Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated ~~filer”~~filer,” “smaller reporting company,” and ~~“smaller reporting~~“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 ☒

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June ~~30, 2016~~28, 2019 was approximately ~~$18.9~~$11.6 billion, based upon the closing price of ~~$36.25~~$28.52 per share as reported by the New York Stock Exchange on such date. On February ~~8, 2017, 524.6~~5, 2020, 382.9 million shares of common stock were outstanding.

Portions of Registrant’s definitive Proxy ~~statement for the 2017~~Statement relating to Registrant’s 2020 annual meeting of stockholders –have been incorporated by reference in Part III

Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” ~~“Devon”~~“Devon,” the “Company” and ~~the “Company”~~“Registrant” 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 Annual Report on Form 10-K:

“~~2009 Plan” means the Devon Energy Corporation 2009 Long-Term Incentive Plan, as amended and restated.~~

“2015 Plan” means the Devon Energy Corporation 2015 Long-Term Incentive Plan.

“2017 Plan” means the Devon Energy Corporation 2017 Long-Term Incentive Plan.

“ASR” means 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. All dollar amounts associated with Canada are in U.S. dollars, unless stated otherwise.

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

~~“Crosstex” means Crosstex Energy, Inc. together with Crosstex Energy L.P.~~L.L.C.

“~~E2” means E2 Energy Services, LLC together with E2 Appalachian Compression, LLC.~~

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

“Federal Funds Rate” means the interest rate at which depository institutions lend balances at the Federal Reserve to other depository institutions overnight.

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

~~“GeoSouthern” means GeoSouthern Energy Corporation.~~EnLink, and, unless the context otherwise indicates, EnLink Midstream Manager, LLC, the managing member of EnLink Midstream, LLC.

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

“~~PHMSA” means United States Department of Transportation Pipeline and Hazardous Materials Safety Administration.~~

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

“Standardized measure” means the present value of after-tax future net revenues discounted at 10% per annum.

“~~Tall Oak”~~Tax Reform Legislation” means ~~Tall Oak Midstream, LLC.~~Tax Cuts and Jobs Act.

“~~VEX”~~VIE” means ~~Victoria Express Pipeline and related truck terminal and storage assets.~~variable interest entity.

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.

A Delaware corporation formed in 1971 and publicly held since 1988, Devon (NYSE: DVN) is an independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Our operations are concentrated in various ~~North American~~ onshore areas in the U.S. In June 2019, we completed the sale of substantially all of our oil and gas assets and operations in Canada. ~~Additionally,~~In December 2019, we ~~control EnLink, a publicly–traded MLP with an integrated midstream business with significant size and scale in key operating regions in~~announced the ~~U.S. For additional information regarding~~sale of our ~~control of, and ownership interest in, EnLink and its indirect general partner, the General Partner, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.~~Barnett Shale assets.

~~Devon has been publicly held since 1988, and our common stock is listed on the NYSE under the ticker symbol DVN.~~ Our principal and administrative offices are located at 333 West Sheridan, Oklahoma City, OK 73102-5015 (telephone 405-235-3611). As of December 31, ~~2016,~~2019, Devon and its consolidated subsidiaries had approximately ~~5,000 employees, of which approximately 1,500 employees are employed by EnLink (through its subsidiaries).~~1,800 employees.

Devon files or furnishes annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments to these reports, with the SEC. Through our website, www.devonenergy.com, we make available electronic copies of the documents we file or furnish to the SEC, the charters of the committees of our Board of Directors and other documents related to our corporate governance. The corporate governance documents available on our website include our Code of Ethics for Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, and any amendments to and waivers from any provision of that Code will also be posted on our website. Access to these electronic filings is available free of charge as soon as reasonably practicable after filing or furnishing them to the SEC. Printed copies of our committee charters or other governance documents and filings can be requested by writing to our corporate secretary at the address on the cover of this report.

In addition, the public may read and copy any materials Devon files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington D.C. 20549. The public may also obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov.

~~Devon~~Our business strategy is ~~committed to~~focused on delivering ~~consistent top-quartile~~a consistently competitive shareholder return among ~~its~~our peer ~~group through~~group. Because the business of exploring for, developing and producing oil and natural gas is capital intensive, delivering sustainable, capital efficient cash flow growth is a key tenant to our success. While our cash flow is highly ~~engaged culture focused~~dependent on ~~innovation, safety, operational excellence, environmental stewardship~~volatile and ~~social responsibility. We also maintain a strong commitment to financial strength and flexibility through~~uncertain commodity prices, we pursue our strategy throughout all commodity price cycles ~~as reflected in the company’s investment grade credit ratings.~~with four fundamental principles.

Proven and responsible operator – We ~~focus~~operate our business ~~on building value per share by:~~

Our formidable portfolio of exploration and production assets and operations provides stable, environmentally responsible production and a platform for future growth. For Devon, 2016 was a transformational year as we executed our strategy. We successfully reshaped our asset portfolio with non-core divestitures and the continued development of our world-class operations in the STACK and Delaware Basin. These assets provide us with a sustainable, multi-decade growth platform that continues to improve in response to our successful drilling programs. During 2016, we delivered the best well productivity in Devon’s 45-year history and continued a four-year streak of increasing Devon’s initial 90-day production rates. Devon has more than doubled its onshore North American oil

~~production since 2011 and has a deep inventory of development opportunities to deliver future oil growth. Adding to these operational highlights, we had several key actions in 2016 as discussed below.~~

As we enter 2017 and continue to look toward the future, we will approach the current environment in a manner that drives efficiencies across our portfolio. We will manage activity levels within our cash flow by achieving additional operating cost savings and increasing capital productivity, while remaining committed to allocating capital in a disciplined manner that is driven by both value and return. We believe we capture the full value of our assets and improve returns through maximizing our base production and optimizing our capital program. The activities that support this strategy include minimizing controllable downtime, enhancing well productivity, ensuring disciplined project execution, performing premier technical work, focusing on developmental drilling and reducing our operating and capital costs.

~~EnLink focuses on providing gathering, transmission, processing, storage, fractionation and marketing to upstream~~independent oil and natural gas ~~producers, including Devon.~~ exploration and production company, the work our employees do every day contributes to the local, national and global economies. We produce a valuable commodity that is fundamental to society, and we endeavor to do so in a safe, environmentally responsible and ethical way, while striving to deliver strong returns to our shareholders. We have an ongoing commitment to transparency in reporting our environmental, social and governance performance. See our Sustainability Report published on our company website for performance highlights and additional information. Information contained in our Sustainability Report is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

~~EnLink connects~~A premier, sustainable portfolio of assets – As discussed in the ~~wells~~next section of this Annual Report, we own a portfolio of assets located in the United States. We strive to own premier assets capable of generating cash flows in excess of our capital and operating requirements, as well as competitive rates of return. We also desire to own a portfolio of assets that can provide a production growth platform extending many years into the future. Due to the strength of oil prices relative to natural gas, ~~producers~~we have been positioning our portfolio to be more heavily weighted to U.S. oil assets in its market areas to its gathering systems, processes natural gas for the removal of NGLs, fractionates NGLs into purity products and markets those products for a fee, transports natural gas and ultimately provides natural gasrecent years.

During 2019, we completed our transition to a ~~variety~~U.S. oil company. We sold our Canadian business, generating $2.6 billion in proceeds, and announced the sale of ~~markets. Furthermore, EnLink purchases natural gas~~our Barnett Shale assets for approximately $770 million, before purchase price adjustments. As a result of these divestitures, we expect our oil production growth, price realizations and field-level margins will all improve, as we sharpen our focus on four U.S. oil plays located in the Delaware Basin, STACK, Powder River Basin and Eagle Ford.

Superior execution – As we pursue cash flow growth, we continually work to optimize the efficiency of our capital programs and production operations, with an underlying objective of reducing absolute and per unit costs and enhancing our returns. We also strive to leverage our culture of health, safety and environmental stewardship in all aspects of our business.

Throughout 2019, we continued to achieve efficiency gains in various aspects of our business. Our initial production rates from ~~natural gas~~new wells continued to improve in our four U.S. oil plays and have exceeded the average of the top 40 U.S. producers since 2015 by more than 40%. We continued to improve cycle times, incorporate production optimization strategies and other ~~supply sources~~cost reduction initiatives, driving down breakeven costs across our portfolio of assets.

As we focus on a more streamlined portfolio of U.S. oil assets, we are aggressively pursuing an improved cost structure to further expand margins. We have realized annualized cost savings by reducing well costs, production expense, financing costs and ~~sells that natural gas to utilities, industrial consumers, other marketers and pipelines.~~G&A costs.

EnLink’s primary business objective is to provide cash flow stability, while growing through prudent and profitable investments. EnLink accomplishes its objectives through long-term, fee-based contracts and maintaining a strong financial position through a conservative and balanced capital structure highlighted by its investment grade status. EnLink has consistently demonstrated expertise within the MLP space and continues to employ a proven business model that includes growing, expanding and executing on its strategy within top basins where Devon and other successful upstream producers operate.

Financial strength and flexibility – Commodity prices are uncertain and volatile, so we strive to maintain a strong balance sheet, as well as adequate liquidity and financial flexibility, in order to operate competitively in all commodity price cycles. Our capital allocation decisions are made with attention to these financial stewardship principles, as well as the priorities of funding our core operations, protecting our investment-grade credit ratings, and paying and growing our shareholder dividend.

During 2019, we reduced our consolidated debt by $1.7 billion, primarily from proceeds from our divestitures. We also raised our quarterly dividend 12.5% and repurchased 69 million shares of common stock under our share repurchase program.

As a result of our divestment of substantially all of our oil and gas assets and operations in Canada, as well as the recently announced divestiture of our Barnett Shale assets, amounts associated with these assets are presented as discontinued operations. Therefore, financial and operational data, such as reserves, production, wells and acreage, provided in this document exclude amounts related to our Canadian and Barnett Shale assets unless otherwise noted. Included within the amounts presented as discontinued operations associated with the Barnett Shale are properties divested in previous reporting periods located primarily in Johnson and Wise counties, Texas. For additional information, please see Note 2in “Item 8. Financial Statements and Supplementary Data” of this report.

~~The following table outlines a~~Key summary ~~of key~~ data infrom each of our ~~operating~~ areas of operation as of and for the year ended December 31, ~~2016. Notes 21 and 22 to~~2019 are detailed in the ~~financial statements included in “Item 8. Financial Statements and Supplementary Data”~~map below.

~~Led by results from the STACK,~~ Delaware Basin and Eagle Ford, Devon achieved the best drilling results in our 45-year history. Our initial 90-day production rates in 2016 increased for the fourth consecutive year, advancing more than 300% from 2012 levels. These productivity improvements were driven by activity focused in top resource plays, improved subsurface reservoir characterization, leading-edge completion designs and improvements in lateral placement. Excluding the effects of divestitures, our drilling results increased our proved reserves in 2016 on a retained asset basis by 3%. The most significant reserves growth came from our U.S. operations, where we replaced approximately 175% of our 2016 production.

~~Barnett Shale~~ – This is our largest property in terms of production and proved reserves. Our leases are located primarily in Denton, Johnson, Parker, Tarrant and Wise counties in north Texas. Since acquiring a substantial position in this field in 2002, we continue to introduce technology and new innovations to optimize production operations and have transformed this asset into one of the top producing gas fields in North America. Given the sustained low gas price environment, we continue to focus on enhancing existing well performance through re-fracturing, artificial lift and line pressure reduction projects. In 2017, we plan on minimal development activity, with planned capital investment of up to $50 million to optimize base production and further de-risk future development activity.

~~Delaware Basin~~ – The Delaware Basin is ~~one of~~ Devon’s ~~top-two franchise assets and continues to offer~~most active program in the portfolio. Through capital-efficient growth, it offers exploration and low-risk development opportunities from many geologic reservoirs and play types, including the oil-rich Bone Spring, ~~Delaware,~~ Wolfcamp and Leonard formations. ~~These~~With a significant inventory of oil and liquids-rich drilling opportunities ~~across our acreage in the Delaware Basin will offer~~that have multi-zone development potential, Devon has a robust platform to deliver high-margin growth for many years to come. At December 31, ~~2016,~~2019, we had ~~three~~eight operated ~~rigs.~~rigs developing this asset. In ~~2017,~~2020, we plan to invest approximately ~~$700 million~~$1.0 billion of capital in the Delaware Basin, ~~and steadily ramp up activity with as many as 10 operated rigs running by~~making it the ~~end of the year, primarily focused on the Bone Spring, Leonard and Wolfcamp formations.~~

~~Eagle Ford~~ ~~– We acquired our position~~top-funded asset in the Eagle Ford in 2014 from GeoSouthern and have approximately 66,000 net acres located in DeWitt and Lavaca counties in south Texas. Since acquiring these assets, we have delivered tremendous results by producing 94 million oil-equivalent barrels. Our excellent results are driven by our development in DeWitt County, located in the economic core of the play. With the highest margins in our portfolio, our Eagle Ford assets generated approximately $550 million of direct cash margin in 2016. In 2017, we plan approximately $175 million of capital investment.

~~Heavy Oil~~ – Our operations in Canada are focused on our heavy oil assets in Alberta, Canada. Our most significant Canadian operation is our Jackfish complex, an industry-leading thermal heavy oil operation in the non-conventional oil sands of east central Alberta. We employ a recovery method known as steam-assisted gravity drainage at Jackfish. The Jackfish operation consists of three facilities. In 2014, we brought the third phase of Jackfish into operation, which ramped up to facility capacity bythe third quarter of 2015. At $55/Bbl WTI, direct cash margin from our Heavy Oil assets has the potential to approach $800 million in 2017. We expect Jackfish to maintain a reasonably flat production profile for greater than 20 years requiring only approximately $200 million of annual maintenance capital based on current economic conditions.

Our Pike oil sands acreage is situated directly to the southeast of our Jackfish acreage in east central Alberta and has similar reservoir characteristics to Jackfish. The Pike leasehold is currently undeveloped and has no proved reserves or production as of December 31, 2016. With our 50% partner, we continue to evaluate our development timeline for Pike.

In addition to Jackfish and Pike, we hold acreage and own producing assets in the Bonnyville region, located to the south and east of Jackfish in eastern Alberta. Bonnyville is a low-risk, high margin oil development play that produces heavy oil by conventional means, without the need for steam injection.

~~In 2017, we plan approximately $300 million of capital investment in our Canadian Heavy Oil business.~~

~~Rockies Oil~~ – Our acreage in the Rockies includes approximately 470,000 net surface acres, focused on emerging oil opportunities in the Powder River Basin and the Wind River Basin. Recent drilling success in these formations has expanded our drilling inventory, and we expect further growth as we continue to de-risk this emerging light-oil opportunity. As of December 31, 2016, we had one operated rig targeting the Parkman, Teapot and Turner formations within the Cretaceous oil objectives of the Powder River Basin. In 2017, we plan approximately $175 million of capital investment.portfolio.

STACK – The STACK development, located primarily in Oklahoma’s Canadian, Kingfisher and Blaine counties, is one of Devon’s top-two franchise assets. Devon has two primary fields in the area: the Woodford Shale and the Meramec. In 2016, we increased our acreage in these positions by acquiring 80,000 net acres in the STACK. Our acreage in the play now includes approximately 430,000 net acres.provides long-term optionality through its significant inventory. Our STACK position is ~~the largest and~~ one of the ~~best~~largest in the industry, providing visible long-term ~~growth. Recent well-completion design enhancements have resulted in greater productivity and improved economics. Early~~production. In December 2019, we announced an agreement with Dow to jointly develop a portion of our STACK acreage. Dow will fund approximately 65% of the partnership capital requirements through a drilling ~~activity~~carry of $100 million over the next four years. In 2020, we plan approximately $75 million of capital investment.

Powder River Basin – This asset is focused on emerging oil opportunities in the ~~Meramec play~~Powder River Basin. Recent drilling success in this basin has ~~produced record setting results across~~expanded our ~~core~~drilling inventory, and we expect further growth as we accelerate activity and continue to de-risk this emerging light-oil opportunity. As of December 31, 2019, we had three operated rigs targeting the Turner, Parkman, Teapot and Niobrara formations in northern Converse County, Wyoming of the Powder River Basin. In 2020, we plan approximately $350 million of capital investment.

Eagle Ford – We acquired our position in the Eagle Ford in 2014. Since acquiring these assets, we have delivered tremendous results driven by our development in DeWitt County, Texas located in the economic core of the play. Our Eagle Ford production is leveraged to oil and ~~liquids window. At December 31, 2016, we had six operated rigs with drilling focused~~has low-cost access to premium Gulf Coast pricing, providing for solid operating margins. Our Eagle Ford assets generated substantial cash flow in ~~the Meramec formation.~~2019. In ~~2017,~~2020, we plan approximately ~~$750~~$300 million of capital ~~investment and expect to continue to increase drilling activity throughout 2017 and run up to 10 operated rigs by the end of the year.~~investment.

For estimates of our proved developed and proved undeveloped reserves and the discussion of the contribution by each property, see Note 22 in “Item 8. Financial Statements and Supplementary Data” of this report.

Proved oil and gas reserves are those quantities of oil, gas and NGLs which ~~by analysis of geoscience and engineering data,~~ can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. To be considered proved, oil and gas reserves must be economically producible before contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Also, the project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.For estimates of our proved developed and proved undeveloped reserves and the discussion of the contribution by each property, see Note 21 in “Item 8. Financial Statements and Supplementary Data” of this report.

The process of estimating oil, gas and NGL reserves is complex and requires significant judgment, as discussed in “Item 1A. Risk Factors” of this report. As a result, we have developed internal policies for estimating and recording ~~reserves. Such policies require proved~~ reserves ~~to be~~ in compliance with ~~the~~applicable SEC definitions and guidance. Our policies assign responsibilities for compliance in reserves bookings to our Reserve Evaluation Group

~~(the~~ (the “Group”). ~~These same policies also require that reserve estimates be made by professionally qualified reserves estimators, as defined by the Society of Petroleum Engineers’ standards.~~

The Group, which is led by Devon’s Director of Reserves and Economics, is responsible for the internal review and certification of reserves estimates. We ensure the Director and key members of the Group have appropriate technical qualifications to oversee the preparation of reserves ~~estimates. The Group reports to~~estimates and ~~is managed through our finance department. No portion~~are independent of the ~~Group’s compensation is directly dependent on the quantity of reserves booked.~~

operating groups. The Director of the Group has ~~approximately~~over 30 years of industry experience, with positions of increasing responsibility for the estimation and evaluation of reserves. He has been employed by Devon for the past 16 years, including the past nine in his current position. His further professional qualifications include a degree in ~~petroleum~~ engineering and is a registered professional engineer, member of the Society of Petroleum Engineers and experience in reserves estimation for projects in the U.S. (both onshore and offshore), as well as in Canada, Asia, the Middle East and South America.

~~Throughout the year, the Group performs internal reserves audits of each operating division’s reserves.~~engineer. The Group also oversees audits and reserves estimates performed by qualified third-party petroleum consulting firms. During ~~2016,~~2019, we engaged ~~two such firms to audit 89% of our proved reserves in accordance with generally accepted petroleum engineering and evaluation methods and procedures.~~ LaRoche Petroleum Consultants, Ltd. ~~audited 86%~~to audit approximately 85% of our ~~2016 U.S. reserves, and Deloitte LLP audited 96% of our Canadian~~proved reserves.

~~In addition to conducting these internal and external reserves audits,~~ Additionally, we ~~also~~ have a Reserves Committee that provides additional oversight of our reserves process. The committee consists of ~~three~~five independent members of our Board of ~~Directors. This committee provides additional oversight of our reserves estimation and certification process. The members of our Reserves Committee also have educational~~Directors with education or business backgrounds ~~in geology or petroleum engineering, as well as experience~~ relevant to the reserves estimation process. ~~The Reserves Committee meets a minimum~~

The following tables present production, price and cost information for each significant ~~field, country and continent.~~field.

The following table summarizes our development and exploratory drilling ~~results.~~results in the U.S.

~~The following table presents the~~As of December 31, 2019, there were 132 gross and 95.3 net wells that ~~were~~have been spud and are in ~~progress~~the process of drilling, completing or waiting on ~~December 31, 2016. As~~completion. Gross wells are the sum of ~~February 1, 2017, these~~all wells ~~were still~~ in ~~progress.~~which we own a working interest. Net wells are gross wells multiplied by our fractional working interests in each well.

The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs field personnel and performs other functions. We are the operator of approximately ~~15,200~~3,955 gross wells. As operator, we receive reimbursement for direct expenses incurred to perform our duties, as well as monthly per-well producing, drilling, and ~~drilling~~construction overhead reimbursement at rates customarily charged in the respective areas. In presenting our financial data, we record the monthly overhead reimbursements as a reduction of G&A, which is a common industry practice.

The following table sets forth our developed and undeveloped lease and mineral acreage as of December 31, ~~2016.~~2019. Of our ~~4.6~~1.8 million net acres, approximately ~~2.4~~1.1 million acres are held by ~~production.~~production and approximately 20% are located on federal lands. The acreage in the table includes ~~0.3 million, 0.2 million and~~approximately 0.1 million net acres subject to leases that are scheduled to expire during ~~2017, 2018~~2020, 2021 and ~~2019, respectively.~~2022. As of December 31, ~~2016,~~2019, there were no proved undeveloped reserves associated with our expiring acreage. Of the ~~0.6~~0.1 million net acres set to expire by December 31, ~~2019,~~2022, we ~~will perform~~anticipate performing operational and administrative actions to continue the lease terms for portions of the acreage that we intend to further assess. However, we do expect to allow a portion of the acreage to expire in the normal course of business. In ~~2016,~~2019, we allowed approximately ~~0.3~~0.1 million acres to ~~expire, which is consistent with expirations in prior years.~~

Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for taxes not yet due and, in some instances, other encumbrances. We believe that such burdens do not materially detract from the value of properties or from the respective interests therein or materially interfere with their use in the operation of the business.

As is customary in the industry, ~~other than~~ a preliminary title investigation, typically consisting of a review of local title records, ~~little investigation of record title~~ is made at the time of acquisitions of undeveloped properties. ~~Title~~More thorough title investigations, which generally include a review of title records and the preparation of title opinions ofby outside legal counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.

~~EnLink represents the primary component of our midstream operations. EnLink’s assets are comprised of systems and other assets located in four primary regions:~~

The spot markets for oil, gas and NGLs are subject to volatility as supply and demand factors fluctuate. As detailed below, we sell our production under both long-term (one year or more) and short-term (less than one year) agreements at prices negotiated with third parties. Regardless of the term of the contract, the vast majority of our production is sold at variable, or market-sensitive, prices.

Additionally, we may enter into financial hedging arrangements or fixed-price contracts associated with a portion of our oil, gas and NGL production. These activities are intended to support targeted price levels and to manage our exposure to price fluctuations. See Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report for further information.

As of January ~~2017,~~2020, our production was sold under the following contract terms.

A portion of our production is sold under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. As of December 31, ~~2016,~~2019, we were committed to deliver the following fixed quantities of production.

We expect to fulfill our delivery commitments primarily with production from our proved developed reserves. Moreover, our proved reserves have generally been sufficient to satisfy our delivery commitments during the three most recent years, and we expect such reserves will continue to be the primary means of fulfilling our future commitments. However, where our proved reserves are not sufficient to satisfy our delivery commitments, we can and may use spot market purchases to satisfy the commitments.

During ~~2016, 2015~~2019 and ~~2014,~~2017, no purchaser accounted for over 10% of our consolidated sales revenue.

During 2018, we had one purchaser that accounted for approximately 11% of our consolidated sales revenue.

Our industry is subject to a wide range of regulations. Laws, rules, regulations, taxes, fees and other policy implementation actions affecting our industry have been pervasive and are under constant review for amendment or

expansion. Numerous government agencies have issued extensive regulations which are binding on our industry and its individual members, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business and consequently affect profitability. Because public policy changes are commonplace, and existing laws and regulations are frequently amended, we are unable to predict the future cost or impact of compliance. However, we do not expect that any of these laws and regulations will affect our operations materially differently than they would affect other companies with similar operations, size and financial strength. The following are significant areas of government control and regulation affecting our operations.

Our operations are subject to federal, ~~tribal,~~ state ~~provincial~~ and local laws and regulations. These laws and regulations relate to matters that include:

Our operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units; the number of wells that may be drilled in a unit; the rate of production allowable from oil and gas wells; and the unitization or pooling of oil and gas properties. In the U.S., some states allow the forced pooling or ~~integration~~unitization of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.

Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and administered by the BLM or Bureau of Indian Affairs of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has, ~~been particularly active in recent years in evaluating~~from time to time, evaluated and, in some cases, ~~promulgating~~promulgated new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. In addition, permitting activities on federal lands ~~are~~can sometimes be subject to ~~frequent~~ delays.

The royalty calculation in Canada is a significant factor in the profitability of Canadian oil and gas production. Oil sands crown royalties are determined by government regulations and are generally calculated as a percentage of the value of the gross production, net of allowed deductions. The royalty percentage is determined on a sliding-scale based on crown posted prices. For pre-payout oil sands projects, the regulations prescribe lower royalty rates for oil sands projects until allowable capital costs have been recovered. In early 2016, the Alberta government adopted the recommendation of its Royalty Review Panel. The new royalty framework preserves the existing royalty structure and rates for oil sands. For conventional oil and gas royalty calculations for wells drilled after January 1, 2017 in the Modernized Royalty Framework, the calculation is based on a percentage of production net of allowed deductions.

~~Any oil or gas export requires an exporter to obtain export authorizations from Canada’s National Energy Board.~~

We strive to conduct our operations in a socially and environmentally responsible manner, which includes compliance with applicable law. We are subject to many federal, state, ~~provincial, tribal~~ and local laws and regulations concerning occupational safety and health as well as the discharge of materials into, and the protection of, the ~~environment.~~environment and natural resources. Environmental laws and regulations relate to:

Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, administrative, civil or criminal fines or penalties or injunctions limiting our operations in affected areas. Moreover, multiple environmental laws provide for citizen suits, which can allow environmental organizations to ~~act in the place of the government and~~ sue operators for alleged violations of environmental law. ~~We consider~~Environmental organizations also can assert legal and administrative challenges to certain actions of oil and gas regulators, such as the ~~costs of~~BLM, for allegedly failing to comply with environmental laws, which can result in delays in obtaining permits or other necessary authorizations. Environmental protection and health and safety ~~and health~~ compliance are necessary, manageable parts of our business. We have been able to plan for and comply with environmental, safety and health initiatives without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and may continue to increase. ~~We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.~~

Our business and operations, and our industry in general, are subject to a variety of risks. The risks described below may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. If any of the following risks should occur, our business, financial condition, results of operations and liquidity could be materially and adversely impacted. As a result, holders of our securities could lose part or all of their investment in Devon.

Our financial condition, results of operations and the value of our properties are highly dependent on the general supply and demand for oil, gas and NGLs, which impact the prices we ultimately realize on our sales of these commodities. Historically, market prices and our realized prices have been volatile. For example, ~~during~~over the ~~period from January 1, 2014 to December 31, 2016,~~last five years, NYMEX WTI oil and NYMEX Henry Hub prices ranged from ~~a high~~highs of ~~$107.26~~over $75 per Bbl ~~to a low of $26.21 per Bbl. Average daily prices for NYMEX Henry Hub gas ranged from a high of $6.15~~and $4.80 per MMBtu, respectively, to ~~a low~~lows of ~~$1.64~~under $27 per Bbl and $1.70 per MMBtu, ~~during the same period.~~respectively. Such volatility is likely to continue in the future due to numerous factors beyond our control, including, but not limited to:

In the second half of 2014, global energy commodity prices began a rapid and significant decline, which continued through 2015 and into 2016. This commodity price decline adversely affected our business and results of operations and led to substantial impairments to our oil and gas properties during 2015 and 2016. A sustained weakness or further deterioration in commodity prices could materially and adversely impact our business by resulting in, or exacerbating, the following effects:

Estimates of Oil, Gas and NGL Reserves Are Uncertain and May Be Subject to Revision

The process of estimating oil, gas and NGL reserves is complex and requires significant judgment in the evaluation of available geological, engineering and economic data for each reservoir, particularly for new discoveries. Because of the high degree of judgment involved, different reserve engineers may develop different estimates of reserve quantities and related revenue based on the same data. In addition, the reserve estimates for a

given reservoir may change substantially over time as a result of several factors, including additional development and appraisal activity, the viability of production under varying economic conditions, including commodity price declines, and variations in production levels and associated costs. Consequently, material revisions to existing ~~reserve~~reserves estimates may occur as a result of changes in any of these factors. Such revisions to proved reserves could have ~~a material~~an adverse effect on our financial condition and the value of our properties, as well as the estimates of our future net revenue and profitability. Our policies and internal controls related to estimating and recording reserves are included in “Items 1 and 2. Business and Properties” of this report.

Discoveries or Acquisitions of Reserves Are Needed to Avoid a Material Decline in Reserves and Production

The production rates from oil and gas properties generally decline as reserves are depleted, while related per unit production costs generally increase due to decreasing reservoir pressures and other factors. Moreover, our current development activity is focused on unconventional oil and gas assets, which generally have significantly higher decline rates as compared to conventional assets. Therefore, our estimated proved reserves and future oil, gas and NGL production will decline materially as reserves are produced unless we conduct successful exploration and development activities, such as identifying additional producing zones in existing wells, utilizing secondary or tertiary recovery techniques or acquiring additional properties containing proved reserves. Consequently, our future oil, gas and NGL production and related per unit production costs are highly dependent upon our level of success in finding or acquiring additional reserves.

Our ~~exploration and development~~operating activities are subject to numerous costs and risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. Drilling for oil, gas and NGLs can be unprofitable, not only from dry holes, but from productive wells that do not return a profit because of insufficient revenue from production or high costs. Substantial costs are required to locate, acquire and develop oil and gas properties, and we are often uncertain as to the amount and timing of those costs. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Declines in commodity prices and overruns in budgeted expenditures are common risks that can make a particular project uneconomic or less economic than forecasted. While both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. In addition, our oil and gas properties can become damaged, our ~~drilling~~ operations may be curtailed, delayed or canceled and the costs of such operations may increase as a result of a variety of factors, including, but not limited to:

The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, ~~and~~as well as significant liabilities. Moreover, certain of these events ~~particularly equipment failures or accidents,~~ could result in environmental pollution and impact to third parties, including persons living in proximity to our operations, our employees and employees of our contractors, leading to possible injuries, death or significant damage to property ~~damage.~~and natural resources. For example, we have from time to time experienced well-control events that have resulted in various remediation and clean-up costs and certain of the other impacts described above.

