51		- 6	%

We recently unveiled our “2020 Vision,” which is a strategic plan through the end of the decade intended to deliver top-tier returns on invested capital, while delivering sustainable, long-term growth for our business. We plan to attain leading returns with our 2020 Vision by pursing the following objectives:

~~Disciplined capital allocation that builds scale in the STACK and Delaware Basin.~~

~~Maximize returns by growing higher-value liquids production and lowering operating expenses with a technology focus across all areas of the business.~~

~~Further high-grade portfolio with monetization of several billion dollars of assets.~~

~~Reduce debt balances.~~

~~Return cash to shareholders.~~

~~Table of Contents~~

~~Results of Operations~~

~~Oil, Gas and NGL Production~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

Change

2017

2016

Change

Oil (MBbls/d)

Barnett Shale

1

1

- 13
%

1

1

- 22
%
Delaware Basin

31

31

+0
%

31

35

- 12
%
Eagle Ford

30

33

- 10
%

38

44

- 15
%
Heavy Oil

18

22

- 15
%

18

23

- 22
%
Rockies Oil

12

11

+9
%

13

14

- 9
%
STACK

27

21

+31
%

24

18

+34
%
Other

11

11

+ 4
%

10

12

- 17
%
Retained assets

130

130

+0
%

135

147

- 8
%
Divested assets

—

6

N/M

—

13

N/M

Total

130

136

- 5
%

135

160

- 16
%
Bitumen (MBbls/d)

Heavy Oil

103

115

- 11
%

109

105

+4
%
Gas (MMcf/d)

Barnett Shale

672

730

- 8
%

677

752

- 10
%
Delaware Basin

90

92

- 3
%

91

92

- 0
%
Eagle Ford

88

85

+4
%

101

111

- 9
%
Heavy Oil

16

18

- 11
%

17

20

- 14
%
Rockies Oil

11

19

- 39
%

14

27

- 47
%
STACK

313

292

+7
%

300

296

+1
%
Other

11

13

- 16
%

12

14

- 16
%
Retained assets

1,201

1,249

- 4
%

1,212

1,312

- 8
%
Divested assets

—

75

N/M

—

165

N/M

Total

1,201

1,324

- 9
%

1,212

1,477

- 18
%
NGLs (MBbls/d)

Barnett Shale

36

44

- 18
%

40

45

- 10
%
Delaware Basin

11

12

- 14
%

10

12

- 19
%
Eagle Ford

12

13

- 8
%

13

18

- 29
%
Rockies Oil

1

1

+9
%

1

1

- 2
%
STACK

32

23

+37
%

30

28

+7
%
Other

2

3

- 10
%

2

3

- 13
%
Retained assets

94

96

- 2
%

96

107

- 10
%
Divested assets

—

8

N/M

—

17

N/M

Total

94

104

- 10
%

96

124

- 22
%
Combined (MBoe/d)

Barnett Shale

148

166

- 11
%

154

171

- 10
%
Delaware Basin

57

59

- 3
%

56

62

- 11
%
Eagle Ford

57

61

- 7
%

67

81

- 17
%
Heavy Oil

124

140

- 11
%

130

132

- 1
%
Rockies Oil

16

16

+0
%

17

20

- 17
%
STACK

111

92

+20
%

104

95

+9
%
Other

14

16

- 8
%

14

17

- 17
%
Retained assets

527

550

- 4
%

542

578

- 6
%
Divested assets

—

27

N/M

—

57

N/M

Total

527

577

- 9
%

542

635

- 15
%

~~Table of Contents~~

~~Oil, Gas and NGL Pricing~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017 ⁽¹⁾

2016 ⁽¹⁾

Change

2017 ⁽¹⁾

2016 ⁽¹⁾

Change

Oil (per Bbl)

U.S.

$
47.12

$
42.51

+11
%

$
47.84

$
36.89

+30
%

Canada

$
35.02

$
27.46

+28
%

$
32.77

$
22.26

+47
%

Total

$
45.41

$
40.12

+13
%

$
45.83

$
34.78

+32
%

Bitumen (per Bbl)

Canada

$
31.75

$
23.00

+38
%

$
28.49

$
17.77

+60
%

Gas (per Mcf)

U.S.

$
2.45

$
2.24

+10
%

$
2.54

$
1.70

+50
%

NGLs (per Bbl)

U.S.

$
15.15

$
9.80

+55
%

$
14.62

$
8.84

+65
%

Combined (per Boe)

U.S.

$
23.85

$
20.26

+18
%

$
24.44

$
17.16

+42
%

Canada

$
31.59

$
23.23

+36
%

$
28.50

$
18.15

+57
%

Total

$
25.67

$
20.98

+22
%

$
25.41

$
17.37

+46
%

~~(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 commodity sales between the three and nine months ended September 30, 2017 and 2016.~~

Three Months Ended September 30,

Oil

Bitumen

Gas

NGLs

Total

(Millions)

2016 sales

$
502

$
244

$
273

$
94

$
1,113

Change due to volumes

(23
)

(26
)

(25
)

(9
)

(83
)
Change due to prices

63

83

23

46

215

2017 sales

$
542

$
301

$
271

$
131

$
1,245

Nine Months Ended September 30,

Oil

Bitumen

Gas

NGLs

Total

(Millions)

2016 sales

$
1,523

$
512

$
688

$
300

$
3,023

Change due to volumes

(243
)

16

(125
)

(68
)

(420
)
Change due to prices

407

319

279

152

1,157

2017 sales

$
1,687

$
847

$
842

$
384

$
3,760

Commodity sales increased in the third quarter and the first nine months of 2017 due to price increases for all commodities. The increase in oil and bitumen sales resulted from a higher average WTI crude oil index price. Additionally, our bitumen sales benefited from tighter heavy oil differentials. The increases in gas and NGL sales were due to higher North American regional index prices upon which our gas sales are based and higher NGL prices at the Mont Belvieu, Texas hub.

The increases in sales due to the favorable movement in commodity prices was partially offset by a decline in production volumes. In 2016, we significantly reduced our drilling and completion capital programs in response to depressed commodity prices. Consequently, production from our retained U.S. assets, other than STACK, steadily declined throughout 2016 and into 2017. Our 2016 asset divestiture program also caused our volumes to decline significantly in the third and fourth quarters of 2016. Additionally, Hurricane Harvey negatively impacted our third quarter 2017 production in the Eagle Ford as we temporarily suspended operations.

~~Table of Contents~~

~~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 ourRealized oil, gas and NGL prices ~~with,~~decreased primarily due to lower Henry Hub and ~~without,~~Mont Belvieu index prices and widening natural gas differentials in the ~~effects of~~Permian Basin and STACK which are partially mitigated by our regional natural gas basis swaps. These decreases were slightly offset by a 9% improvement in the ~~cash settlements. The prices do not include the effects of fair value gains and losses.~~WTI index price.

Hedging

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(Millions)

Cash settlements:

Oil derivatives

$
11

$
20

$
29

$
(41
)
Gas derivatives

13

(4
)

14

47

NGL derivatives

—

—

—

(2
)
Total cash settlements

24

16

43

4

Gains (losses) on fair value changes:

Oil derivatives

(157
)

23

72

(7
)
Gas derivatives

(7
)

35

101

(26
)
NGL derivatives

(4
)

5

(2
)

(1
)
Total gains (losses) on fair value changes

(168
)

63

171

(34
)
Oil, gas and NGL derivatives

$
(144
)

$
79

$
214

$
(30
)

Three Months Ended September 30, 2017

Oil

Bitumen

Gas

NGLs

Boe

(Per Bbl)

(Per Bbl)

(Per Mcf)

(Per Bbl)

(Per Boe)

Realized price without hedges

$
45.41

$
31.75

$
2.45

$
15.15

$
25.67

Cash settlements of hedges

0.96

—

0.12

(0.03
)

0.52

Realized price, including cash settlements

$
46.37

$
31.75

$
2.57

$
15.12

$
26.19

��

Three Months Ended September 30, 2016

Oil

Bitumen

Gas

NGLs

Boe

(Per Bbl)

(Per Bbl)

(Per Mcf)

(Per Bbl)

(Per Boe)

Realized price without hedges

$
40.12

$
23.00

$
2.24

$
9.80

$
20.98

Cash settlements of hedges

1.56

—

(0.04
)

0.10

0.32

Realized price, including cash settlements

$
41.68

$
23.00

$
2.20

$
9.90

$
21.30

Nine Months Ended September 30, 2017

Oil

Bitumen

Gas

NGLs

Boe

(Per Bbl)

(Per Bbl)

(Per Mcf)

(Per Bbl)

(Per Boe)

Realized price without hedges

$
45.83

$
28.49

$
2.54

$
14.62

$
25.41

Cash settlements of hedges

0.80

—

0.05

(0.02
)

0.29

Realized price, including cash settlements

$
46.63

$
28.49

$
2.59

$
14.60

$
25.70

Nine Months Ended September 30, 2016

Oil

Bitumen

Gas

NGLs

Boe

(Per Bbl)

(Per Bbl)

(Per Mcf)

(Per Bbl)

(Per Boe)

Realized price without hedges

$
34.78

$
17.77

$
1.70

$
8.84

$
17.37

Cash settlements of hedges

(0.94
)

—

0.12

(0.06
)

0.02

Realized price, including cash settlements

$
33.84

$
17.77

$
1.82

$
8.78

$
17.39

	Q2 2019			Q1 2019			Change
	Q
Oil	$	(6	)	$	46			N/M
Natural gas		18			(16	)		N/M
NGL		11			4			N/M
Total cash settlements		23			34			N/M
Valuation changes		117			(639	)		N/M
Total	$	140		$	(605	)		N/M

~~Table of Contents~~

Cash settlements as presented in the tables above represent realized gains or losses related to ~~various commodity derivatives.~~ the instruments described in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

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~~relationship between contract prices and the associated forward curves. ~~Including~~

Production Expenses

	Q2 2019			Q1 2019			Change
LOE	$	133		$	132			+1	%
Gathering, processing & transportation		161			159			+1	%
Production taxes		66			64			+3	%
Property taxes		11			10			+10	%
Total	$	371		$	365			+2	%
Per Boe:
LOE	$	3.44		$	3.55			- 3	%
Gathering, processing & transportation	$	4.17		$	4.26			- 2	%
Percent of oil, gas and NGL sales:
Production taxes		6.3	%		6.0	%		+4	%

General and Administrative Expenses

	Q2 2019			Q1 2019			Change
Labor and benefits	$	92		$	103			- 11	%
Non-labor		40			49			- 18	%
Reimbursed G&A		(18	)		(17	)		- 6	%
Total Devon	$	114		$	135			- 16	%

Labor and benefits and non-labor expenses decreased primarily as a result of the ~~cash settlements discussed above, our oil, gas~~workforce reduction and NGL derivatives incurred a net loss in the third quarter of 2017 and generated a net gain in the third quarter of 2016. Including the cash settlements discussed above, our oil, gas and NGL derivatives generated a net gaincost savings initiatives that were initiated during the first ~~nine months~~quarter of ~~2017 and incurred a net loss during the first nine months of 2016.~~2019.

~~Marketing and Midstream Revenues and Operating Expenses~~

Other

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

Change

2017

2016

Change

(Millions)

Operating revenues

$
2,055

$
1,690

+22
%

$
5,992

$
4,503

+33
%
Product purchases

(1,721
)

(1,391
)

+24
%

(5,043
)

(3,618
)

+39
%
Operations and maintenance expenses

(92
)

(89
)

+3
%

(276
)

(266
)

+4
%
Operating profit

$
242

$
210

+15
%

$
673

$
619

+9
%

Devon loss

$
(11
)

$
(18
)

+39
%

$
(47
)

$
(37
)

-27
%
EnLink profit

253

228

+11
%

720

656

+10
%
Total profit

$
242

$
210

+15
%

$
673

$
619

+9
%

	Q2 2019			Q1 2019			Change
Asset dispositions	$	(1	)	$	(44	)		+98	%
Restructuring		12			51			- 75	%
Other		8			(17	)		+146	%
Total	$	19		$	(10	)		+288	%

~~The overall increase~~We recognized gains in marketing and midstream operating margin during the third quarter and the first nine months of 2017 was primarily due to an increase in EnLink’s throughput volumes related to gas processing and transmission activities, offset by a decline in margins on Devon’s downstream marketing commitments. Devon is actively engaged in optimization activities to improve margins to help offset the costs of downstream commitments; however, we expect those commitments to negatively impact our margins throughout 2017.

~~Asset Dispositions and Other~~

In conjunction with ~~the non-core upstream~~certain of our U.S. asset ~~divestitures, we recognized a gain during the third quarter of 2016.~~dispositions in 2019. For further discussion, see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.

~~Lease Operating Expenses~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

Change

2017

2016

Change

(Millions, except per Boe amounts)

LOE:

U.S.

$
256

$
248

+3
%

$
761

$
886

- 14
%
Canada

135

107

+26
%

415

329

+26
%
Total

$
391

$
355

+10
%

$
1,176

$
1,215

- 3
%
LOE per Boe:

U.S.

$
6.89

$
6.17

+12
%

$
6.76

$
6.42

+5
%
Canada

$
11.81

$
8.31

+42
%

$
11.70

$
9.13

+28
%
Total

$
8.05

$
6.69

+20
%

$
7.95

$
6.98

+14
%

Total LOE and LOE per Boe increased during the third quarter of 2017 primarily due to higher transportation of $38 million resulting from tolls on Canada’s Access Pipeline of $27 million, which commenced in the fourth quarter of 2016 subsequent to the sale of our interest in the pipeline, and continued development of the STACK.

Total LOE decreased during the first nine months of 2017 primarily due to our non-core U.S. property divestitures during 2016 and continued well optimization and cost reduction initiatives across our portfolio which have offset industry inflation. These initiatives have been primarily focused on reducing costs associated with water disposal, power and fuel, compression and workovers. These cost savings and non-core divestitures impact were partially offset by Access Pipeline transportation tolls of $87 million during the first nine months of 2017, which was the primary driver of the increase in total LOE per Boe.

~~Table of Contents~~

~~General and Administrative Expenses~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

Change

2017

2016

Change

(Millions)

Gross G&A

$
196

$
184

+7
%

$
623

$
642

- 3
%
Capitalized G&A

(55
)

(54
)

+3
%

(170
)

(183
)

- 7
%
Reimbursed G&A

(19
)

(19
)

+1
%

(53
)

(66
)

- 20
%
Devon Net G&A

122

111

+10
%

400

393

+2
%
EnLink Net G&A

31

30

+2
%

98

89

+10
%
Net G&A

$
153

$
141

+8
%

$
498

$
482

+3
%

Gross G&A increased during the third quarter of 2017 due to an increase in costs related to automation and process improvement initiatives and decreased the first nine months of 2017 largely due to lower Devon employee costs resulting from our 2016 workforce reduction and other cost reduction initiatives. During the first nine months of 2017, reimbursed G&A decreased primarily due to the divestitures of operated properties in 2016. EnLink net G&A increased during the third quarter and for the first nine months of 2017 primarily due to higher employee compensation costs.

~~Production and Property Taxes~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

Change

2017

2016

Change

(Millions)

Production taxes

$
40

$
39

+3
%

$
131

$
110

+19
%
Property and other taxes

20

19

+2
%

62

79

- 21
%
Devon production and property taxes

60

58

+4
%

193

189

+2
%
EnLink property taxes

11

9

+24
%

34

31

+7
%
Production and property taxes

$
71

$
67

+5
%

$
227

$
220

+3
%
Percentage of oil, gas and NGL sales:

Production taxes

3.2
%

3.5
%

- 8
%

3.5
%

3.6
%

- 4
%
Property and other taxes

2.5
%

2.6
%

- 3
%

2.6
%

3.7
%

- 30
%
Total

5.7
%

6.1
%

- 6
%

6.1
%

7.3
%

- 17
%

~~Production taxes increased during each period in 2017 on an absolute dollar basis primarily due to an increase in our U.S. revenues, on which the majority of our production taxes are assessed.~~

During the first ~~nine~~six months of ~~2017, property~~2019, we recognized restructuring and ~~other taxes decreased~~transaction costs primarily as a result of ~~lower property value assessments from the local taxing authorities across~~ our key operating areas and as a result of our non-core oil and gas property divestitures during 2016. Property taxes do not always change in direct correlation with the change 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 September 30,

Nine Months Ended September 30,

2017

2016

Change

2017

2016

Change

(Millions, except per Boe amounts)

DD&A:

Oil and gas properties

$
232

$
239

- 3
%

$
675

$
930

- 27
%
Other assets

26

29

- 9
%

80

117

- 31
%
Devon DD&A

258

268

- 4
%

755

1,047

- 28
%
EnLink DD&A

142

126

+13
%

407

373

+9
%
Total DD&A

$
400

$
394

+2
%

$
1,162

$
1,420

- 18
%
DD&A per Boe:

Oil and gas properties

$
4.78

$
4.51

+6
%

$
4.56

$
5.35

- 15
%

workforce reductions. See ~~Table of Contents~~

DD&A from our oil and gas properties decreased in the third quarter primarily due to lower production and decreased during the first nine months of 2017 largely due to lower DD&A rates, resulting from the oil and gas asset impairments and non-core U.S. divestures in 2016. DD&A from our other assets decreased due to the divestiture of Access Pipeline in the fourth quarter of 2016.

~~EnLink’s DD&A increased primarily due to acquisitions made during 2016 and gathering system expansions in 2017.~~

~~Asset Impairments~~

~~During the third quarter and the first nine months of 2016, we recognized asset impairments totaling $319 million and $4.9 billion, respectively. For further discussion, see~~ Note 56 in “Part I. Financial Information – Item 1. Financial Statements” ofin this ~~report.~~report for additional information.

~~Restructuring and Transaction Costs~~

Income Taxes

	Q2 2019			Q1 2019
Current expense (benefit)	$	2		$	(3	)
Deferred expense (benefit)		69			(107	)
Total expense (benefit)	$	71		$	(110	)
Effective income tax rate		30	%		24	%

During the first nine months of 2016, we recognized restructuring costs of $249 million as a result of a reduction in workforce driven by our cost reduction initiatives and divestiture of non-core properties.

~~During the first nine months of 2016, we recognized transaction costs of $17 million, primarily associated with the closing of the acquisitions discussed in~~ For discussion on income taxes, see Note 27 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.

~~Net Financing Costs~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

Change

2017

2016

Change

(Millions)

Devon net financing costs:

Interest based on debt outstanding

$
97

$
120

- 19
%

$
292

$
376

- 22
%
Early retirement of debt

—

84

N/M

—

84

N/M

Capitalized interest

(19
)

(16
)

+21
%

(53
)

(47
)

+12
%
Other

(1
)

7

- 114
%

(3
)

18

- 117
%
Total Devon net financing costs

77

195

- 60
%

236

431

- 45
%
EnLink net financing costs:

Interest based on debt outstanding

43

37

+16
%

125

105

+19
%
Interest accretion on deferred installment payment

7

13

- 46
%

20

39

- 49
%
Early retirement of debt

—

—

N/M

(9
)

—

N/M

Other

—

(2
)

N/M

(2
)

(5
)

- 60
%
Total EnLink net financing costs

50

48

+2
%

134

139

- 3
%
Total net financing costs

$
127

$
243

- 48
%

$
370

$
570

- 35
%

Discontinued Operations - Canada

~~Devon’s net financing costs~~

	Q2 2019			Q1 2019
Upstream revenues	$	388		$	247
Production expenses	$	153		$	141
Asset dispositions	$	(189	)	$	—
Asset impairments	$	37		$	—
Restructuring and transaction costs	$	236		$	3
Net earnings	$	329		$	29
Production (MBoe/d)		97			113
Realized price, unhedged (per Boe)	$	43.03		$	34.42

Canada revenues increased in the second quarter of 2019 compared to the first quarter of 2019 due to increased realized prices partially offset by lower production volumes. Canadian production decreased during the ~~third~~second quarter ~~and~~of 2019 compared to the first ~~nine months~~quarter of ~~2017~~2019 primarily due to scheduled turnaround at the ~~2016 repayment~~Jackfish 2 facility and recording four less days of ~~$2.5 billion in borrowings, including scheduled maturities and early retirements funded~~production due to the divestiture close date.

In conjunction with ~~asset divestiture proceeds.~~

~~EnLink’s interest on debt outstanding increased~~the sale of our Canadian business during the ~~third~~second quarter ~~and the first nine months~~ of ~~2017 due to increased borrowings. In the first nine months of 2017, EnLink~~2019, we recognized a pre-tax gain of $189 million as well as restructuring and transaction costs and related asset impairment charges of $273 million. For a discussion on ~~extinguishment of debt as disclosed in~~ discontinued operations, see Note 1418 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.

~~Income Taxes~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(Millions)

Current income tax expense

$
39

$
85

$
71

$
72

Deferred income tax expense (benefit)

(14
)

86

(20
)

(300
)
Total income tax expense (benefit)

$
25

$
171

$
51

$
(228
)
Effective income tax rate

9
%

15
%

4
%

5
%

3632

Table of Contents

~~We continue~~Results of Operations –2019 vs. 2018

The following graphs, discussion and analysis are intended to ~~expect low~~provide an understanding of our results of operations and current ~~income tax rates~~financial condition. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests.

Q2 2019 vs. Q2 2018

The graph below shows the change in net earnings from the three months ended June 30, 2018 to the three months ended June 30, 2019. The material changes are further discussed by category below. Further analysis of the upstream operations change has been provided within a supplemental section to our results of operations beginning on page 34.

* Other includes asset dispositions, restructuring and transaction costs and other expenses.

Net earnings increased $830 million during the second quarter of 2019 compared to the second quarter of 2018. The increase primarily related to a $460 million increase in upstream operations, a $228 million change in other items and a $168 million increase in discontinued operations. Upstream operations increased primarily due to a $627 million gain on valuation changes and cash settlements for commodity derivatives, partially offset by a $229 million lower field price effect primarily related to our oil and NGL production. Other items increased primarily due to $154 million of asset impairments and $85 million of restructuring charges recognized in the ~~U.S. segment based~~second quarter of 2018. During the second quarter of 2019, earnings from discontinued operations increased due to recognizing a gain on the disposition of our ~~continuing net operating loss position. For~~Canadian business partially offset by related restructuring and asset impairment charges as further ~~discussion on income taxes, see~~ discussed in Note 718 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.

June 30, 2019 YTD vs. June 30, 2018 YTD

The graph below shows the change in net earnings from the six months ended June 30, 2018 to the six months ended June 30, 2019. The material changes are further discussed by category below. Further analysis of the upstream operations change has been provided within a supplemental section to our results of operations beginning on page 34.

* Other includes asset dispositions, restructuring and transaction costs and other expenses.

Table of Contents

Net earnings increased $666 million during the six months ended 2019 compared to the same period in 2018. The increase primarily related to a $327 million decrease in financing costs, a $177 million change in other items, a $142 million increase in discontinued operations, a $72 million decrease in exploration expense, partially offset by a $127 million increase in DD&A. Financing costs decreased primarily from $312 million of early retirement costs associated with our $800 million debt retirement in 2018. Other items decreased due to $154 million of asset impairments recognized in 2018 and an approximately $45 million gain recognized during 2019. During the second quarter of 2019, earnings from discontinued operations increased due to recognizing a gain on the disposition of our Canadian business partially offset by related restructuring and asset impairment charges further discussed in Note 18 in “Part I. Financial Information – Item 1. Financial Statements” in this report. Exploration expense decreased due to unproved asset impairments of $61 million during 2018.

Upstream Operations

The supplemental graphs and charts below present the drivers and details of the upstream operations changes discussed in the previous section.