We Are Subject to Extensive Governmental Regulation, Which Can Change and Could Adversely Impact Our Business

Our operations are subject to extensive federal, state, ~~provincial, tribal,~~ local and other laws, rules and regulations, including with respect to environmental matters, worker health and safety, wildlife conservation, the gathering and transportation of oil, gas and NGLs, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well ~~operations.~~operations and decommissioning obligations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. In addition, we may be required to make large expenditures to comply with applicable governmental laws, rules, regulations, permits or orders. For example, certain regulations require the plugging and abandonment of wells and removal of production facilities by current and former operators, ~~which~~including corporate successors of former operators. These requirements may result in significant costs associated with the removal of tangible equipment and other restorative ~~actions at the end of operations.~~actions.

In addition, changes in public policy have affected, and ~~at times~~ in the future could further affect, our operations. Regulatory and public policy developments could, among other things, restrict production levels, impose price controls, change environmental protection requirements and increase taxes, royalties and other amounts payable to governments or governmental agencies. Our operating and

other compliance costs could increase further if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. In addition, changes in public policy may indirectly impact our operations by, among other things, increasing the cost of supplies and equipment and fostering general economic uncertainty. For example, changes in U.S. trade relations, particularly the imposition of tariffs by the U.S. and China, may increase the cost of materials we or our vendors use, thereby increasing our operating expense. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity, particularly changes related to hydraulic fracturing, ~~pipeline safety,~~environmental matters more generally, seismic activity and income taxes, ~~and climate change,~~ as discussed below.

Hydraulic Fracturing – ~~The EPA and other~~In recent years, various federal agencies ~~including~~have asserted regulatory authority over certain aspects of the ~~BLM, have made proposals that would subject~~ hydraulic fracturing ~~to further regulation and could restrict the practice of hydraulic fracturing.~~process. For example, the EPA has issued ~~final~~ regulations under the federal Clean Air Act establishing performance standards for oil and gas activities, including standards for the capture of air emissions released during hydraulic fracturing, and it finalized in ~~June~~ 2016 regulations that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. The EPA also released a ~~study~~report in ~~December~~ 2016 finding that certain aspects of hydraulic fracturing, such as water withdrawals and wastewater management practices, could result in impacts to water ~~resources, although the report did not identify a direct link between hydraulic fracturing and impacts to groundwater~~ resources. The BLM ~~and~~previously finalized regulations to regulate hydraulic fracturing on federal lands but subsequently issued a repeal of those regulations in 2017. Moreover, several states in which we operate have ~~already~~ adopted, ~~and more states are considering adopting~~or stated intentions to adopt, laws ~~and/~~or regulations that ~~require~~mandate further restrictions on hydraulic fracturing, such as requiring disclosure of chemicals used in hydraulic fracturing, ~~and impose~~imposing more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing ~~operations.~~operations and establishing standards for the capture of air emissions released during hydraulic fracturing. In addition ~~some states and municipalities have significantly limited~~to state laws, local land use restrictions, such as city ordinances, may restrict drilling ~~activities and/~~in general or hydraulic fracturing ~~or are considering doing so.~~in particular.

Beyond these regulatory efforts, various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed implementing even further restrictions on hydraulic fracturing, including prohibiting the technology outright. For example, certain candidates running to be elected President of the United States in 2020 have pledged to impose a ban on hydraulic fracturing. It is possible that any such restrictions may particularly target industry activity on federal lands, which could adversely impact our operations in the Delaware and Powder River Basins, as well as other areas where we operate under federal leases. As of December 31, 2019, approximately 20% of our total leasehold resides on federal lands, and approximately 40% and 60% of our leasehold in the Delaware and Powder River Basins, respectively, resides on federal lands. Although it is not possible at this time to predict the ~~final~~ outcome of these or other proposals, any new ~~federal, state or local~~ restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could potentially result in increased compliance costs, delays or cessation in development or other restrictions on our operations.

~~Pipeline Safety~~Environmental Laws Generally – ~~The pipeline assets in which~~In addition to regulatory efforts focused on hydraulic fracturing, we ~~own interests, through EnLink or otherwise,~~ are subject to ~~stringent~~various other federal, state and ~~complex~~local laws and regulations ~~related~~relating to ~~pipeline safety~~discharge of materials into, and integrity management. The PHMSA has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas.” Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. For example, in March 2016 PHMSA proposed new rules for gas pipelines that extend pipeline safety programs beyond high consequence areas to newly proposed “moderate consequence areas” and would also impose more rigorous testing and reporting requirements on such pipelines. More recently, in January 2017, PHMSA finalized regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection and repairs), regardlessprotection of, the ~~pipeline’s proximity to a high consequence area. The final rule also imposes new reporting requirements~~environment. These laws and regulations may, among other things, impose liability on us for ~~certain unregulated pipelines, including all hazardous liquid gathering lines. At this time, we cannot predict~~ the cost of ~~such requirements, but they could be significant. Moreover, violations of pipeline safety~~remediating pollution that results from our operations. Environmental laws may impose strict, joint and several liability, and failure to comply with environmental laws and regulations can result in the imposition of administrative, civil or criminal fines and penalties, as well as injunctions limiting operations in affected areas. Any future environmental costs of fulfilling our commitments to the environment are uncertain and will be governed by several factors, including future changes to regulatory requirements. Any such changes could have a significant ~~penalties.~~impact on our operations and profitability.

Seismic Activity – ~~Recent earthquakes~~Earthquakes in northern and central Oklahoma and elsewhere have prompted concerns about seismic activity and possible relationships with the ~~energy~~oil and gas industry. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation or other requirements that could lead to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. In addition, we are currently defending against certain third-party lawsuits and could be subject to additional claims, seeking alleged property damages or other remedies as a result of alleged induced seismic activity in our areas of operation.

~~Potential~~ Changes to Tax Laws – We are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions, and our operating cash flow is sensitive to the amount of income taxes we must pay. In the jurisdictions in which we operate, income taxes are assessed on our earnings after consideration of all allowable deductions and credits. Changes in the types of earnings that are subject to income tax, the types of costs that are considered allowable deductions or the rates assessed on our taxable earnings would all impact our income taxes and resulting operating cash flow. ~~In past years, legislation has been proposed that would, if enacted into law, make significant changes~~

Continuing and ~~development costs, (iii) the elimination of the deduction for certain domestic production activities~~increasing political and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some or all of these proposals as part of tax reform legislation, to accompany lower federal income tax rates. Moreover, other more general features of tax reform legislation, including changes to cost recovery rules andsocial attention to the ~~deductibility~~issue of ~~interest expense, may be developed that also would~~climate change ~~the taxation of oil~~has resulted in legislative, regulatory and other initiatives, including international agreements, to reduce greenhouse gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.

~~Climate Change~~ ~~– Policy makers in the U.S. and Canada are increasingly focusing on whether the~~ emissions, ~~of greenhouse gases,~~ such as carbon dioxide and ~~methane, are contributing to harmful climatic changes.~~methane. Policy makers at both the U.S. federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse ~~gases through inventories, limitations and/or taxes on greenhouse gas emissions.~~gases. For example, both the EPA and the BLM have issued regulations for the control of methane emissions, which also include leak detection and repair requirements, for the oil and gas industry. ~~Legislative~~Following the change in presidential administrations, however, the agencies have attempted to revise or rescind their previously issued methane standards. Litigation concerning these methane regulations and ~~state initiatives~~subsequent attempts to ~~date~~revise or rescind them is ongoing. Nevertheless, several states where we operate, including Wyoming and New Mexico, have ~~generally focused on~~already imposed, or stated intentions to impose, laws or regulations designed to reduce methane emissions from oil and gas exploration and production activities. With respect to more comprehensive regulation, policy makers and political candidates have made, or expressed support for, a variety of proposals, such as the development of cap-and-trade ~~and/~~or carbon tax ~~programs. A~~programs, as well as the more sweeping “green new deal” resolutions introduced in Congress in early 2019. As generally proposed, a cap-and-trade program ~~generally~~ would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission ~~allowances. Carbon~~allowances, while a carbon tax could impose taxes ~~could likewise affect us by being~~ based on emissions from our ~~equipment and/or~~operations and downstream uses of our products. The “green new deal” resolutions call for a 10-year national mobilization effort to, among other things, transition 100% of power demand in the U.S. to zero-emission sources and overhaul transportation systems in the U.S. to remove greenhouse gas emissions as much as is technologically feasible.

In addition to regulatory risk, other market and social initiatives resulting from the changing perception of climate change present risks for our business. For example, in an effort to promote a lower-carbon economy, there are various public and private initiatives subsidizing the development and adoption of alternative energy sources and technologies, including by mandating the use of ~~our products by our customers. Although it is not possible at this time~~specific fuels or technologies. These initiatives may reduce the competitiveness of carbon-based fuels, such as oil and gas. Moreover, certain financial institutions, funds and other sources of capital have begun restricting or eliminating their investment in oil and natural gas activities due to ~~predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact~~their concern regarding climate change. Such restrictions in capital could decrease the value of our business ~~any such future laws~~ and ~~regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us~~make it more difficult to ~~incur costs to reduce emissions of greenhouse gases associated with~~fund our operations. ~~Limitations on greenhouse gas emissions could also adversely affect demand for~~Finally, governmental entities and other plaintiffs have brought, and may continue to bring, claims against us and other oil and gas companies for purported damages caused by the alleged effects of climate change. These and the other regulatory, social and market risks relating to climate change described above could result in unexpected costs, increase our operating expense and reduce the demand for our products, which in turn could lower the value of our reserves and have ~~a material~~an adverse effect on our profitability, financial condition and liquidity.

In 2015, Alberta released a new Climate Leadership Plan. This plan includes implementing an economy-wide carbon price effective in 2017. The plan also includes a legislated limit for oil sands emissions and a methane emission reduction plan which are under development. Regulations are expected to be finalized by 2018. It is expected that these initiatives will create additional costs for the Alberta oil and gas industry. Presently, it is not possible to accurately estimate the costs we could incur to comply with any law or regulations developed.

Our Hedging Activities Limit Participation in Commodity Price Increases and Involve Other Risks

We enter into ~~hedging activities~~financial derivative instruments with respect to a portion of our production to manage our exposure to oil, gas and NGL price volatility. To the extent that we engage in price risk management activities to protect ourselves from

commodity price declines, we ~~may~~will be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the contract counterparties fail to perform under the contracts. Moreover, as a result of the Dodd-Frank Wall Street Reform and Consumer Protection Act and other legislation and regulation, hedging transactions and many of our contract counterparties have ~~come under increasing~~become subject to increased governmental oversight and regulations in recent years. Although we cannot predict the ultimate impact of these laws and the related rulemaking, some of which is ongoing, existing or future regulations may adversely affect the cost and availability of our hedging ~~arrangements, including by causing our contract counterparties, which are generally financial institutions and other market participants, to curtail or cease their derivatives activities.~~arrangements.

We enter into a variety of transactions that expose us to counterparty credit risk. For example, we have exposure to financial institutions and insurance companies through our hedging arrangements, our syndicated revolving credit facility and our insurance policies. Disruptions in the financial markets or otherwise may impact these counterparties and affect their ability to fulfill their existing obligations and their willingness to enter into future transactions with us.

In addition, we are exposed to the risk of financial loss from trade, joint interest billing and other receivables. We sell our oil, gas and NGLs to a variety of purchasers, and, as an operator, we pay expenses and bill our non-operating partners for their respective ~~shares~~share of costs. We also frequently look to buyers of oil and gas properties from us or our predecessors to perform certain obligations associated with the disposed assets, including the removal of production facilities and plugging and abandonment of wells. Certain of these counterparties or their successors may experience insolvency, liquidity problems or other issues and may not be able to meet their ~~financial~~ obligations and liabilities (including contingent liabilities) owed to, and assumed from, us, particularly during a depressed or volatile commodity price environment. Any such default ~~by these counterparties~~may result in us being forced to cover the costs of those obligations and liabilities, which could adversely impact our financial ~~results.~~results and condition.

Our Debt May Limit Our Liquidity and Financial Flexibility, and Any Downgrade of Our Credit Rating Could Adversely Impact Us

As of December 31, ~~2016,~~2019, we had total ~~consolidated~~ indebtedness of ~~$10.2~~$4.3 billion. Our indebtedness and other financial commitments have important consequences to our business, including, but not limited to:

In addition, we receive credit ratings from rating agencies in the U.S. with respect to our debt. Factors that may impact our credit ratings include, among others, debt levels, planned ~~assets~~asset sales and purchases, liquidity, forecasted production growth and commodity prices. ~~During 2016, Standard & Poor’s Financial Services and Moody’s Investor Service downgraded our senior unsecured debt ratings. Due to our current credit ratings, we~~We are currently required to provide letters of credit or other assurances under certain of our contractual arrangements. ~~Further~~Any credit downgrades could adversely impact our ability to access financing and trade credit, require us to provide additional letters of credit or other assurances under contractual arrangements and increase our interest rate under any credit facility borrowing as well as the cost of any other future debt.

As an owner, lessee or operator of oil and gas properties, we are subject to various federal, state, provincial, tribal and local laws and regulations relating to discharge of materials into, and protection of, the environment.

These laws and regulations may, among other things, impose liability on us for the cost of remediating pollution that results from our operations. Environmental laws may impose strict, joint and several liability, and failure to comply with environmental laws and regulations can result in the imposition of administrative, civil or criminal fines and penalties, as well as injunctions limiting operations in affected areas. Any future environmental costs of fulfilling our commitments to the environment are uncertain and will be governed by several factors, including future changes to regulatory requirements. Changes in or additions to public policy regarding the protection of the environment could have a significant impact on our operations and profitability.

Cyber Attacks ~~Targeting Our Systems and Infrastructure~~ May Adversely Impact Our Operations

Our ~~industry~~business has become increasingly dependent on digital technologies, and we anticipate expanding the use of technology in our operations, including through artificial intelligence, process automation and data analytics. Concurrent with this growing dependence on technology is greater sensitivity to ~~conduct daily operations. Concurrently, the industry has become the subject of increased levels of cyber-attack activity.~~cyber attack related activities, which have frequently targeted our industry. Cyber ~~attacks~~attackers often attempt to gain unauthorized access to digital systems for purposes of misappropriating ~~assets~~sensitive information, intellectual property or ~~sensitive information,~~financial assets, corrupting data or causing operational ~~disruption~~disruptions as well as to prevent users from accessing systems or information and demand payment in order to regain access. These attacks may be ~~carried out~~perpetrated by third parties or insiders. ~~The techniques utilized~~Techniques used in these attacks often range from highly sophisticated efforts to electronically circumvent network security to more traditional intelligence gathering and social engineering aimed at obtaining information necessary to gain access. Cyber attacks may also be ~~carried out~~performed in a manner that does not require gaining unauthorized access, such as by causing denial-of-service attacks. In addition, our vendors, midstream providers and other business partners may separately suffer disruptions or breaches from cyber attacks, which, in turn, could adversely impact our operations and compromise our information. Although we have not suffered material losses related to cyber attacks to date, if we were successfully attacked, we could incur substantial remediation and other costs or suffer other negative ~~consequences.~~consequences, including litigation risks. Moreover, as the sophistication of cyber attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities.

Certain of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. We have limited influence and control over the operation or future development of such properties, including compliance with environmental, health and safety regulations or the amount and timing of required future capital expenditures. These limitations and our dependence on the operator and other working interest owners for these properties could result in unexpected future costs and delays, curtailments or cancellations of operations or future development, which could adversely affect our financial condition and results of operations.

We rely on midstream facilities and systems owned and operated by others to process our gas production and to transport our oil, gas and NGL production to downstream markets. ~~Such midstream systems include EnLink’s systems, as well as other systems operated by us~~All or ~~third parties. Regardless of who operates the midstream systems we rely upon,~~ a portion of our production in ~~any region~~one or more regions may be interrupted or shut in from time to time due to losing access to plants, pipelines or gathering systems. Such access could be lost due to a number of factors, including, but not limited to, weather conditions and natural disasters, accidents, field labor issues or strikes. Additionally, ~~we and third parties~~the midstream operators may be subject to constraints that limit ~~our or~~ their ability to construct, maintain or repair midstream facilities needed to process and transport our production. Such interruptions or constraints could negatively impact our production and associated profitability.

~~Our~~As discussed above, our business is hazardous and is subject to all of the operating risks normally associated with the exploration, development ~~production, processing~~ and ~~transportation~~production of oil, gas and NGLs. Such risks include potential blowouts, cratering, fires, loss of well control, mishandling of fluids and chemicals and possible underground migration of hydrocarbons and chemicals. The occurrence of any of these risks could result in environmental pollution, damage to or destruction of our property, equipment and natural resources, injury to people or loss of life.

To mitigate financial losses resulting from these operational hazards, we maintain comprehensive general liability insurance, as well as insurance coverage against certain losses resulting from physical damages, loss of well

control, business interruption and pollution events that are considered sudden and accidental. We also maintain workers’ compensation and employer’s liability insurance. However, our insurance coverage does not provide 100% reimbursement of potential losses resulting from these operational hazards. Additionally, ~~insurance coverage is generally not available to us for pollution events that are considered gradual, and~~ we have limited or no insurance coverage for ~~certain~~a variety of other risks, ~~such as~~including pollution events that are considered gradual, war and political ~~risk~~risks and ~~war. Our insurance does not cover~~fines or penalties ~~or fines~~ assessed by governmental authorities. The occurrence of a significant event against which we are not fully insured could have ~~a material~~an adverse effect on our profitability, financial condition and liquidity.

Strong competition exists in all sectors of the oil and gas industry. We compete with major integrated and independent oil and gas companies for the acquisition of oil and gas leases and properties. We also compete for the equipment and personnel required to explore, develop and operate properties. Typically, during times of rising commodity prices, drilling and operating costs will also increase. During these periods, there is often a shortage of drilling rigs and other oilfield services, which could adversely affect our ability to execute our development plans on a timely basis and within budget. Competition is also prevalent in the marketing of oil, gas and NGLs. Certain of our competitors have financial and other resources substantially greater than ~~ours. They also~~ours and may have established superior strategic long-term positions and relationships, ~~in areas in which we may seek new entry.~~including with respect to midstream take-away capacity. As a consequence, we may be at a competitive disadvantage in bidding for assets or services and accessing ~~capital.~~capital and downstream markets. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for oil and gas production, such as changing worldwide price and production levels, the cost and availability of alternative ~~fuels~~energy sources and the application of government regulations.

Our Business Could Be Adversely Impacted by Investors Attempting to Effect Change

Stockholder activism has been increasing in our industry, and investors may from time to time attempt to effect changes to our business or governance, whether by stockholder proposals, public campaigns, proxy solicitations or otherwise. Such actions could adversely impact our business by distracting our board of directors and employees from core business operations, requiring us to incur increased advisory fees and related costs, interfering with our ability to successfully execute on strategic transactions and plans and provoking perceived uncertainty about the future direction of our business. Such perceived uncertainty may, in turn, make it more difficult to retain employees and could result in significant fluctuation in the market price of our common stock.

Our business depends, in part, on making acquisitions that complement or expand our current business and successfully integrating any acquired assets or businesses. If we are unable to make attractive acquisitions, our future growth could be limited. Furthermore, even if we do make acquisitions, they may not result in an increase in our cash flow from operations or otherwise result in the benefits anticipated due to various risks, including, but not limited to:

Under the Devon Plan, eligible employees ~~may~~previously had the option to purchase shares of our common stock through an investment in the Devon Stock Fund, which is administered by an independent trustee. Eligible employees purchased approximately ~~80,600~~27,000 shares of our common stock in ~~2016,~~2019, at then-prevailing stock prices, that they held through their ownership in the Devon Stock Fund. We acquired the shares of our common stock sold under ~~the Devon Plan~~this plan through open-market purchases.

The financial information below should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of this report.

Item 7.Management’s Discussion and ~~Analysis~~Analysis of Financial Condition and Results of Operations

The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report.

~~By executing~~During 2019, we completed our transformation to a U.S. oil growth company with our exit from Canada and pending sale of the Barnett Shale. These transactions accelerate efforts to focus exclusively on our resource-rich U.S. oil portfolio, which provides us with a strong foundation to grow returns, margin and profitability. By operating under a disciplined returns-driven strategy ~~outlined in “Items 1~~focused on delivering strong operational results, financial strength and ~~2. Business and Properties” of this report, we strive~~value to ~~optimize value for~~ our shareholders ~~by growing cash flow, earnings, production~~ and ~~reserves, all on a per debt-adjusted share basis. Despite the challenges~~continuing our ~~company~~commitment to environmental, social and ~~the entire upstream energy sector have faced from the sustained low commodity price environment,~~governance excellence, we ~~have continued~~completed our transformation to ~~execute~~“New Devon” and made significant progress toward our strategy and position our company for long-term success. Although we have seen moderate improvements in oil and natural gas prices over the course of 2016, prices for oil and natural gas were still significantly lower than 2015 and 2014 and remain under pressure due to excess supply concerns. In response to this environment, we remained committed to an approach centered on:

In 2017 and beyond, we have the financial capacity to further accelerate investment across our best-in-class U.S. resource plays. We are increasing drilling activity and will continue to rapidly shift our production mix to high-margin products. We will continue our premier technical work to drive capital allocation and efficiency and industry-leading well productivity results. We will continue to maximize the value of our base production by sustaining the operational efficiencies we have achieved. Finally, we will continue to manage activity levels within our cash flows. We expect this disciplined approach will position us to deliver substantial cash flow expansion over the next two years.

In addition, we recognized $267 million of restructuring and transaction costs during 2016 related to the workforce reduction and incurred $5.0 billion of noncash asset impairments as a result of the continued depressed prices for commodities but recognized $1.9 billion in gains on our divestiture transactions. While the gain on divestitures and impairments significantly impacted our earnings, they had no effect on our operating cash flow or debt covenants.

~~Key measures of our financial performance in 2016 are summarized in the following table:~~

Trends of our annual earnings, operating cash flow, EBITDAX and capital expenditures are shown below. The annual earnings chart presents amounts pertaining to both Devon’s continuing and discontinued operations. The annual cash flow chart presents amounts pertaining to Devon’s continuing operations. “Core earnings” and “EBITDAX” are financial measures not prepared in accordance with GAAP. For a description of these measures, including reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 7.

Our ~~2016~~ net earnings in recent years have been significantly impacted by divestiture transactions and temporary, noncash adjustments to the value of our commodity hedges. Net earnings in 2017 included a $0.1 billion gain on asset dispositions from continuing operations and a $0.2 billion hedge valuation gain, both net of taxes. Net earnings in 2018 included a $2.2 billion gain on our EnLink disposition, a $0.5 billion hedge valuation gain and a $0.2 billion gain on asset dispositions from continuing operations, all net of taxes. Net earnings in 2019 included a $0.4 billion hedge valuation loss, $0.2 billion net gains and charges related to our Canadian disposition and a $0.6 billion asset impairment related to our Barnett Shale disposition, all net ~~loss per share improved compared~~of taxes. Excluding these amounts, our core earnings have been more stable over recent years but continue to ~~2015 primarily due~~be heavily influenced by commodity prices.

Like earnings, our operating cash flow is sensitive to ~~more significant noncash asset impairments recognized in 2015~~volatile commodity prices. EBITDAX, which excludes financial amounts related to discontinued operations, has been increasing over the past three years as a result of ~~the large commodity price declines. Core loss, core loss per share~~our New Devon production growth and cost reductions. Regardless of cash flow fluctuations, we remain focused on managing our capital investment to generate free cash flow. As operating cash flow ~~for 2016 decreased significantly compared~~has declined, we have adjusted our capital development plans accordingly.

Devon marked its ~~45th~~48th anniversary in the oil and gas business and its ~~28th~~31st year as a public company during ~~2016.~~2019. As an established company with a strong leadership team, we have experience operating inthrough periods of ~~challenged~~volatile commodity prices. With our focused strategy and portfolio of quality assets, we are ~~prepared~~committed to ~~successfully navigate~~navigating the current environment while ~~ensuring~~safeguarding our long-term financial strength.

Market prices for crude oil and natural gas are inherently volatile. ~~Therefore, we cannot predict with certainty the future prices for the commodities we produce and sell. During 2016,~~In 2019, WTI oil prices ~~ranged from $26.21/~~averaged approximately $57.02/Bbl ~~to $54.06/Bbl. As a result of the ongoing worldwide oversupply issue, OPEC agreed to its first oil production cut~~versus $64.79/Bbl in ~~eight years in November 2016. Following the agreements by both OPEC and non-OPEC producers to reduce output by nearly 1.8 million barrels per day~~2018. Despite price support in the first half of ~~2017,~~2019 driven by supply tightness and geopolitical tensions, 2019 WTI oil prices ~~jumped approximately 10% in~~overall were negatively impacted by trade concerns and economic slowdown fears, even with strong supply and demand fundamentals. Looking ahead, crude oil has experienced near term downward pressure as a result of softer demand from the ~~fourth quarter~~growing impact of ~~2016, averaging $49.21/Bbl. Current market fundamentals indicate improved prices~~the coronavirus related crisis. Positive factors that could reduce these recent negative factors and create more demand for crude oil are the extension of OPEC cuts through 2020, as well as the International Maritime Organization 2020 regulations.

Henry Hub gas prices averaged approximately $2.63/MMBtu in 2019 versus $3.09/MMBtu in 2018. Mt. Belvieu Blended Index NGL prices averaged approximately $19.22/Bbl in 2019 versus $28.31/Bbl in 2018. Natural gas and NGL prices faced strong headwinds in 2019 due to U.S. supply growth far outpacing demand for both commodities domestically and internationally. These factors continue to weigh on current natural gas and ~~natural~~NGL prices.

As discussed in our Critical Accounting Estimates, our STACK assets are susceptible to a material asset impairment should prices decrease from current levels. While such an impairment would materially impact our reported net earnings, it would not impact our operating cash flow or our current near-term drilling plans.

To mitigate our exposure to commodity price volatility and ensure our financial strength, we continue to execute a disciplined, risk-management hedging program. Our hedging program incorporates both systematic hedges added on a regular basis and discretionary hedges layered in on an opportunistic basis to take advantage of favorable market conditions. We are adding 2020 positions at desirable prices, and we currently have approximately 40% of our anticipated oil volumes and 25% of our anticipated gas ~~liquids~~volumes hedged. Additionally, we are actively adding attractive hedges for 2021. Further insulating our cash flow, we continue to examine and, when appropriate, execute attractive regional basis swap hedges in ~~2017; however, changes in OPEC production strategies,~~an effort to protect price realizations across our portfolio.

Throughout 2019, our operational efficiencies continued to accelerate. Our improved cost structure expanded margins, and we ended the ~~macro-economic environment, geopolitical risks, winter~~year ahead of our multi-year cost savings initiative plan. As we carry our 2019 momentum into 2020, we will maintain our capital-efficiency focus and ~~summer temperature ranges or other factors could impact current forecasts.~~intensify our steadfast commitment to capital discipline. Our returns-driven strategy will be underpinned by our continued efforts to improve our cost structure and grow higher-margin oil production. As such, ~~we anticipate continued volatility into 2017.~~ our 2020 capital program has been optimized for strong returns, high single-digit oil growth, free cash flow and enhanced per-share cash flow growth.

~~While we expect that~~the 2020 spend will be focused in on our ~~industry will remain challenged by relatively low prices for~~highest margin U.S. oil play, the ~~near-term, we have strategically positioned our company for continued growth and investment~~Delaware Basin. As the most active program in ~~our~~Devon’s portfolio, of assets. Leveraging the success of our 2016 divestiture program and other key achievements noted above, we are in a position of significant strength and anticipate expanding our exploration and development capital ~~spend by approximately 80% in 2017. Our 2017 outlook is marked by accelerated~~ activity ~~across our key basins, focusing an expanded rig count~~ in the ~~STACK and~~ Delaware Basin ~~and achieving 15% growth in~~will be diversified across five core areas. Also accretive to our 2020 returns-focused capital program is our 2020 Rockies activity, where spend will be prioritized to our top-tier Powder River Basin development activity. In total, our 2020 operating plan is expected to deliver U.S. oil production through some of our best-in-class positions. Additionally, we ramped up our hedging program in 2016, with approximately 50% of our oil and 45% of our gas production hedged entering into 2017.

~~Finally, EnLink continues to be a strategic advantage for us, allowing for improved midstream~~ growth ~~potential. Annual distributions~~ of approximately ~~$270 million provide~~7.5% to 9.0% on a ~~visible cash flow stream to be further invested in our upstream capital programs discussed above.~~retained asset basis.

~~Oil, Gas~~provide an understanding of our results of operations and ~~NGL Pricing~~current financial condition. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests. Analysis of the change in net earnings from continuing operations is shown below and analysis of the change in net earnings from discontinued operations is shown on page 33.

Our 2019 net loss from continuing operations was $79 million and decreased $793 million compared to 2018. The ~~volume and price~~graph below shows the change in net earnings from 2018 to 2019. The material changes are further discussed by category on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests.

Production Volumes

	2019		% of Total			2018		Change
Oil (MBbls/d)
Delaware Basin		70		47	%		42		+67	%
STACK		31		20	%		32		- 4	%
Powder River Basin		17		11	%		14		+26	%
Eagle Ford		23		16	%		28		- 17	%
Other		6		4	%		5		+4	%
New Devon		147		98	%		121		+21	%
U.S. divest assets		3		2	%		9		- 70	%
Total		150		100	%		130		+15	%

	2019		% of Total			2018		Change
Gas (MMcf/d)
Delaware Basin		177		29	%		105		+68	%
STACK		314		53	%		334		- 6	%
Powder River Basin		24		4	%		16		+55	%
Eagle Ford		79		13	%		79		- 0	%
Other		1		0	%		1		- 18	%
New Devon		595		99	%		535		+11	%
U.S. divest assets		4		1	%		31		- 87	%
Total		599		100	%		566		+6	%

	2019		% of Total			2018		Change
NGLs (MBbls/d)
Delaware Basin		27		36	%		16		+74	%
STACK		36		46	%		37		- 5	%
Powder River Basin		2		3	%		1		+53	%
Eagle Ford		11		14	%		13		- 15	%
Other		1		1	%		1		+12	%
New Devon		77		100	%		68		+13	%
U.S. divest assets		—		0	%		3		N/M
Total		77		100	%		71		+9	%

	2019		% of Total			2018		Change
Combined (MBoe/d)
Delaware Basin		127		39	%		75		+69	%
STACK		119		36	%		125		- 5	%
Powder River Basin		23		7	%		17		+34	%
Eagle Ford		47		15	%		54		- 12	%
Other		7		2	%		7		+5	%
New Devon		323		99	%		278		+16	%
U.S. divest assets		4		1	%		18		- 80	%
Total		327		100	%		296		+11	%

From 2018 to 2019, an 11% increase in production volumes contributed to a $410 million increase in earnings. Continued development in the ~~tables above caused the following changes~~Delaware Basin and Powder River Basin drove a 16% production increase for New Devon which was slightly offset by decreased production associated with divested assets.

Field Prices

	2019		Realization		2018			Change
Oil (per Bbl)
WTI index	$	57.02			$	64.79			- 12	%
Realized price, unhedged	$	54.73		96%	$	61.96			- 12	%
Cash settlements	$	1.71			$	(8.01	)
Realized price, with hedges	$	56.44		99%	$	53.95			+5	%

	2019		Realization		2018		Change
Gas (per Mcf)
Henry Hub index	$	2.63			$	3.09		- 15	%
Realized price, unhedged	$	1.79		68%	$	2.34		- 23	%
Cash settlements	$	0.14			$	0.02
Realized price, with hedges	$	1.93		73%	$	2.36		- 18	%

	2019		Realization		2018			Change
NGLs (per Bbl)
Mont Belvieu blended index ⁽¹⁾	$	19.22			$	28.31			- 32	%
Realized price, unhedged	$	15.21		79%	$	25.47			- 40	%
Cash settlements	$	1.61			$	(1.75	)
Realized price, with hedges	$	16.82		88%	$	23.72			- 29	%

(1)

Based upon composition of our NGL barrel.

	2019		2018			Change
Combined (per Boe)
Realized price, unhedged	$	31.93	$	37.87			- 16	%
Cash settlements	$	1.43	$	(3.89	)
Realized price, with hedges	$	33.36	$	33.98			- 2	%

From 2018 to ~~our~~2019, field prices contributed to a $686 million decrease in earnings. Unhedged realized oil, gas and NGL ~~sales.~~

Oil

Bitumen

Gas

NGLs

Total

(Millions)

2014 sales

$
4,773

$
1,138

$
2,737

$
1,262

$
9,910

Change due to volumes

976

584

(443
)

(23
)

1,094

Change due to prices

(2,813
)

(1,000
)

(1,034
)

(775
)

(5,622
)
2015 sales

$
2,936

$
722

$
1,260

$
464

$
5,382

Change due to volumes

(608
)

209

(151
)

(70
)

(620
)
Change due to prices

(299
)

(143
)

(159
)

21

(580
)
2016 sales

$
2,029

$
788

$
950

$
415

$
4,182

~~Volumes 2016 vs. 2015~~ ~~Commodity sales~~prices decreased due to our 67% reduction in exploration and development capital related to our retained assets during 2016. While expanded drilling in the STACK and the performance of our Jackfish assets drove production increases, these production increases were more than offset by reduced completion activity in the Eagle Ford and natural production declines in the Barnett Shale and Rockies Oil. Delaware Basin production was relatively flat as natural declines offset the increases from new wells. Additionally, our production decreased as a result of our U.S. non-core divestiture program.

~~Volumes 2015 vs. 2014~~ ~~Commodity sales increased due to volumes in 2015 because of strong production growth from our U.S. oil properties. The growth was primarily driven by the continued development of our Eagle~~

~~Table of Contents~~

~~Index to Financial Statements~~

~~Ford, Delaware Basin and Rockies Oil properties. Additionally, our bitumen production increased~~ primarily due to ~~Jackfish 3 coming on-line late in the third quarter of 2014~~lower WTI, Henry Hub and reaching nameplate capacity in the third quarter of 2015. Lower royalties resulting from the significant price decrease also increased our heavy oil production. The increases were partially offset by a decrease in our gas production, which resulted primarily from asset divestitures in 2014 and natural reservoir declines.

~~Prices 2016 vs. 2015~~ ~~Commodity sales decreased in 2016 as a result of lower prices for oil, bitumen and gas. The decrease in oil and bitumen sales primarily resulted from lower average WTI crude oil~~Mont Belvieu index ~~prices, which were approximately 11% lower in 2016 as compared to 2015. The decreases in gas were driven by lower North American regional index prices upon which our gas sales are based.~~prices. These decreases were partially offset by ~~slightly higher NGL prices at the Mont Belvieu, Texas hub.~~

~~Prices 2015 vs. 2014~~ Commodity sales decreased in 2015 as a result of significantly lower prices for all commodities. The decrease in oil and bitumen sales primarily resulted from significantly lower average WTI crude oil index prices, which were approximately 50% lower in 2015 as compared to 2014. The decreases in gas and NGL sales were driven by lower North American regional index prices upon which our gas sales are based and lower NGL prices at the Mont Belvieu, Texas hub.

~~Oil, Gas and NGL Derivatives~~

~~The following tables provide financial information associated with our oil, gas and NGL hedges. The first table presents the~~favorable hedge cash settlements ~~and fair value gains and losses recognized as components~~across each of our ~~revenues. The subsequent tables present our oil, gas and NGL prices with and without the effects of the cash settlements. The prices do not include the effects of fair value gains and losses.~~ products.

Year Ended December 31,

2016

2015

2014

(Millions)

Cash settlements:

Oil derivatives

$
(41
)

$
2,083

$
90

Gas derivatives

35

333

(36
)
NGL derivatives

(5
)

—

1

Total cash settlements

(11
)

2,416

55

Gains (losses) on fair value changes:

Oil derivatives

(103
)

(1,687
)

1,721

Gas derivatives

(86
)

(226
)

213

NGL derivatives

(1
)

—

—

Total gains (losses) on fair value changes

(190
)

(1,913
)

1,934

Oil, gas and NGL derivatives

$
(201
)

$
503

$
1,989

Table of Contents

Index to Financial Statements

Year Ended December 31, 2016

Oil

Bitumen

Gas

NGLs

Boe

(Per Bbl)

(Per Bbl)

(Per Mcf)

(Per Bbl)

(Per Boe)

Realized price without hedges

$
36.72

$
19.82

$
1.84

$
9.81

$
18.72

Cash settlements of hedges

(0.74
)

—

0.07

(0.11
)

(0.05
)
Realized price, including cash settlements

$
35.98

$
19.82

$
1.91

$
9.70

$
18.67

Year Ended December 31, 2015

Oil

Bitumen

Gas

NGLs

Boe

(Per Bbl)

(Per Bbl)

(Per Mcf)

(Per Bbl)

(Per Boe)

Realized price without hedges

$
42.12

$
23.41

$
2.14

$
9.32

$
21.68

Cash settlements of hedges

29.88

—

0.57

—

9.74

Realized price, including cash settlements

$
72.00

$
23.41

$
2.71

$
9.32

$
31.42

Year Ended December 31, 2014

Oil

Bitumen

Gas

NGLs

Boe

(Per Bbl)

(Per Bbl)

(Per Mcf)

(Per Bbl)

(Per Boe)

Realized price without hedges

$
82.47

$
55.88

$
3.90

$
24.89

$
40.33

Cash settlements of hedges

1.56

—

(0.05
)

0.02

0.22

Realized price, including cash settlements

$
84.03

$
55.88

$
3.85

$
24.91

$
40.55

Hedge Settlements

	2019		2018			Change
	Q
Oil	$	93	$	(380	)		N/M
Natural gas		31		5			N/M
NGL		46		(45	)		N/M
Total cash settlements	$	170	$	(420	)		N/M

Cash settlements as presented in the tables above represent realized gains or losses related to ~~these various instruments. A summary of our open commodity derivative positions is included~~the instruments described in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report. ~~Our~~

Production Expenses

	2019			2018			Change
LOE	$	462		$	480			- 4	%
Gathering, processing & transportation		463			407			+14	%
Production taxes		251			248			+1	%
Property taxes		21			18			+17	%
Total	$	1,197		$	1,153			+4	%
Per Boe:
LOE	$	3.87		$	4.45			- 13	%
Gathering, processing & transportation	$	3.88		$	3.77			+3	%
Percent of oil, gas and NGL sales:
Production taxes		6.6	%		6.1	%		+8	%

LOE per Boe decreased in 2019 compared to 2018 due to the impact of our cost reduction initiatives. Gathering, processing and transportation increased primarily due to increased activity in the Delaware Basin.

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 ~~derivatives include price swaps, costless collars~~revenues less production expenses and ~~basis swaps.~~is not prepared in accordance with GAAP. A reconciliation to the comparable GAAP measures is found in “Non-GAAP Measures” in this Item 7. The changes in production volumes, field prices and production expenses, shown above, had the following impacts on our field-level cash margins by asset.

~~In addition~~

	2019		$ per BOE		2018		$ per BOE
Field-level cash margin (non-GAAP)
Delaware Basin	$	1,157	$	25.00	$	786	$	28.65
STACK		685	$	15.81		992	$	21.75
Powder River Basin		246	$	28.64		249	$	38.50
Eagle Ford		446	$	25.80		717	$	36.30
Other		65	$	25.37		72	$	28.59
New Devon		2,599	$	22.02		2,816	$	27.67
U.S. divest assets		13	$	11.01		116	$	19.15
Total	$	2,612	$	21.90	$	2,932	$	27.19

Depreciation, Depletion and Amortization

	2019		2018		Change
Oil and gas per Boe	$	11.72	$	10.51		+11	%

Oil and gas	$	1,398	$	1,134		+23	%
Other property and equipment		99		94		+5	%
Total	$	1,497		1,228		+22	%

Our oil and gas DD&A increased due to ~~cash settlements, we also~~continued development in the Delaware Basin and Powder River Basin.

General and Administrative Expense

	2019		2018		Change
Labor and benefits (net of reimbursements)	$	307	$	365		- 16	%
Non-labor		168		209		- 20	%
Total Devon	$	475	$	574		- 17	%

From 2018 to 2019, G&A decreased $99 million primarily as a result of the workforce reduction and other cost-saving initiatives that occurred during 2019 as discussed in Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.

Other Items

	2019			2018			Change in earnings
Commodity hedge valuation changes ⁽¹⁾	$	(624	)	$	877		$	(1,501	)
Marketing operations		53			33			20
Exploration expenses		58			128			70
Asset impairments		—			156			156
Asset dispositions		(48	)		(278	)		(230	)
Net financing costs		250			580			330
Restructuring and transaction costs		84			97			13
Other expenses		4			(7	)		(11	)
							$	(1,153	)

(1)

Included as a component of upstream revenues on the consolidated statements of comprehensive earnings.

We 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 the cash settlements discussed above, our oil, gas and NGL derivatives incurred a net loss in 2016 and generated net gains in 2015 and 2014.~~

~~Marketing and Midstream Revenues and Operating Expenses~~

Year Ended December 31,

2016

Change

2015

Change

2014

(Millions)

Operating revenues

$
6,323

- 13
%

$
7,260

- 5
%

$
7,667

Product purchases

(5,133
)

- 15
%

(6,028
)

- 8
%

(6,540
)
Operations and maintenance expenses

(359
)

- 8
%

(392
)

+43
%

(275
)
Operating profit

$
831

- 1
%

$
840

- 1
%

$
852

Devon profit (loss)

$
(48
)

- 443
%

$
14

- 84
%

$
88

EnLink profit

879

+6
%

826

+8
%

764

Total profit

$
831

- 1
%

$
840

- 1
%

$
852

~~2016 vs. 2015~~ ~~The overall decrease in marketing and midstream margin during 2016 was~~Exploration expense decreased primarily due to ~~lower margins on Devon’s downstream marketing commitments, offset by EnLink’s margin growth largely~~recognizing $95 million in unprovedimpairments related to ~~its acquisition activity~~certain non-core acreage in ~~late 2015~~the U.S during 2018 compared to $18 million in 2019.

Asset impairments decreased due to recognizing $109 million of proved asset impairments and ~~the first quarter~~$47 million of ~~2016. We anticipate the margins on Devon’s downstream marketing commitments to continue to negatively impact our marketing~~non-oil and ~~midstream margins into 2017.~~gas asset impairments during 2018 as discussed in Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report.

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Table of Contents

Index to Financial Statements

~~2015 vs. 2014~~ ~~Marketing and midstream operating profit changes were largely driven by a decrease in Devon’s marketing activities~~Asset dispositions decreased primarily due to a decrease in commodity prices. These declines were partially offset by a full year of EnLink’s legacy asset operations compared to prior year and facility expansions coming online in late 2014, along with assets acquired during 2015.

~~Asset Dispositions and Other~~

~~During 2016, we~~gains recognized ~~gains of $1.9 billion~~ in conjunction with ~~the non-core U.S. upstream asset divestitures and the divestiture~~certain of our ~~50% interest~~U.S. asset dispositions in ~~the Access Pipeline in Canada. During 2014, in conjunction with the divestiture of certain Canadian properties, we recognized gains of $1.1 billion.~~2018. For ~~further discussion,~~ additional information see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

~~Lease Operating Expenses~~

Year Ended December 31,

2016

Change

2015

Change

2014

(Millions, except per Boe amounts)

LOE:

U.S.

$
1,123

- 28
%

$
1,551

- 0
%

$
1,559

Canada

459

- 17
%

553

- 28
%

773

Total

$
1,582

- 25
%

$
2,104

- 10
%

$
2,332

LOE per Boe:

U.S.

$
6.44

- 14
%

$
7.52

+0
%

$
7.52

Canada

$
9.36

- 29
%

$
13.18

- 34
%

$
20.10

Total

$
7.08

- 17
%

$
8.48

- 11
%

$
9.49

~~2016 vs. 2015~~ ~~LOE and LOE per Boe~~Netfinancing costs decreased ~~during 2016~~ primarily due to $312 million of early retirement charges associated with our ~~well optimization~~debt retirement in 2018 as discussed in Note 13 in “Item 8. Financial Statements and ~~cost reduction initiatives, as well as~~Supplementary Data” of this report.

Income Taxes

	2019			2018
Current benefit	$	(5)		$	(17)
Deferred expense (benefit)		(25)			247
Total expense (benefit)	$	(30)		$	230
Effective income tax rate		28	%		24	%

For discussion on income taxes, see Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.

Results of Operations – 2018 vs. 2017

Our 2018 net earnings from continuing operations were $714 million and increased $681 million compared to 2017. The graph below shows the change in net earnings from 2017 to 2018. The material changes are further discussed by category on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests.

(1)

As further discussed in Note 1 in “Item 8. Financial Statements and Supplementary Data” of this report, the presentation of certain processing arrangements changed from a net to a gross presentation in 2018. The change resulted in an increase to our upstream revenues and production expenses by $191 million during 2018 with no impact to net earnings.

Table of Contents

Index to Financial Statements

Production Volumes

	2018		% of Total			2017		Change
Oil (MBbls/d)
Delaware Basin		42		32	%		29		+42	%
STACK		32		25	%		25		+28	%
Powder River Basin		14		10	%		10		+37	%
Eagle Ford		28		22	%		34		- 17	%
Other		5		4	%		6		- 6	%
New Devon		121		93	%		104		+17	%
U.S. divest assets		9		7	%		11		- 24	%
Total		130		100	%		115		+13	%

	2018		% of Total			2017		Change
Gas (MMcf/d)
Delaware Basin		105		19	%		86		+22	%
STACK		334		59	%		294		+13	%
Powder River Basin		16		3	%		8		+85	%
Eagle Ford		79		14	%		95		- 17	%
Other		1		0	%		1		+6	%
New Devon		535		95	%		484		+10	%
U.S. divest assets		31		5	%		35		- 10	%
Total		566		100	%		519		+9	%

	2018		% of Total			2017		Change
NGLs (MBbls/d)
Delaware Basin		16		22	%		10		+53	%
STACK		37		53	%		30		+24	%
Powder River Basin		1		2	%		1		+75	%
Eagle Ford		13		18	%		13		+2	%
Other		1		1	%		1		- 4	%
New Devon		68		96	%		55		+25	%
U.S. divest assets		3		4	%		3		- 10	%
Total		71		100	%		58		+23	%

	2018		% of Total			2017		Change
Combined (MBoe/d)
Delaware Basin		75		26	%		54		+39	%
STACK		125		42	%		104		+20	%
Powder River Basin		17		6	%		12		+43	%
Eagle Ford		54		18	%		62		- 13	%
Other		7		2	%		7		- 3	%
New Devon		278		94	%		239		+16	%
U.S. divest assets		18		6	%		21		- 14	%
Total		296		100	%		260		+14	%

From 2017 to 2018, an increase in production volumes contributed to a $246 million increase in earnings. Focused development activities in the Delaware Basin, STACK and Powder River Basin drove production increases for New Devon and were partially offset by decreased activity in the Eagle Ford and lower production volumes associated with our ~~non-core oil~~U.S. divested assets.

Oil, Gas and ~~gas property divestitures. On an absolute dollar basis, LOE decreased approximately $200~~NGL Prices

	2018			Realization		2017		Change
Oil (per Bbl)
WTI index	$	64.79				$	50.99		+27	%
Realized price, unhedged	$	61.96			96%	$	49.41		+25	%
Cash settlements	$	(8.01	)			$	1.98
Realized price, with hedges	$	53.95			83%	$	51.39		+5	%

	2018		Realization		2017		Change
Gas (per Mcf)
Henry Hub index	$	3.09			$	3.11		- 1	%
Realized price, unhedged	$	2.34		76%	$	2.57		- 9	%
Cash settlements	$	0.02			$	0.18
Realized price, with hedges	$	2.36		76%	$	2.75		- 14	%

	2018			Realization		2017			Change
NGLs (per Bbl)
Mont Belvieu blended index ⁽¹⁾	$	28.31				$	24.77			+14	%
Realized price, unhedged	$	25.47			90%	$	16.74			+52	%
Cash settlements	$	(1.75	)			$	(0.16	)
Realized price, with hedges	$	23.72			84%	$	16.58			+43	%

(1)	Based upon composition of average Devon NGL barrel.

	2018			2017		Change
Combined (per Boe)
Realized price, unhedged	$	37.87		$	30.80		+23	%
Cash settlements	$	(3.89	)	$	1.21
Realized price, with hedges	$	33.98		$	32.01		+6	%

Upstream revenues increased $918 million as a result of ~~our U.S. upstream divestitures,~~higher unhedged, realized prices for oil and ~~we anticipate realizing~~NGLs. The increase in oil sales primarily resulted from higher average WTI crude index prices, which were 27% higher in 2018, resulting in an increase of approximately ~~$100~~$600 million.

NGL sales increased $282 million ~~in additional LOE savings in 2017~~ as a result of ~~these divestitures. Our cost reduction initiatives have been primarily focused on reducing costs associated with water disposal, power and fuel, compression and workovers.~~ 14% higher NGL prices at the Mont Belvieu, Texas hub, as well as improved realizations in our NGL price.These ~~cost savings~~increases were partially offset by ~~$28~~unfavorable hedge cash settlements for our oil and NGL hedges.

In 2018, the presentation of certain processing arrangements changed from a net to a gross presentation. The change resulted in an increase to our upstream revenues and production expenses by approximately $191 million with no impact to net earnings.

Hedge Settlements

	2018			2017			Change
	Q
Oil	$	(380	)	$	83			N/M
Natural gas		5			35			N/M
NGL		(45	)		(3	)		N/M
Total cash settlements	$	(420	)	$	115			N/M

Table of ~~Access Pipeline transportation tolls which commenced~~Contents

Index to Financial Statements

Production Expenses

	2018			2017			Change
LOE	$	480		$	411			+17	%
Gathering, processing & transportation		407			205			+99	%
Production taxes		248			161			+54	%
Property taxes		18			14			+29	%
Total	$	1,153		$	791			+46	%
Per Boe:
LOE	$	4.45		$	4.33			+3	%
Gathering, processing & transportation	$	3.77		$	2.16			+74	%
Percent of oil, gas and NGL sales:
Production taxes		6.1	%		5.5	%		+10	%

LOE increased $69 million primarily due to continued focus on growing our liquids-rich assets within the STACK and Delaware Basin, partially offset by our U.S. non-core divestitures.

Production taxes increased on an absolute dollar basis primarily due to the increase in our upstream revenues. Additionally, the increase in Oklahoma severance tax rates that became effective during the third quarter of 2018 also contributed to the increase on an absolute dollar basis and as a percentage of oil, gas and NGL sales.

Field-Level Cash Margin

The changes in production volumes, field prices and production expenses, shown above, had the following impact on our field-level cash margins by asset.

	2018		$ per BOE		2017		$ per BOE
Field-level cash margin (non-GAAP)
Delaware Basin	$	786	$	28.65	$	455	$	23.04
STACK		992	$	21.75		683	$	17.99
Powder River Basin		249	$	38.50		128	$	28.67
Eagle Ford		717	$	36.30		667	$	29.41
Other		72	$	28.59		68	$	26.21
New Devon		2,816	$	27.67		2,001	$	22.88
U.S. divest assets		116	$	19.15		129	$	17.47
Total	$	2,932	$	27.19	$	2,130	$	22.46

Depreciation, Depletion and Amortization

	2018		2017		Change
Oil and gas per Boe	$	10.51	$	9.58		+10	%

Oil and gas	$	1,134	$	908		+25	%
Other property and equipment		94		100		- 5	%
Total	$	1,228	$	1,008		+22	%

Our oil and gas DD&A increased primarily due to continued development in the ~~fourth quarter of 2016 subsequent~~STACK, Delaware Basin and Powder River Basin properties.

General and Administrative Expense

	2018		2017		Change
Labor and benefits (net of reimbursements)	$	365	$	445		- 18	%
Non-labor		209		200		+ 5	%
Total Devon	$	574	$	645		- 11	%

From 2017 to ~~the sale of our interest in Access. Our Access transportation agreement contains a base transportation commitment, which for the initial five years averages $110~~2018, G&A decreased $71 million ~~annually.~~

~~2015 vs. 2014~~ ~~LOE per Boe decreased during 2015~~ primarily as a result of ~~higher Jackfish 3 volumes,~~the workforce reductions that occurred during 2018 as discussed in Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.

Other Items

	2018			2017			Change in earnings
Commodity hedge valuation changes ⁽¹⁾	$	877		$	(48	)	$	925
Marketing operations		33			(46	)		79
Exploration expenses		128			346			218
Asset impairments		156			—			(156	)
Asset dispositions		(278	)		(219	)		59
Net financing costs		580			321			(259	)
Restructuring and transaction costs		97			—			(97	)
Other expenses		(7	)		10			17
							$	786

(1)

Included as a component of upstream revenues on the consolidated statements of comprehensive earnings.

Marketing operations increased primarily due to improved commodity prices, which were partially offset by the impact of our ~~well optimization and cost reduction initiatives, lower royalties and changes~~downstream marketing commitments.

Exploration expense decreased due torecognizing $95 million in unprovedimpairments related to certain non-core acreage in the ~~Canadian~~U.S during 2018 compared to ~~U.S. foreign exchange rate. As Canadian royalties decrease, our net production volumes increase, causing improvements~~$217 million in 2017. Additionally, geological and geophysical costs decreased $86 million primarily in the STACK and Delaware Basin.

Asset impairments increased due to ~~our per-unit operating costs. The flat U.S. rate is primarily related to our 2014 non-core natural~~recognizing $109 million of proved asset impairments and $47 million of non-oil and gas asset ~~divestitures~~impairments during 2018. For additional information, see Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report.

Asset dispositions increased primarily due to gains recognized in conjunction with certain of our ~~oil production growth, where projects generate higher margins but generally require a higher cost~~U.S. asset dispositions in 2018. For additional information, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

Netfinancing costs increased primarily due to ~~produce per unit than~~$312 million of early retirement charges associated with our ~~retained~~debt retirement in 2018 as discussed in Note 13 in “Item 8. Financial Statements and ~~divested gas projects.~~Supplementary Data” of this report.

Table of Contents

Index to Financial Statements

~~General and Administrative Expenses~~

Year Ended December 31,

2016

Change

2015

Change

2014

(Millions)

Gross G&A

$
853

- 30
%

$
1,210

- 5
%

$
1,272

Capitalized G&A

(244
)

- 34
%

(372
)

- 1
%

(376
)
Reimbursed G&A

(82
)

- 32
%

(120
)

- 18
%

(146
)
Devon Net G&A

527

- 27
%

718

- 4
%

750

EnLink Net G&A

118

- 14
%

137

+41
%

97

Net G&A

$
645

- 25
%

$
855

+1
%

$
847

~~2016 vs. 2015~~ ~~Gross G&A~~Restructuring and ~~capitalized G&A decreased during 2016 largely due to lower Devon employee~~transaction costs ~~resulting from~~increased primarily as a result of our workforce reductions ~~as discussed~~ in 2018. See Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report and other cost reduction initiatives. Reimbursed G&A decreased primarily due to a reduction in drilling activity in response to the decline in commodity prices as well as the divestiture of operated properties. EnLink net G&A decreased primarily due to lower employee compensation expense and other cost reductions initiatives during 2016.for additional information.

~~2015 vs. 2014~~ Gross G&A decreased during 2015 largely because of a lower employee performance bonus pool and our cost reduction initiatives. Furthermore, $22 million in one-time costs related to the EnLink and GeoSouthern transactions contributed to higher costs in the first quarter of 2014. Reimbursed G&A decreased subsequent to our 2014 asset divestitures. EnLink G&A increased primarily due to a workforce increase associated with EnLink’s 2015 acquisitions.

~~Production and Property~~Income Taxes

Year Ended December 31,

2016

Change

2015

Change

2014

(Millions)

Production taxes

$
141

- 29
%

$
198

- 45
%

$
360

Property and other taxes

95

- 37
%

151

+3
%

147

Devon production and property taxes

236

- 32
%

349

- 31
%

507

EnLink property taxes

39

- 1
%

39

+39
%

28

Production and property taxes

$
275

- 29
%

$
388

- 28
%

$
535

Percentage of oil, gas and NGL sales:

Production taxes

3.4
%

- 8
%

3.7
%

+1
%

3.6
%
Property and other taxes

3.2
%

- 9
%

3.5
%

+100
%

1.8
%
Total

6.6
%

- 9
%

7.2
%

+33
%

5.4
%

~~2016 vs. 2015~~ Production taxes decreased on an absolute dollar basis primarily due to the decrease in our U.S. revenues, on which the majority of our production taxes are assessed. Furthermore, property and other taxes decreased as a result of lower property value assessments from the local taxing authorities across our key operating areas and as a result of our U.S. non-core divestitures. Property taxes do not change in direct correlation with the decline in oil, gas and NGL sales and are generally determined based on the valuation of the underlying assets.

~~2015 vs. 2014~~ ~~Production taxes decreased during 2015 primarily because of a decrease in our U.S. revenues, on which the majority of our production taxes are assessed.~~

~~Table of Contents~~

~~Index to Financial Statements~~

~~Depreciation, Depletion and Amortization~~

Year Ended December 31,

2016

Change

2015

Change

2014

(Millions, except per Boe amounts)

DD&A:

Oil and gas properties

$
1,143

- 56
%

$
2,580

- 11
%

$
2,896

Other assets

145

- 10
%

162

+16
%

139

Devon DD&A

1,288

- 53
%

2,742

- 10
%

3,035

EnLink DD&A

504

+30
%

387

+36
%

284

Total DD&A

$
1,792

- 43
%

$
3,129

- 6
%

$
3,319

DD&A per Boe:

Oil and gas properties

$
5.11

- 51
%

$
10.40

- 12
%

$
11.79

	2018			2017
Current expense (benefit)	$	(17	)	$	9
Deferred expense (benefit)		247			(2	)
Total expense	$	230		$	7
Effective income tax rate		24	%		18	%

~~A description of how DD&A of our oil and gas properties is calculated is included in~~ For discussion on income taxes, see Note 17 in “Item 8. Financial Statements and Supplementary Data” of this report. ~~Generally, when reserve volumes are revised up or down,~~

Discontinued Operations

The table below presents key components from discontinued operations for the ~~DD&A rate per unit~~time periods presented. Discontinued operations include our aggregate ownership interests in EnLink and the General Partner that Devon divested in July 2018 and the Canadian business that Devon sold in June 2019. Discontinued operations also include the Barnett Shale assets that Devon has contracted to sell and which is expected to close during the second quarter of ~~production will change inversely. However, when~~2020, as well as previously divested Barnett Shale properties located primarily in Johnson and Wise counties, Texas. For additional information on discontinued operations, see Note 18in “Part I. Financial Information – Item 1. Financial Statements” of this report.

	2019			2018			2017
Upstream revenues	$	1,114		$	1,742		$	2,319
Production expenses	$	599		$	1,072		$	1,031
Marketing margin	$	20		$	708		$	958
Gain on sale of Canadian operations	$	(223	)	$	—		$	—
Gain on sale of EnLink and General Partner interests	$	—		$	(2,607	)	$	—
Asset impairments	$	785		$	—		$	17
Financing costs, net	$	87		$	112		$	177
Restructuring and transaction costs	$	248		$	17		$	—
Earnings (loss) from discontinued operations before income taxes	$	(632	)	$	2,839		$	856
Income tax expense (benefit)	$	(358	)	$	329		$	(189	)
Net earnings (loss) from discontinued operations, net of tax	$	(274	)	$	2,510		$	1,045

Production (MMBoe):
Barnett Shale		37			45			56
Canada		19			42			48
Total production		56			87			104
Realized price, unhedged (per Boe) - Barnett Shale	$	13.30		$	17.36		$	14.79
Realized price, unhedged (per Boe) - Canada	$	38.98		$	19.12		$	29.39

2019 vs 2018

Net earnings from discontinued operations, net of tax decreased $2.8 billion as we recognized a $2.6 billion ($2.2 billion after-tax) gain on the ~~depletable base changes,~~sale of our aggregate ownership interests in EnLink and the ~~DD&A rate moves~~General Partner during 2018. Net earnings from discontinued operations also decreased due to a $748 million asset impairment to our Barnett Shale assets in the ~~same direction.~~fourth quarter of 2019.