Q2 2019 vs. Q2 2018

June 30, 2019 YTD vs. June 30, 2018 YTD

Table of Contents

Field-Level Cash Margin

	Three Months Ended June 30,								Six Months Ended June 30,
	2019		$ per BOE		2018		$ per BOE		2019		$ per BOE		2018		$ per BOE
Field-level cash margin (non-GAAP)
Delaware Basin	$	267	$	24.46	$	222	$	32.11	$	501	$	24.43	$	387	$	31.23
STACK		177	$	15.77		247	$	21.66		380	$	17.01		481	$	21.39
Powder River Basin		60	$	31.79		62	$	42.23		110	$	29.44		125	$	40.49
Eagle Ford		120	$	26.63		181	$	36.95		249	$	27.58		312	$	36.17
Other		15	$	22.67		24	$	33.87		28	$	22.03		41	$	33.30
New Devon		639	$	21.88		736	$	28.99		1,268	$	22.29		1,346	$	28.15
U.S. divest assets		41	$	4.38		111	$	8.05		115	$	6.03		236	$	8.25
Total	$	680	$	17.63	$	847	$	21.60	$	1,383	$	18.21	$	1,582	$	20.71

Production Volumes

	Three Months Ended June 30,										Six Months Ended June 30,
	2019		% of Total			2018		Change			2019		% of Total			2018		Change
Oil (MBbls/d)
Delaware Basin		67		46	%		45		+49	%		63		44	%		39		+60	%
STACK		31		21	%		34		- 8	%		32		22	%		34		- 6	%
Powder River Basin		15		11	%		13		+19	%		15		11	%		14		+12	%
Eagle Ford		23		16	%		28		- 17	%		24		17	%		26		- 6	%
Other		6		4	%		6		- 4	%		6		4	%		6		- 6	%
New Devon		142		98	%		126		+13	%		140		98	%		119		+18	%
U.S. divest assets		3		2	%		10		- 75	%		3		2	%		10		- 69	%
Total		145		100	%		136		+7	%		143		100	%		129		+11	%
Gas (MMcf/d)
Delaware Basin		158		16	%		94		+68	%		152		15	%		94		+61	%
STACK		313		32	%		329		- 5	%		323		32	%		327		- 1	%
Powder River Basin		22		2	%		13		+75	%		20		2	%		12		+66	%
Eagle Ford		81		8	%		74		+9	%		82		8	%		69		+19	%
Other		1		0	%		3		- 56	%		1		0	%		1		+2	%
New Devon		575		58	%		513		+12	%		578		57	%		503		+15	%
U.S. divest assets		423		42	%		603		- 30	%		431		43	%		637		- 32	%
Total		998		100	%		1,116		- 11	%		1,009		100	%		1,140		- 12	%
NGLs (MBbls/d)
Delaware Basin		27		24	%		15		+74	%		25		23	%		13		+88	%
STACK		40		36	%		37		+10	%		38		35	%		36		+6	%
Powder River Basin		2		1	%		1		+60	%		2		2	%		1		+52	%
Eagle Ford		12		11	%		13		- 6	%		12		11	%		11		+14	%
Other		1		1	%		2		- 43	%		1		1	%		1		+11	%
New Devon		82		73	%		68		+22	%		78		72	%		62		+26	%
U.S. divest assets		30		27	%		41		- 27	%		30		28	%		41		- 27	%
Total		112		100	%		109		+3	%		108		100	%		103		+5	%
Combined (MBoe/d)
Delaware Basin		120		28	%		76		+58	%		113		27	%		68		+66	%
STACK		124		29	%		125		- 1	%		123		29	%		124		- 1	%
Powder River Basin		21		5	%		16		+29	%		21		5	%		17		+21	%
Eagle Ford		49		12	%		54		- 8	%		50		12	%		48		+5	%
Other		7		2	%		8		- 6	%		7		2	%		7		+0	%
New Devon		321		76	%		279		+15	%		314		75	%		264		+19	%
U.S. divest assets		103		24	%		151		- 32	%		105		25	%		158		- 33	%
Total		424		100	%		430		- 2	%		419		100	%		422		- 1	%

Table of Contents

Strong performance in the Delaware Basin and Powder River Basin drove production growth for New Devon during the three and six months ended 2019 compared to the three and six months ended 2018. These production gains were offset by lower production volumes associated with our U.S. divested assets.

Field Prices

	Three Months Ended June 30,										Six Months Ended June 30,
	2019			Realization	2018			Change			2019		Realization	2018			Change
Oil (per Bbl)
WTI index	$	59.85			$	67.83			- 12	%	$	57.36		$	65.38			- 12	%
Realized price, unhedged	$	57.09		95%	$	65.41			- 13	%	$	54.50	95%	$	63.71			- 14	%
Cash settlements	$	(0.41	)		$	(11.43	)				$	1.58		$	(10.32	)
Realized price, with hedges	$	56.68		95%	$	53.98			+5	%	$	56.08	98%	$	53.39			+5	%
Gas (per Mcf)
Henry Hub index	$	2.64			$	2.80			- 6	%	$	2.90		$	2.90			- 0	%
Realized price, unhedged	$	1.61		61%	$	2.03			- 20	%	$	2.08	72%	$	2.23			- 7	%
Cash settlements	$	0.20			$	0.13					$	0.01		$	0.16
Realized price, with hedges	$	1.81		69%	$	2.16			- 16	%	$	2.09	72%	$	2.39			- 13	%
NGLs (per Bbl)
Mont Belvieu blended index ⁽¹⁾	$	19.05			$	28.05			- 32	%	$	21.00		$	26.97			- 22	%
Realized price, unhedged	$	14.79		78%	$	24.10			- 39	%	$	16.62	79%	$	23.38			- 29	%
Cash settlements	$	1.03			$	(1.66	)				$	0.77		$	(1.13	)
Realized price, with hedges	$	15.82		83%	$	22.44			- 29	%	$	17.39	83%	$	22.25			- 22	%
Combined (per Boe)
Realized price, unhedged	$	27.24			$	31.97			- 15	%	$	27.90		$	31.20			- 11	%
Cash settlements	$	0.60			$	(3.67	)				$	0.76		$	(3.01	)
Total	$	27.84			$	28.30			- 2	%	$	28.66		$	28.19			+2	%

(1)

Based upon composition of our NGL barrel.

Hedging

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Cash settlements:
Oil derivatives	$	(6	)	$	(142	)	$	40		$	(240	)
Gas derivatives		18			14			2			32
NGL derivatives		11			(16	)		15			(21	)
Total cash settlements		23			(144	)		57			(229	)
Valuation changes		117			(343	)		(522	)		(371	)
Oil, gas and NGL derivatives	$	140		$	(487	)	$	(465	)	$	(600	)

Production Expenses

	Three Months Ended June 30,									Six Months Ended June 30,
	2019			2018			Change			2019			2018			Change
LOE	$	133		$	154			- 14	%	$	265		$	302			- 12	%
Gathering, processing & transportation		161			180			- 11	%		320			362			- 12	%
Production taxes		66			64			+3	%		130			121			+7	%
Property taxes		11			8			+29	%		21			16			+30	%
Total	$	371		$	406			- 8	%	$	736		$	801			- 8	%
Per Boe:
LOE	$	3.44		$	3.93			- 12	%	$	3.49		$	3.94			- 11	%
Gathering, processing & transportation	$	4.17		$	4.60			- 9	%	$	4.21		$	4.73			- 11	%
Percent of oil, gas and NGL sales:
Production taxes		6.3	%		5.1	%		+23	%		6.2	%		5.1	%		+21	%

Table of Contents

LOE decreased for the three month and six month periods of 2019 compared to the same periods in 2018 primarily due to the impact of our U.S. non-core asset divestitures. Gathering, processing and transportation decreased in the three month and six month periods of 2019 compared to the same time periods of 2018 primarily due to the expiration of the EnLink Bridgeport minimum volume commitment at the end of 2018. Production taxes increased, on an absolute dollar basis and as a percentage of oil, gas and NGL sales, primarily due to the increase in Oklahoma severance tax rates that became effective in the third quarter of 2018.

Discontinued Operations – Canada

	Three Months Ended June 30,					Six Months Ended June 30,
	2019			2018		2019			2018
Upstream revenues	$	388		$	303	$	635		$	605
Production expenses	$	153		$	166	$	294		$	314
Asset dispositions	$	(189	)	$	—	$	(189	)	$	—
Asset impairments	$	37		$	—	$	37		$	—
Restructuring and transaction costs	$	236		$	9	$	239		$	9
Net earnings	$	329		$	22	$	358		$	19
Production (MBoe/d)		97			111		105			121
Realized price, unhedged (per Boe)	$	43.03		$	31.17	$	38.41		$	24.84

Canadian production was lower during the second quarter of 2019 compared to the second quarter of 2018 as a result of less days of production due to the divestiture close date. Canadian production was lower during the six months ended 2019 compared to the six months ended 2018 primarily as a result of higher royalties.

In conjunction with the sale of our Canadian business during the second quarter of 2019, we recognized a pre-tax gain on the sale of our Canadian business of $189 million and restructuring and transaction costs and related asset impairment charges of $273 million. For additional details on discontinued operations financial results, see Note 18 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Table of Contents

Capital Resources, Uses and Liquidity

Sources and Uses of Cash

The following table presents the major changes in cash and cash equivalents for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016.~~

2018.

Devon

EnLink

Consolidated

2017

2016

2017

2016

2017

2016

(Millions)

Operating cash flow

$
1,892

$
724

$
528

$
513

$
2,420

$
1,237

Divestitures of property and equipment

321

1,884

2

5

323

1,889

Issuance of common stock

—

1,469

—

—

—

1,469

Proceeds from sale of investment

—

—

190

—

190

—

Capital expenditures

(1,541
)

(1,235
)

(662
)

(424
)

(2,203
)

(1,659
)
Acquisitions of property, equipment and businesses

(39
)

(849
)

—

(792
)

(39
)

(1,641
)
Debt activity, net

—

(1,946
)

252

178

252

(1,768
)
Payment of installment payable

—

—

(250
)

—

(250
)

—

Shareholder and noncontrolling interests distributions

(95
)

(190
)

(247
)

(224
)

(342
)

(414
)
EnLink and General Partner distributions

199

199

(199
)

(199
)

—

—

Issuance of subsidiary units

—

—

486

835

486

835

Effect of exchange rate and other

(45
)

(23
)

30

150

(15
)

127

Net change in cash and cash equivalents

$
692

$
33

$
130

$
42

$
822

$
75

Cash and cash equivalents at end of period

$
2,639

$
2,325

$
142

$
60

$
2,781

$
2,385

	Three months ended June 30,						Six months ended June 30,
	2019			2018			2019			2018
Operating cash flow from continuing operations	$	488		$	526		$	966		$	959
Divestitures of property and equipment		28			560			339			607
Capital expenditures		(494	)		(543	)		(996	)		(1,105	)
Acquisitions of property and equipment		(13	)		(10	)		(23	)		(16	)
Debt activity, net		—			—			(162	)		(1,111	)
Repurchases of common stock		(187	)		(428	)		(1,185	)		(499	)
Common stock dividends		(37	)		(42	)		(71	)		(74	)
Other		(3	)		(6	)		(22	)		(35	)
Net change in cash, cash equivalents and restricted cash from discontinued operations		2,716			(2	)		2,561			115
Net change in cash, cash equivalents and restricted cash	$	2,498		$	55		$	1,407		$	(1,159	)
Cash, cash equivalents and restricted cash at end of period	$	3,853		$	1,525		$	3,853		$	1,525

Operating Cash Flow

~~Net~~

As presented in the table above, net cash provided by operating activities ~~increased 96% primarily due~~continued to ~~significantly higher commodity prices as compared to the first nine months~~be a significant source of ~~2016.~~

~~Our consolidated operating~~capital and liquidity. Operating cash flow nearly funded ~~100%~~all of our capital expenditures during the first ~~nine~~three months and six months of ~~2017. In 2016, leveraging our liquidity, we also used~~2019. We utilized available cash balances and divestiture proceeds ~~from~~to supplement our ~~common stock offering~~operating cash flows and ~~non-core asset divestitures to~~ fund ~~our acquisitions~~other investing and ~~capital expenditures.~~financing cash uses.

~~Divestitures of Property and Equipment~~Operating Cash Flow

During the first nine months of 2017, as part of our announced divestiture program, we sold non-core U.S. assets for approximately $320 million, net of customary purchase price adjustments. During the first nine months of 2016, we divested certain non-core upstream assets in the U.S. for approximately $1.9 billion. For further discussion, see Note 2 in “Part 1. Financial Information – Item 1. Financial Statements” in this report.

~~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.

~~Proceeds from Sale of Investment~~

During the first quarter of 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million. Proceeds were primarily used to pay a portion of the $250 million installment payment related to EnLink’s 2016 acquisition further discussed in Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

~~Table of Contents~~

~~Capital Expenditures and Acquisitions of Property, Equipment and Businesses~~

~~The amounts~~As presented in the table ~~below reflect~~above, net cash ~~payments for~~provided by operating activities continued to be a significant source of capital ~~expenditures, including cash paid for capital expenditures incurred in prior periods.~~

Nine Months Ended September 30,

2017

2016

(Millions)

Oil and gas

$
1,480

$
1,212

Corporate and other

61

23

Devon capital expenditures

1,541

1,235

EnLink capital expenditures

662

424

Total capital expenditures

$
2,203

$
1,659

Devon acquisitions

39

849

EnLink acquisitions

—

792

Total acquisitions

$
39

$
1,641

~~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. Devon’s 2017 objectives are to concentrate capital spend in the STACK and Delaware Basin, while investing withinliquidity. Operating cash flow ~~and maintaining significant flexibility. Our~~nearly funded all of our capital ~~investment program is driven by a disciplined allocation process focused on returns.~~

~~Capital~~ expenditures for 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 development activities.

Acquisition capital for the first nine 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 $1.4 billion. Approximately $850 million and $800 million, respectively, was paid in cash at the closings with the remainder 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 nine months of 2017, consolidated net debt borrowings increased $252 million. In May 2017, EnLink issued $500 million of 5.45% senior notes due in 2047 to repay outstanding borrowings under its revolving credit facility and for general partnership purposes. In June 2017, EnLink redeemed its 7.125% senior unsecured notes due in 2022 for aggregate cash consideration of $174 million. Additionally, EnLink reduced its credit facility borrowings $74 million during the first ~~nine~~three months and six months of ~~2017.~~

~~During the first nine months of 2016, our consolidated net debt borrowings decreased $1.8 billion. The decrease was primarily due~~2019. We utilized available cash balances and divestiture proceeds to completed tender offers to purchase and redeem $1.2 billion of debt securities. For additional information, see Note 14 in “Part I. Financial Information – Item 1. Financial Statements” in this report. The remaining decrease was due to reducing our commercial paper balances by $626 million during the first nine months of 2016.