2018 vs 2017

Net earnings from discontinued operations, net of tax increased $1.5 billion as we recognized a $2.6 billion ($2.2 billion after-tax) gain on the sale of our aggregate ownership interests in EnLink and the General Partner during 2018. The ~~per unit DD&A rate is not affected~~gain was partially offset by ~~production volumes. Absolute or total DD&A, as opposed~~a decrease in upstream revenues, which was primarily driven by widening differentials for bitumen sales in Canada to the ~~rate per unit~~WTI index during the fourth quarter of 2018. Market forces widened Canadian heavy oil differentials beyond historical norms and negatively impacted the price we realized on our Canadian production. We had basis swaps for approximately half of our fourth quarter production ~~generally moves in~~to mitigate the ~~same direction as production volumes.~~

~~2016 vs. 2015~~ ~~DD&A from our oil and gas properties decreased largely because~~effect of the ~~significant asset impairments recognized throughout 2015 and 2016.~~ lower market price. To further mitigate the effects of the lower price, we reduced our Jackfish production in November 2018 which impacted our fourth quarter production by approximately 8 MBbls/d. For discussion ~~of asset impairments,~~on discontinued operations, see Note 518 in “Item 8. Financial Statements and Supplementary Data” of this report. ~~EnLink’s DD&A increased primarily due to EnLink acquisitions in 2016 and 2015.~~

~~2015 vs. 2014~~ DD&A from our oil and gas properties decreased in 2015 compared to 2014 largely because of the 2014 divestitures of certain U.S. and Canadian assets and the oil and gas asset impairments recognized in 2015. EnLink’s DD&A increased primarily due to EnLink’s acquisitions in 2014 and 2015.

~~Asset Impairments~~

During 2016, 2015 and 2014, we recognized asset impairments of $5.0 billion, $20.8 billion and $2.0 billion, respectively. For discussion of asset impairments, see Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report.

~~Restructuring and Transaction Costs~~

During 2016, 2015 and 2014, we recognized restructuring and transaction costs of $267 million, $78 million and $46 million, respectively. For discussion of our reorganization programs and the associated restructuring costs, see Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.

3833

Table of Contents

Index to Financial Statements

~~Net Financing Costs~~

Year Ended December 31,

2016

Change

2015

Change

2014

(Millions)

Devon net financing costs:

Interest based on debt outstanding

$
488

+9
%

$
450

- 4
%

$
468

Early retirement of debt

269

N/M

—

N/M

48

Capitalized interest

(64
)

+18
%

(54
)

-7
%

(58
)
Other

21

+50
%

14

- 7
%

15

Total Devon net financing costs

714

+74
%

410

- 13
%

473

EnLink net financing costs:

Interest based on debt outstanding

144

+26
%

115

+80
%

64

Interest accretion on deferred installment payment

52

N/M

—

N/M

—

Other

(6
)

- 25
%

(8
)

- 27
%

(11
)
Total EnLink net financing costs

190

+77
%

107

+102
%

53

Total net financing costs

$
904

+75
%

$
517

- 2
%

$
526

~~2016 vs. 2015~~ Net financing costs increased during 2016 primarily as a result of the retirement premiums and costs related to early redemptions of senior notes in 2016, which is further discussed in Note 14 in “Item 8. Financial Statements and Supplementary Data” of this report. Furthermore, net financing costs increased due to EnLink’s fixed rate borrowings and accretion of its future installment payments related to 2016 acquisition activity discussed in Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

~~2015 vs. 2014~~ ~~Net financing costs decreased primarily because of the 2014 early retirement premium and costs and a decrease in average fixed-rate borrowings.~~

~~Income Taxes~~

Year Ended December 31,

2016

2015

2014

(Millions)

Current income tax expense (benefit)

$
100

$
(237
)

$
477

Deferred income tax expense (benefit)

(273
)

(5,828
)

1,891

Total income tax expense (benefit)

$
(173
)

$
(6,065
)

$
2,368

Effective income tax rate

4
%

29
%

58
%

~~For discussion on income taxes, see Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.~~

~~Table of Contents~~

~~Index to Financial Statements~~

Capital Resources, Uses and Liquidity

Sources and Uses of Cash

The following table presents the major ~~source and use categories of our~~changes in cash and cash ~~equivalents.~~equivalents for the time periods presented below.

Devon

EnLink

Consolidated

2016

2015

2014

2016

2015

2014

2016

2015

2014

(Millions)

Operating cash flow

$
1,080

$
4,746

$
5,507

$
666

$
627

$
514

$
1,746

$
5,373

$
6,021

Issuance of common stock

1,469

—

—

—

—

—

1,469

—

—

Divestitures of property and
   equipment

3,025

106

5,120

93

1

—

3,118

107

5,120

Capital expenditures

(1,667
)

(4,735
)

(6,192
)

(663
)

(573
)

(796
)

(2,330
)

(5,308
)

(6,988
)
Acquisitions of property, equipment
   and businesses

(849
)

(583
)

(6,104
)

(792
)

(524
)

(358
)

(1,641
)

(1,107
)

(6,462
)
Debt activity, net

(3,383
)

770

(2,829
)

228

1,061

555

(3,155
)

1,831

(2,274
)
Shareholder and noncontrolling
   interests distributions

(221
)

(396
)

(486
)

(304
)

(254
)

(135
)

(525
)

(650
)

(621
)
EnLink and General Partner
   distributions

265

268

158

(265
)

(268
)

(158
)

—

—

—

EnLink dropdowns

—

167

—

—

(167
)

—

—

—

—

Issuance of subsidiary units

—

—

—

892

25

410

892

25

410

Sale of subsidiary units

—

654

—

—

—

—

—

654

—

Effect of exchange rate and other

(64
)

(117
)

172

139

22

36

75

(95
)

208

Net change in cash and cash
   equivalents

$
(345
)

$
880

$
(4,654
)

$
(6
)

$
(50
)

$
68

$
(351
)

$
830

$
(4,586
)
Cash and cash equivalents at end of
   period

$
1,947

$
2,292

$
1,412

$
12

$
18

$
68

$
1,959

$
2,310

$
1,480

	Year ended December 31,
	2019			2018			2017
Operating cash flow from continuing operations	$	2,043		$	1,583		$	1,243
Divestitures of property and equipment		390			500			425
Capital expenditures		(1,910	)		(2,116	)		(1,614	)
Acquisitions of property and equipment		(31	)		(55	)		(44	)
Debt activity, net		(162	)		(1,226	)		—
Repurchases of common stock		(1,849	)		(2,956	)		—
Common stock dividends		(140	)		(149	)		(127	)
Contributions from noncontrolling interests		116			—			—
Other		(26	)		(46	)		(46	)
Net change in cash, cash equivalents and restricted cash from discontinued operations		967			4,227			888
Net change in cash, cash equivalents and restricted cash	$	(602	)	$	(238	)	$	725
Cash, cash equivalents and restricted cash at end of period	$	1,844		$	2,446		$	2,684

Operating Cash Flow – Continuing Operations

Net cash provided by operating activities continued to be a significant source of capital and liquidity in ~~2016.~~2019. Our operating cash flow ~~decreased $3.6~~increased $460 million, or 29%, to $2.0 billion ~~or 68%, during 2016. Throughout 2015,~~year over year. In 2019, our ~~commodity hedges provided us with $2.4 billion of additional operating cash flow. The majority of these hedges expired in 2015 and were the primary driver of our decrease in~~ operating cash flow ~~in 2016. The remainder~~nearly funded the entirety of ~~the decrease is primarily related~~our capital expenditures program and dividends, allowing us to ~~the continued decrease in commodity prices, partially offset by our focused cost initiatives.~~ use available cash balances and net divestiture proceeds to fund other capital uses.

Our operating cash flow ~~decreased 10% during 2015 primarily due~~increased $340 million, or 27%, from 2017 to lower commodity prices. The effects of lower commodity prices were partially offset by the collection of $425 million of income taxes receivable in the first quarter of 2015 and $2.4 billion of cash settlements associated with our commodity derivatives during 2015.

~~Excluding payments made for acquisitions, our consolidated~~2018. Our operating cash flow funded ~~75%, 100% and 86%~~approximately 70% of our capital expenditures ~~during 2016, 2015~~program and ~~2014,~~dividends in 2018 and 2017, respectively. ~~In 2016, 2015 and 2014, leveraging our liquidity and other capital resources,~~As a result, we ~~also used~~utilized available cash balances ~~short-term debt, proceeds from EnLink transactions~~ and divestiture proceeds to ~~fund~~supplement our ~~acquisitions, dividends and capital requirements.~~operating cash flows.

~~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.

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~~Index to Financial Statements~~

Divestitures of Property and ~~Equipment~~Investments – Continuing Operations

During ~~2016,~~2019, 2018 and 2017, as part of our announced divestiture programs, we ~~divested certain~~sold non-core U.S. upstream assets ~~in the U.S.~~for $390 million, $500 million and our 50% interest in the Access Pipeline in Canada for approximately $3.0 billion, net of purchase price adjustments. Proceeds from these divestitures were used primarily for debt repayment and to support capital investment in Devon’s core resource plays. We did not have significant current cash income taxes resulting from these divestitures.$425 million, respectively. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

During 2014, we divested certain non-core upstream assets in the U.S. and Canada for approximately $5.1 billion. These proceeds were used primarily for debt repayment relating to the GeoSouthern transaction. For additional discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

Capital Expenditures

The following table summarizes our capital expenditures and property acquisitions.

Year Ended December 31,

2016

2015

2014

(Millions)

Oil and gas

$
1,624

$
4,577

$
5,735

Corporate and other

43

158

457

Devon capital expenditures

1,667

4,735

6,192

EnLink capital expenditures

663

573

796

Total capital expenditures

$
2,330

$
5,308

$
6,988

Devon acquisitions

$
849

$
583

$
6,104

EnLink acquisitions

792

524

358

Total acquisitions

$
1,641

$
1,107

$
6,462

	Year ended December 31,
	2019		2018		2017
Delaware Basin	$	912	$	768	$	394
STACK		396		827		742
Powder River Basin		308		157		121
Eagle Ford		194		215		115
Other		36		110		155
Total oil and gas		1,846		2,077		1,527
Midstream		42		16		50
Other		22		23		37
Total capital expenditures	$	1,910	$	2,116	$	1,614
Acquisitions	$	31	$	55	$	44

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Index to Financial Statements

Capital expenditures consist primarily of amounts related to our oil and gas exploration and development operations ~~our midstream operations,~~and other corporate ~~activities and EnLink growth and maintenance~~ activities. The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties. ~~In response~~Our capital program is designed to ~~our lower~~operate within or near operating cash flow ~~Devon’s 2016 capital program was designed~~and may fluctuate with changes to ~~be lower than 2015.~~commodity prices and other factors impacting cash flow. This ~~change~~ is evidenced by ~~a 56% decrease in total~~our operating cash flow fully funding capital expenditures ~~from 2015 to 2016, excluding acquisitions. Since 2014, we have reduced our~~in 2019 and funding approximately 75% and 77% of capital expenditures ~~by approximately 70%.~~

~~Capital expenditures for Devon’s~~in 2018 and ~~EnLink’s midstream operations are primarily for the construction and expansion of oil and gas gathering facilities and pipelines. Midstream~~2017, respectively. Our capital expenditures are ~~largely impacted~~lower in 2019 primarily due to our decreased spending in the STACK, partially offset by ~~oil and gas drilling and development activities.~~

~~Acquisition~~increased capital investment in ~~2016 primarily consisted of Devon’s bolt-on acquisition of~~higher margin assets in the ~~STACK play for $1.5 billion~~Delaware and ~~EnLink’s acquisition~~Powder River Basins.

Debt Activity, Net

During 2019, our debt decreased $162 million due to the repayment of ~~Anadarko Basin gathering and processing midstream assets for $1.5 billion. Approximately $849~~our 6.30% senior notes at maturity.

During 2018, our debt decreased $922 million ~~and $792 million, respectively, was paid in cash at~~due to completed tender offers of certain long-term debt as well as the ~~closings~~maturity of certain senior notes. In conjunction with the ~~remainder~~tender offers, we recognized a $312 million loss on the early retirement of ~~the purchase prices funded with equity consideration~~debt, including $304 million of cash retirement costs and debt. In 2015 our acquisition activity primarily consisted of the Powder River Basin asset acquisition in the fourth quarter. The majority of the acquisition capital in 2014 related to the GeoSouthern acquisition in the Eagle Ford. EnLink’s acquisitions in 2015 and 2014 consisted offees. For additional ~~oil and gas pipeline assets, including gathering, transportation and processing facilities. For further discussion on acquisition activity,~~information, see Note 213 in “Item 8. Financial Statements and Supplementary Data” of this report.

~~Debt Activity, Net~~

During 2016, our consolidated net debt decreased $2.9 billion. The decrease was primarily due to completed tender offers to purchase and redeem $2.1 billion of debt securities prior to their maturity and a $1 billion reduction in short-term borrowings during 2016. In conjunction with the tender offers, we recognized a $269 million loss on the early retirement of debt, including $265 million of cash retirement costs and fees. The decrease was partially

~~Table of Contents~~

~~Index to Financial Statements~~Repurchases of Common Stock and Shareholder Distributions

~~offset~~We repurchased 68.6 million shares of common stock for $1.8 billion in 2019 and 78.1 million shares of common stock for $3.0 billion in 2018 under a share repurchase program authorized by ~~$229 million~~our Board of ~~net borrowings from EnLink.~~Directors. For additional information, see Note 1417 in “Item 8. Financial Statements and Supplementary Data” in this report.

During 2015, our consolidated net debt increased $1.8 billion. In June 2015, we issued $750 million of 5.0% senior notes. We used these proceeds to repay the aggregate principal amount of our floating rate senior notes upon maturity on December 15, 2015, as well as outstanding commercial paper balances. In December 2015, we issued $850 million of 5.85% senior notes to fund acquisitions announced in the fourth quarter. EnLink’s net debt borrowings increased $1.1 billion primarily from borrowings made to fund acquisitions and dropdowns.

During 2014, we decreased our net debt by $2.2 billion. The decrease was primarily related to the repayment of debt used to fund the GeoSouthern transaction. This was partially offset by $555 million of net borrowings from EnLink to fund its operations.

~~Shareholder and Noncontrolling Interests Distributions~~

~~The following table summarizes our~~Devon paid common stock ~~dividends.~~

Amounts

Rate

(Millions)

(Per Share)

Year Ended 2016:

First quarter 2016
$
125

$
0.24

Second quarter 2016

33

$
0.06

Third quarter 2016

32

$
0.06

Fourth quarter 2016
31

$
0.06

Total year-to-date
$
221

Year Ended 2015:

First quarter 2015
$
99

$
0.24

Second quarter 2015

98

$
0.24

Third quarter 2015

99

$
0.24

Fourth quarter 2015

100

$
0.24

Total year-to-date
$
396

Year Ended 2014:

First quarter 2014
$
90

$
0.22

Second quarter 2014

99

$
0.24

Third quarter 2014

98

$
0.24

Fourth quarter 2014

99

$
0.24

Total year-to-date
$
386

~~In response to~~dividends of $140 million, $149 million and $127 million during 2019, 2018 and 2017, respectively. During the ~~depressed commodity price environment,~~second quarter of 2018, we ~~reduced~~increased our quarterly dividend 33% from $0.06 to ~~$0.06~~$0.08 per share as part of our focus on returning cash to shareholders. In February 2019, we further increased our quarterly dividend 12.5% to $0.09 per share, beginning in the second quarter of ~~2016.~~

In conjunction with the formation of EnLink in the first quarter of 2014, we made a payment of $100 million to noncontrolling interests. Furthermore, EnLink and the General Partner distributed $304 million, $254 million and $135 million to non-Devon unitholders during 2016, 2015 and 2014, respectively.

~~EnLink and General Partner Distributions~~

~~Devon received $265 million, $268 million and $158 million in distributions from EnLink and the General Partner during 2016, 2015 and 2014, respectively.~~

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~~Index to Financial Statements~~

~~EnLink Dropdowns~~

~~In the second quarter of 2015, Devon received $167 million in cash from EnLink in exchange for VEX.~~2019. For ~~further discussion,~~additional information, see Note 217 in “Item 8. Financial Statements and Supplementary Data” of this report.

~~Issuance~~

Contributions from Noncontrolling Interests

During 2019, we received approximately $116 million in cash contributions from our partner in CDM.

Table of ~~Subsidiary Units~~Contents

Index to Financial Statements

Cash Flows from Discontinued Operations

All cash flows in the following table relate to activities from discontinued operations for the time periods presented. Discontinued operations include our aggregate ownership interests in EnLink and the General Partner that Devon divested in July 2018 and the Canadian business that Devon sold in June 2019. Discontinued operations also include the Barnett Shale assets that Devon has contracted to sell and which is expected to close during the second quarter of 2020, as well as previously divested Barnett Shale properties located primarily in Johnson and Wise counties, Texas.

	Year ended December 31,
	2019			2018			2017
Settlements of intercompany foreign denominated assets/liabilities	$	(32	)	$	(241	)	$	9
Other		60			1,362			1,657
Operating activities		28			1,121			1,666
Divestitures of property and equipment - Canadian operations		2,608			—			—
Divestitures of investments - EnLink and General Partner		—			3,104			190
Divestitures of property and equipment - Barnett Shale assets		—			513			—
Capital expenditures and other		(136	)		(891	)		(1,156	)
Investing activities		2,472			2,726			(966	)
Debt activity, net		(1,552	)		347			2
Issuance of subsidiary units		—			1			501
Distributions to noncontrolling interests		—			(217	)		(354	)
Other		(26	)		43			33
Financing activities		(1,578	)		174			182
Settlements of intercompany foreign denominated assets/liabilities		32			241			(9	)
Other		13			(35	)		15
Effect of exchange rate changes on cash		45			206			6
Net change in cash, cash equivalents and restricted cash of discontinued operations	$	967		$	4,227		$	888

Operating cash flow in 2019 decreased $1.1 billion and $1.6 billion from 2018 and 2017, respectively, as a result of the divestitures referenced above. Additionally, 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. Foreign currency denominated intercompany loan activity resulted in a realized loss of $32 million and $241 million in 2019 and 2018, respectively, as a result of the strengthening of the U.S. dollar in relation to the Canadian dollar. Foreign currency denominated intercompany loan activity resulted in a realized gain of $9 million in 2017, as a result of the weakening 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.

On June 27, 2019, Devon completed the sale of substantially all its oil and gas assets and operations in Canada for proceeds of $2.6 billion. In ~~January 2016, to fund~~the second and fourth quarter of 2018, Devon completed the sale of a portion of its Barnett Shale assets, located primarily in Johnson and Wise counties, Texas for approximately $500 million in combined proceeds. On July 18, 2018, Devon completed the ~~cash consideration~~sale of its ~~acquisition of Anadarko Basin gathering~~aggregate ownership interests in EnLink and ~~processing midstream assets, EnLink issued 50 million preferred units in a private placement generating cash proceeds of approximately $725 million.~~the General Partner for $3.125 billion. During 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million.

Cash flows from financing activities includes the $1.5 billion of senior notes retired prior to maturity in July 2019 and common ~~units were also issued as consideration in the transaction.~~

~~During 2016, 2015~~ and ~~2014,~~preferred units EnLink issued and sold ~~approximately 10.0 million, 1.3 million and 14.8 million common units through general public offerings and its “at the market” equity program,~~during 2017 generating net proceeds of ~~approximately $167 million, $25~~$501 million. 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. Distributions EnLink and the General Partner paid to Devon were $134 million and ~~$410~~$265 million during 2018 and 2017, respectively.

~~Sale~~Liquidity

The business of ~~Subsidiary Units~~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

~~In early 2015, we conducted an underwritten secondary public offering~~36

Table of ~~26.2 million common units representing limited partner interests in EnLink, raising proceeds of $654 million, net of underwriting discount. See Note 18 in “Item 8.~~Contents

Index to Financial Statements

from existing wells. At opportunistic times, we also acquire operations and ~~Supplementary Data”~~properties from other operators or land owners to enhance our existing portfolio of ~~this report.~~

~~Effect of Exchange Rate and Other~~

~~In 2016, EnLink received contributions from noncontrolling interests. For further discussion see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.~~

~~Liquidity~~assets.

Historically, our primary sources of capital funding and liquidity have been our operating cash flow, cash on hand and asset divestiture ~~proceeds and cash on hand.~~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. ~~Available sources of capital and liquidity include, among other things,~~ If needed, we can also issue debt and equity securities, ~~that can be issued pursuant to~~including through transactions under our shelf registration statement filed with the SEC, as well as the sale of a portion of our common units representing interests in our investment in EnLink and the General Partner. The most significant source of liquidity in 2016 has come from approximately $3.0 billion of proceeds related to our asset divestitures.SEC. We estimate the combination of ~~these~~our sources of capital will continue to be adequate to fund our planned capital ~~expenditures, future debt repayments and other contractual commitments~~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 2019, we held approximately $1.8 billion of cash, inclusive of $380 million of cash restricted for discontinued operations. Our operating cash flow isforecasts are sensitive to many variables ~~the~~and include a measure of uncertainty as these variables 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 decreased 68% in 2016 as a result of the expiration of certain favorable commodity hedging positions and the continued decrease in commodity prices. In spite of this decline, we expect operating cash flow to continue to be a primary source of liquidity as we adjust our capital program in response to lower commodity prices. Additionally, we anticipate utilizing our credit availability to provide additional liquidity as needed.

~~Commodity Prices~~ – 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 prices and are beyond our control. As

To mitigate some of the risk inherent in prices, we utilize various derivative financial instruments to protect a ~~result, entering into 2017 we have hedged approximately 50%~~portion of our ~~oil and 45%~~production against downside price risk. We hedge 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 ~~our gas production.~~favorable market conditions. The key

~~Table of Contents~~

~~Index to Financial Statements~~

terms to our oil, gas and NGL derivative financial instruments as of December 31, ~~2016~~2019 are presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.

Further, when considering the current commodity price environment and our current hedge position, we expect to achieve our capital investment priorities. Should WTI drop closer to $45/Bbl for an extended period, we would shift our focus to preserving our financial strength and operational continuity. However, as WTI/Bbl rises above $50, our free cash flow will accelerate, providing additional capital allocation opportunities.

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.

~~Interest Rates~~ ~~– Our operating cash flow can also be impacted by interest rate fluctuations. As of December 31, 2016,~~In 2019, we ~~had total debt of $10.2 billion. Of this amount, $10.0 billion bears fixed interest rates averaging 5.3%,~~aggressively optimized our cost structure in conjunction with our Canadian and ~~approximately $150 million is comprised of floating rate debt~~Barnett Shale asset divestitures, as we focus on our remaining four U.S. oil plays, align our workforce with ~~interest rates averaging 2.5%.~~

~~As of December 31, 2016, we had open interest rate swap positions that are presented in Note 3 in “Item 8. Financial Statements~~the retained business and ~~Supplementary Data” in this report.~~reduce outstanding debt. These optimizations include cost reductions and efficiencies related to our capital programs, G&A, financing costs 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~~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.

~~As recent years indicate,~~37

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Index to Financial Statements

Divestitures of Property and Equipment

In December 2019, we ~~have a history of investing more than 100%~~announced the sale of our ~~operating cash flow into capital development activities~~Barnett Shale assets for approximately $770 million. We expect this transaction to ~~grow our company and maximize value for our shareholders. Therefore, negative movements~~close in ~~any~~the second quarter of the variables discussed above would not only impact our operating cash flow but also would likely impact the amount of capital investment we could or would make. In the current environment, assuming current pricing expectations, our 2017 exploration and development capital budget is expected to be approximately $2.0 billion to $2.3 billion.

At the end of 2016, we held approximately $2.0 billion of cash. Included in this total was $644 million of cash held by our foreign subsidiaries. If we were to repatriate a portion or all of the cash held by our foreign subsidiaries, we would recognize and pay current income taxes in accordance with current U.S. tax law. The payment of such additional income tax would decrease the amount of cash ultimately available to fund our business.2020.

Credit Availability

We have a $3.0 billion of available borrowing capacity under our Senior Credit ~~Facility. The~~Facility at December 31, 2019. On December 13, 2019, we entered into an amendment and extension agreement to, among other things, (i) effect the extension of the maturity date ~~for $30 million~~ of the Senior Credit Facility isfrom October ~~24, 2017. The~~5, 2023 to October 5, 2024 with respect to the consenting lenders and (ii) modify the maximum number of maturity ~~date for $164 million~~extension requests during the term of the Senior Credit Facility isfrom two to three. As a result of this amendment, the Senior Credit Facility matures on October ~~24, 2018. The~~5, 2024, with the option to extend the maturity date ~~for~~by two additional one-year periods subject to lender consent. Subsequent to October 5, 2023, the ~~remaining~~borrowing capacity decreases to $2.8 ~~billion is October 24, 2019. This credit facility~~billion. The Senior Credit Facility supports our $3.0 billion of short-term credit under our commercial paper program. As of December 31, ~~2016,~~2019, there were no borrowings under our commercial paper program. See Note 1413 in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion.

The Senior Credit Facility contains only one material financial covenant. This covenant requires us to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65%. The credit agreement defines total funded debt as funds received through the issuance of debt securities such as debentures, bonds, notes payable, credit facility borrowings and short-term commercial paper borrowings. In addition, total funded debt includes all obligations with respect to payments received in consideration for oil, gas and NGL production yet to be acquired or produced at the time of payment. Funded debt excludes our outstanding letters of credit and trade payables. The credit agreement defines total capitalization as the sum of funded debt and stockholders’ equity adjusted for noncash financial write-downs, such as full cost ceiling and goodwill impairments. As of December 31, ~~2016,~~2019, we were in compliance with this ~~covenant. Our~~covenant with a 19.1% debt-to-capitalization ~~ratio at December 31, 2016, as calculated pursuant to the terms of the agreement, was 18.7%.~~ratio.

~~Table of Contents~~

~~Index to Financial Statements~~

Our access to funds from the Senior Credit Facility is not restricted under any “material adverse effect” clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments or the enforceability of material terms of the creditagreement. While our credit facility includes covenants that require us to report a condition or event having a material adverse effect, the obligation of the banks to fund the credit facility is not conditioned on the absence of a material adverse effect.

As market conditions warrant and subject to our contractual restrictions, liquidity position and other factors, we may from time to time seek to repurchase or retire our outstanding debt through cash purchases and/or exchanges for other debt or equity securities in open market transactions, privately negotiated transactions, by tender offer or otherwise. Any such cash repurchases by us may be funded by cash on hand or incurring new debt. The amounts involved in any such transactions, individually or in the aggregate, may be material. Furthermore, any such repurchases or exchanges may result in our acquiring and retiring a substantial amount of such indebtedness, which would impact the trading liquidity of such indebtedness.

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. ~~In February 2016, our~~Our credit rating ~~was revised by~~from Standard &and Poor’s Financial Services ~~from BBB+~~is BBB- with a ~~negative outlook to~~stable outlook. Our credit rating from Fitch is BBB with a stable ~~outlook, and~~outlook. Our credit rating from Moody’s Investor Service ~~revised our senior unsecured rating from Baa1~~is Ba1 with a ~~stable outlook to Ba2 with negative~~positive outlook. In March 2016, Fitch Ratings affirmed our BBB+ rating but revised our outlook from stable to negative. Further, in July 2016, Moody’s revised the outlook to stable. The downgrade in ratings required us to post letters of credit and cash collateral as financial assurance of performance under certain contractual arrangements. Any ~~further~~ 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 of our ~~or EnLink’s~~ contractual debt obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. However, ~~these downgrades~~a downgrade could adversely impact our ~~and EnLink’s~~ interest rate on any credit facility borrowings and the ability to economically access debt markets in the future.

Share Repurchase Program

In December 2019, our Board of Directors approved a $1.0 billion share repurchase program that expires on December 31, 2020. This repurchase program was approved in conjunction with the announced divestiture of Devon’s assets in the Barnett Shale. Under this new program, $800 million of the $1.0 billion authorization is conditioned upon the closing of the pending Barnett Shale divestiture.

Table of Contents

Index to Financial Statements

Capital Expenditures

~~Excluding EnLink,~~Our 2020 exploration and development budget is expected to be approximately $1.7 billion to $1.85 billion.

In December 2019, we announced a partnership under which we will monetize half our ~~2017 capital expenditures~~working interest across 133 undrilled locations in the STACK for an approximate $100 million drilling carry spread over the next four years. Drilling operations under this agreement are expected to range from $2.3 billion to $2.7 billion, including $2.0 billion to $2.3 billion for our exploration and development capital program. To a certain degree, the ultimate timing of these capital expenditures is within our control. Therefore, if commodity prices fluctuate from our current estimates, we could choose to defer a portion of these planned 2017 capital expenditures until later periods or accelerate capital expenditures planned for periods beyond 2017 to achieve the desired balance between sources and uses of liquidity. Based upon current price expectations for 2017, available cash balances and credit availability, we anticipate having adequate capital resources to fund our 2017 capital expenditures.

~~EnLink Liquidity~~

~~EnLink has a $1.5 billion unsecured revolving credit facility. The General Partner has a $250 million revolving credit facility. As of December 31, 2016, there were $12 million~~commence in outstanding letters of credit and $120 million borrowed under the $1.5 billion credit facility and $28 million outstanding borrowings under the $250 million credit facility. All of EnLink’s and the General Partner’s debt is non-recourse to Devon.mid-2020.

~~Table of Contents~~

~~Index to Financial Statements~~

EnLink’s 2017 capital budget includes approximately $610 million to $770 million of identified growth projects. EnLink’s primary capital projects for 2017 include construction of the Lobo II plant and gathering system in the Delaware Basin, completing construction of an NGL pipeline in Louisiana and development of its Tall Oak assets.

EnLink expects to fund the growth capital expenditures from the proceeds of borrowings under its bank credit facility and proceeds from other debt and equity sources. EnLink expects to fund its 2017 maintenance capital expenditures from operating cash flows. EnLink employs a strategy that includes maintaining stable operating cash flows that are supported by long-term, fixed-fee contracts. Approximately 97% of EnLink’s cash flows were generated from fee-based services in 2016. In 2017, it is possible that not all of the planned projects will be commenced or completed. EnLink’s ability to pay distributions to its unitholders, fund planned capital expenditures and make acquisitions will depend upon its future operating performance, which will be affected by prevailing economic conditions in the industry and financial, business and other factors, some of which are beyond its control.