~~Payment of Installment Payable~~

During the first quarter of 2017, EnLink made the first installment payment related to its 2016 acquisition further discussed in Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

~~Table of Contents~~

~~Shareholder and Noncontrolling Interests Distributions~~

The following table summarizes our common stock dividends during the first nine months of 2017 and 2016. In the second quarter of 2016, we decreased our quarterly cash dividend rate to $0.06 per share.

Amounts

Rate

(Millions)

(Per Share)

Quarter Ended 2017:

First quarter 2017
$
32

$
0.06

Second quarter 2017

33

$
0.06

Third quarter 2017

30

$
0.06

Total year-to-date
$
95

Quarter Ended 2016:

First quarter 2016
$
125

$
0.24

Second quarter 2016

33

$
0.06

Third quarter 2016

32

$
0.06

Total year-to-date
$
190

~~EnLink and the General Partner distributed $247 million and $224 million to non-Devon unitholders during the first nine months of 2017 and 2016, respectively.~~

~~EnLink and General Partner Distributions~~

~~Devon received $199 million in distributions from EnLink and the General Partner during the first nine months of 2017 and 2016.~~

~~Issuance of Subsidiary Units~~

During the first nine months of 2017, EnLink issued and sold 5 million common units through its “at the market” programs and generated $92 million in net proceeds. In September 2017, EnLink issued preferred units in an underwritten public offering generating net proceeds of approximately $394 million.

In January 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 cash proceeds of approximately $725 million. General Partner common units were also issued as consideration in the transaction. Additionally, during the first nine months of 2016, EnLink issued and sold 7 million common units for net proceeds of $110 million through its “at the market” programs.

~~Liquidity~~

~~Our primary sources of capital and liquidity are~~supplement our operating cash ~~flow, asset divestiture proceeds~~flows and fund other investing and financing 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 also include, among other things, 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. We estimate the combination of these sources of capital will continue to be adequate to fund our planned capital expenditures, future debt repayments and other contractual commitments as discussed in this section.uses.

Operating Cash Flow

As presented in the table above, net cash provided by operating activities continued to be a significant source of capital and liquidity. Operating cash flow nearly funded all of our capital expenditures during the first three months and six months of 2019. We utilized available cash balances and divestiture proceeds to supplement our operating cash flows and fund other investing and financing cash uses.

Divestitures of Property and Equipment

During the first six months of 2019, we sold non-core U.S. assets for approximately $339 million, net of customary purchase price adjustments. During the first six months of 2018, we sold non-core U.S. assets, including certain Barnett Shale assets, for $607 million. For additional information, please see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Capital Expenditures and Acquisitions of Property and Equipment

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

	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
Delaware Basin	$	245	$	157	$	470	$	332
STACK		101		225		237		429
Powder River Basin		60		30		116		78
Eagle Ford		53		72		108		128
Other		17		56		40		111
Total oil and gas		476		540		971		1,078
Corporate and other		18		3		25		27
Total capital expenditures	$	494	$	543	$	996	$	1,105
Acquisitions	$	13	$	10	$	23	$	16

Capital expenditures consist of amounts related to our oil and gas exploration and development operations and other corporate activities. Our capital program is designed to operate within or near operating cash flow and maintain significant flexibility. Our capital investment program is driven by a disciplined allocation process focused on returns. Our capital expenditures are lower in 2019 primarily due to our decreased spending in the STACK, partially offset by increased capital investment in higher margin assets in the Delaware and Powder River Basin.

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Debt Activity

During the first six months of 2019, our debt decreased $162 million due to the repayment of our 6.30% senior notes at maturity.

During the first six months of 2018, our debt decreased approximately $800 million due to completed tender offers of certain long-term debt. In conjunction with the tender offers, we recognized a $312 million loss on the early retirement of debt, including $304 million of cash retirement costs and fees. For additional information, see Note 13 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Shareholder Distributions and Stock Activity

The following table summarizes our common stock dividends during the first six months of 2019 and 2018. Beginning with the second quarter of 2019, we increased our quarterly dividend to $0.09 per share.

	Amounts		Rate Per Share
Quarter Ended 2019:
First quarter	$	34	$	0.08
Second quarter		37	$	0.09
Total year-to-date	$	71
Quarter Ended 2018:
First quarter	$	32	$	0.06
Second quarter		42	$	0.08
Total year-to-date	$	74

We repurchased 42.1 million shares of common stock for $1.2 billion in the first six months of 2019 and 13.7 million shares of common stock for $521 million in the first six months of 2018 under a share repurchase program authorized by our Board of Directors. For additional information, see Note 17in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Cash Flows from Discontinued Operations

All cash flows in the following table relate to activities of our divested Canadian operations and our aggregate ownership interests in EnLink and the General Partner, which were divested in June 2019 and July 2018, respectively.

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Settlements of intercompany foreign denominated assets/liabilities	$	(32	)	$	(244	)	$	(31	)	$	(243	)
Other		167			223			64			593
Operating activities		135			(21	)		33			350
Divestitures of property and equipment		2,601			—			2,601			1
Capital expenditures and other		(57	)		(281	)		(104	)		(551	)
Investing activities		2,544			(281	)		2,497			(550	)
Debt activity, net		—			158			—			280
Distributions to noncontrolling interests		—			(115	)		—			(217	)
Other		—			30			(8	)		40
Financing activities		—			73			(8	)		103
Settlements of intercompany foreign denominated assets/liabilities		32			244			31			243
Other		5			(17	)		8			(31	)
Effect of exchange rate changes on cash		37			227			39			212
Net change in cash, cash equivalents and restricted cash of discontinued operations	$	2,716		$	(2	)	$	2,561		$	115

Foreign currency denominated intercompany loan activity during the first six months of 2019 and 2018 resulted in a realized loss of $31 million and $243 million, respectively, as a result of the strengthening of the U.S. dollar in relation to the Canadian dollar. There was an offset in the effect of exchange rate changes on cash line in the above table, resulting in no impact to the net change in cash, cash equivalents and restricted cash.

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Other operating cash flow from the first three and six months of 2019 decreased from the same periods in 2018 as a result of the divestiture of our aggregate ownership interests in EnLink and the General Partner in July 2018. In addition, operating cash flow was negatively affected in the first quarter of 2019 primarily due to realization impacts associated with the widening Canadian differentials in the fourth quarter of 2018.

On June 27, 2019, Devon completed the sale of all its operating assets and operations in Canada for proceeds of $2.6 billion. For additional information, see Note 2and Note 18 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

In July 2019, we retired $1.5 billion of senior notes prior to maturity. These senior notes were reclassified to liabilities associated with discontinued operations on the consolidated balance sheets. For additional information, see Note 18 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Devon received $134 million in distributions from EnLink and the General Partner during the first six months of 2018. Distributions to noncontrolling interests in the table above exclude the distributions EnLink and the General Partner paid to Devon, which have been eliminated in consolidation.

Liquidity

The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, we, like all upstream operators, must continually make capital investments to grow and even sustain production. Generally, our capital investments are focused on drilling and completing new wells and maintaining production from existing wells. At opportunistic times, we also acquire operations and properties from other operators or land owners to enhance our existing portfolio of assets.

Historically, our primary sources of capital funding and liquidity have been our operating cash flow, cash on hand and asset divestiture proceeds. 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. If needed, we can also issue debt and equity securities, including through transactions under our shelf registration statement filed with the SEC. In February 2019, we announced plans to separate our Canadian and Barnett Shale assets and operations. In June 2019, we closed on the sale of our Canadian business and expect to complete the separation of our Barnet Shale assets by the end of 2019. We plan to use the proceeds from these transactions for debt repayments and return cash to shareholders. We estimate the combination of our sources of capital will continue to be adequate to fund our planned capital requirements as discussed in this section.

Operating Cash Flow

Key inputs into determining our planned capital investment is the amount of cash we hold and operating cash flow we expect to generate over the next one to three or more years. At the end of the second quarter of 2019, we held approximately $3.8 billion of cash, inclusive of $370 million of cash restricted for discontinued operations. Our operating cash flow isforecasts are sensitive to many variables and include a measure of uncertainty as the actual results of these variables may differ from our expectations.

Commodity Prices – The most uncertain and volatile ~~of which~~variables for our operating cash flow are the prices of the oil, ~~bitumen,~~ gas and NGLs we produce and sell. ~~Our consolidated operating cash flow increased approximately $1.2 billion~~Prices are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in the first nine months of 2017 compared to the first nine months of 2016 largely due to increases in commodity prices. We expect operating cash flow to continue to be a key source of liquidity as we adjustprices and are beyond our ~~capital program to invest within our operating cash flow. Furthermore, proceeds from non-core asset divestitures will provide additional liquidity as needed.~~control.

~~Table of Contents~~

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. We target hedging approximately 50% of our production in a manner that systematically places hedges for several quarters in advance, allowing us to maintain a disciplined risk management program as it relates to commodity price volatility. We supplement the systematic hedging program with discretionary hedges that take advantage of favorable market conditions. The key terms to our oil, gas and NGL derivative financial instruments as of June 30, 2019 are presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.

Operating Expenses – Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price decreases can lead to a decrease in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also decrease, causing a positive impact on our cash flow as the prices paid for services and equipment decline. However, the inverse is also generally true during periods of rising commodity prices.

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For 2019, we are aggressively optimizing our cost structure in conjunction with our Canadian and planned Barnett Shale asset divestitures, as we focus on our remaining four U.S. oil plays, align our workforce with the retained business and reduce outstanding debt. We anticipate the planned $780 million reduction of annualized costs will occur over three years, with roughly 70% of the savings delivered by the end of 2019. Approximately 40% of the reduced costs relate to our capital programs and the remainder relates to our operating expenses, including G&A, interest expense and production expenses.

Credit Losses – Our operating cash flow is also exposed to credit risk in a variety of ways. This includes the credit risk related to customers who purchase our oil, gas and NGL production, the collection of receivables from our joint-interest partners for their proportionate share of expenditures made on projects we operate and counterparties to our derivative financial contracts. We utilize a variety of mechanisms to limit our exposure to the credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions, requiring letters of credit, prepayments or collateral postings.

Divestitures of Property and Equipment

In February 2019, we announced the separation of our Canadian and Barnett Shale businesses. In June 2019, we completed the sale of our Canadian operations for $2.6 billion ($3.4 billion Canadian dollars) and are progressing on the separation of our Barnett Shale assets. For additional information, ~~on our derivative positions in place at September 30, 2017,~~ see Note 32 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

~~Divestitures of Property and Equipment~~

In May 2017, we announced a program to divest approximately $1 billion of upstream assets. These non-core assets identified for monetization include select portions of the Barnett Shale focused primarily in and around Johnson County and other properties located principally within Devon’s U.S. resource base. Through September 30, 2017, Devon completed divestiture transactions totaling approximately $400 million, before purchase price adjustments. The most significant asset remaining in this program is select Barnett Shale leasehold. Data rooms for the Barnett properties opened in September 2017 and initial bids are expected during the fourth quarter of 2017.

Capital Expenditures

~~Excluding EnLink, our 2017 capital expenditures are~~Our exploration and development budget for the remainder of 2019 is expected to range from ~~$2.4~~$0.8 billion to ~~$2.5~~$0.9 billion, ~~including $2.0 billion to $2.1 billion for~~excluding capital associated with our ~~exploration and development capital program. Our capital expenditures excluding EnLink were $1.7 billion in the first nine months of 2017 and are forecasted to range from $0.7 billion to $0.8 billion in the fourth quarter of 2017.~~Barnett Shale assets.

Credit Availability

~~We have a $3.0 billion Senior Credit Facility.~~ As of ~~September~~June 30, ~~2017,~~2019, we had approximately ~~$2.9~~$3.0 billion of available borrowings under ~~this facility, net of $59 million in outstanding letters of credit, and were in compliance with the facility’s financial covenant.~~our Senior Credit Facility. This credit facility supports our $3.0 billion of short-term credit under our commercial paper program. At ~~September~~June 30, ~~2017,~~2019, there were no borrowings under our commercial paper ~~program.~~

~~EnLink Liquidity~~

~~EnLink has a $1.5 billion unsecured revolving credit facility. The General Partner has a $250 million secured revolving credit facility. As~~program, and we were in compliance with the facility’s financial covenant. In connection with the closing of ~~September 30, 2017, there were $9 million in outstanding letters~~the sale of ~~credit~~our Canadian business, we reallocated and ~~no outstanding borrowings~~terminated all Canadian commitments under the ~~$1.5~~Senior Credit Facility in accordance with the terms of the credit agreement governing the Senior Credit Facility. The termination of the Canadian subfacility was effective as of June 27, 2019, and such termination did not decrease the $3.0 billion ~~credit facility and $74 million~~ in ~~outstanding borrowings~~total revolving commitments under, or otherwise modify the ~~$250 million credit facility. All~~terms of, ~~EnLink’s and~~ the ~~General Partner’s debt is non-recourse to Devon.~~

In January 2017, EnLink paid the first $250 million installment payment related to the 2016 Anadarko Basin gathering and processing midstream assets acquisition. The remaining $250 million installment payment is payable by January 2018.Senior Credit Facility.

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 and ~~near-term and long-term~~ production growth opportunities. Our credit rating from Standard and Poor’s Financial Services is BBB with a ~~stable~~negative outlook. ~~In March 2017,~~Our credit rating from Fitch ~~Ratings affirmed our~~is BBB+ with a negative outlook. Our credit rating ~~and revised our outlook to stable~~ from ~~negative. In April 2017,~~ Moody’s Investor Service ~~upgraded our credit rating from Ba2 to~~is Ba1 with a ~~stable~~positive outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

~~There are no “rating triggers” in any~~Share Repurchase Program

In February 2019, our Board of Directors authorized an expansion of our or EnLink’s contractual debt obligations that would accelerate scheduled maturities should a debt rating fall below a specified level. However, these downgrades could adversely impact our and EnLink’s interest rate on any credit facility borrowings andpre-existing share repurchase program by an additional $1.0 billion to $5.0 billion. The share repurchase program expires December 31, 2019. Through July 31, 2019, we had executed $4.4 billion of the ~~ability to economically access debt markets in the future.~~authorized program.

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Table of Contents

Critical Accounting Estimates

~~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 ifOn June 27, 2019, we ~~deem it is more likely than not that some portion or~~divested all of our Canadian operating assets. Our foreign earnings have not been considered indefinitely reinvested since the ~~deferred tax~~announcement of the plan to separate the assets will not be realized. At September 30, 2017, we continued to have a 100% valuation allowance against the U.S. deferred tax assets that largely resulted from prior year cumulative financial losses primarily due to full cost impairments. Further, we continue to record a partial valuation allowance against certain Canadian deferred tax assets.

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~~first quarter of 2019. For additional information see Note 7 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

For additional information regarding our critical accounting policies and estimates, see our 2018 Annual Report on ~~the progress of ongoing audits, changes in legislation or resolution of other pending matters.~~Form 10-K.

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 ~~2017~~2019 Results” in this Item 2.2 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. For more information on the results of discontinued operations for our Canadian operations and for EnLink and the General Partner, see Note 18 in “Part I. Financial Information – Item 1. Financial Statements” in this report. Our non-GAAP measures are typically used as a quarterly performance measure. Amounts excluded ~~for the third quarter and first nine months of 2017~~ relate to ~~changes in derivatives and financial instrument fair values and foreign currency, gains and losses on~~ asset ~~sales,~~ dispositions, noncash asset impairments ~~gains~~(including noncash unproved asset impairments), deferred tax asset valuation allowance, costs associated with early retirement of debt, ~~and deferred tax asset valuation allowance. Amounts excluded for the third quarter and first nine months of 2016 relate to~~fair value changes in ~~derivatives and~~derivative financial ~~instrument fair values~~instruments and foreign currency, ~~noncash asset impairments (including an impairment of goodwill),~~settlements related to minimum volume contract commitments, restructuring and transaction costs ~~gains on asset sales,~~associated with the workforce reductions in 2019 and 2018 and restructuring and transaction costs associated with the ~~early retirement~~divestment of ~~debt and deferred tax asset valuation allowance.~~ our Canadian operations in 2019.

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.

~~Table of Contents~~

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 September 30,

Nine Months Ended September 30,

Before tax

After tax

After Noncontrolling Interests

Per Share

Before tax

After tax

After Noncontrolling Interests

Per Share

(Millions, except per share amounts)

2017

Earnings attributable to Devon
    (GAAP)

$
272

$
247

$
228

$
0.43

$
1,328

$
1,277

$
1,218

$
2.31

Adjustments:

Fair value changes in financial
   instruments and foreign currency

106

40

39

0.08

(292
)

(233
)

(232
)

(0.44
)
Gains and losses on asset sales

1

1

—

—

(6
)

(4
)

(4
)

(0.01
)
Asset impairments

2

1

1

—

9

7

4

0.01

Early retirement of debt

—

—

—

—

(9
)

(7
)

(4
)

(0.01
)
Deferred tax asset valuation allowance

—

(26
)

(26
)

(0.05
)

—

(346
)

(346
)

(0.66
)
Core earnings attributable to Devon
   (Non-GAAP)

$
381

$
263

$
242

$
0.46

$
1,030

$
694

$
636

$
1.20

2016

Earnings (loss) attributable to Devon
    (GAAP)

$
1,178

$
1,007

$
993

$
1.89

$
(4,252
)

$
(4,024
)

$
(3,633
)

$
(7.22
)
Adjustments:

Fair value changes in financial
   instruments and foreign currency

(16
)

(3
)

(3
)

(0.01
)

201

91

86

0.17

Asset impairments

319

202

202

0.38

4,851

3,492

3,076

6.12

Restructuring and transaction costs

(5
)

(3
)

(3
)

(0.01
)

266

171

169

0.33

Gains on asset sales

(1,351
)

(787
)

(787
)

(1.48
)

(1,351
)

(787
)

(787
)

(1.56
)
Early retirement of debt

84

53

53

0.10

84

53

53

0.11

Deferred tax asset valuation allowance

—

(408
)

(408
)

(0.78
)

—

867

867

1.71

Core earnings (loss) attributable to
    Devon (Non-GAAP)

$
209

$
61

$
47

$
0.09

$
(201
)

$
(137
)

$
(169
)

$
(0.34
)

Table of Contents

	Three Months Ended June 30,												Six Months Ended June 30,
	Before tax			After tax			After Noncontrolling Interests			Per Diluted Share			Before tax			After tax			After Noncontrolling Interests			Per Diluted Share
2019
Continuing Operations
Earnings (loss) attributable to Devon (GAAP)	$	237		$	166		$	166		$	0.40		$	(219	)	$	(180	)	$	(180	)	$	(0.43	)
Adjustments:
Asset dispositions		(1	)		(1	)		(1	)		(0.00	)		(45	)		(35	)		(35	)		(0.08	)
Asset and exploration impairments		2			2			2			0.00			2			2			2			0.00
Deferred tax asset valuation allowance		—			11			11			0.03			—			(2	)		(2	)		(0.01	)
Fair value changes in financial instruments		(117	)		(91	)		(91	)		(0.22	)		522			402			402			0.95
Restructuring and transaction costs		12			10			10			0.02			63			49			49			0.12
Core earnings attributable to Devon (Non-GAAP)	$	133		$	97		$	97		$	0.23		$	323		$	236		$	236		$	0.55
Discontinued Operations
Earnings attributable to Devon (GAAP)	$	44		$	329		$	329		$	0.79		$	73		$	358		$	358		$	0.85
Adjustments:
Gain on sale of Canadian operations		(189	)		(460	)		(460	)		(1.12	)		(189	)		(460	)		(460	)		(1.10	)
Asset and exploration impairments		37			27			27			0.07			37			27			27			0.07
Deferred tax asset valuation allowance		—			32			32			0.08			—			27			27			0.06
Fair value changes in financial instruments and foreign currency		(20	)		(17	)		(17	)		(0.04	)		(23	)		(23	)		(23	)		(0.06	)
Restructuring and transaction costs		236			172			172			0.42			239			174			174			0.42
Core earnings attributable to Devon (Non-GAAP)	$	108		$	83		$	83		$	0.20		$	137		$	103		$	103		$	0.24
Total
Earnings (loss) attributable to Devon (GAAP)	$	281		$	495		$	495		$	1.19		$	(146	)	$	178		$	178		$	0.42
Adjustments:
Continuing Operations		(104	)		(69	)		(69	)		(0.17	)		542			416			416			0.98
Discontinued Operations		64			(246	)		(246	)		(0.59	)		64			(255	)		(255	)		(0.61	)
Core earnings attributable to Devon (Non-GAAP)	$	241		$	180		$	180		$	0.43		$	460		$	339		$	339		$	0.79

2018
Continuing Operations
Loss attributable to Devon (GAAP)	$	(483	)	$	(496	)	$	(496	)	$	(0.97	)	$	(694	)	$	(704	)	$	(704	)	$	(1.36	)
Adjustments:
Asset dispositions		23			18			18			0.03			11			9			9			0.02
Asset and exploration impairments		207			159			159			0.31			217			166			166			0.32
Deferred tax asset valuation allowance		—			123			123			0.24			—			131			131			0.25
Early retirement of debt		—			—			—			—			312			240			240			0.46
Fair value changes in financial instruments		322			249			249			0.48			307			238			238			0.45
Restructuring and transaction costs		85			65			65			0.13			85			65			65			0.13
Core earnings attributable to Devon (Non-GAAP)	$	154		$	118		$	118		$	0.22		$	238		$	145		$	145		$	0.27
Discontinued Operations
Earnings attributable to Devon (GAAP)	$	151		$	161		$	71		$	0.14		$	181		$	216		$	82		$	0.16
Adjustments:
Deferred tax asset valuation allowance		—			(50	)		(50	)		(0.10	)		—			(52	)		(52	)		(0.10	)
Fair value changes in financial instruments and foreign currency		66			51			45			0.10			144			124			117			0.22
EnLink minimum volume commitments		(48	)		(39	)		(14	)		(0.03	)		(48	)		(39	)		(14	)		(0.02	)
Restructuring and transaction costs		9			7			7		$	0.01			9			7			7		$	0.01
Core earnings attributable to Devon (Non-GAAP)	$	178		$	130		$	59		$	0.12		$	286		$	256		$	140		$	0.27
Total
Loss attributable to Devon (GAAP)	$	(332	)	$	(335	)	$	(425	)	$	(0.83	)	$	(513	)	$	(488	)	$	(622	)	$	(1.20	)
Adjustments:
Continuing Operations		637			614			614			1.19			932			849			849			1.63
Discontinued Operations		27			(31	)		(12	)		(0.02	)		105			40			58			0.11
Core earnings attributable to Devon (Non-GAAP)	$	332		$	248		$	177		$	0.34		$	524		$	401		$	285		$	0.54

Table of Contents

EBITDAX and Field-Level Cash Margin

To assess the performance of our assets, we use EBITDAX and Field-Level Cash Margin. We compute EBITDAX as net earnings from continuing operations before income tax expense; financing costs, net; exploration expenses; depreciation, depletion and amortization; asset impairments; asset disposition gains and losses; non-cash share-based compensation; non-cash valuation changes for derivatives and financial instruments; restructuring and transaction costs; accretion on discounted liabilities; and other items not related to our normal operations. Field-Level Cash Margin is computed as oil, gas and NGL revenues less production expenses. Production expenses consist of lease operating, gathering, processing and transportation expenses, as well as production and property taxes.

We exclude financing costs from EBITDAX to assess our operating results without regard to our financing methods or capital structure. Exploration expenses and asset disposition gains and losses are excluded from EBITDAX because they are not indicators of operating efficiency for a given reporting period. DD&A and impairments are excluded from EBITDAX because capital expenditures are evaluated at the time capital costs are incurred. We exclude share-based compensation, valuation changes, restructuring and transaction costs, accretion on discounted liabilities and other items from EBITDAX because they are not considered a measure of asset operating performance.

We believe EBITDAX and Field-Level Cash Margin provide information useful in assessing our operating and financial performance across periods. EBITDAX and Field-Level Cash Margin as defined by Devon may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net earnings from continuing operations.

Below are reconciliations of net earnings from continuing operations to EBITDAX and a further reconciliation to Field-Level Cash Margin. We have excluded the EBITDAX and Field-Level Cash Margin for our U.S. divested assets, Canada (which has been reclassified as discontinued operations on our consolidated comprehensive statements of earnings) and the Barnett Shale to compute Adjusted EBITDAX and Adjusted Field-Level Cash Margin for New Devon. We use Adjusted EBITDAX and Adjusted Field-Level Cash Margin to assess the performance of our portfolio of upstream assets on a “same-store” basis across periods.