Contractual Obligations

The following table presents a summary of our contractual obligations as of December 31, ~~2016.~~2019.

Payments Due by Period

Total

Less Than 1 Year

1-3 Years

3-5 Years

More Than 5 Years

(Millions)

Devon obligations:

Debt ⁽¹⁾

$
6,933

$
—

$
277

$
500

$
6,156

Interest expense ⁽²⁾

6,579

390

771

752

4,666

Purchase obligations ⁽³⁾

2,949

609

1,411

929

—

Operational agreements ⁽⁴⁾

4,726

545

914

600

2,667

Operational agreements with EnLink ⁽⁵⁾

1,589

600

847

142

—

Asset retirement obligations ⁽⁶⁾

1,258

46

143

163

906

Drilling and facility obligations ⁽⁷⁾

388

76

133

94

85

Lease obligations ⁽⁸⁾

371

50

168

98

55

Other ⁽⁹⁾

202

202

—

—

—

Total Devon obligations

24,995

2,518

4,664

3,278

14,535

EnLink obligations:

Debt ⁽¹⁾

3,311

—

428

120

2,763

Interest expense⁽²⁾

1,966

144

283

267

1,272

Other ⁽⁹⁾

794

313

334

35

112

Total EnLink obligations

6,071

457

1,045

422

4,147

Total obligations

$
31,066

$
2,975

$
5,709

$
3,700

$
18,682

	Payments Due by Period
	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
Continuing Operations
Debt ⁽¹⁾	$	4,349	$	—	$	—	$	—	$	4,349
Interest expense ⁽²⁾		4,513		259		518		518		3,218
Operational agreements ⁽³⁾		1,468		320		431		301		416
Asset retirement obligations ⁽⁴⁾		398		18		13		25		342
Drilling and facility obligations ⁽⁵⁾		262		131		61		38		32
Lease obligations ⁽⁶⁾		426		51		53		24		298
Other ⁽⁷⁾		223		11		75		32		105
Total		11,639		790		1,151		938		8,760
Discontinued Operations
Barnett Shale obligations ⁽⁸⁾		271		35		63		46		127
Canadian obligations ⁽⁹⁾		347		55		69		55		168
Total		618		90		132		101		295
Total obligations	$	12,257	$	880	$	1,283	$	1,039	$	9,055

(1)	Debt amounts represent scheduled maturities of debt obligations at December 31, ~~2016,~~2019, excluding net discounts and debt issue costs included in the carrying value of debt.

(2)	Interest expense represents the scheduled cash payments on long-term fixed-rate debt.

(3)

Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at our heavy oil projects in Canada. We have entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in our ability to obtain condensate could negatively affect our ability to transport heavy oil at these locations. Our total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and our internal estimate of future condensate market prices.

~~(4)~~

Operational agreements represent commitments to transport or process certain volumes of oil, gas and NGLs for a fixed fee. We have entered into these agreements to aid the movement of our production to downstream markets.

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~~(5)~~

Operational agreements between Devon and EnLink represent fixed-fee gathering and processing and transportation agreements. These agreements also include minimum volume commitments that will remain in effect for approximately two more years, as well as annual rate escalators.

~~(6)~~(4)

Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31, ~~2016~~2019 balance sheet.

~~(7)~~(5)

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

~~(8)~~(6)

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

~~(9)~~

~~Other Devon obligations primarily relate to uncertain tax positions as discussed in~~ equipment. For additional information, see Note 714 in “Item 8. Financial Statements and Supplementary Data” of this report.

(7)	Other ~~EnLink~~ obligations primarily ~~consist of $500~~relate to various tax obligations.

(8)

Barnett Shale obligations primarily represent approximately $240 million of ~~future installment payments on~~asset retirement obligations and firm transportation agreements which will be transferred to BKV when the ~~Tall Oak acquisition as discussed~~divestiture of those assets close. The remainder of the Barnett Shale obligations relate to abandoned gas processing contracts which Devon retained in connection with the 2018 Barnett Shale divestitures. For additional information, see Note 2 18in “Item 8. Financial Statements and Supplementary Data” of this report.

(9)

Canadian obligations are related to a firm transportation agreement and office lease abandonments that were retained after Devon’s sale of substantially all of its oil and gas assets and operations in Canada. For additional information, see Note 18in “Item 8. Financial Statements and Supplementary Data” of this report.

Contingencies and Legal Matters

For a detailed discussion of contingencies and legal matters, see Note 19 in “Item 8. Financial Statements and Supplementary Data” of this report.

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Critical Accounting Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires us to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. We consider the following to be our most critical accounting estimates that involve judgment and have reviewed these critical accounting estimates with the Audit Committee of our Board of Directors.

~~Full Cost~~

Oil and Gas Assets Accounting, Classification, Reserves & Valuation

Successful Efforts Method of Accounting and ~~Proved~~ Classification

We utilize the successful efforts method of accounting for our oil and natural gas exploration and development activities which requires management’s assessment of the proper designation of wells and associated costs as developmental or exploratory. This classification assessment is dependent on the determination and existence of proved reserves, which is a critical estimate discussed in the section below. The classification of developmental and exploratory costs has a direct impact on the amount of costs we initially recognize as exploration expense or capitalize, then subject to DD&A calculations and impairment assessments and valuations.

Once a well is drilled, the determination that proved reserves have been discovered may take considerable time and requires both judgment and application of industry experience. Development wells are always capitalized. Costs associated with drilling an exploratory well are initially capitalized, or suspended, pending a determination as to whether proved reserves have been found. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs to determine whether the costs should continue to remain capitalized or shall be expensed. When making this determination, management considers current activities, near-term plans for additional exploratory or appraisal drilling and the likelihood of reaching a development program. If management determines future development activities and the determination of proved reserves are unlikely to occur, the associated suspended exploratory well costs are recorded as dry hole expense and reported in exploration expense in the consolidated statements of comprehensive earnings. Otherwise, the costs of exploratory wells remain capitalized. At December 31, 2019, all suspended well costs have been suspended for less than one year.

Similar to the evaluation of suspended exploratory well costs, costs for undeveloped leasehold, for which reserves have not been proven, must also be evaluated for continued capitalization or impairment. At the end of each quarter, management assesses undeveloped leasehold costs for impairment by considering future drilling plans, drilling activity results, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. At December 31, 2019, Devon had approximately $250 million of undeveloped leasehold. Of the remaining undeveloped leasehold costs at December 31, 2019, approximately $6 million is scheduled to expire in 2020. The leasehold expiring in 2020 relates to areas in which Devon is actively drilling. If our drilling is not successful, this leasehold could become partially or entirely impaired.

Reserves

Our estimates of proved and proved developed reserves are a major component of ~~the depletion and full cost ceiling~~DD&A calculations. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Our engineers prepare our reserve estimates. We then subject certain of our reserve estimates to audits performed by a third-party petroleum consulting ~~firms.~~firm. In ~~2016, 89%~~2019, 85% of our reserves were subjected to such audits.

The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. In the past five years, annual performance revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged less than 5% of the previous year’s estimate. However, there can be no assurance that more significant revisions will not be necessary in the future. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

While the quantities of proved reserves require substantial judgment, the associated prices of oil, gas and NGL reserves, and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment. Applicable rules require future net revenues to be calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to the end of each quarterly period. Such

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~~rules also dictate that a 10% discount factor be used. Therefore, the discounted future net revenues associated with the estimated~~Valuation of Long-Lived Assets

Long-lived assets used in operations, including proved ~~reserves are not based on our assessment of future prices or costs or our enterprise risk.~~

~~Because the ceiling calculation dictates the use of prices that are not representative of future prices~~ and requires a 10% discount factor, the resulting value is not indicative of the true fair value of the reserves. Oil and gas prices have historically been cyclical and, for any particular 12-month period, can be either higher or lower than our long-term price forecast, which is a more appropriate input for estimating fair value. Therefore, oil and gas property write-downs that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.

Because of the volatile nature of oil and gas prices, it generally is not possible to predict the timing or magnitude of full cost write-downs. In addition, because of the inter-relationship of the various judgments made to estimate proved reserves, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates. However, decreases in estimates of proved reserves would generally increase our depletion rate and, thus, our depletion expense. Decreases in our proved reserves may also increase the likelihood of recognizing a full cost ceiling write-down.

Based on prices from the last nine months of 2016 and the short-term pricing outlook for the first quarter of 2017, we do not expect to recognize U.S. and Canadian full cost impairments in the first quarter of 2017.

~~Derivative Financial Instruments~~

We enter into derivative financial instruments with respect to a portion of our oil, gas and NGL production to hedge future prices received. Additionally, EnLink periodically enters into derivative financial instruments with respect to its oil, gas and NGL marketing activity. These commodity derivative financial instruments include financial price swaps, basis swaps, costless price collars and call options.

The estimates of the fair values of our derivative instruments require substantial judgment. We estimate the fair values of our commodity derivative financial instruments primarily by using internal discounted cash flow calculations. The most significant variable to our cash flow calculations is our estimate of future commodity prices. We base our estimate of future prices upon published forward commodity price curves such as the Inside FERC Henry Hub forward curve for gas instruments and the NYMEX WTI forward curve for oil instruments. Another key input to our cash flow calculations is our estimate of volatility for these forward curves, which we base primarily upon implied volatility. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted primarily using U.S. Treasury bill rates. These pricing and discounting variables are sensitive to the period of the contract and market volatility as well as changes in forward prices and regional price differentials.

We periodically enter into interest rate swaps to manage our exposure to interest rate volatility. We estimate the fair values of our interest rate swap financial instruments primarily by using internal discounted cash flow calculations based upon forward interest rate yields. The most significant variable to our cash flow calculations is our estimate of future interest rate yields. We base our estimate of future yields upon our own internal model that utilizes forward curves such as the LIBOR or the Federal Funds Rate provided by third parties. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted using the LIBOR and money market futures rates. These yield and discounting variables are sensitive to the period of the contract and market volatility.

We periodically enter into foreign exchange forward contracts to manage our exposure to fluctuations in exchange rates. Under the terms of our foreign exchange forward contracts, we generally receive U.S. dollars and pay Canadian dollars based on a total notional amount. We estimate the fair values of our foreign exchange forward contracts primarily by using internal discounted cash flow calculations based upon forward exchange rates. The most significant variable to our cash flow calculations is our observation of forward foreign exchange rates. The resulting future cash inflows or outflows at maturity of the contracts are discounted using Treasury rates. These discounting variables are sensitive to the period of the contract and market volatility.

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~~We periodically validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties.~~

Counterparty credit risk has not had a significant effect on our cash flow calculations and derivative valuations. This is primarily the result of two factors. First, we have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Our oil, gas and NGL commodity derivative contracts are held with thirteen separate counterparties. Second, our derivative contracts generally require cash collateral to be posted if either our or the counterparty’s credit rating falls below certain credit rating levels.

Because we have chosen not to qualify our derivatives for hedge accounting treatment, changes in the fair values of derivatives can have a significant impact on our reported results of operations. Generally, changes in derivative fair values will not impact our liquidity or capital resources.

Settlements of derivative instruments, regardless of whether they qualify for hedge accounting, do have an impact on our liquidity and results of operations. Generally, if actual market prices are higher than the price of the derivative instruments, our net earnings and cash flow from operations will be lower relative to the results that would have occurred absent these instruments. The opposite is also true. Additional information regarding the effects that changes in market prices can have on our derivative financial instruments, net earnings and cash flow from operations is included in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of this report.

~~Business Combinations~~

Accounting for the acquisition of a business requires the assets and liabilities of the acquired business to be recorded at fair value. Deferred taxes are recorded for any differences between the fair value and the tax basis of the acquired assets and liabilities. Any excess of the purchase price over the fair values of the tangible and intangible net assets acquired is recorded as goodwill.

There are various assumptions we make in determining the fair values of an acquired company’s assets and liabilities. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of theunproved oil and gas properties, ~~acquired. To determine the fair values of these properties, we prepare estimates of oil, natural gas~~are depreciated and ~~NGL reserves. These estimates are~~assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For DD&A calculations and impairment assessments, management groups individual assets based on ~~work performed by our engineers and that~~a judgmental assessment of ~~outside consultants. The judgments associated with these estimated reserves are described earlier in this section in connection with~~ the ~~full cost ceiling calculation.~~

~~However,~~lowest level (“common operating field”) for which there are ~~factors involved~~identifiable cash flows that are largely independent of the cash flows of other groups of assets. The determination of common operating fields is largely based on geological structural features or stratigraphic condition, which requires judgment. Management also considers the nature of production, common infrastructure, common sales points, common processing plants, common regulation and management oversight to make common operating field determinations. These determinations impact the amount of DD&A recognized each period and could impact the determination and measurement of a potential asset impairment.

Management evaluates assets for impairment through an established process in ~~estimating~~which changes to significant assumptions such as prices, volumes and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair ~~values~~value. Because there usually is a lack of acquired oil, natural gas and NGL properties that require more judgment than that involved in the full cost ceiling calculation. As stated above, the full cost ceiling calculation applies a historical 12-month average price to the reserves to arrive at the ceiling amount. By contrast,quoted market prices for long-lived assets, the fair value of ~~reserves acquired in a business combination must be~~impaired assets is typically determined based on ~~our estimates~~the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future ~~oil, natural gas~~production volumes, commodity prices, operating costs and NGL prices. Our estimates of future prices are based on our own analysis of pricing trends. These estimates are based on current data obtained with regard to regional and worldwide supply and demand dynamics such as economic growth forecasts. They are also based on industry data regarding natural gas storage availability, drilling rig activity, changes in delivery capacity, trends in regional pricing differentials and other fundamental analysis. Forecasts of future prices from independent third parties are noted when we make our pricing estimates.

We estimate future prices to apply to the estimated reserve quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are then discounted using a rate determined appropriatecapital investment plans, considering all available information at the ~~time~~date of ~~the business combination based upon our cost of capital.~~

~~We also apply these same general principles to estimate the fair value of unproved properties acquired in a business combination. These unproved properties generally represent the value of~~review. The expected future cash flows used for impairment reviews include future production volumes associated with proved producing and risk-adjusted proved undeveloped, probable and possible reserves. ~~Because of their very nature, probable and possible reserve estimates are more imprecise than those of proved reserves. To compensate for~~Besides the inherent risk of estimating and valuing unproved reserves, the discounted future net revenues of probable and possible reserves are reduced by what we consider to be an appropriate risk-weighting factor in each particular instance.

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In addition, our acquisitions have involved other entities whose operations included substantial midstream activities. In these transactions, the purchase price is allocated to the fair value of midstream facilities and equipment, generally consisting of processing facilities and pipeline systems. Estimating the fair value of these assets requires certain assumptions to be made regarding future quantities of commodities estimated to be processed and transported through these facilities and pipelines, as well as estimates of reserves and future ~~expected prices and operating and capital costs.~~

~~Goodwill~~

We test goodwill for impairment annually at October 31, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. While we use data as of October 31 for our test, we typically complete the test in late December or early January as the October 31 market data used in our test becomes available. We first assess the qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If we determine that it is more likely than not that its fair value is less than its carrying amount, then the two-step goodwill impairment test is performed.

In the first step of the impairment test, the fair value of a reporting unit is compared to its carrying value. Because quoted market prices are not available for our reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid. If the carrying value of a reporting unit exceeds its fair value, the second step of the impairment test is performed for purposes of measuring the impairment. In the second step, the fair value of the reporting unit is allocated to all of the assets and liabilities of the reporting unit to determine an implied goodwill value. This allocation is similar to a purchase price allocation. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of goodwill, an impairment loss is recognized in an amount equal to that excess. The determination of fair value requires judgment and involves the use of significant estimates and assumptions about expected future cash flows derived from internal forecasts and the impact of market conditions on those assumptions. Critical assumptions primarily include revenue growth rates driven byproduction volumes, future commodity prices ~~and volume expectations, operating margins and capital expenditures.~~

~~For~~are the October 31, 2016 impairment tests for Devon’s U.S. reporting unit and each of EnLink’s reporting units, step one of the impairment analyses showed that the fair value of each reporting unit exceeded its carrying value.

~~Sustained weakness~~largest driver in the ~~overall energy sector driven~~variability of undiscounted pre-tax cash flows. For our impairment determinations, we utilize the forward strip prices for the first five years and apply internally generated price forecasts for subsequent years. We estimate and escalate or de-escalate future capital and operating costs by ~~low~~using a method that correlates cost movements to price movements similar to recent history. Changes to any of these assumptions could result in lower undiscounted pre-tax cash flows and impact both the recognition and timing of impairments. Should management materially reduce planned capital investment and commodity prices ~~together with a decline in the EnLink unit price, caused a change in circumstances warranting an interim impairment test~~remain depressed, recognition of material asset impairments could become more likely for ~~EnLink’s reporting units in the first quarter~~certain of 2016. Using the fair value approaches described above, in the first quarter of 2016 it was determined that the estimated fair value of EnLink’s Texas, General Partner and Crude and Condensate reporting units were less than their carrying amounts, primarily due to changes in assumptions related toour assets.

As commodity prices decreased throughout 2019 and ~~discount rates. Through~~at year-end approximated the ~~analysis,~~prices Devon used to determine and compute material asset impairments in 2019, management conducted a ~~goodwill~~robust review of its assets for impairment ~~loss of $473 million, $307 million and $93 million for EnLink’s Texas, General Partner and Crude and Condensate reporting units, respectively, was recognized in the first quarter of 2016.~~

As of March 31, 2016, the goodwill allocated to the Crude and Condensate reporting unit was fully impaired. Other than those mentioned above, no other goodwill impairment was identified or recorded for the remaining reporting units as a result of the interim goodwill assessment, as their estimated fair values were in excess of carrying values. However, the fair value of EnLink’s Texas and General Partner reporting units are not substantially in excess of their carrying value. The fair value of the Texas and General Partner reporting units approximates their carrying values after considering the impairment loss above, and as of December 31, ~~2016, $233 million and $1.1 billion~~2019. Based on our recent impairment evaluations, our STACK asset’s sum of ~~goodwill remains allocated to the reporting units, respectively.~~

Our impairment determinations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual future results are not consistent with these assumptions and estimates, or the assumptions and estimates change due to new information, we may be exposed to additional goodwill impairment charges, which would be

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~~recognized in the period in which we would determine that~~undiscounted pre-tax cash flows exceeds the carrying value ~~exceeds fair value. We would expect that a prolonged or sustained period~~by less than 10%. This cushion has narrowed significantly since the end of ~~lower~~2018 due primarily to approximately 30% and 5% declines in forward NGL and natural gas pricing, respectively, and negative non-price reserve revisions of approximately 40 MMBoe as discussed in Note 21 in “Item 8. Financial Statements and Supplementary Data” of this report.As of December 31, 2019, the difference between the STACK’s undiscounted pre-tax cash flows, which is used to determine whether an impairment exists, and the discounted pre-tax cash flows, which is used to measure an impairment, is approximately $2.0 billion. Therefore, if commodity prices ~~would adversely affect~~deteriorate or we materially reduce future development plans, causing the ~~estimate of future operating results, which could result in future goodwill impairments for other reporting units due~~capitalized costs to exceed the ~~potential impact on the~~undiscounted pre-tax cash flows, of our ~~operations.~~

~~The~~STACK asset would be subject to a material impairment of ~~goodwill has no effect on liquidity or capital resources. However, it adversely affects our results of operations in the period recognized.~~

~~Other Intangible Assets~~

In 2015, the assessment of customer relationships was updated due to the factors described in the aforementioned goodwill section. This assessment resulted in a $223 million impairment of other intangible assets related to EnLink’s Crude and Condensate reporting unit. Level 3 fair value measurements were utilized for the impairment analysis of definite-lived intangible assets, which included discounted cash flow estimates, consistent with those utilized in the goodwill impairment assessment.

~~The other intangible assets impairment has no effect on liquidity or capital resources. However, it adversely affects our results of operations in the period recognized.~~capitalized costs.

Income Taxes

The amount of income taxes recorded requires interpretations of complex rules and regulations of federal, state, provincial and foreign tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. ~~At the end~~Within continuing operations, Devon maintains only a valuation allowance against a portion of ~~2016 and 2015, we had~~its deferred tax assets, ~~that largely resulted from the full cost impairments recognized throughout 2015~~including certain tax credits and ~~2016. As a result of our recent cumulative losses and our current realization assessment, we~~state net operating losses. Devon also has recorded a ~~100%~~ valuation allowance ~~against our U.S. deferred tax assets as of December 31, 2016 and December 31, 2015. Further,~~ in ~~2016, we recorded a $69 million valuation allowance~~discontinued operations against certain Canadian deferred tax ~~assets as a result of continued financial losses.~~ 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 on the progress of ongoing audits, changes in legislation or resolution of pending matters.

We also assess factors relative to whether our foreign earnings are considered indefinitely reinvested. These factors include forecasted and actual results for both our U.S. and Canadian operations, borrowing conditions in the U.S. and existing U.S. income tax laws, particularly the laws pertaining to the deductibility of intangible drilling costs and repatriations of foreign earnings. Changes in any of these factors could require recognition of additional deferred, or even current, U.S. income tax expense. We accrue deferred U.S. income tax expense on our foreign earnings when the factors indicate that these earnings are no longer considered indefinitely reinvested.

For our foreign earnings deemed indefinitely reinvested, we do not calculate a hypothetical deferred tax liability on these earnings. Calculating a hypothetical tax on these accumulated earnings is much different from the calculation of the deferred tax liability on our earnings deemed not indefinitely reinvested. A hypothetical tax calculation on the indefinitely reinvested earnings would require the following additional activities:

~~separate analysis of a diverse chain of foreign entities;~~

~~relying on tax rates on a future remittance that could vary significantly depending on alternative approaches available to repatriate the earnings;~~

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determining the nature of a yet-to-be-determined future remittance, such as whether the distribution would be a non-taxable return of capital or a distribution of taxable earnings and calculation of associated withholding taxes, which would vary significantly depending on the circumstances at the deemed time of remittance; and

further analysis of a variety of other inputs such as the earnings, profits, U.S./foreign country tax treaty provisions and the related foreign taxes paid by our foreign subsidiaries, whose earnings are deemed permanently reinvested, over a lengthy history of operations.

Because of the administrative burden required to perform these additional activities, it is impractical to calculate a hypothetical tax on the foreign earnings associated with this separate and more complicated chain of companies.

Non-GAAP Measures

Core Earnings

We make reference to “core earnings (loss) attributable to Devon” and “core earnings (loss) per share attributable to Devon” in “Overview of ~~2016~~2019 Results” in this Item 7.7 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 ~~alternatives to GAAP measures.~~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 ~~or non-recurring~~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 Barnett Shale assets, Canadian operations and for EnLink and the General Partner, see Note 18 in “Item 8. Financial Statements and Supplementary Data” in this report. Our non-GAAP measures are typically used as a quarterly performance measure. Items may appear to be recurring when comparing on an annual basis. In the table below, restructuring and transaction costs were incurred in each of the three year periods; however, these costs relate to different restructuring programs. Amounts excluded for ~~2016~~2019 relate to ~~derivatives and financial instrument fair value changes,~~asset dispositions, the gain on the sale of Canadian operations, noncash asset impairments (including ~~an impairment of goodwill)~~noncash Barnett Shale and unproved asset impairments), deferred tax asset valuation allowance, ~~gains and losses on asset sales,~~ costs associated with early retirement of debt, fair value changes in derivative financial instruments and foreign currency, restructuring and transaction costs associated with the workforce reductions in 2019 and restructuring and transaction costs associated with the ~~2016 workforce reduction.~~divestment of our Canadian operations in 2019.

Amounts excluded for ~~2015~~2018 relate to asset dispositions, the gain on the sale of Devon’s aggregate ownership interests in EnLink and the General Partner, noncash asset impairments (including noncash unproved asset impairments), deferred tax asset valuation allowance, costs associated with early retirement of debt, fair value changes in derivative financial instruments and foreign currency, restructuring and transaction costs associated with the workforce reductions in 2018.

Amounts excluded for 2017 relate to asset dispositions, noncash asset impairments (including noncash unproved asset impairments), U.S. tax reform changes, deferred tax asset valuation allowance, derivatives and financial instrument fair value changes, ~~asset impairments (including an impairment of goodwill), deferred tax asset valuation allowance,~~legal entity restructuring and ~~transaction costs and repatriation of funds to the U.S.~~

~~Amounts excluded for 2014 relate to derivatives and financial instrument fair value changes, asset impairments (including an impairment of goodwill), gains and losses on asset sales,~~ costs associated with early retirement of debt, restructuring and transaction costs associated with our 2014 divestiture program, repatriation of proceeds to the U.S. and deferred income tax on the formation of the General Partner. For more information on our restructuring programs, see Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.debt.

We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates published by securities ~~analysts, which typically make similar adjustments in their estimates of our financial results.~~analysts. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers.

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Below are reconciliations of our core earnings and earnings per share to their comparable GAAP measures.

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	Before tax			After tax			After Noncontrolling Interests			Per Diluted Share
2019
Continuing Operations
Loss attributable to Devon (GAAP)	$	(109	)	$	(79	)	$	(81	)	$	(0.21	)
Adjustments:
Asset dispositions		(48	)		(37	)		(37	)		(0.09	)
Asset and exploration impairments		20			15			15			0.04
Fair value changes in financial instruments		623			480			480			1.19
Restructuring and transaction costs		84			64			64			0.15
Core earnings attributable to Devon (Non-GAAP)	$	570		$	443		$	441		$	1.08
Discontinued Operations
Loss attributable to Devon (GAAP)	$	(632	)	$	(274	)	$	(274	)	$	(0.68	)
Adjustments:
Gain on sale of Canadian operations		(223	)		(425	)		(425	)		(1.05	)
Asset and exploration impairments		785			613			613			1.52
Deferred tax asset valuation allowance		—			24			24			0.06
Early retirement of debt		58			45			45			0.11
Fair value changes in financial instruments and foreign currency and other		(33	)		(37	)		(37	)		(0.10	)
Restructuring and transaction costs		248			183			183			0.45
Core earnings attributable to Devon (Non-GAAP)	$	203		$	129		$	129		$	0.31
Total
Loss attributable to Devon (GAAP)	$	(741	)	$	(353	)	$	(355	)	$	(0.89	)
Adjustments:
Continuing Operations		679			522			522			1.29
Discontinued Operations		835			403			403			0.99
Core earnings attributable to Devon (Non-GAAP)	$	773		$	572		$	570		$	1.39
2018
Continuing Operations
Earnings attributable to Devon (GAAP)	$	944		$	714		$	714		$	1.42
Adjustments:
Asset dispositions		(278	)		(214	)		(214	)		(0.42	)
Asset and exploration impairments		257			198			198			0.40
Deferred tax asset valuation allowance		—			(4	)		(4	)		(0.01	)
Early retirement of debt		312			240			240			0.48
Fair value changes in financial instruments		(938	)		(723	)		(723	)		(1.45	)
Restructuring and transaction costs		97			76			76			0.15
Core earnings attributable to Devon (Non-GAAP)	$	394		$	287		$	287		$	0.57
Discontinued Operations
Earnings attributable to Devon (GAAP)	$	2,839		$	2,510		$	2,350		$	4.68
Adjustments:
Asset dispositions		(2,593	)		(2,250	)		(2,250	)		(4.49	)
Fair value changes in financial instruments and foreign currency		339			277			270			0.54
Minimum volume commitment and restructuring and transaction costs		(31	)		(27	)		(2	)		(0.00	)
Core earnings attributable to Devon (Non-GAAP)	$	554		$	510		$	368		$	0.73
Total
Earnings attributable to Devon (GAAP)	$	3,783		$	3,224		$	3,064		$	6.10
Adjustments:
Continuing Operations		(550	)		(427	)		(427	)		(0.85	)
Discontinued Operations		(2,285	)		(2,000	)		(1,982	)		(3.95	)
Core earnings attributable to Devon (Non-GAAP)	$	948		$	797		$	655		$	1.30

Table of Contents

Index to Financial Statements

Year Ended December 31,

Before tax

After tax

After Noncontrolling Interests

Per Share

2016

Loss attributable to Devon (GAAP)
$
(3,877
)

$
(3,704
)

$
(3,302
)

$
(6.52
)
Adjustments:

Gains and losses on asset sales

(1,890
)

(1,243
)

(1,249
)

(2.44
)
Asset impairments

4,996

3,599

3,176

6.28

Deferred tax asset valuation allowance

—

851

851

1.66

Restructuring and transaction costs

267

173

170

0.33

Fair value changes in financial
   instruments and foreign currency

270

153

145

0.28

Early retirement of debt

269

171

171

0.33

Core earnings (loss) attributable to Devon
   (Non-GAAP)
$
35

$
—

$
(38
)

$
(0.08
)
2015

Loss attributable to Devon (GAAP)
$
(21,268
)

$
(15,203
)

$
(14,454
)

$
(35.55
)
Adjustments:

Asset impairments

20,820

13,923

13,100

32.18

Deferred tax asset valuation allowance

—

967

967

2.37

Restructuring and transaction costs

78

52

52

0.13

Fair value changes in financial
   instruments and foreign currency

1,967

1,349

1,346

3.31

Repatriations

—

33

33

0.08

Core earnings attributable to Devon (Non-GAAP)
$
1,597

$
1,121

$
1,044

$
2.52

2014

Earnings attributable to Devon (GAAP)
$
4,059

$
1,691

$
1,607

$
3.91

Adjustments:

Gains and losses on asset sales

(1,072
)

(625
)

(625
)

(1.52
)
Asset impairments

1,953

1,948

1,948

4.74

Restructuring and transaction costs

46

35

35

0.08

Fair value changes in financial
   instruments and foreign currency

(1,828
)

(1,139
)

(1,132
)

(2.75
)
Investment in General Partner deferred income tax

—

48

48

0.12

Repatriations

—

105

105

0.26

Early retirement of debt

48

31

31

0.07

Core earnings attributable to Devon (Non-GAAP)
$
3,206

$
2,094

$
2,017

$
4.91

	Before tax			After tax			After Noncontrolling Interests			Per Diluted Share
2017
Continuing Operations
Earnings attributable to Devon (GAAP)	$	40		$	33		$	33		$	0.06
Adjustments:
Asset dispositions		(219	)		(140	)		(140	)		(0.27	)
Asset and exploration impairments		217			138			138			0.26
Deferred tax asset valuation allowance		—			(4	)		(4	)		(0.01	)
Fair value changes in financial instruments		70			45			45			0.09
Core earnings attributable to Devon (Non-GAAP)	$	108		$	72		$	72		$	0.13
Discontinued Operations
Earnings attributable to Devon (GAAP)	$	856		$	1,045		$	865		$	1.64
Adjustments:
U.S. tax reform		—			(211	)		(112	)		(0.21	)
Fair value changes in financial instruments and foreign currency		(289	)		(248	)		(248	)		(0.47	)
Asset dispositions, impairments and early retirement of debt		11			9			7			0.01
Legal entity restructuring and deferred tax asset valuation allowance		—			(157	)		(157	)		(0.29	)
Core earnings attributable to Devon (Non-GAAP)	$	578		$	438		$	355		$	0.68
Total
Earnings attributable to Devon (GAAP)	$	896		$	1,078		$	898		$	1.70
Adjustments:
Continuing Operations		68			39			39			0.07
Discontinued Operations		(278	)		(607	)		(510	)		(0.96	)
Core earnings attributable to Devon (Non-GAAP)	$	686		$	510		$	427		$	0.81

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Index to Financial Statements

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; DD&A; 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 generally 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 to EBITDAX and a further reconciliation to Field-Level Cash Margin.