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Net earnings (loss) from continuing operations (GAAP)	$	166		$	(496	)	$	(180	)	$	(704	)
Financing costs, net		66			64			126			453
Income tax expense (benefit)		71			13			(39	)		10
Exploration expenses		7			62			11			83
Depreciation, depletion and amortization		394			342			774			647
Asset impairments		—			154			—			154
Asset dispositions		(1	)		23			(45	)		11
Share-based compensation		21			26			44			59
Derivative and financial instrument non-cash valuation changes		(117	)		322			522			307
Restructuring and transaction costs		12			85			63			85
Accretion on discounted liabilities and other		8			6			(9	)		—
EBITDAX (non-GAAP)		627			601			1,267			1,105
Marketing revenues and expenses, net		(17	)		(7	)		(32	)		(3	)
Commodity derivative cash settlements		(23	)		144			(57	)		229
General and administration expenses, cash-based		93			109			205			251
Field-level cash margin (non-GAAP)	$	680		$	847		$	1,383		$	1,582

EBITDAX (non-GAAP)	$	627		$	601		$	1,267		$	1,105
EBITDAX, U.S. divested assets		(2	)		(38	)		(8	)		(78	)
EBITDAX, Barnett Shale		(39	)		(73	)		(107	)		(158	)
Adjusted EBITDAX (non-GAAP)	$	586		$	490		$	1,152		$	869

Field-level cash margin (non-GAAP)	$	680		$	847		$	1,383		$	1,582
Field-level cash margin, U.S. divested assets		(2	)		(38	)		(8	)		(78	)
Field-level cash margin, Barnett Shale		(39	)		(73	)		(107	)		(158	)
Adjusted field-level cash margin (non-GAAP)	$	639		$	736		$	1,268		$	1,346

Table of Contents

Item 3. Quantitative and ~~Qualitati~~veQualitative Disclosures About Market Risk

Commodity Price Risk

As of ~~September~~June 30, ~~2017,~~2019, we have commodity derivatives that pertain to a portion of our estimated production for the last ~~three~~six months of ~~2017,~~2019, as well as ~~2018 and 2019.~~for 2020. The key terms to our open oil, gas and NGL derivative financial instruments are presented in Note 3in “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 ~~September~~June 30, ~~2017,~~2019, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net ~~asset~~ positions by approximately ~~$170~~$180 million.

Interest Rate Risk

As of ~~September~~June 30, ~~2017,~~2019, we had total debt of ~~$10.4~~$5.8 billion. OfAll of this ~~amount, $10.3 billion bears~~debt was based on fixed interest rates averaging ~~5.3%,~~5.4%. Total debt is inclusive of the $1.5 billion of debt that was reclassified to liabilities associated with discontinued operations at June 30, 2019 and ~~$74 million is comprised of floating rate debt with interest rates averaging 3.2%.~~

~~As of September 30, 2017, we had open interest rate swap positions that are presented~~retired early in July 2019. See Note 318 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 September 30, 2017.report for additional information.

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~~Devon has certain Canadian dollar ~~functional currency. Assets and liabilities~~obligations resulting from its divestment of its Canadian operations which are to be paid with the ~~Canadian subsidiaries~~cash restricted for discontinued operations. These balances are ~~translated to U.S. dollars~~remeasured 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 ~~September~~June 30, ~~2017~~2019 balance ~~sheet.~~sheet for these items. See Note 18 in “Part I. Financial Information – Item 1. Financial Statements” in this report for additional information.

Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, certain 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 ~~September~~June 30, ~~2017~~2019 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

We implemented internal controls to ensure we adequately evaluated our contracts and properly assessed the impact of the new lease accounting standard on our financial statements to facilitate its adoption in the first quarter of 2019. There were no significant changes to our internal control over financial reporting due to the adoption of the new lease accounting standard. There were no other changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

4345

Table of Contents

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.

On April 4, 2019, Devon Energy Production Company, L.P., a wholly-owned subsidiary of the Company (“DEPCO”), agreed to settle its previously disclosed negotiations with the EPA relating to certain alleged Clean Air Act violations at its Beaver Creek Gas Plant located near Riverton, Wyoming by executing an agreed order with the EPA. The order included a penalty of $150,000 and was approved by the regional EPA judicial officer on June 12, 2019. Moreover, in connection with the resolution of this matter with the EPA, DEPCO entered into a consent decree on May 9, 2019 with respect to the same matter with the Wyoming Department of Environmental Quality, which also included a separate penalty of $150,000.

Please see our ~~2016~~2018 Annual Report on Form 10-K for additional ~~information regarding certain environmental matters involving the Company.~~information.

Item 1A. Risk Factors

There have been no material changes to the information included in Item 1A. “Risk Factors” in our ~~2016~~2018 Annual Report on Form ~~10-K.~~10-K.

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

The following table provides information regarding purchases of our common stock that were made by us during the ~~third~~second quarter of ~~2017.~~

2019 (shares in thousands).

Period

Total Number of
Shares Purchased ⁽¹⁾

Average Price Paid
per Share

July 1 - July 31

48,112

$
32.08

August 1 - August 31

16,504

$
31.69

September 1 - September 30

1,108

$
31.81

Total

65,724

$
31.97

Period	Total Number of Shares Purchased ⁽¹⁾		Average Price Paid per Share		Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs ⁽²⁾		Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs ⁽²⁾
April 1 - April 30		78	$	31.34		—	$	998
May 1 - May 31		242	$	26.20		220	$	993
June 1 - June 30		5,699	$	27.05		5,691	$	839
Total		6,019	$	27.07		5,911

~~(1)~~

~~Share repurchases represent~~(1)

In addition to shares purchased under the share repurchase program described below, these amounts also included 108,000 shares received by us from employees for the payment of personal income tax withholding on vesting transactions.

(2)

On March 7, 2018, we announced a $1.0 billion share repurchase program. On June 6, 2018, we announced the expansion of this program to $4.0 billion. On February 19, 2019, we announced a further expansion to $5.0 billion with a December 31, 2019 expiration date. As of June 30, 2019, we had repurchased 120.2 million common shares for $4.2 billion, or $34.62 per share, under our share repurchases program. Future purchases under the program will be made in open market, private transactions or through the use of ASR programs.

Under the Devon Plan, eligible employees ~~may purchase~~made purchases of shares of our common stock through an investment in the Devon Stock Fund, which is administered by an independent trustee. Eligible employees purchased approximately ~~10,400~~8,800 shares of our common stock in the ~~third~~second quarter of ~~2017,~~2019, 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 third quarter of 2017, there were approximately 4,200 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.

4446

Table of Contents

Item 6. E~~xhibits~~Exhibits

Exhibit Number		Description

2.1		Agreement of Purchase and Sale, dated as of May 28, 2019, among Devon Canada Corporation, Devon Canada Crude Marketing Corporation and Canadian Natural Resources Limited (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed May 31, 2019; File No. 001-32318).

4.1		Assignment and Assumption Agreement, dated as of June 19, 2019, by and between Devon Financing Company, L.L.C. and Devon Energy Corporation, relating to that certain Indenture, dated as of October 3, 2001, by and among Devon Financing Company, L.L.C. (f/k/a Devon Financing Company, U.L.C.), as issuer, Devon Energy Corporation, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as successor to The Chase Manhattan Bank, as trustee, and the 7.875% Debentures due 2031 issued thereunder.

10.1		Amendment 2019-1, executed June 19, 2019, to the Devon Energy Corporation Defined Contribution Restoration Plan (as amended and restated effective January 1, 2012).*

10.2		Amendment 2019-1, executed June 19, 2019, to the Devon Energy Corporation Supplemental Contribution Plan (as amended and restated effective January 1, 2012).*

10.3		Amendment 2019-1, executed June 19, 2019, to the Devon Energy Corporation Supplemental Executive Retirement Plan (as amended and restated effective January 1, 2012).*

10.4		Amendment 2019-1, executed June 19, 2019, to the Devon Energy Corporation Incentive Savings Plan (as amended and restated effective January 1, 2018).*

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.~~Document – the XBRL Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH		XBRL Taxonomy Extension Schema Document.

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB		XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.

______________

45* Indicates management contract or compensatory plan or arrangement.

Table of Contents

~~SIGNATURES~~SIGNATURES

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

				DEVON ENERGY CORPORATION

Date: ~~November 1, 2017~~August 7, 2019				/s/ Jeremy D. Humphers
				Jeremy D. Humphers
				Senior Vice President and Chief Accounting Officer

4648

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)


Title of each class	Trading Symbol	Name of each exchange on which registered
Common Stock, par value $0.10 per share	DVN	The New York Stock Exchange

	September 30, 2017			December 31, 2016
	(Unaudited)						June 30, 2019			December 31, 2018
	(Millions, except share data)						(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	2,781		$	1,959		$	3,470		$	2,414
Cash restricted for discontinued operations								370			—
Accounts receivable		1,462			1,356			842			855
Assets held for sale		—			193
Current assets associated with discontinued operations								131			283
Other current assets		379			264			354			885
Total current assets		4,622			3,772			5,167			4,437
Property and equipment, at cost:
Oil and gas, based on full cost accounting:
Subject to amortization		78,470			75,648
Not subject to amortization		2,853			3,437
Total oil and gas		81,323			79,085
Midstream and other		11,097			10,455
Total property and equipment, at cost		92,420			89,540
Less accumulated depreciation, depletion and amortization		(75,338	)		(73,350	)
Property and equipment, net		17,082			16,190
Oil and gas property and equipment, based on successful efforts accounting, net								8,987			8,982
Other property and equipment, net								1,050			1,044
Total property and equipment, net								10,037			10,026
Goodwill		3,964			3,964			841			841
Right-of-use assets								273			—
Other long-term assets		1,891			1,987			232			276
Long-term assets associated with discontinued operations								99			3,986
Total assets	$	27,559		$	25,913		$	16,649		$	19,566
LIABILITIES AND EQUITY
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	797		$	642		$	522		$	563
Revenues and royalties payable		1,012			908			772			832
Short-term debt		20			—			—			162
Current liabilities associated with discontinued operations								1,894			338
Other current liabilities		1,003			1,066			279			331
Total current liabilities		2,832			2,616			3,467			2,226
Long-term debt		10,383			10,154			4,294			4,292
Lease liabilities								263			—
Asset retirement obligations		1,100			1,226			528			606
Other long-term liabilities		645			894			431			442
Long-term liabilities associated with discontinued operations								189			2,285
Deferred income taxes		665			648			483			529
Equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 525 million and 523 million shares in 2017 and 2016, respectively		53			52
Stockholders' equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 410 million and 450 million shares in 2019 and 2018, respectively								41			45
Additional paid-in capital		7,207			7,237			3,352			4,486
Accumulated deficit		(428	)		(1,646	)
Accumulated other comprehensive earnings		297			284
Total stockholders’ equity attributable to Devon		7,129			5,927
Noncontrolling interests		4,805			4,448
Total equity		11,934			10,375
Total liabilities and equity	$	27,559		$	25,913
Retained earnings								3,738			3,650
Accumulated other comprehensive earnings (loss)								(117	)		1,027
Treasury stock, at cost, 0.7 million and 1.0 million shares in 2019 and 2018, respectively								(20	)		(22	)
Total stockholders’ equity								6,994			9,186
Total liabilities and stockholders' equity							$	16,649		$	19,566

	Three Months Ended September 30, 2016
	(Millions)
Proceeds received, net of purchase price adjustments and selling costs	$	1,653
Asset retirement obligation assumed by purchasers		250
Total consideration received		1,903

Allocated oil and gas property basis sold		355
Allocated goodwill		197
Total assets sold		552

Gain on asset sales	$	1,351

	Price Swaps				Price Collars
Period	Volume (Bbls/d)		Weighted Average Price ($/Bbl)		Volume (Bbls/d)		Weighted Average Floor Price ($/Bbl)		Weighted Average Ceiling Price ($/Bbl)
Q4 2017		82,167	$	53.87		79,200	$	45.51	$	57.41
Q1-Q4 2018		22,792	$	51.13		34,121	$	45.71	$	55.71
Q1-Q4 2019		1,356	$	49.79		2,096	$	44.10	$	54.10


Large accelerated filer	☑	Accelerated filer	☐	Non-accelerated filer	☐
Smaller reporting company	☐	Emerging growth company	☐

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 Equity	9
	Notes to Consolidated Financial Statements	10
	Note 1 – Summary of Significant Accounting Policies	10
	Note 2 – Divestitures	11
	Note 3 – Derivative Financial Instruments	12
	Note 4 – Share-Based Compensation	14
	Note 5 – Asset Impairments	15
	Note 6 – Restructuring and Transaction Costs	15
	Note 7 – Income Taxes	16
	Note 8 – Net Earnings (Loss) Per Share From Continuing Operations	17
	Note 9 – Other Comprehensive Earnings (Loss)	18
	Note 10 – Supplemental Information to Statements of Cash Flows	18
	Note 11 – Accounts Receivable	19
	Note 12 – Property, Plant and Equipment	19
	Note 13 – Debt and Related Expenses	19
	Note 14 – Leases	20
	Note 15 – Asset Retirement Obligations	22
	Note 16 – Retirement Plans	23
	Note 17 – Stockholders’ Equity	23
	Note 18 – Discontinued Operations and Assets Held For Sale	24
	Note 19 – Commitments and Contingencies	27
	Note 20 – Fair Value Measurements	28
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4345
Item 4.	Controls and Procedures	4345