	2019			2018			2017
Net earnings (loss) (GAAP)	$	(353	)	$	3,224		$	1,078
Net (earnings) loss from discontinued operations, net of tax		274			(2,510	)		(1,045	)
Financing costs, net		250			580			321
Income tax expense (benefit)		(30	)		230			7
Exploration expenses		58			128			346
Depreciation, depletion and amortization		1,497			1,228			1,008
Asset impairments		—			156			—
Asset dispositions		(48	)		(278	)		(219	)
Share-based compensation		83			104			121
Derivative and financial instrument non-cash valuation changes		623			(938	)		70
Restructuring and transaction costs		84			97			—
Accretion on discounted liabilities and other		5			54			(12	)
EBITDAX (non-GAAP)		2,443			2,075			1,675
Marketing revenues and expenses, net		(53	)		(33	)		46
Commodity derivative cash settlements		(170	)		420			(115	)
General and administration expenses, cash-based		392			470			524
Field-level cash margin (non-GAAP)	$	2,612		$	2,932		$	2,130

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Item 7A.Quantitative and ~~Qualitative~~Qualitative Disclosures about Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to our risk of loss arising from adverse changes in oil, gas and NGL prices, interest rates and foreign currency exchange rates. The following disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is the pricing applicable to our oil, gas and NGL production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our ~~U.S.~~gas and ~~Canadian gas~~NGL production. Pricing for oil and gas production has been volatile and unpredictable as discussed in “Item 1A. Risk Factors” of this report. Consequently, we ~~periodically~~systematically hedge a portion of our production through various financial transactions. The key terms to our oil and gas derivative financial instruments as of December 31, ~~2016~~2019 are presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.

The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At December 31, ~~2016,~~2019, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net ~~liability~~asset positions by ~~the following amounts:~~approximately $115 million.

10% Increase

10% Decrease

Gain (loss):

(Millions)

Gas derivatives

$
(67
)

$
64

Oil derivatives

$
(234
)

$
220

NGL derivatives

$
(1
)

$
1

Processing and fractionation derivatives

$
(3
)

$
3

Interest Rate Risk

At December 31, ~~2016,~~2019, we had total debt of ~~$10.2~~$4.3 billion. ~~Of this amount, $10.0 billion bears~~All of our debt is based on fixed interest rates averaging ~~5.3%, and approximately $150 million is comprised of floating rate debt with interest rates averaging 2.5%~~6.0%.

As of December 31, 2016, we had open interest rate swap positions that are presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report. The fair values of our interest rate swaps are largely determined by estimates of the forward curves of the three month LIBOR rate. A 10% change in these forward curves would not have materially impacted our balance sheet or liquidity at December 31, 2016.

Foreign Currency Risk

~~Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the~~Devon has certain Canadian dollar ~~functional currency. Assets and liabilities of~~obligations associated with its divested 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 December 31, ~~2016~~2019 balance ~~sheet.~~sheet for these items. See Note 18 in “Item 8. Financial Statements and Supplementary Data” in this report for additional information.

Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, some of our subsidiaries hold Canadian-dollar cash and engage in intercompany loans with Canadian subsidiaries that are based in Canadian dollars. The value of the Canadian-dollar cash and intercompany loans increases or decreases from the remeasurement of the cash and loans into the U.S. dollar functional currency. Based on the amount of the cash and

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Index to Financial Statements

~~intercompany loans as of December 31, 2016, a 10% change in the foreign currency exchange rates would not have materially impacted our balance sheet.~~

~~Table of Contents~~

~~Index to~~ Item 8.Financial Statements

~~Item 8.Financial Statemen~~ts and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

Report of Independent Registered Public Accounting Firm		5748

Consolidated Financial Statements
Consolidated ~~Comprehensive~~ Statements of Comprehensive Earnings		5851
Consolidated Statements of Cash Flows		5952
Consolidated Balance Sheets		6053
Consolidated Statements of ~~Stockholders’~~ Equity		6154
Notes to Consolidated Financial Statements		6255
Note 1 – Summary of Significant Accounting Policies		6255
Note 2 – ~~Acquisitions and~~ Divestitures		65
Note 3 – Derivative Financial Instruments		66
Note 4 – Share-Based Compensation		67
Note 5 – Asset Impairments		70
Note 36 – ~~Derivative Financial Instruments~~Restructuring and Transaction Costs		70
Note 7 – Income Taxes		71
Note 8 – Net Earnings (Loss) Per Share From Continuing Operations		74
Note 9 – Other Comprehensive Earnings		75
~~Note 4 – Share-Based Compensation~~		77
~~Note 5 – Asset Impairments~~		81
~~Note 6 – Restructuring and Transaction Costs~~		81
~~Note 7 – Income Taxes~~		83
~~Note 8 – Net Earnings (Loss) Per Share Attributable to Devon~~		87
~~Note 9 – Other Comprehensive Earnings~~		88
Note 10 – Supplemental Information to Statements of Cash Flows		8875
Note 11 – Accounts Receivable		8976
Note 12 – ~~Goodwill~~Property, Plant and ~~Other Intangible Assets~~Equipment		76
Note 13 – Debt and Related Expenses		8977
Note 1314 – ~~Other Current Liabilities~~Leases		79
Note 15 – Asset Retirement Obligations		81
Note 16 – Retirement Plans		82
Note 17 – Stockholders’ Equity		85
Note 18 – Discontinued Operations and Assets Held For Sale		87
Note 19 – Commitments and Contingencies		91
~~Note 14 – Debt and Related Expenses~~		92
~~Note 15 – Asset Retirement Obligations~~		95
~~Note 16 – Retirement Plans~~		95
~~Note 17 – Stockholders’ Equity~~		~~102~~
~~Note 18 – Noncontrolling Interests~~		~~103~~
~~Note 19 – Commitments and Contingencies~~		~~104~~
Note 20 – Fair Value Measurements		~~106~~93
Note 21 ~~– Segment Information~~		~~107~~
~~Note 22~~ – Supplemental Information on Oil and Gas Operations (Unaudited)		~~109~~94
Note 2322 – Supplemental Quarterly Financial Information (Unaudited)		~~121~~99

All financial statement schedules are omitted as they are inapplicable or the required information has been included in the consolidated financial statements or notes thereto.

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Index to Financial Statements

Report of Independent ~~Registered~~Registered Public Accounting Firm

~~The~~To the Stockholders and Board of Directors ~~and Stockholders~~

Devon Energy Corporation:

Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting

We have audited the accompanying consolidated balance sheets of Devon Energy Corporation and subsidiaries (the Company) as of December 31, ~~2016~~2019 and ~~2015, and~~2018, the related consolidated ~~comprehensive~~ statements of comprehensive earnings, ~~stockholders’~~ equity, and cash flows for each of the years in the three-year period ended December 31, ~~2016.~~2019, and the related notes (collectively, the consolidated financial statements). We also have audited ~~Devon Energy Corporation’s~~the Company’s internal control over financial reporting as of December 31, ~~2016,~~2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway ~~Commission (COSO)~~Commission.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019 based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Changes in Accounting Principles

As discussed in Note 14 to the consolidated financial statements, the Company has changed its method of accounting for leases in 2019 due to the adoption of Accounting Standards Update 2016-02, Leases (Topic 842). ~~Devon Energy Corporation’s~~

As discussed in Note 1 to the consolidated financial statements, the Company has changed its method of accounting for revenue in 2018 due to the adoption of Accounting Standards Codification 606, Revenue from Contracts with Customers (ASC 606).

Basis for Opinions

The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting contained in “Item 9A. Controls and ~~Procedures” of Devon Energy Corporation’s Annual Report on Form 10-K.~~Procedures.” Our responsibility is to express an opinion on ~~these~~the Company’s consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the ~~Public Company Accounting Oversight Board (United States).~~PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence ~~supporting~~regarding the amounts and disclosures in the consolidated financial ~~statements, assessing~~statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, ~~and~~as well as evaluating the overall presentation of the consolidated financial ~~statement presentation.~~statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the

Table of Contents

Index to Financial Statements

maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

~~In our opinion,~~

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements ~~referred~~that were communicated or required to ~~above present fairly,~~be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in ~~all material respects,~~any way our opinion on the consolidated financial ~~position~~statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Evaluation of ~~Devon Energy Corporation~~the estimate of proved and ~~subsidiaries~~unproved oil and gas reserves used to assess the recoverability of the carrying value of oil and gas properties in the STACK common operating field

As discussed in Notes 1, 5, and 12 to the consolidated financial statements, the Company performs recoverability tests for the carrying value of its proved oil and gas properties subject to amortization. The recoverability tests are performed on an annual basis or more often if events and circumstances indicate that the carrying value of such properties may not be recoverable. The determination of the undiscounted cash flows is driven by the underlying estimate of proved and unproved oil and gas reserves for oil and gas properties as determined by the Company’s internal reservoir engineers. Estimating common operating fields’ future cash flows requires the expertise of reservoir engineers who take into consideration the estimate of future production quantities, future operating and capital cost assumptions, and projected oil and gas prices inclusive of market differentials. The STACK common operating field had a carrying value of $3.7 billion as of December 31, ~~2016~~2019.

We identified the evaluation of the estimate of proved and ~~2015,~~unproved oil and gas reserves used to assess the recoverability of the carrying value of the STACK common operating field’s oil and gas properties as a critical audit matter. Based on current and forecasted commodity prices and costs, production volumes and drilling plans, and the ~~results~~risk adjustment factors associated with the unproved reserve volumes, the STACK common operating field required more judgment to evaluate the estimate of ~~its operations~~both proved and ~~its~~unproved oil and gas reserves used in determining undiscounted future net cash flows for ~~each~~the asset group.

The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s processes to develop and monitor the estimate of proved and unproved oil and gas reserves used to determine future cash flows. We assessed compliance of the ~~years~~methodology used by the Company’s internal reservoir engineers and external reservoir engineers to estimate proved and unproved oil and gas reserves with industry and regulatory standards. To assess the Company’s ability to accurately estimate future proved and unproved production quantities, we compared the future production quantity assumptions used by the Company in prior periods to the actual production amounts in the ~~three-year~~current year and the year-end forecasted future production quantities. We compared the estimated future proved and unproved production quantities used by the Company in the current period to historical production trends and investigated differences. In addition, we assessed the competence, objectivity, and capabilities of the Company’s internal reservoir engineers and third-party reservoir engineers. We read and considered the report of the Company’s external reservoir engineers in connection with our evaluation of the Company’s reserve estimates. We also tested the processes and methodologies used by internal reservoir engineers to estimate unproved future production quantities. We have compared the risk adjustment factors for unproved reserves selected by the Company by prospect to the guideline risk adjustment factor ranges by reserve class in published industry surveys. We have also evaluated the Company’s selected risk adjustment factors by evaluation of the proximity of the unproved reserves to proved producing reserves. We evaluated the future operating and capital cost assumptions used by the internal reservoir engineers to estimate future cash flows by comparing them to historical costs. We also tested the projected oil and gas prices used by the internal reservoir engineers to estimate future cash flows by comparing those prices to publicly available prices and tested the relevant market differentials based on past results and any contractual changes in marketing and/or transportation and processing agreements that would impact future cash flows to be received.

Table of Contents

Index to Financial Statements

Assessment of the estimate of proved oil and gas reserves used in the depletion of proved oil and gas properties

As discussed in Notes 1 and 12 to the consolidated financial statements, the Company calculates depletion for its proved oil and gas properties subject to amortization using a units-of-production method. The rates used to deplete the balance of oil and gas properties subject to amortization are set using the estimate of proved oil and gas reserves by common operating field. Under the units-of-production method, a rate is set annually using the beginning of year balance of oil and gas properties subject to amortization and estimated proved oil and gas reserves for each common operating field. That rate is then applied to production throughout the year to determine the amount of depletion expense to be recorded by common operating field. The Company’s internal reservoir engineers estimate proved oil and gas reserves, and the Company engages external reservoir engineers to perform an independent evaluation of a portion of the estimates of proved oil and gas reserves. These common operating fields had depletion expense of $1.4 billion for the year ended December 31, ~~2016,~~2019.

We identified the assessment of the estimate of proved oil and gas reserves used in ~~conformity~~the depletion of proved oil and gas properties as a critical audit matter. There was a high degree of subjectivity in evaluating the Company’s estimate of the proved oil and gas reserves used as an input to determine depletion for each common operating field.

The primary procedures we performed to address this critical audit matter including the following. We tested certain internal controls over the Company’s depletion expense calculation process, including controls related to the determination and monitoring of the estimate of proved oil and gas reserves. We analyzed the grouping of costs and proved oil and gas reserves by common operating field. We analyzed and assessed the determination of depletion expense for compliance with U.S. generally accepted accounting principles. Also in our opinion, Devon Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in ~~Internal Control – Integrated Framework~~ ~~issued~~industry and regulatory standards. To assess the Company’s ability to accurately estimate proved oil and gas reserves, we compared the estimated future production quantities assumptions used by the ~~Committee of Sponsoring Organizations~~Company in prior periods to the actual production amounts received and the year-end future production quantities forecasted. We compared the estimated future production quantities used by the Company in the current period to historical production trends and investigated differences. In addition, we assessed the competence, objectivity, and capabilities of the ~~Treadway Commission (COSO).~~Company’s internal reservoir engineers and the Company’s external reservoir engineers. We read and considered the report of the Company’s third-party reservoir engineers in connection with our evaluation of the Company’s reserve estimates.

/s/ KPMG LLP

We have served as the Company’s auditor since 1980.

Oklahoma City, Oklahoma

February ~~15, 2017~~19, 2020

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED ~~COMPREHENSIVE~~ STATEMENTS OF COMPREHENSIVE EARNINGS

Year Ended December 31,

2016

2015

2014

(Millions, except per share amounts)

Oil, gas and NGL sales

$
4,182

$
5,382

$
9,910

Oil, gas and NGL derivatives

(201
)

503

1,989

Marketing and midstream revenues

6,323

7,260

7,667

Asset dispositions and other

1,893

—

1,072

Total revenues and other

12,197

13,145

20,638

Lease operating expenses

1,582

2,104

2,332

Marketing and midstream operating expenses

5,492

6,420

6,815

General and administrative expenses

645

855

847

Production and property taxes

275

388

535

Depreciation, depletion and amortization

1,792

3,129

3,319

Asset impairments

4,975

20,820

1,953

Restructuring and transaction costs

267

78

46

Other operating items

64

78

93

Total operating expenses

15,092

33,872

15,940

Operating income (loss)

(2,895
)

(20,727
)

4,698

Net financing costs

904

517

526

Other nonoperating items

78

24

113

Earnings (loss) before income taxes

(3,877
)

(21,268
)

4,059

Income tax expense (benefit)

(173
)

(6,065
)

2,368

Net earnings (loss)

(3,704
)

(15,203
)

1,691

Net earnings (loss) attributable to noncontrolling interests

(402
)

(749
)

84

Net earnings (loss) attributable to Devon

$
(3,302
)

$
(14,454
)

$
1,607

Net earnings (loss) per share attributable to Devon:

Basic

$
(6.52
)

$
(35.55
)

$
3.93

Diluted

$
(6.52
)

$
(35.55
)

$
3.91

Comprehensive earnings (loss):

Net earnings (loss)

$
(3,704
)

$
(15,203
)

$
1,691

Other comprehensive earnings (loss), net of tax:

Foreign currency translation

32

(559
)

(465
)
Pension and postretirement plans

22

10

(24
)
Other comprehensive earnings (loss), net of tax

54

(549
)

(489
)
Comprehensive earnings (loss)

(3,650
)

(15,752
)

1,202

Comprehensive earnings (loss) attributable to
noncontrolling interests

(402
)

(749
)

84

Comprehensive earnings (loss) attributable to Devon

$
(3,248
)

$
(15,003
)

$
1,118

	Year Ended December 31,
	2019			2018			2017
	(Millions, except per share amounts)
Upstream revenues	$	3,355		$	4,542		$	2,988
Marketing and midstream revenues		2,865			4,354			3,513
Total revenues		6,220			8,896			6,501
Production expenses		1,197			1,153			791
Exploration expenses		58			128			346
Marketing and midstream expenses		2,812			4,321			3,559
Depreciation, depletion and amortization		1,497			1,228			1,008
Asset impairments		—			156			—
Asset dispositions		(48	)		(278	)		(219	)
General and administrative expenses		475			574			645
Financing costs, net		250			580			321
Restructuring and transaction costs		84			97			—
Other expenses		4			(7	)		10
Total expenses		6,329			7,952			6,461
Earnings (loss) from continuing operations before income taxes		(109	)		944			40
Income tax expense (benefit)		(30	)		230			7
Net earnings (loss) from continuing operations		(79	)		714			33
Net earnings (loss) from discontinued operations, net of income taxes		(274	)		2,510			1,045
Net earnings (loss)		(353	)		3,224			1,078
Net earnings attributable to noncontrolling interests		2			160			180
Net earnings (loss) attributable to Devon	$	(355	)	$	3,064		$	898
Basic net earnings (loss) per share:
Basic earnings (loss) from continuing operations per share	$	(0.21	)	$	1.43		$	0.06
Basic earnings (loss) from discontinued operations per share		(0.68	)		4.71			1.65
Basic net earnings (loss) per share	$	(0.89	)	$	6.14		$	1.71
Diluted net earnings (loss) per share:
Diluted earnings (loss) from continuing operations per share	$	(0.21	)	$	1.42		$	0.06
Diluted earnings (loss) from discontinued operations per share		(0.68	)		4.68			1.64
Diluted net earnings (loss) per share	$	(0.89	)	$	6.10		$	1.70
Comprehensive earnings (loss):
Net earnings (loss)	$	(353	)	$	3,224		$	1,078
Other comprehensive earnings (loss), net of tax:
Foreign currency translation, discontinued operations		78			(152	)		83
Release of Canadian cumulative translation adjustment, discontinued operations		(1,237	)		—			—
Pension and postretirement plans		13			44			29
Other comprehensive earnings (loss), net of tax		(1,146	)		(108	)		112
Comprehensive earnings (loss):		(1,499	)		3,116			1,190
Comprehensive earnings attributable to noncontrolling interests		2			160			180
Comprehensive earnings (loss) attributable to Devon	$	(1,501	)	$	2,956		$	1,010

See accompanying notes to consolidated financial statements.

5851

Table of Contents

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2019			2018			2017
Cash flows from operating activities:
Net earnings (loss)	$	(353	)	$	3,224		$	1,078
Adjustments to reconcile net earnings (loss) to net cash from operating activities:
Net (earnings) loss from discontinued operations, net of income taxes		274			(2,510	)		(1,045	)
Depreciation, depletion and amortization		1,497			1,228			1,008
Asset impairments		—			156			—
Leasehold impairments		18			94			219
Accretion on discounted liabilities		33			27			27
Total (gains) losses on commodity derivatives		454			(457	)		(66	)
Cash settlements on commodity derivatives		166			(420	)		115
Gains on asset dispositions		(48	)		(278	)		(219	)
Deferred income tax expense (benefit)		(25	)		247			(2	)
Share-based compensation		115			137			126
Early retirement of debt		—			312			—
Other		(6	)		(19	)		(8	)
Changes in assets and liabilities, net		(82	)		(158	)		10
Net cash from operating activities - continuing operations		2,043			1,583			1,243
Cash flows from investing activities:
Capital expenditures		(1,910	)		(2,116	)		(1,614	)
Acquisitions of property and equipment		(31	)		(55	)		(44	)
Divestitures of property and equipment		390			500			425
Net cash from investing activities - continuing operations		(1,551	)		(1,671	)		(1,233	)
Cash flows from financing activities:
Repayments of long-term debt		(162	)		(922	)		—
Early retirement of debt		—			(304	)		—
Repurchases of common stock		(1,849	)		(2,956	)		—
Dividends paid on common stock		(140	)		(149	)		(127	)
Contributions from noncontrolling interests		116			—			—
Shares exchanged for tax withholdings		(25	)		(39	)		(46	)
Other		(1	)		(7	)		—
Net cash from financing activities - continuing operations		(2,061	)		(4,377	)		(173	)
Net change in cash, cash equivalents and restricted cash of continuing operations		(1,569	)		(4,465	)		(163	)
Cash flows from discontinued operations:
Operating activities		28			1,121			1,666
Investing activities		2,472			2,726			(966	)
Financing activities		(1,578	)		174			182
Effect of exchange rate changes on cash		45			206			6
Net change in cash, cash equivalents and restricted cash of discontinued operations		967			4,227			888
Net change in cash, cash equivalents and restricted cash		(602	)		(238	)		725
Cash, cash equivalents and restricted cash at beginning of period		2,446			2,684			1,959
Cash, cash equivalents and restricted cash at end of period	$	1,844		$	2,446		$	2,684

Reconciliation of cash, cash equivalents and restricted cash:
Cash and cash equivalents	$	1,464		$	2,414		$	2,642
Cash restricted for discontinued operations		380			—			—
Restricted cash included in other current assets		—			32			11
Cash and cash equivalents included in current assets associated with discontinued operations		—			—			31
Total cash, cash equivalents and restricted cash	$	1,844		$	2,446		$	2,684

See accompanying notes to consolidated financial statements.

Table of Contents

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

Year Ended December 31,

2016

2015

2014

(Millions)

Cash flows from operating activities:

Net earnings (loss)

$
(3,704
)

$
(15,203
)

$
1,691

Adjustments to reconcile net earnings (loss) to net cash
from operating activities:

Depreciation, depletion and amortization

1,792

3,129

3,319

Asset impairments

4,975

20,820

1,953

Gains and losses on asset sales

(1,887
)

—

(1,072
)
Deferred income tax expense (benefit)

(273
)

(5,828
)

1,891

Derivatives and other financial instruments

386

(738
)

(2,070
)
Cash settlements on derivatives and financial instruments

(142
)

2,688

104

Asset retirement obligation accretion

75

75

89

Amortization of stock-based compensation

194

181

163

Other

303

281

245

Net change in working capital

(8
)

(311
)

50

Change in long-term other assets

36

285

(421
)
Change in long-term other liabilities

(1
)

(6
)

79

Net cash from operating activities

1,746

5,373

6,021

Cash flows from investing activities:

Capital expenditures

(2,330
)

(5,308
)

(6,988
)
Acquisitions of property, equipment and businesses

(1,641
)

(1,107
)

(6,462
)
Divestitures of property and equipment

3,118

107

5,120

Redemptions of long-term investments

—

—

57

Other

(19
)

(16
)

89

Net cash from investing activities

(872
)

(6,324
)

(8,184
)
Cash flows from financing activities:

Borrowings of long-term debt, net of issuance costs

2,145

4,772

5,340

Repayments of long-term debt

(4,409
)

(2,634
)

(7,178
)
Net short-term debt repayments

(626
)

(307
)

(385
)
Early retirement of debt

(265
)

—

(51
)
Issuance of common stock

1,469

—

—

Sale of subsidiary units

—

654

—

Issuance of subsidiary units

892

25

410

Dividends paid on common stock

(221
)

(396
)

(386
)
Contributions from noncontrolling interests

168

16

6

Distributions to noncontrolling interests

(304
)

(254
)

(235
)
Other

(13
)

(18
)

85

Net cash from financing activities

(1,164
)

1,858

(2,394
)
Effect of exchange rate changes on cash

(61
)

(77
)

(29
)
Net change in cash and cash equivalents

(351
)

830

(4,586
)
Cash and cash equivalents at beginning of period

2,310

1,480

6,066

Cash and cash equivalents at end of period

$
1,959

$
2,310

$
1,480

	December 31, 2019			December 31, 2018

ASSETS
Current assets:
Cash and cash equivalents	$	1,464		$	2,414
Cash restricted for discontinued operations		380			—
Accounts receivable		832			812
Current assets associated with discontinued operations		896			331
Other current assets		279			880
Total current assets		3,851			4,437
Oil and gas property and equipment, based on successful efforts accounting, net		7,558			7,430
Other property and equipment, net ($80 million related to CDM in 2019)		1,035			1,032
Total property and equipment, net		8,593			8,462
Goodwill		753			753
Right-of-use assets		243			—
Other long-term assets		196			276
Long-term assets associated with discontinued operations		81			5,638
Total assets	$	13,717		$	19,566
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	428		$	530
Revenues and royalties payable		730			722
Short-term debt		—			162
Current liabilities associated with discontinued operations		459			492
Other current liabilities		310			320
Total current liabilities		1,927			2,226
Long-term debt		4,294			4,292
Lease liabilities		244			—
Asset retirement obligations		380			468
Other long-term liabilities		426			411
Long-term liabilities associated with discontinued operations		185			2,454
Deferred income taxes		341			529
Stockholders' equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 382 million and 450 million shares in 2019 and 2018, respectively		38			45
Additional paid-in capital		2,735			4,486
Retained earnings		3,148			3,650
Accumulated other comprehensive earnings (loss)		(119	)		1,027
Treasury stock, at cost, 1.0 million shares in 2018		—			(22	)
Total stockholders’ equity attributable to Devon		5,802			9,186
Noncontrolling interests		118			—
Total equity		5,920			9,186
Total liabilities and equity	$	13,717		$	19,566

See accompanying notes to consolidated financial statements.

5953

Table of Contents

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED ~~BALANCE SHEETS~~STATEMENTS OF EQUITY

December 31, 2016

December 31, 2015

(Millions, except share data)

ASSETS

Current assets:

Cash and cash equivalents

$
1,959

$
2,310

Accounts receivable

1,356

1,105

Assets held for sale

193

—

Other current assets

264

606

Total current assets

3,772

4,021

Property and equipment, at cost:

Oil and gas, based on full cost accounting:

Subject to amortization

75,648

78,190

Not subject to amortization

3,437

2,584

Total oil and gas

79,085

80,774

Midstream and other

10,455

10,380

Total property and equipment, at cost

89,540

91,154

Less accumulated depreciation, depletion and amortization

(73,350
)

(72,086
)
Property and equipment, net

16,190

19,068

Goodwill

3,964

5,032

Other long-term assets

1,987

1,330

Total assets

$
25,913

$
29,451

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:

Accounts payable

$
642

$
906

Revenues and royalties payable

908

763

Short-term debt

—

976

Other current liabilities

1,066

650

Total current liabilities

2,616

3,295

Long-term debt

10,154

12,056

Asset retirement obligations

1,226

1,370

Other long-term liabilities

894

853

Deferred income taxes

648

888

Stockholders’ equity:

Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 523 million and 418 million shares in 2016 and 2015, respectively

52

42

Additional paid-in capital

7,237

4,996

Retained earnings (accumulated deficit)

(1,646
)

1,781

Accumulated other comprehensive earnings

284

230

Total stockholders’ equity attributable to Devon

5,927

7,049

Noncontrolling interests

4,448

3,940

Total stockholders’ equity

10,375

10,989

Total liabilities and stockholders’ equity

$
25,913

$
29,451

										Retained			Other
							Additional			Earnings			Comprehensive
	Common Stock						Paid-In			(Accumulated			Earnings			Treasury			Noncontrolling			Total
	Shares			Amount			Capital			Deficit)			(Loss)			Stock			Interests			Equity
Balance as of December 31, 2016		523		$	52		$	7,237		$	(69	)	$	1,054		$	—		$	4,448		$	12,722
Net earnings		—			—			—			898			—			—			180			1,078
Other comprehensive earnings, net of tax		—			—			—			—			112			—			—			112
Restricted stock grants, net of cancellations		1			1			—			—			—			—			—			1
Common stock repurchased		—			—			—			—			—			(44	)		—			(44	)
Common stock retired		—			—			(44	)		—			—			44			—			—
Common stock dividends		—			—			—			(127	)		—			—			—			(127	)
Share-based compensation		1			—			126			—			—			—			—			126
Subsidiary equity transactions		—			—			14			—			—			—			576			590
Distributions to noncontrolling interests		—			—			—			—			—			—			(354	)		(354	)
Balance as of December 31, 2017		525		$	53		$	7,333		$	702		$	1,166		$	—		$	4,850		$	14,104
Net earnings		—			—			—			3,064			—			—			160			3,224
Other comprehensive loss, net of tax		—			—			—			—			(108	)		—			—			(108	)
Restricted stock grants, net of cancellations		3			—			—			—			—			—			—			—
Common stock repurchased		—			—			—			—			—			(3,017	)		—			(3,017	)
Common stock retired		(79	)		(8	)		(2,987	)		—			—			2,995			—			—
Common stock dividends		—			—			—			(149	)		—			—			—			(149	)
Share-based compensation		1			—			140			—			—			—			—			140
Divestment of subsidiary equity investment		—			—			—			—			2			—			(4,863	)		(4,861	)
Subsidiary equity transactions		—			—			—			—			—			—			72			72
Distributions to noncontrolling interests		—			—			—			—			—			—			(219	)		(219	)
Other		—			—			—			33			(33	)		—			—			—
Balance as of December 31, 2018		450		$	45		$	4,486		$	3,650		$	1,027		$	(22	)	$	—		$	9,186
Effect of adoption of lease accounting		—			—			—			(7	)		—			—			—			(7	)
Net earnings (loss)		—			—			—			(355	)		—			—			2			(353	)
Other comprehensive loss, net of tax		—			—			—			—			(1,146	)		—			—			(1,146	)
Restricted stock grants, net of cancellations		3			—			—			—			—			—			—			—
Common stock repurchased		—			—			—			—			—			(1,852	)		—			(1,852	)
Common stock retired		(71	)		(7	)		(1,867	)		—			—			1,874			—			—
Common stock dividends		—			—			—			(140	)		—			—			—			(140	)
Share-based compensation		—			—			116			—			—			—			—			116
Contributions from noncontrolling interests		—			—			—			—			—			—			116			116
Balance as of December 31, 2019		382		$	38		$	2,735		$	3,148		$	(119	)	$	—		$	118		$	5,920

See accompanying notes to consolidated financial statements.

6054

Table of Contents

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

~~CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY~~

Accumulated

Additional

Retained

Other

Total

Common Stock

Paid-In

Earnings

Comprehensive

Treasury

Noncontrolling

Stockholders’

Shares

Amount

Capital

(Accumulated Deficit)

Earnings

Stock

Interests

Equity

(Millions)

Balance as of December 31, 2013

406

$
41

$
3,780

$
15,410

$
1,268

$
—

$
—

$
20,499

Net earnings

—

—

—

1,607

—

—

84

1,691

Other comprehensive loss, net of tax

—

—

—

—

(489
)

—

—

(489
)
Stock option exercises

1

—

93

—

—

—

—

93

Restricted stock grants, net of
   cancellations

2

—

—

—

—

—

—

—

Common stock repurchased

—

—

—

—

—

(27
)

—

(27
)
Common stock retired

—

—

(27
)

—

—

27

—

—

Common stock dividends

—

—

—

(386
)

—

—

—

(386
)
Share-based compensation

—

—

151

—

—

—

—

151

Share-based compensation tax expense

—

—

(3
)

—

—

—

—

(3
)
Acquisition of noncontrolling interests

—

—

—

—

—

—

4,670

4,670

Subsidiary equity transactions

—

—

93

—

—

—

277

370

Distributions to noncontrolling interests

—

—

—

—

—

—

(235
)

(235
)
Other

—

—

1

—

—

—

6

7

Balance as of December 31, 2014

409

$
41

$
4,088

$
16,631

$
779

$
—

$
4,802

$
26,341

Net loss

—

—

—

(14,454
)

—

—

(749
)

(15,203
)
Other comprehensive loss, net of tax

—

—

—

—

(549
)

—

—

(549
)
Stock option exercises

—

—

4

—

—

—

—

4

Restricted stock grants, net of
   cancellations

2

—

—

—

—

—

—

—

Common stock repurchased

—

—

—

—

—

(35
)

—

(35
)
Common stock retired

—

—

(35
)

—

—

35

—

—

Common stock dividends

—

—

—

(396
)

—

—

—

(396
)
Common stock issued

7

1

198

—

—

—

—

199

Share-based compensation

—

—

165

—

—

—

—

165

Share-based compensation tax expense

—

—

(9
)

—

—

—

—

(9
)
Subsidiary equity transactions

—

—

585

—

—

—

141

726

Distributions to noncontrolling interests

—

—

—

—

—

—

(254
)

(254
)
Balance as of December 31, 2015

418

$
42

$
4,996

$
1,781

$
230

$
—

$
3,940

$
10,989

Net loss

—

—

—

(3,302
)

—

—

(402
)

(3,704
)
Other comprehensive earnings, net of
   tax

—

—

—

—

54

—

—

54

Restricted stock grants, net of cancellations

2

—

—

—

—

—

—

—

Common stock repurchased

—

—

—

—

—

(28
)

—

(28
)
Common stock retired

—

—

(28
)

—

—

28

—

—

Common stock dividends

—

—

(96
)

(125
)

—

—

—

(221
)
Common stock issued

103

10

2,117

—

—

—

—

2,127

Share-based compensation

—

—

168

—

—

—

—

168

Subsidiary equity transactions

—

—

80

—

—

—

1,214

1,294

Distributions to noncontrolling interests

—

—

—

—

—

—

(304
)

(304
)
Balance as of December 31, 2016

523

$
52

$
7,237

$
(1,646
)

$
284

$
—

$
4,448

$
10,375

~~See accompanying notes to consolidated financial statements.~~

~~Table of Contents~~

~~Index to Financial Statements~~

~~DEVON ENERGY CORPORATION AND SUBSIDIARIES~~

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	Summary of Significant Accounting Policies

Devon is a leading independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Devon’s operations are concentrated in various ~~North American~~ onshore areas in the U.S.

As further discussed in Note 18, Devon reached an agreement to sell its Barnett Shale assets in December 2019, sold its Canadian operations on June 27, 2019 and ~~Canada. Devon also owns natural gas pipelines, plants and treatment facilities through~~sold its ownership interests in EnLink and the General ~~Partner.~~Partner on July 18, 2018. Activity relating to Devon’s Barnett Shale assets, inclusive of properties divested as partial sales of the Barnett Shale common operating field in previous reporting periods located primarily in Johnson and Wise counties, Texas, Canadian operations and EnLink and the General Partner are classified as discontinued operations within Devon’s consolidated statements of comprehensive earnings and consolidated statements of cash flows. The associated assets and liabilities of Devon’s Barnett Shale assets and Canadian operations are presented as assets and liabilities associated with discontinued operations on the consolidated balance sheets.

Accounting policies used by Devon and its subsidiaries conform to accounting principles generally accepted in the U.S. and reflect industry practices. The more significant of such policies are discussed below.

Principles of Consolidation

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

Devon entered into an agreement in the fourth quarter of 2019 to form Cotton Draw Midstream, L.L.C. or, “CDM”, a partnership in the Delaware Basin with an affiliate of QL Capital Partners, LP (“QLCP”). As ~~discussed more fully~~part of this transaction, Devon contributed gathering system and compression assets in ~~Note 2,~~the Cotton Draw area to CDM in exchange for a $100 million cash distribution funded by QLCP. Devon ~~completed~~will continue to operate the assets pursuant to the management services agreement. QLCP has also committed $40 million of expansion capital to CDM to fund the build out of the assets over the next several years. Devon holds a ~~business combination~~controlling interest in ~~2014 whereby Devon controls both EnLink~~CDM and the General Partner. Devon controls both the General Partner’s and EnLink’s operations; therefore, the General Partner’s and EnLink’s accounts are included in Devon’s accompanying consolidated financial statements subsequent to the completion of the transaction. The portions of ~~the General Partner’s and EnLink’s~~CDM’s net earnings and ~~stockholders’~~ equity not attributable to Devon’s controlling interest are shown separately as noncontrolling interests in the accompanying consolidated ~~comprehensive~~ statements of comprehensive earnings and consolidated balance sheets. CDM is considered a VIE to Devon.

Devon, through its controlling interest in CDM, has the power to direct the activities that significantly affect the economic performance of CDM and the obligation to absorb losses or the right to receive benefits that could be significant to CDM; therefore, Devon is considered the primary beneficiary and consolidates CDM. CDM maintains its own capital structure that is separate from Devon.

The assets of CDM cannot be used by Devon for general corporate purposes and are included in and disclosed parenthetically on Devon's consolidated balance sheets. The carrying amount of liabilities related to CDM for which the creditors do not have recourse to Devon's assets are also included in and disclosed parenthetically on Devon's consolidated balance sheets, if material.

Segment Information

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

Table of Contents

Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

Use of Estimates

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following:

•

proved reserves and related present value of future net revenues;

•

evaluation of suspended well costs;

•

the carrying and fair values of oil and gas properties, other property and equipment and product and equipment inventories;

•

derivative financial instruments;

•

the fair value of reporting units and related assessment of goodwill for impairment;

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income taxes;

•

asset retirement obligations;

•

obligations related to employee pension and postretirement benefits;

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legal and environmental risks and exposures; and

•

general credit risk associated with receivables and other assets.

Revenue Recognition

Impact of ASC 606 Adoption

In January 2018, Devon adopted ASC 606 – Revenue from Contracts with Customers (ASC 606) using the modified retrospective method and ~~related present value~~applied the standard to all existing contracts at adoption. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of ~~future~~goods or services to customers in an amount that reflects the consideration in exchange for those goods or services.

The changes to upstream revenues and production expenses were due to the conclusion that Devon represents the principal and controls a promised product before transferring it to the ultimate third party customer in accordance with the control model in ASC 606. This was a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where the assessment was focused on Devon passing title and not control to the processing entity and Devon ultimately receiving a net ~~revenues;~~

~~Revenue Recognition~~midstream revenues and marketing and midstream expenses were not impacted.

Upstream revenues include the sale of oil, gas and NGL production. Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, ~~title~~control has transferred and collectability of the revenue is probable. ~~Delivery~~Devon’s performance obligations are satisfied at a point in time. This occurs ~~and title typically~~when control is transferred ~~when~~to the purchaser upon delivery of contract specified production ~~has been delivered~~volumes at a specified point. The transaction price used to recognize revenue is a ~~pipeline, railcar or truck. Cash~~function of the contract billing terms. Revenue is invoiced, if required, by calendar month based on volumes at contractually based rates with payment typically received ~~relating to future~~within 30 days of the end of the production ~~is deferred and recognized when all revenue recognition criteria are met.~~month. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying consolidated ~~comprehensive~~ statements of comprehensive earnings.

Devon’s oil sales contracts are generally structured in one of two ways. First, production is sold at the wellhead at an agreed-upon index price, net of pricing differentials. In this scenario, revenue is recognized when control transfers to the purchaser at the wellhead at the net price received. Alternatively, production is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, a third party is paid to transport the product and Devon receives a specified index price from the purchaser with no transportation deduction. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as gathering, processing and transportation expense as a component of production expenses in the consolidated statements of comprehensive earnings.

Under Devon’s natural gas processing contracts, natural gas is delivered to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. In these scenarios, Devon evaluates whether it is the principal or the agent in the transaction. Devon has concluded it is the principal under these contracts and the ultimate third party is the customer. Revenue is recognized on a gross basis, with gathering, processing and transportation fees presented as a component of production expenses in the consolidated statements of comprehensive earnings.

In certain natural gas processing agreements, Devon may elect to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the product is delivered to the ultimate third-party purchaser at a contractually agreed-upon delivery point, and Devon receives a specified index price from the purchaser. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as gathering, processing and transportation expense as a component of production expenses in the consolidated statements of comprehensive earnings.

Marketing revenues are ~~recorded~~generated primarily as a result of Devon selling commodities purchased from third parties. Marketing revenues are recognized when performance obligations are satisfied. This occurs at the time contract-specified products are sold ~~or services are provided~~ to third parties at a contractually fixed or determinable price, delivery occurs at

a specified point or performance has occurred, ~~title~~control has transferred and collectability of the revenue is probable. ~~Revenues~~The transaction price used to recognize revenue and invoice customers is based on a contractually stated fee or on a third party published index price plus or minus a known differential. Devon typically receives payment for invoiced amounts within 30 days. Marketing revenues and expenses attributable to oil, gas and NGL purchases ~~transportation and processing contracts~~ are reported on a gross basis when Devon takes ~~title to~~control of the products and has risks and rewards of ownership.

Because Devon has a right to consideration from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, Devon recognizes revenue for sales at the time the crude oil, natural gas or NGLs are delivered at a fixed or determinable price.

Most of Devon’s contracts are short-term in nature with a contract term of one year or less. Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For contracts with terms greater than one year, Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under Devon’s contracts, each unit of product typically represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Cash received relating to future performance obligations is deferred and recognized when all revenue recognition criteria are met. Contract liabilities generated from such deferred revenue are not considered material as of December 31, 2019. Devon’s product sales and marketing contracts do not give rise to contract assets.

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

During ~~2016, 2015~~2019 and ~~2014, no~~2017, 0 purchaser accounted for more than 10% of Devon’s consolidated sales revenue.

During 2018, Devon had 1 purchaser that accounted for approximately 11% of Devon’s consolidated sales revenue.

Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices ~~interest rates~~ and ~~Canadian to U.S. dollar exchange~~interest rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk and interest rate ~~risk and foreign exchange~~ risk. Devon does not intend to issue or hold derivative financial instruments for speculative trading purposes.

Devon enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. ~~Additionally, Devon and EnLink periodically enter into derivative financial instruments with respect to a portion of their oil, gas and NGL marketing activities.~~ These instruments are used to manage the inherent uncertainty of future revenues resulting from commodity price volatility. Devon’s derivative financial instruments typically include financial price swaps, basis swaps and costless price ~~collars and call options.~~collars. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional index prices and pays a variable differential on the same two index prices to the contract counterparty. For price collars, Devon utilizes two-way price collars. The two-way price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the ~~counterparty to the collars. The call options give counterparties the right to purchase production at a predetermined price.~~counterparty.

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 December 31, ~~2016,~~2019, Devon did not have any open ~~foreign exchange~~interest rate swap contracts.

All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in earnings unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, ~~2016,~~2019, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon’s derivative financial

instruments are also recorded in earnings. Cash settlements that Devon is entitled to are accrued for in other current assets in the accompanying consolidated balance sheets. As of December 31, 2015, Devon accrued $236 million that it received in January 2016 related to cash settlements.

By using derivative financial instruments to hedge exposures to changes in commodity prices ~~interest rates~~ and ~~foreign currency~~interest rates, 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 require cash collateral to be posted if either its or the counterparty’s credit rating falls below certain credit rating levels. As of December 31, ~~2016,~~2019, Devon held ~~no collateral from counterparties. As of December 31, 2015, Devon held $75 million of~~0 cash collateral ~~which represented the estimated fair value~~ of ~~certain derivative positions in excess of Devon’s credit guidelines. The~~its counterparties 0r posted collateral ~~is reported in other current liabilities in the accompanying consolidated balance sheets. As a result of ratings downgrades for Devon during 2016, we were required~~ to post $17 million of cash collateral under certain of our derivative contracts. The collateral is reported in other current assets in the accompanying December 31, 2016 consolidated balance sheet. In January 2017, this collateral was deemed to be no longer required and was returned to Devon. As of the date of this report, Devon has no cash collateral held by its counterparties.

G&A is reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by ~~Devon and net~~Devon.

~~Independent of EnLink,~~ Devon grants share-based awards to members of its Board of Directors, management and ~~select employees. EnLink and the General Partner also grant share-based awards to members of its Board of Directors and select~~ employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of G&A in the accompanying consolidated ~~comprehensive~~ statements of comprehensive earnings over the applicable requisite service periods. As a result of Devon’s restructuring activity discussed in Note 6, certain share-based awards were accelerated and recognized as a component of restructuring and transaction costs in the accompanying consolidated ~~comprehensive~~ statements of comprehensive earnings.

Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are generally available to be issued as part of Devon’s share-based awards. However, Devon has historically canceled these shares upon repurchase.

Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of the deferred tax assets is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Devon periodically weighs the positive and negative evidence to determine if it is more likely than not that some or all of the deferred tax assets will be realized. Forming a conclusion that a valuation allowance is not required is difficult when there is negative evidence, such as cumulative losses in recent years. See Note 7 for further discussion.

Devon does not recognize U.S. deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be indefinitely reinvested. When such earnings are no longer deemed indefinitely reinvested, Devon recognizes the appropriate deferred, or even current, income tax liabilities.

Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense.

Devon estimates its annual effective income tax rate in recording its 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 period in which they occur.

Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon’s outstanding restricted stock awards, as well as performance-based restricted stock awards that have met the requisite performance targets. Diluted earnings per share is calculated using the

treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of ~~outstanding stock options.~~unvested performance share units.

Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.

In conjunction primarily with the sale of its Canadian operations in June 2019, approximately $380 million of Devon’s cash balance is restricted for funding certain tax and other obligations related to the disposed assets. Other obligations primarily relate to abandoned firm transportation and office lease agreements. This cash is not legally restricted and can be used by Devon for other general corporate purposes. However, it has been designated to settle retained obligations associated with discontinued operations.

Devon’s accounts receivable balance primarily consists of oil and gas sales receivables, marketing and midstream revenue receivables and joint interest receivables for which Devon does not require collateral security. Devon has established an allowance for bad debts equal to the estimable portions of accounts receivable, including joint interest receivables, for which failure to collect is considered probable. When a portion of the receivable is deemed uncollectible, the write-off is made against the allowance.

Devon follows the ~~full cost~~successful efforts method of accounting for its oil and gas properties. ~~Accordingly, all~~Exploration costs, ~~incidental to~~such as exploratory geological and geophysical costs, and costs associated with nonproductive exploratory wells, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling successful exploratory wells along with acquisition costs and the ~~acquisition, exploration and~~costs of drilling development ofwells, including those that are unsuccessful, are capitalized. Devon groups its oil and gas properties ~~including~~with a common geological structure or stratigraphic condition (“common operating field”) for purposes of computing DD&A, assessing proved property impairments and accounting for asset dispositions.

Exploratory drilling costs and exploratory-type stratigraphic test wells are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory well costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. Devon reviews the status of all suspended exploratory drilling costs quarterly.

Capitalized costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Internal costs incurred that are directly identified with acquisition, exploration and development activities undertaken by Devon for its own account, and that are not related to production, general corporate overhead or similar activities, are also capitalized. Interest costs incurred and attributable to unprovedproved oil and gas properties under current evaluation and major development projects of oil and gas properties are also capitalized. All costs related to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.

~~Capitalized costs~~ are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six Mcf of gas to one Bbl of oil. ~~Depletion is calculated using the capitalized~~Proved leasehold acquisition costs, less accumulated amortization, are depleted over total proved reserves, which includes proved undeveloped reserves.

Capitalized costs of wells and related equipment and facilities, including estimated asset retirement costs, ~~plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves,~~ net of estimated salvage ~~values.~~values and less accumulated amortization are depreciated over proved developed reserves associated with those capitalized costs. Depletion is calculated by applying the DD&A rate (amortizable base divided by beginning of period proved reserves) to current period production.

Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment ~~quarterly.~~annually, or more frequently if events or changes in circumstances dictate that the carrying value of those assets may not be recoverable. Significant unproved properties are assessed individually. ~~Costs of insignificant unproved~~

Proved properties are ~~transferred into~~assessed for impairment annually, or more frequently if events or changes in circumstances dictate that the ~~depletion calculation over their respective holding periods generally ranging from three~~carrying value of those assets may not be recoverable. Individual assets are grouped for impairment purposes based on a common operating field. If there is an indication the carrying amount of an asset may not be recovered, the asset is assessed for potential impairment by management through an established process. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset, the carrying value is written down to ~~four years.~~estimated fair value. Because there is usually a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or by comparable transactions. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review.

~~Sales~~Gains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire common operating field or which result in a significant alteration of the common operating field’s DD&A rate. These gains and losses are classified as asset dispositions in the accompanying consolidated statements of earnings. Partial common operating field sales or dispositions deemed not to significantly alter the DD&A rates are generally accounted for as adjustments to capitalized costs with no gain or loss recognized. ~~However, if a disposition or series of dispositions occurring in a quarterly reporting period significantly alters the relationship between capitalized~~

Devon capitalizes interest costs and proved reserves in a particular country, a gain or loss is recognized. As discussed more fully in Note 2, the 2014 and 2016 divestitures of certain Canadian and U.S. non-core upstream assets significantly altered such relationship, and Devon recognized gains on these transactions. These gainsincurred that are ~~classified as asset dispositions and other in the accompanying consolidated statements of earnings. Furthermore, upon recognizing the gain on the 2016 divestitures and~~attributable to be more consistent with industry practice, Devon began presenting gains on asset sales in the total revenues and other section of the accompanying consolidated statements of earnings, and has reclassified the 2014 gain on asset sales of $1.1 billion from operating expenses to total revenues and other to reflect consistent financial statement presentation.

~~Under the full cost method of accounting, capitalized costs of~~material unproved 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. The estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book valuemajor development projects of oil and gas properties.

Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts in place that qualify for hedge accounting treatment. None of Devon’s derivative contracts held during the three-year period ended December 31, 2016 qualified for hedge accounting treatment.

Any excess of the net book value, less related deferred taxes, over the ceiling is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher commodity prices may have increased the ceiling applicable to the subsequent period.

Costs for midstream assets that are in use are depreciated over the assets’ estimated useful lives, using ~~either~~ the ~~unit-of-production or~~ straight-line method. Depreciation and amortization of other property and equipment, including corporate and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 60 years. Interest costs incurred and attributable to major ~~midstream and~~ corporate construction projects are also capitalized.

Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites ~~and midstream pipelines and processing plants~~ when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Devon’s asset retirement obligations also include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of such long-lived assets. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.

Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes ana qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If the qualitative ~~and~~assessment determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, then a quantitative ~~factors.~~goodwill impairment test is performed. The quantitative goodwill impairment test requires ~~allocating goodwill and all other assets and liabilities to assigned reporting units. The~~the fair value of each reporting unit ~~is estimated and~~be compared to the ~~net book~~carrying value of the reporting unit. If the ~~estimated~~ fair value of the reporting unit is less than the ~~net book~~carrying value, ~~including goodwill, then~~an impairment charge will be recognized for the ~~goodwill is written down to~~amount by which the ~~implied~~carrying amount exceeds the fair ~~value of the goodwill through a charge to expense.~~value. Because quoted market prices are not available for Devon’s reporting ~~units,~~unit, the fair ~~values~~value of the reporting ~~units are~~unit is estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid.

Devon ~~and EnLink~~ performed ~~annual~~ impairment tests of goodwill in the fourth quarters of ~~2016, 2015~~2019, 2018 and ~~2014.~~2017. No impairment ~~write-down~~ was required as a result of the annual tests in 2016; however, sustained weakness in the overall energy sector driven by low commodity prices, together with a decline in the EnLink unit price, caused a change in circumstances warranting an interim impairment test and write-down for certain of EnLink’s reporting units in the first quarter of 2016. Write-downs were also required in 2015 for certain EnLink reporting units and in 2014 for Devon’s Canadian reporting unit based on interim and annual impairment tests. See Note 12 for further discussion.

Unamortized capitalized intangible assets, consisting of EnLink customer relationships, are presented in other long-term assets in the accompanying consolidated balance sheets. These assets are amortized on a straight-line basis over the expected periods of benefits, which range from 10-20 years. During 2016 and 2015, EnLink’s customer relationships were also evaluated for impairment, and in 2015, a portion of these ~~intangible assets was considered impaired. See Note 12 for further discussion.~~time periods.

Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for

environmental remediation or restoration claims resulting from allegations of improper operation of assets are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon’s accounting policy for property and equipment.

Certain of Devon’s assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels:

The U.S. dollar is the functional currency for Devon’s consolidated operations. Devon’s recently divested Canadian operations ~~except its Canadian subsidiaries, which use~~used the Canadian dollar as the functional currency. Assets and liabilities of the Canadian ~~subsidiaries are~~operations were translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow ~~are~~were translated using an average exchange rate during the reporting period. ~~Translation adjustments have no effect on net income~~

The disposition of substantially all of Devon’s Canadian oil and ~~are included~~gas assets and operations resulted in Devon releasing its historical cumulative foreign currency translation adjustment of $1.2 billion from accumulated other comprehensive earnings ~~in stockholders’ equity.~~to be included within the gain computation.

Noncontrolling interests represent third-party ownership in the net assets of Devon’s consolidated subsidiaries and are presented as a component of equity. Changes in Devon’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity.

In January ~~2016,~~2019, Devon adopted ASU ~~2015-03,~~ ~~Interest – Imputation of Interest~~2016-02, Leases (Topic ~~835): Simplifying~~842), using the ~~Presentation of Debt Issuance Costs.~~ This ASU requires debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than as an asset. As a resultmodified retrospective method. See Note 14for further discussion regarding Devon’s adoption of the ~~adoption, Devon reclassified unamortized debt issuance~~leases standard.

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 manner that reduces costs ~~of $81 million as of December 31, 2015 from other long-term assets to a reduction of long-term debt~~and burdens on ~~the consolidated balance sheets.~~

~~The FASB issued ASU 2016-15,~~ ~~Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.~~ Its objective is to clarify guidance and eliminate diversity in practice of classification on certain cash receipts and payments in the statement of cash flows. Devon early adopted this ASU as of September

30, 2016 using a retrospective transition method. As a result of the adoption, Devon has classified $265 million of debt retirement payments as cash flows from financing activities in the accompanying 2016 consolidated statement of cash flows and has reclassified $40 million of debt retirement payments previously classified as cash flows from operating activities to cash flows from financing activities in the accompanying 2014 consolidated statement of cash flows.

~~The FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosures of Uncertainties about an Entity’s Ability to Continue as a Going Concern. Its objective is~~registrants while continuing to provide ~~guidance about management’s responsibility~~all material information to ~~evaluate whether there are conditions~~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 events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern. Certain disclosures are required should substantial doubt exist. This evaluation is performed each annual and interim reporting period to assess conditions or events within one year after the date that the financial statements are issued. This ASU was effective for Devon beginning December 31, 2016; however, no additional disclosures as contemplated byeliminating disclosures. Other than presentation, this ~~ASU were warranted.~~

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

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

~~The FASB issued ASU 2016-09,~~ ~~Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting~~. Its objective is to simplify several aspects of the accounting for share-based payments, and associated income taxes, statutory withholding and forfeitures. Classification of these aspects on the statement of cash flows is also addressed. Devon adopted this ASU as of January 1, 2017. For recording periods following adoption, Devon will make certain income tax presentation changes, most notably prospectively presenting excess tax benefits as income tax expense in the consolidated comprehensive statements of earnings and as operating cash flows in the consolidated statements of cash flows. While Devon does not expect that these

changes will materially impact its consolidated financial statements and related disclosures, the adoption of this ASU could result in increased volatility in income tax expense and net earnings in Devon’s financial statements.

~~The FASB issued ASU No. 2016-13,~~ ~~Credit Losses, Measurement of Credit Losses on Financial Instruments~~. This ASU changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace today’s incurred loss approach with an expected loss model for instruments measured at amortized cost. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. This ASU is effective for Devon beginning January 1, 2020, with early adoption permitted. Devon is evaluating the impact this ASU will have on its consolidated financial statements and related disclosures.

On January 7, 2016, Devon acquired approximately 80,000 net acres (unaudited) and assets in the STACK play for approximately $1.5 billion. Devon funded the acquisition with $849 million of cash and $659 million of equity. The allocation of the purchase price at December 31, 2016 was approximately $1.3 billion to unproved properties and approximately $200 million to proved properties.

On December 17, 2015, Devon acquired approximately 253,000 net acres (unaudited) and assets in the Powder River Basin for approximately $499 million. Devon funded the acquisition with $300 million of cash and $199 million of equity. The allocation of the purchase price was $393 million to unproved properties and $106 million to proved properties and gathering systems.

On February 28, 2014, Devon acquired approximately 82,000 net acres (unaudited) and assets located in DeWitt and Lavaca counties in south Texas from GeoSouthern for approximately $6.0 billion. Devon funded the acquisition with cash on hand and debt financing. The allocation of the purchase price was approximately $5.0 billion to proved properties and approximately $1.0 billion to unproved properties.

During 2016, Devon divested certain non-core upstream assets in the U.S. and its 50% interest in the Access Pipeline in Canada. Proceeds from the transactions have been utilized primarily for debt repayment and to support future capital investment in Devon’s core resource plays.

In the second quarter of 2016, Devon divested its non-core Mississippian assets for approximately $200 million. Estimated proved reserves associated with these assets were approximately 11 MMBoe, or less than 1% of total U.S. proved reserves.

During the third quarter of 2016, in several separate transactions 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.

Absent gain recognition, the divestiture transactions that closed in the third quarter of 2016 would have 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.~~

In October 2016, Devon divested Access Pipeline for $1.1 billion ($1.4 billion Canadian dollars) and recognized a gain of approximately $540 million on the transaction. In conjunction with the divestiture, Devon entered into a transportation agreement whereby Devon’s Canadian thermal-oil acreage is dedicated to Access Pipeline for an initial term of 25 years. Devon will be charged a market-based toll on its thermal-oil production over this term. Devon is committed to use less than 90% of the potential pipeline capacity. In addition, Devon is entitled to an incremental payment of approximately $150 million Canadian dollars following sanctioning and committing to the requisite volume increase in respect of a new thermal-oil project on Devon’s Pike lease in Alberta, with such incremental payment being received prior to tolls being payable on such volumes.

During 2014, Devon divested certain upstream properties located throughout Canada and the U.S. as part of its asset portfolio transformation for approximately $5 billion. A gain of $1.1 billion was recognized with the sale of the Canadian conventional assets. This gain is included as a separate item in the accompanying consolidated comprehensive statements of earnings. Devon repatriated the Canadian asset proceeds to the U.S. Between collecting the divestiture proceeds and repatriating the funds to the U.S., Devon recognized an $84 million foreign currency exchange loss and a $29 million foreign exchange currency derivative loss. These losses are included in other nonoperating items in the accompanying consolidated comprehensive statements of earnings. The proceeds were used to repay debt.

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

the accompanying consolidated comprehensive statement of earnings. The first installment payment of $250 million was paid in January 2017 and was funded using divestiture proceeds, proceeds from equity issuances and borrowings under EnLink’s credit facility. The allocation of the purchase price at December 31, 2016 was $1.0 billion to intangible assets and approximately $400 million to property and equipment.

On August 1, 2016, EnLink formed a joint venture to operate and expand its midstream assets in the Delaware Basin. The joint venture is initially owned 50.1% by EnLink and 49.9% by the joint venture partner. As of December 31, 2016, EnLink contributed approximately $251 million of existing non-monetary assets and cash to the joint venture and had committed an additional $285 million in capital to fund potential future development projects and potential acquisitions. The joint venture partner committed an aggregate of approximately $400 million of capital, including cash contributions of approximately $144 million, and granted EnLink call rights beginning in 2021 to acquire increasing portions of the joint venture partner’s interest.