Part II. Other Information
Item 1.	Legal Proceedings	4446
Item 1A.	Risk Factors	4446
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4446
Item 3.	Defaults Upon Senior Securities	4446
Item 4.	Mine Safety Disclosures	4446
Item 5.	Other Information	4446
Item 6.	Exhibits	4547

Signatures		4648

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Unaudited)
	(Millions, except per share amounts)
Oil, gas and NGL sales	$	1,245		$	1,113		$	3,760		$	3,023
Oil, gas and NGL derivatives		(144	)		79			214			(30	)
Marketing and midstream revenues		2,055			1,690			5,992			4,503
Asset dispositions and other		—			1,351			10			1,351
Total revenues and other		3,156			4,233			9,976			8,847
Lease operating expenses		391			355			1,176			1,215
Marketing and midstream operating expenses		1,813			1,480			5,319			3,884
General and administrative expenses		153			141			498			482
Production and property taxes		71			67			227			220
Depreciation, depletion and amortization		400			394			1,162			1,420
Asset impairments		2			319			9			4,851
Restructuring and transaction costs		—			(5	)		—			266
Other operating items		—			17			11			41
Total operating expenses		2,830			2,768			8,402			12,379
Operating income (loss)		326			1,465			1,574			(3,532	)
Net financing costs		127			243			370			570
Other nonoperating items		(73	)		44			(124	)		150
Earnings (loss) before income taxes		272			1,178			1,328			(4,252	)
Income tax expense (benefit)		25			171			51			(228	)
Net earnings (loss)		247			1,007			1,277			(4,024	)
Net earnings (loss) attributable to noncontrolling interests		19			14			59			(391	)
Net earnings (loss) attributable to Devon	$	228		$	993		$	1,218		$	(3,633	)
Net earnings (loss) per share attributable to Devon:
Basic	$	0.43		$	1.90		$	2.32		$	(7.22	)
Diluted	$	0.43		$	1.89		$	2.31		$	(7.22	)
Comprehensive earnings (loss):
Net earnings (loss)	$	247		$	1,007		$	1,277		$	(4,024	)
Other comprehensive earnings, net of tax:
Foreign currency translation		1			2			1			28
Pension and postretirement plans		5			11			14			20
Other		—			—			(2	)		—
Other comprehensive earnings, net of tax		6			13			13			48
Comprehensive earnings (loss)		253			1,020			1,290			(3,976	)
Comprehensive earnings (loss) attributable to noncontrolling interests		19			14			59			(391	)
Comprehensive earnings (loss) attributable to Devon	$	234		$	1,006		$	1,231		$	(3,585	)

	Oil Basis Swaps
Period	Index	Volume (Bbls/d)		Weighted Average Differential to WTI ($/Bbl)
Q4 2017	Midland Sweet		20,000	$	(0.41	)
Q4 2017	Western Canadian Select		87,304	$	(14.57	)
Q1-Q4 2018	Midland Sweet		23,000	$	(1.02	)
Q1-Q4 2018	Western Canadian Select		59,718	$	(14.85	)
Q1-Q4 2019	Midland Sweet		1,000	$	(0.80	)

	Natural Gas Basis Swaps
Period	Index	Volume (MMBtu/d)		Weighted Average Differential to Henry Hub ($/MMBtu)
Q4 2017	Panhandle Eastern Pipe Line		150,000	$	(0.34	)
Q4 2017	El Paso Natural Gas		80,000	$	(0.13	)
Q4 2017	Houston Ship Channel		35,000	$	0.06
Q4 2017	Transco Zone 4		205,000	$	0.03
Q1-Q4 2018	Panhandle Eastern Pipe Line		50,000	$	(0.29	)

~~Period~~	~~Product~~	~~Volume (Total)~~			~~Weighted Average Price Paid~~	~~Weighted Average Price Received~~
~~Q4 2017-Q3 2018~~	~~Propane~~		~~537~~	~~MBbls~~	~~Index~~	~~$0.66/gal~~
~~Q4 2017-Q3 2018~~	~~Normal Butane~~		~~344~~	~~MBbls~~	~~Index~~	~~$0.77/gal~~

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Millions)
Commodity derivatives:
Oil, gas and NGL derivatives	$	(144	)	$	79		$	214		$	(30	)
Marketing and midstream revenues		(5	)		(1	)		3			(7	)
Interest rate derivatives:
Other nonoperating items		(4	)		(20	)		(19	)		(163	)
Foreign currency derivatives:
Other nonoperating items		—			—			—			(159	)
Net gains (losses) recognized	$	(153	)	$	58		$	198		$	(359	)

	Three Months Ended June 30,					Six Months Ended June 30,
	2019		2018			2019			2018
Commodity derivatives:
Upstream revenues	$	140	$	(487	)	$	(465	)	$	(600	)
Marketing revenues		—		(1	)		1			(1	)
Interest rate derivatives:
Other expenses		—		19			—			65
Net gains (losses) recognized	$	140	$	(469	)	$	(464	)	$	(536	)

	Restricted Stock					Performance-Based					Performance							Restricted Stock					Performance-Based					Performance
	Awards and Units					Restricted Stock Awards					Share Units							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		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)																	(Thousands, except fair value data)
Unvested at 12/31/16		6,407		$	34.40		585		$	37.60		2,604				$	46.66
Unvested at 12/31/18																			5,963		$	35.47		302		$	35.93		2,868				$	30.14
Granted		2,691		$	44.87		223		$	44.85		1,010				$	52.58		4,383		$	25.49		—		$	—		741				$	28.97
Vested		(2,321	)	$	39.51		(233	)	$	41.27		(832	)			$	78.19		(4,295	)	$	33.60		(141	)	$	37.48		(145	)			$	37.23
Forfeited		(252	)	$	36.06		—		$	—		(24	)			$	40.70		(557	)	$	27.16		—		$	—		(1,276	)			$	11.34
Unvested at 9/30/17		6,525		$	36.83		575		$	38.92		2,758		⁽¹	⁾	$	41.21
Unvested at 6/30/19																			5,494		$	29.80		161		$	34.56		2,188		⁽¹	⁾	$	40.25

	2017					2019
Grant-date fair value	$	51.05	—	$	53.12	$	28.43	—	$	29.53
Risk-free interest rate	1.50%					2.48%
Volatility factor	45.8%					39.1%
Contractual term (years)	2.89					2.89

	General Partner				EnLink
	Restricted		Performance		Restricted		Performance
	Incentive Units		Units		Incentive Units		Units
Unrecognized compensation cost (millions)	$	14	$	6	$	15	$	6
Weighted average period for recognition (years)		1.8		2.0		1.7		1.9

	September 30, 2016
	Three Months Ended			Nine Months Ended
	(Millions)
2016 reduction in workforce:
Employee related costs	$	(7	)	$	229
Lease obligations		—			17
Asset impairments		—			3
Transaction costs		2			17
Restructuring and transaction costs	$	(5	)	$	266

	Other			Other
	Current			Long-term
	Liabilities			Liabilities			Total
	(Millions)
Balance as of December 31, 2016	$	48		$	62		$	110
Changes due to 2016 workforce reductions		(25	)		(2	)		(27	)
Changes related to prior years' restructurings		(3	)		(24	)		(27	)
Balance as of September 30, 2017	$	20		$	36		$	56
Balance as of December 31, 2015	$	13		$	63		$	76
Changes due to 2016 workforce reductions		58			13			71
Changes related to prior years' restructurings		5			(8	)		(3	)
Balance as of September 30, 2016	$	76		$	68		$	144

	June 30, 2019			December 31, 2018
Property and equipment:
Proved	$	41,155		$	40,378
Unproved and properties under development		770			833
Total oil and gas		41,925			41,211
Less accumulated DD&A		(32,938	)		(32,229	)
Oil and gas property and equipment, net		8,987			8,982
Other property and equipment		1,735			1,707
Less accumulated DD&A		(685	)		(663	)
Other property and equipment, net		1,050			1,044
Property and equipment, net	$	10,037		$	10,026

	June 30, 2019			December 31, 2018

6.30% due January 15, 2019	$	—		$	162
5.85% due December 15, 2025		485			485
7.50% due September 15, 2027		73			73
7.875% due September 30, 2031 ⁽¹⁾		675			675
7.95% due April 15, 2032 ⁽¹⁾		366			366
5.60% due July 15, 2041		1,250			1,250
4.75% due May 15, 2042		750			750
5.00% due June 15, 2045		750			750
Net discount on debentures and notes		(20	)		(21	)
Debt issuance costs		(35	)		(36	)
Total debt		4,294			4,454
Less amount classified as short-term debt		—			162
Total long-term debt	$	4,294		$	4,292

	Finance		Operating		Total
Right-of-use assets	$	209	$	64	$	273
Lease liabilities:
Current lease liabilities ⁽¹⁾	$	7	$	39	$	46
Long-term lease liabilities		239		24		263
Total lease liabilities	$	246	$	63	$	309

		Three Months Ended			Six Months Ended
		June 30, 2019
Operating lease cost	Property, plant and equipment; G&A	$	12		$	25
Short-term lease cost ⁽¹⁾	Property, plant and equipment; G&A		21			45
Financing lease cost:
Amortization of right-of-use assets	DD&A		6			12
Interest on lease liabilities	Net financing costs		2			5
Variable lease cost	G&A		—			1
Lease income	G&A		(1	)		(2	)
Net lease cost		$	40		$	86

	Finance			Operating			Total ⁽¹⁾
2019	$	3		$	22		$	25
2020		7			32			39
2021		7			8			15
2022		8			1			9
2023		8			1			9
Thereafter		306			1			307
Total lease payments		339			65			404
Less: interest		(93	)		(2	)		(95	)
Present value of lease liabilities	$	246		$	63		$	309

	Operating
	Lease Income ⁽¹⁾
2019	$	3
2020		6
2021		7
2022		7
2023		7
Thereafter		53
Total	$	83

	Pension Benefits												Postretirement Benefits
	Three Months Ended						Nine Months Ended						Three Months Ended				Nine Months Ended
	September 30,						September 30,						September 30,				September 30,						Pension Benefits
	2017			2016			2017			2016			2017		2016		2017			2016			Three Months Ended June 30,						Six Months Ended June 30,
	(Millions)																						2019			2018			2019			2018
Service cost	$	4		$	3		$	12		$	12		$	—	$	—	$	—		$	—		$	2		$	3		$	3		$	5
Interest cost		11			9			32			32			—		—		—			—			8			10			17			20
Expected return on plan assets		(14	)		(14	)		(41	)		(40	)		—		—		—			—			(9	)		(14	)		(19	)		(27	)
Amortization of prior service cost ⁽¹⁾		—			1			1			2			—		—		(1	)		(1	)		—			1			1			1
Net actuarial loss ⁽¹⁾		5			6			14			19			—		—		—			—			3			3			6			7
Net periodic benefit cost ⁽²⁾	$	6		$	5		$	18		$	25		$	—	$	—	$	(1	)	$	(1	)	$	4		$	3		$	8		$	6

	Total Number of Shares Purchased		Dollar Value of Shares Purchased		Average Price Paid per Share
First quarter 2018:
Open-Market		2,561	$	82	$	32.19
Second quarter 2018:
Open-Market		11,154		439		39.35
Third quarter 2018:
Open-Market		16,492		712		43.13
ASR		24,330		1,000		41.10
Total		40,822		1,712		41.92
Fourth quarter 2018:
Open-Market		23,612		745		31.57
First quarter 2019:
Open-Market		36,141		1,024		28.33
Second quarter 2019:
Open-Market		5,911		159		27.01
Total inception-to-date		120,201	$	4,161	$	34.62

	Amounts		Rate
	(Millions)		(Per Share)
Quarter Ended 2017:
First quarter 2017	$	32	$	0.06
Second quarter 2017		33	$	0.06
Third quarter 2017		30	$	0.06
Total year-to-date	$	95
Quarter Ended 2016:
First quarter 2016	$	125	$	0.24
Second quarter 2016		33	$	0.06
Third quarter 2016		32	$	0.06
Total year-to-date	$	190

	Three months ended June 30,									Six months ended June 30,
	Canada			EnLink			Total			Canada			EnLink			Total
2019
Upstream revenues	$	388		$	—		$	388		$	635		$	—		$	635
Marketing and midstream revenues		12			—			12			38			—			38
Total revenues		400			—			400			673			—			673
Production expenses		153			—			153			294			—			294
Exploration expenses		4			—			4			13			—			13
Marketing and midstream expenses		9			—			9			18			—			18
Depreciation, depletion and amortization		49			—			49			128			—			128
Asset impairments		37			—			37			37			—			37
Asset dispositions		(189	)		—			(189	)		(189	)		—			(189	)
General and administrative expenses		13			—			13			31			—			31
Financing costs, net		13			—			13			26			—			26
Restructuring and transaction costs		236			—			236			239			—			239
Other expenses		31			—			31			3			—			3
Total expenses		356			—			356			600			—			600
Earnings from discontinued operations before income taxes		44			—			44			73			—			73
Income tax benefit		(285	)		—			(285	)		(285	)		—			(285	)
Net earnings from discontinued operations, net of tax	$	329		$	—		$	329		$	358		$	—		$	358
2018
Upstream revenues	$	303		$	—		$	303		$	605		$	—		$	605
Marketing and midstream revenues		24			1,595			1,619			41			3,207			3,248
Total revenues		327			1,595			1,922			646			3,207			3,853
Production expenses		166			—			166			314			—			314
Exploration expenses		6			—			6			18			—			18
Marketing and midstream expenses		11			1,269			1,280			18			2,610			2,628
Depreciation, depletion and amortization		78			106			184			172			244			416
General and administrative expenses		18			31			49			42			58			100
Financing costs, net		(2	)		45			43			(4	)		89			85
Restructuring and transaction costs		9			—			9			9			—			9
Other expenses		39			(5	)		34			109			(7	)		102
Total expenses		325			1,446			1,771			678			2,994			3,672
Earnings (loss) from discontinued operations before income taxes		2			149			151			(32	)		213			181
Income tax expense (benefit)		(20	)		10			(10	)		(51	)		16			(35	)
Net earnings from discontinued operations, net of tax		22			139			161			19			197			216
Net earnings attributable to noncontrolling interests		—			90			90			—			134			134
Net earnings from discontinued operations, attributable to Devon	$	22		$	49		$	71		$	19		$	63		$	82

							Fair Value
							Measurements Using:
	Carrying			Total Fair			Level 1		Level 2
	Amount			Value			Inputs		Inputs
	(Millions)
September 30, 2017 assets (liabilities):
Cash equivalents	$	1,510		$	1,510		$	1,431	$	79
Commodity derivatives	$	43		$	43		$	—	$	43
Commodity derivatives	$	(60	)	$	(60	)	$	—	$	(60	)
Interest rate derivatives	$	1		$	1		$	—	$	1
Interest rate derivatives	$	(62	)	$	(62	)	$	—	$	(62	)
Debt	$	(10,403	)	$	(11,480	)	$	—	$	(11,480	)
Installment payment	$	(243	)	$	(244	)	$	—	$	(244	)
Capital lease obligations	$	(4	)	$	(4	)	$	—	$	(4	)

December 31, 2016 assets (liabilities):
Cash equivalents	$	1,542		$	1,542		$	1,298	$	244
Commodity derivatives	$	10		$	10		$	—	$	10
Commodity derivatives	$	(203	)	$	(203	)	$	—	$	(203	)
Interest rate derivatives	$	1		$	1		$	—	$	1
Interest rate derivatives	$	(41	)	$	(41	)	$	—	$	(41	)
Debt	$	(10,154	)	$	(10,760	)	$	—	$	(10,760	)
Installment payment	$	(473	)	$	(477	)	$	—	$	(477	)
Capital lease obligations	$	(7	)	$	(6	)	$	—	$	(6	)

							Fair Value Measurements Using:
	Carrying			Total Fair			Level 1		Level 2
	Amount			Value			Inputs		Inputs
June 30, 2019 assets (liabilities):
Cash equivalents	$	2,784		$	2,784		$	2,784	$	—
Commodity derivatives	$	127		$	127		$	—	$	127
Commodity derivatives	$	(7	)	$	(7	)	$	—	$	(7	)
Debt	$	(4,294	)	$	(5,311	)	$	—	$	(5,311	)
December 31, 2018 assets (liabilities):
Cash equivalents	$	1,505		$	1,505		$	1,405	$	100
Commodity derivatives	$	674		$	674		$	—	$	674
Commodity derivatives	$	(33	)	$	(33	)	$	—	$	(33	)
Debt	$	(4,454	)	$	(4,494	)	$	—	$	(4,494	)

	U.S.			Canada			EnLink			Eliminations			Total
	(Millions)
Three Months Ended September 30, 2017:
Revenues from external customers	$	1,575		$	358		$	1,223		$	—		$	3,156
Asset dispositions and other	$	1		$	—		$	(1	)	$	—		$	—
Intersegment revenues	$	—		$	—		$	174		$	(174	)	$	—
Depreciation, depletion and amortization	$	195		$	63		$	142		$	—		$	400
Interest expense	$	82		$	17		$	49		$	(15	)	$	133
Asset impairments	$	—		$	—		$	2		$	—		$	2
Earnings before income taxes	$	167		$	85		$	20		$	—		$	272
Income tax expense	$	(5	)	$	28		$	2		$	—		$	25
Net earnings	$	172		$	57		$	18		$	—		$	247
Net earnings attributable to noncontrolling interests	$	—		$	—		$	19		$	—		$	19
Net earnings (loss) attributable to Devon	$	172		$	57		$	(1	)	$	—		$	228
Capital expenditures, including acquisitions	$	560		$	103		$	170		$	—		$	833
Three Months Ended September 30, 2016:
Revenues from external customers	$	1,653		$	305		$	924		$	—		$	2,882
Asset dispositions and other	$	1,351		$	—		$	—		$	—		$	1,351
Intersegment revenues	$	—		$	—		$	180		$	(180	)	$	—
Depreciation, depletion and amortization	$	196		$	72		$	126		$	—		$	394
Interest expense	$	185		$	34		$	49		$	(23	)	$	245
Asset impairments	$	317		$	2		$	—		$	—		$	319
Restructuring and transaction costs	$	(10	)	$	5		$	—		$	—		$	(5	)
Earnings before income taxes	$	1,122		$	37		$	19		$	—		$	1,178
Income tax expense	$	5		$	159		$	7		$	—		$	171
Net earnings (loss)	$	1,117		$	(122	)	$	12		$	—		$	1,007
Net earnings attributable to noncontrolling interests	$	—		$	—		$	14		$	—		$	14
Net earnings (loss) attributable to Devon	$	1,117		$	(122	)	$	(2	)	$	—		$	993
Capital expenditures, including acquisitions	$	277		$	48		$	132		$	—		$	457
Nine Months Ended September 30, 2017:
Revenues from external customers	$	5,547		$	951		$	3,468		$	—		$	9,966
Asset dispositions and other	$	11		$	—		$	(1	)	$	—		$	10
Intersegment revenues	$	—		$	—		$	515		$	(515	)	$	—
Depreciation, depletion and amortization	$	556		$	199		$	407		$	—		$	1,162
Interest expense	$	243		$	48		$	133		$	(42	)	$	382
Asset impairments	$	—		$	—		$	9		$	—		$	9
Earnings before income taxes	$	1,133		$	126		$	69		$	—		$	1,328
Income tax expense	$	—		$	42		$	9		$	—		$	51
Net earnings	$	1,133		$	84		$	60		$	—		$	1,277
Net earnings attributable to noncontrolling interests	$	—		$	—		$	59		$	—		$	59
Net earnings attributable to Devon	$	1,133		$	84		$	1		$	—		$	1,218
Property and equipment, net	$	7,726		$	2,787		$	6,569		$	—		$	17,082
Total assets	$	13,302		$	3,761		$	10,548		$	(52	)	$	27,559
Capital expenditures, including acquisitions	$	1,460		$	275		$	636		$	—		$	2,371
Nine Months Ended September 30, 2016:
Revenues from external customers	$	4,320		$	688		$	2,488		$	—		$	7,496
Asset dispositions and other	$	1,351		$	—		$	—		$	—		$	1,351
Intersegment revenues	$	—		$	—		$	539		$	(539	)	$	—
Depreciation, depletion and amortization	$	763		$	284		$	373		$	—		$	1,420
Interest expense	$	400		$	101		$	140		$	(66	)	$	575
Asset impairments	$	2,810		$	1,168		$	873		$	—		$	4,851
Restructuring and transaction costs	$	245		$	15		$	6		$	—		$	266
Loss before income taxes	$	(2,040	)	$	(1,359	)	$	(853	)	$	—		$	(4,252	)
Income tax expense (benefit)	$	(6	)	$	(223	)	$	1		$	—		$	(228	)
Net loss	$	(2,034	)	$	(1,136	)	$	(854	)	$	—		$	(4,024	)
Net earnings (loss) attributable to noncontrolling interests	$	1		$	—		$	(392	)	$	—		$	(391	)
Net loss attributable to Devon	$	(2,035	)	$	(1,136	)	$	(462	)	$	—		$	(3,633	)
Property and equipment, net	$	7,196		$	2,778		$	6,195		$	—		$	16,169
Total assets	$	12,317		$	4,355		$	10,197		$	(56	)	$	26,813
Capital expenditures, including acquisitions	$	2,454		$	158		$	816		$	—		$	3,428

	Three Months Ended September 30,							Nine Months Ended September 30, ⁽³⁾
	2017		2016		Change			2017		2016			Change
	(Millions, except per share amounts)
Net earnings (loss) attributable to Devon	$	228	$	993		- 77	%	$	1,218	$	(3,633	)		N/M
Net earnings (loss) per diluted share attributable to Devon	$	0.43	$	1.89		- 77	%	$	2.31	$	(7.22	)		N/M
Core earnings (loss) attributable to Devon⁽¹⁾	$	242	$	47		+415	%	$	636	$	(169	)		N/M
Core earnings (loss) per diluted share attributable to Devon ⁽¹⁾	$	0.46	$	0.09		+411	%	$	1.20	$	(0.34	)		N/M
Retained production (MBoe/d)		527		550		- 4	%		542		578			- 6	%
Total production (MBoe/d)		527		577		- 9	%		542		635			- 15	%
Realized price per Boe ⁽²⁾	$	25.67	$	20.98		+22	%	$	25.41	$	17.37			+46	%
Operating cash flow	$	776	$	727		+7	%	$	2,420	$	1,237			+96	%
Capital expenditures, including acquisitions	$	833	$	457		+82	%	$	2,371	$	3,428			- 31	%
Shareholder and noncontrolling interests distributions	$	114	$	109		+5	%	$	342	$	414			- 17	%
Cash and cash equivalents								$	2,781	$	2,385			+17	%
Total debt								$	10,403	$	11,354			- 8	%

	Q2 2019 ⁽⁴⁾		Q1 2019 ⁽⁴⁾			Change
Net earnings (loss) from continuing operations	$	166	$	(346	)		+148	%
Net earnings (loss) from continuing operations per diluted share	$	0.40	$	(0.81	)		+149	%
Core earnings from continuing operations⁽¹⁾	$	97	$	139			- 30	%
Core earnings from continuing operations per diluted share ⁽¹⁾	$	0.23	$	0.32			- 27	%
New Devon production (MBoe/d) ⁽²⁾		321		308			+4	%
Realized price per Boe ⁽³⁾	$	27.24	$	28.58			- 5	%
Operating cash flow from continuing operations	$	488	$	478			+2	%
Capitalized expenditures, including acquisitions	$	530	$	481			+10	%
Cash and cash equivalents	$	3,470	$	1,327			+161	%
Total debt - continuing operations	$	4,294	$	4,292			+0	%

	Three Months Ended September 30,							Nine Months Ended September 30,
	2017 ⁽¹⁾		2016 ⁽¹⁾		Change			2017 ⁽¹⁾		2016 ⁽¹⁾		Change
Oil (per Bbl)
U.S.	$	47.12	$	42.51		+11	%	$	47.84	$	36.89		+30	%
Canada	$	35.02	$	27.46		+28	%	$	32.77	$	22.26		+47	%
Total	$	45.41	$	40.12		+13	%	$	45.83	$	34.78		+32	%
Bitumen (per Bbl)
Canada	$	31.75	$	23.00		+38	%	$	28.49	$	17.77		+60	%
Gas (per Mcf)
U.S.	$	2.45	$	2.24		+10	%	$	2.54	$	1.70		+50	%
NGLs (per Bbl)
U.S.	$	15.15	$	9.80		+55	%	$	14.62	$	8.84		+65	%
Combined (per Boe)
U.S.	$	23.85	$	20.26		+18	%	$	24.44	$	17.16		+42	%
Canada	$	31.59	$	23.23		+36	%	$	28.50	$	18.15		+57	%
Total	$	25.67	$	20.98		+22	%	$	25.41	$	17.37		+46	%