On November 9, 2016, EnLink entered into a gathering and compression joint venture with a commitment of approximately $40 million to expand its midstream assets in the STACK. The joint venture is initially owned 30% by EnLink and 70% by the joint venture partner. As of December 31, 2016, EnLink contributed approximately $29 million in cash for new infrastructure build. After the initial capital commitment, EnLink and the joint venture partner will be responsible for their proportionate share of capital expenses.

~~The following table presents a summary of EnLink’s acquisition activity for 2015.~~

In December 2016, EnLink entered into definitive agreements to divest approximately $278 million of certain non-core midstream assets. Certain of these transactions are expected to close during the first quarter of 2017. As of December 31, 2016, these assets were classified as held for sale.

In February 2015, EnLink acquired a 25% equity interest in EMH from the General Partner in exchange for units valued at approximately $925 million. In May 2015, EnLink acquired the remaining 25% equity interest in EMH from the General Partner in exchange for units valued at approximately $900 million.

In April 2015, EnLink acquired VEX from Devon for approximately $176 million in cash and equity. EnLink also assumed approximately $35 million in certain future construction costs to expand the system to full capacity. Because Devon controls EnLink and the General Partner, the acquisition of VEX by EnLink from Devon was accounted for as a transfer of net assets between entities under common control.

On March 7, 2014, Devon and Crosstex completed a transaction to combine substantially all of Devon’s U.S. midstream assets with Crosstex’s assets to form a midstream business that consists of the General Partner and EnLink, which are both publicly traded.

In exchange for a controlling interest in both EnLink and the General Partner, Devon contributed its equity interest in a newly formed Devon subsidiary, EMH, and $100 million in cash. EMH owned midstream assets in the Barnett Shale in north Texas and the Cana- and Arkoma-Woodford Shales in Oklahoma, as well as an economic interest in Gulf Coast Fractionators in Mont Belvieu, Texas.

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

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

The following unaudited pro forma financial information has been prepared assuming both the EnLink formation and the GeoSouthern acquisition occurred on January 1, 2014. The pro forma information is not intended to reflect the actual results of operations that would have occurred if the business combination and acquisition had been completed at the dates indicated. In addition, they do not project Devon’s results of operations for any future period.

In February 2019, Devon announced its intent to separate its Canadian business and Barnett Shale assets from the Company, based on authorizations provided by its Board of Directors. On June 27, 2019, Devon completed the sale of substantially all of its oil and gas 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), and recognized a pre-tax gain of $223 million ($425 million, net of tax, primarily due to a significant deferred tax benefit). As a part of the transaction, $436 million of asset retirement obligations were assumed by Canadian Natural Resources Limited. In aggregate, the total 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 approximately $285 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.

In December 2019, Devon announced the sale of its Barnett Shale assets to BKV for approximately $770 million, before purchase price adjustments. Estimated proved reserves associated with Devon’s Barnett Shale assets are approximately 45% of total U.S. proved reserves. In connection with the announced sale of its Barnett Shale assets, Devon recognized a $748 million asset impairment related to these assets, primarily due to the difference between the net carrying value and the purchase price, net of estimated customary purchase price adjustments. This transaction is expected to close in the second quarter of 2020. For additional information see Note 18.

During 2018, Devon received proceeds of approximately $500 million and recognized a $26 million net gain on asset dispositions from the sales of non-core assets in the Barnett Shale, located primarily in Johnson and Wise counties, Texas. In conjunction with these divestitures, Devon settled certain gas processing contracts and recognized $40 million in settlement expense, which is included in asset dispositions within the discontinued operations. For additional information, see Note 18.

During the third quarter of 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). The proceeds from the sale were utilized to increase Devon’s share repurchase activities, which are discussed further in Note 17. Additional information on these discontinued operations can be found in Note 18.

During 2019, Devon received proceeds of approximately $390 million and recognized a $48 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 54 MMBoe. As of December 31, 2018, assets and liabilities associated with the Permian Basin divested assets were classified as held for sale in the accompanying consolidated balance sheet.

During 2018, Devon received proceeds totaling approximately $500 million, primarily from the sales of non-core assets in the Delaware Basin, and recognized a net gain on asset dispositions of $278 million. In aggregate, the total estimated proved reserves associated with these divested assets were approximately 24 MMBoe.

During 2017, Devon received proceeds totaling approximately $425 million, and recognized a net gain on asset dispositions of $219 million. Estimated proved reserves associated with these assets were less than 1% of total U.S. proved reserves.

As of December 31, ~~2016,~~2019, Devon had the following open oil derivative positions. The first table presents Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The second table presents Devon’s oil derivatives that settle against the respective indices noted within the table.

As of December 31, ~~2016,~~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 December 31, ~~2016, EnLink~~2019, Devon had the following open NGL derivative ~~positions associated with gas processing and fractionation. EnLink’s~~positions. Devon’s NGL positions settle ~~by purity product~~ against the average of the prompt month OPIS Mont Belvieu, Texas index. ~~EnLink’s natural gas positions settle against the Henry Hub Gas Daily index.~~

~~As of December 31, 2016, 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 comprehensive 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 2015,~~2017, Devon’s stockholders approved the ~~2015 Long-Term Incentive~~2017 Plan. The ~~2015~~2017 Plan replaces the ~~2009 Long-Term Incentive Plan, as amended.~~2015 Plan. From the effective date of the ~~2015~~2017 Plan, no further awards may be made under the ~~2009~~2015 Plan, and awards previously granted will continue to be governed by the terms of the ~~2009 Plan.~~respective award documents. Subject to the terms of the ~~2015~~2017 Plan, awards may be made ~~under the 2015 Plan~~ for a total of 2833.5 million shares of Devon common stock, plus the number of shares available for issuance under the ~~2009~~2015 Plan (including shares subject to outstanding awards ~~under~~that were transferred to the ~~2009~~2017 Plan ~~that are subsequently forfeited, canceled or expire)~~in accordance with its terms). The ~~2015~~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 ~~awards or~~ units and stock appreciation rights to eligible employees. The ~~2015~~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 ~~2015~~2017 Plan, options and stock appreciation rights represent ~~one~~1 share and other awards represent ~~three~~2.3 shares.

Devon also has a stock option plan that was adopted in 2005 under which stock options were issued to certain employees. Options granted under this plan remain exercisable by the employees owning such options, but no new options or restricted stock awards will be granted under this plan.

The table below presents the effects of share-based compensation included in Devon’s accompanying consolidated comprehensive statements of earnings. Gross G&A in 2016, 2015 and 2014 includes $24 million, $31 million and $17 million, respectively, of unit-based compensation related to grants made under EnLink’s long-term incentive plans.

The vesting for certain share-based awards was accelerated in ~~2016~~2019 and 2018 in conjunction with the reduction of workforce activities described in Note ~~6. Approximately $60 million of associated expense for these accelerated awards~~6 and is included in restructuring and transaction costs in the accompanying consolidated ~~comprehensive~~ statements of comprehensive earnings. ~~In 2014, vesting of certain~~

The table below presents the share-based ~~awards was accelerated in conjunction with the divestiture of Devon’s Canadian conventional assets. Approximately $15 million of associated~~compensation expense ~~for these accelerated awards is~~ included in ~~restructuring and transaction costs in the~~Devon’s accompanying consolidated ~~comprehensive~~ statements of comprehensive earnings.

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 plans.

The following table presents the aggregate fair value of awards and units that vested during the indicated period.

~~The following table presents the unrecognized compensation cost and the related weighted average recognition period associated with unvested awards and units as of December 31, 2016.~~

Restricted stock awards and units are subject to the terms, conditions, restrictions and limitations, if any, that the Compensation Committee deems appropriate, including restrictions on continued employment. Generally, the service requirement for vesting ranges from one to four years. During the vesting period, recipients of restricted stock awards receive dividends that are not subject to restrictions or other limitations. Devon estimates the fair values of restricted stock awards and units as the closing price of Devon’s common stock on the grant date of the award or unit, which is expensed over the applicable vesting period.

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

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

PART I		6

Items 1 and 2. Business and Properties		6
Item 1A. Risk Factors		1713
Item 1B. Unresolved Staff Comments		2420
Item 3. Legal Proceedings		2520
Item 4. Mine Safety Disclosures		2520

PART II		2621

Item 5. Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		2621
Item 6. Selected Financial Data		2823
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		2924
Item 7A. Quantitative and Qualitative Disclosures about Market Risk		5446
Item 8. Financial Statements and Supplementary Data		5647
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		~~123~~100
Item 9A. Controls and Procedures		~~123~~100
Item 9B. Other Information		~~123~~100

PART III		~~124~~101

Item 10. Directors, Executive Officers and Corporate Governance		~~124~~101
Item 11. Executive Compensation		~~124~~101
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		~~124~~101
Item 13. Certain Relationships and Related Transactions, and Director Independence		~~124~~101
Item 14. Principal Accountant Fees and Services		~~124~~101

PART IV		~~125~~102

Item 15. Exhibits and Financial Statement Schedules		~~125~~102
~~Signatures~~Item 16. Form 10-K Summary		~~133~~107
Signatures		108

	Average Sales Price ⁽¹⁾
Year Ended December 31,	Oil (Per Bbl)		Gas (Per Mcf)		NGLs (Per Bbl)		Production Cost (Per Boe) ⁽¹⁾⁽²⁾
2019 ⁽¹⁾
STACK	$	55.13	$	1.97	$	15.90	$	7.36
Delaware Basin	$	54.01	$	0.99	$	13.54	$	6.43
U.S.	$	54.73	$	1.79	$	15.21	$	7.75
2018 ⁽¹⁾
STACK	$	63.81	$	2.29	$	25.53	$	7.16
Delaware Basin	$	57.24	$	1.80	$	24.05	$	8.15
U.S.	$	61.96	$	2.34	$	25.47	$	8.22
2017
STACK	$	48.43	$	2.40	$	17.78	$	4.72
Delaware Basin	$	48.38	$	2.43	$	16.44	$	8.19
U.S.	$	49.41	$	2.57	$	16.74	$	6.49


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


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


	Proved Reserves								Production
	MMBoe		% of Total			% Liquids			MBoe/d		% of Total			% Liquids			Gross Wells Drilled
Barnett Shale		895		44	%		25	%		169		28	%		27	%		—
Delaware Basin		108		5	%		75	%		60		10	%		74	%		58
Eagle Ford		75		4	%		76	%		76		12	%		76	%		63
Heavy Oil		504		24	%		99	%		134		22	%		98	%		25
Rockies Oil		24		1	%		64	%		19		3	%		79	%		19
STACK		393		19	%		47	%		93		15	%		48	%		133
Other		59		3	%		90	%		17		3	%		81	%		28
Retained assets		2,058		100	%		54	%		568		93	%		62	%		326
Divested assets ⁽¹⁾		—		—			—			43		7	%		51	%		14
Total		2,058		100	%		54	%		611		100	%		61	%		340

	Production
Year Ended December 31,	Oil (MMBbls)		Bitumen (MMBbls)		Gas (Bcf)		NGLs (MMBbls)		Total (MMBoe)
2016
Barnett Shale		—		—		265		15		60
Jackfish		—		40		—		—		40
U.S.		47		—		510		42		174
Canada		8		40		7		—		49
Total North America		55		40		517		42		223
2015
Barnett Shale		—		—		291		17		66
Jackfish		—		31		—		—		31
U.S.		60		—		579		50		206
Canada		10		31		8		—		42
Total North America		70		31		587		50		248
2014
Barnett Shale		1		—		332		20		76
Jackfish		—		20		—		—		20
U.S.		48		—		660		50		207
Canada		10		20		41		1		39
Total North America		58		20		701		51		246

	Average Sales Price
Year Ended December 31,	Oil (Per Bbl)		Bitumen (Per Bbl)		Gas (Per Mcf)		NGLs (Per Bbl)		Production Cost (Per Boe) ⁽¹⁾
2016
Barnett Shale	$	41.03	$	—	$	1.76	$	10.31	$	6.16
Jackfish	$	—	$	19.82	$	—	$	—	$	8.70
U.S.	$	38.92	$	—	$	1.84	$	9.81	$	6.44
Canada	$	23.96	$	19.82		N/M	$	—	$	9.36
Total North America	$	36.72	$	19.82	$	1.84	$	9.81	$	7.08
2015
Barnett Shale	$	46.47	$	—	$	2.00	$	9.62	$	6.02
Jackfish	$	—	$	23.41	$	—	$	—	$	12.43
U.S.	$	44.01	$	—	$	2.17	$	9.32	$	7.52
Canada	$	30.58	$	23.41		N/M	$	—	$	13.18
Total North America	$	42.12	$	23.41	$	2.14	$	9.32	$	8.48
2014
Barnett Shale	$	95.51	$	—	$	3.78	$	21.98	$	5.25
Jackfish	$	—	$	55.88	$	—	$	—	$	20.59
U.S.	$	85.64	$	—	$	3.92	$	24.46	$	7.52
Canada	$	68.14	$	55.88	$	3.64	$	50.52	$	20.10
Total North America	$	82.47	$	55.88	$	3.90	$	24.89	$	9.49


	Development Wells⁽¹⁾				Exploratory Wells ⁽¹⁾				Total Wells ⁽¹⁾
Year Ended December 31,	Productive		Dry		Productive		Dry		Productive		Dry		Total
2016
U.S.		88.5		—		36.4		2.0		124.9		2.0		126.9
Canada		21.5		—		—		—		21.5		—		21.5
Total North America		110.0		—		36.4		2.0		146.4		2.0		148.4
2015
U.S.		298.6		1.8		40.7		—		339.3		1.8		341.1
Canada		79.0		—		—		—		79.0		—		79.0
Total North America		377.6		1.8		40.7		—		418.3		1.8		420.1
2014
U.S.		474.4		0.4		5.0		1.2		479.4		1.6		481.0
Canada		190.8		1.0		—		0.5		190.8		1.5		192.3
Total North America		665.2		1.4		5.0		1.7		670.2		3.1		673.3

	Gross⁽¹⁾		Net⁽²⁾
U.S.		42.0		14.5
Canada		10.0		10.0
Total North America		52.0		24.5


	Oil Wells⁽¹⁾				Natural Gas Wells				Total Wells ⁽¹⁾
	Gross⁽²⁾⁽⁴⁾		Net⁽³⁾		Gross⁽²⁾⁽⁴⁾		Net⁽³⁾		Gross⁽²⁾⁽⁴⁾		Net⁽³⁾
U.S.		9,710		3,499		10,061		7,577		19,771		11,076
Canada		3,239		3,138		644		456		3,883		3,594
Total North America		12,949		6,637		10,705		8,033		23,654		14,670


	Developed				Undeveloped				Total
	Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net⁽²⁾
	(Thousands)
U.S.		1,800		1,218		4,138		1,917		5,938		3,135
Canada		695		512		2,075		953		2,770		1,465
Total North America		2,495		1,730		6,213		2,870		8,708		4,600


	Short-Term						Long-Term					Short-Term						Long-Term
	Variable			Fixed			Variable			Fixed		Variable			Fixed			Variable			Fixed
Oil and bitumen		65	%		—			35	%		—
Oil													64	%		—			36	%		—
Natural gas		54	%		4	%		42	%		—		64	%		3	%		33	%		—
NGLs		53	%		17	%		30	%		—		38	%		28	%		34	%		—


	Price Range of Common Stock				Dividends
	High		Low		Per Share
Quarter Ended 2016:
December 31, 2016	$	50.66	$	36.64	$	0.06
September 30, 2016	$	45.62	$	35.01	$	0.06
June 30, 2016	$	39.47	$	25.55	$	0.06
March 31, 2016	$	32.93	$	18.07	$	0.24
Quarter Ended 2015:
December 31, 2015	$	48.68	$	28.00	$	0.24
September 30, 2015	$	59.80	$	36.01	$	0.24
June 30, 2015	$	70.48	$	58.77	$	0.24
March 31, 2015	$	67.08	$	56.35	$	0.24

Period	Total Number of Shares Purchased ⁽¹⁾		Average Price Paid per Share		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⁾
October 1 - October 31		25,638	$	43.29		4,285	$	21.27		4,244	$	199
November 1 - November 30		96,822	$	42.15		218	$	22.33		192	$	195
December 1 - December 31		3,778	$	47.30		9	$	22.58		—	$	1,000
Total		126,238	$	42.54		4,512	$	21.32		4,436

		As presented in the graph at the left, our operating achievements are subject to the volatility of commodity prices. Over the last four years, NYMEX WTI oil and NYMEX Henry Hub prices ranged from average highs of $64.79 per Bbl and $3.11 per MMBtu, respectively, to average lows of $43.36 per Bbl and $2.46 per MMBtu, respectively.

	Year Ended December 31,
	2016⁽¹⁾		Change			2015 ⁽¹⁾		Change			2014 ⁽¹⁾
Oil (per Bbl)
U.S.	$	38.92		- 12	%	$	44.01		- 49	%	$	85.64
Canada	$	23.96		- 22	%	$	30.58		- 55	%	$	68.14
Total	$	36.72		- 13	%	$	42.12		- 49	%	$	82.47
Bitumen (per Bbl)
Canada	$	19.82		- 15	%	$	23.41		- 58	%	$	55.88
Gas (per Mcf)
U.S.	$	1.84		- 15	%	$	2.17		- 45	%	$	3.92
Canada ⁽²⁾	N/M		N/M			N/M		N/M			$	3.64
Total	$	1.84		- 14	%	$	2.14		- 45	%	$	3.90
NGLs (per Bbl)
U.S.	$	9.81		+5	%	$	9.32		- 62	%	$	24.46
Canada	$	—	N/M			$	—	N/M			$	50.52
Total	$	9.81		+5	%	$	9.32		- 63	%	$	24.89
Combined (per Boe)
U.S.	$	18.34		- 13	%	$	21.12		- 44	%	$	37.96
Canada	$	20.07		- 18	%	$	24.46		- 54	%	$	53.11
Total	$	18.72		- 14	%	$	21.68		- 46	%	$	40.33

	Oil			Bitumen			Gas			NGLs			Total
	(Millions)
2014 sales	$	4,773		$	1,138		$	2,737		$	1,262		$	9,910
Change due to volumes		976			584			(443	)		(23	)		1,094
Change due to prices		(2,813	)		(1,000	)		(1,034	)		(775	)		(5,622	)
2015 sales	$	2,936		$	722		$	1,260		$	464		$	5,382
Change due to volumes		(608	)		209			(151	)		(70	)		(620	)
Change due to prices		(299	)		(143	)		(159	)		21			(580	)
2016 sales	$	2,029		$	788		$	950		$	415		$	4,182

	Year Ended December 31, 2016
	Oil			Bitumen		Gas			NGLs			Boe
	(Per Bbl)			(Per Bbl)		(Per Mcf)			(Per Bbl)			(Per Boe)
Realized price without hedges	$	36.72		$	19.82	$	1.84		$	9.81		$	18.72
Cash settlements of hedges		(0.74	)		—		0.07			(0.11	)		(0.05	)
Realized price, including cash settlements	$	35.98		$	19.82	$	1.91		$	9.70		$	18.67

	Year Ended December 31, 2015
	Oil			Bitumen		Gas			NGLs			Boe
	(Per Bbl)			(Per Bbl)		(Per Mcf)			(Per Bbl)			(Per Boe)
Realized price without hedges	$	42.12		$	23.41	$	2.14		$	9.32		$	21.68
Cash settlements of hedges		29.88			—		0.57			—			9.74
Realized price, including cash settlements	$	72.00		$	23.41	$	2.71		$	9.32		$	31.42

	Year Ended December 31, 2014
	Oil			Bitumen		Gas			NGLs			Boe
	(Per Bbl)			(Per Bbl)		(Per Mcf)			(Per Bbl)			(Per Boe)
Realized price without hedges	$	82.47		$	55.88	$	3.90		$	24.89		$	40.33
Cash settlements of hedges		1.56			—		(0.05	)		0.02			0.22
Realized price, including cash settlements	$	84.03		$	55.88	$	3.85		$	24.91		$	40.55

	Devon									EnLink									Consolidated
	2016			2015			2014			2016			2015			2014			2016			2015			2014
	(Millions)
Operating cash flow	$	1,080		$	4,746		$	5,507		$	666		$	627		$	514		$	1,746		$	5,373		$	6,021
Issuance of common stock		1,469			—			—			—			—			—			1,469			—			—
Divestitures of property and equipment		3,025			106			5,120			93			1			—			3,118			107			5,120
Capital expenditures		(1,667	)		(4,735	)		(6,192	)		(663	)		(573	)		(796	)		(2,330	)		(5,308	)		(6,988	)
Acquisitions of property, equipment and businesses		(849	)		(583	)		(6,104	)		(792	)		(524	)		(358	)		(1,641	)		(1,107	)		(6,462	)
Debt activity, net		(3,383	)		770			(2,829	)		228			1,061			555			(3,155	)		1,831			(2,274	)
Shareholder and noncontrolling interests distributions		(221	)		(396	)		(486	)		(304	)		(254	)		(135	)		(525	)		(650	)		(621	)
EnLink and General Partner distributions		265			268			158			(265	)		(268	)		(158	)		—			—			—
EnLink dropdowns		—			167			—			—			(167	)		—			—			—			—
Issuance of subsidiary units		—			—			—			892			25			410			892			25			410
Sale of subsidiary units		—			654			—			—			—			—			—			654			—
Effect of exchange rate and other		(64	)		(117	)		172			139			22			36			75			(95	)		208
Net change in cash and cash equivalents	$	(345	)	$	880		$	(4,654	)	$	(6	)	$	(50	)	$	68		$	(351	)	$	830		$	(4,586	)
Cash and cash equivalents at end of period	$	1,947		$	2,292		$	1,412		$	12		$	18		$	68		$	1,959		$	2,310		$	1,480

	Amounts		Rate
	(Millions)		(Per Share)
Year Ended 2016:
First quarter 2016	$	125	$	0.24
Second quarter 2016		33	$	0.06
Third quarter 2016		32	$	0.06
Fourth quarter 2016	31		$	0.06
Total year-to-date	$	221
Year Ended 2015:
First quarter 2015	$	99	$	0.24
Second quarter 2015		98	$	0.24
Third quarter 2015		99	$	0.24
Fourth quarter 2015		100	$	0.24
Total year-to-date	$	396
Year Ended 2014:
First quarter 2014	$	90	$	0.22
Second quarter 2014		99	$	0.24
Third quarter 2014		98	$	0.24
Fourth quarter 2014		99	$	0.24
Total year-to-date	$	386

	10% Increase			10% Decrease
Gain (loss):	(Millions)
Gas derivatives	$	(67	)	$	64
Oil derivatives	$	(234	)	$	220
NGL derivatives	$	(1	)	$	1
Processing and fractionation derivatives	$	(3	)	$	3

	December 31, 2016			December 31, 2015
	(Millions, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	1,959		$	2,310
Accounts receivable		1,356			1,105
Assets held for sale		193			—
Other current assets		264			606
Total current assets		3,772			4,021
Property and equipment, at cost:
Oil and gas, based on full cost accounting:
Subject to amortization		75,648			78,190
Not subject to amortization		3,437			2,584
Total oil and gas		79,085			80,774
Midstream and other		10,455			10,380
Total property and equipment, at cost		89,540			91,154
Less accumulated depreciation, depletion and amortization		(73,350	)		(72,086	)
Property and equipment, net		16,190			19,068
Goodwill		3,964			5,032
Other long-term assets		1,987			1,330
Total assets	$	25,913		$	29,451
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	642		$	906
Revenues and royalties payable		908			763
Short-term debt		—			976
Other current liabilities		1,066			650
Total current liabilities		2,616			3,295
Long-term debt		10,154			12,056
Asset retirement obligations		1,226			1,370
Other long-term liabilities		894			853
Deferred income taxes		648			888
Stockholders’ equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 523 million and 418 million shares in 2016 and 2015, respectively		52			42
Additional paid-in capital		7,237			4,996
Retained earnings (accumulated deficit)		(1,646	)		1,781
Accumulated other comprehensive earnings		284			230
Total stockholders’ equity attributable to Devon		5,927			7,049
Noncontrolling interests		4,448			3,940
Total stockholders’ equity		10,375			10,989
Total liabilities and stockholders’ equity	$	25,913		$	29,451

											Accumulated
					Additional			Retained			Other									Total
	Common Stock				Paid-In			Earnings			Comprehensive			Treasury			Noncontrolling			Stockholders’
	Shares		Amount		Capital			(Accumulated Deficit)			Earnings			Stock			Interests			Equity
	(Millions)
Balance as of December 31, 2013		406	$	41	$	3,780		$	15,410		$	1,268		$	—		$	—		$	20,499
Net earnings		—		—		—			1,607			—			—			84			1,691
Other comprehensive loss, net of tax		—		—		—			—			(489	)		—			—			(489	)
Stock option exercises		1		—		93			—			—			—			—			93
Restricted stock grants, net of cancellations		2		—		—			—			—			—			—			—
Common stock repurchased		—		—		—			—			—			(27	)		—			(27	)
Common stock retired		—		—		(27	)		—			—			27			—			—
Common stock dividends		—		—		—			(386	)		—			—			—			(386	)
Share-based compensation		—		—		151			—			—			—			—			151
Share-based compensation tax expense		—		—		(3	)		—			—			—			—			(3	)
Acquisition of noncontrolling interests		—		—		—			—			—			—			4,670			4,670
Subsidiary equity transactions		—		—		93			—			—			—			277			370
Distributions to noncontrolling interests		—		—		—			—			—			—			(235	)		(235	)
Other		—		—		1			—			—			—			6			7
Balance as of December 31, 2014		409	$	41	$	4,088		$	16,631		$	779		$	—		$	4,802		$	26,341
Net loss		—		—		—			(14,454	)		—			—			(749	)		(15,203	)
Other comprehensive loss, net of tax		—		—		—			—			(549	)		—			—			(549	)
Stock option exercises		—		—		4			—			—			—			—			4
Restricted stock grants, net of cancellations		2		—		—			—			—			—			—			—
Common stock repurchased		—		—		—			—			—			(35	)		—			(35	)
Common stock retired		—		—		(35	)		—			—			35			—			—
Common stock dividends		—		—		—			(396	)		—			—			—			(396	)
Common stock issued		7		1		198			—			—			—			—			199
Share-based compensation		—		—		165			—			—			—			—			165
Share-based compensation tax expense		—		—		(9	)		—			—			—			—			(9	)
Subsidiary equity transactions		—		—		585			—			—			—			141			726
Distributions to noncontrolling interests		—		—		—			—			—			—			(254	)		(254	)
Balance as of December 31, 2015		418	$	42	$	4,996		$	1,781		$	230		$	—		$	3,940		$	10,989
Net loss		—		—		—			(3,302	)		—			—			(402	)		(3,704	)
Other comprehensive earnings, net of tax		—		—		—			—			54			—			—			54
Restricted stock grants, net of cancellations		2		—		—			—			—			—			—			—
Common stock repurchased		—		—		—			—			—			(28	)		—			(28	)
Common stock retired		—		—		(28	)		—			—			28			—			—
Common stock dividends		—		—		(96	)		(125	)		—			—			—			(221	)
Common stock issued		103		10		2,117			—			—			—			—			2,127
Share-based compensation		—		—		168			—			—			—			—			168
Subsidiary equity transactions		—		—		80			—			—			—			1,214			1,294
Distributions to noncontrolling interests		—		—		—			—			—			—			(304	)		(304	)
Balance as of December 31, 2016		523	$	52	$	7,237		$	(1,646	)	$	284		$	—		$	4,448		$	10,375

	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

Gains on asset sales	$	1,351

		Purchase Price (Millions)				Allocation (Millions)
Date	Acquiree	Cash		EnLink Units		PP&E		Goodwill		Intangibles		Other
January 2015	LPC	$	108		—	$	30	$	30	$	43	$	5
March 2015	Coronado	$	240	$	360	$	302	$	18	$	281	$	(1	)
October 2015	Matador	$	141		—	$	36	$	11	$	99	$	(5)

Crosstex Energy, Inc. outstanding common shares:
Held by public shareholders		48.0
Restricted shares		0.4
Total subject to conversion		48.4
Exchange ratio		1.0	x
Converted shares		48.4
Crosstex Energy, Inc. common share price ⁽¹⁾	$	37.60
Crosstex Energy, Inc. consideration	$	1,823
Fair value of noncontrolling interest in E2 ⁽²⁾		18
Total Crosstex Energy, Inc. consideration and fair value of noncontrolling interests	$	1,841
Crosstex Energy, LP outstanding units:
Common units held by public unitholders		75.1
Preferred units held by third party ⁽³⁾		17.1
Restricted units		0.4
Total		92.6
Crosstex Energy, LP common unit price⁽⁴⁾	$	30.51
Crosstex Energy, LP common units value	$	2,825
Crosstex Energy, LP outstanding unit options value		4
Total fair value of noncontrolling interests in the Crosstex Energy, LP ⁽⁴⁾		2,829
Total consideration and fair value of noncontrolling interests	$	4,670

Assets acquired:
Current assets	$	437
Property, plant and equipment		2,438
Intangible assets		569
Equity investment		222
Goodwill ⁽¹⁾		3,283
Other long-term assets		1
Liabilities assumed:
Current liabilities		(515	)
Long-term debt		(1,454	)
Deferred income taxes		(210	)
Other long-term liabilities		(101	)
Total purchase price	$	4,670

	Year Ended December 31, 2014
	(Millions)
Total operating revenues	$	20,213
Net earnings	$	1,716
Noncontrolling interests	$	97
Net earnings attributable to Devon	$	1,619
Net earnings per common share attributable to Devon	$	3.94

	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)
Q1-Q4 2017		72,527	$	54.32		53,245	$	45.16	$	57.97
Q1-Q4 2018		2,600	$	53.38		6,189	$	46.97	$	56.97

	Oil Basis Swaps						Oil Basis Swaps
Period	Index	Volume (Bbls/d)		Weighted Average Differential to WTI ($/Bbl)			Index	Volume (Bbls/d)		Weighted Average Differential to WTI ($/Bbl)
Q1-Q4 2017	Midland Sweet		10,000	$	(0.43	)
Q1-Q4 2020							Argus MEH		10,000	$	3.38
Q1-Q4 2020							NYMEX Roll		50,000	$	0.36

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

~~Period~~	~~Product~~	~~Volume (Total)~~			~~Weighted Average Price Paid~~	~~Weighted Average Price Received~~
~~Q1 2017-Q4 2017~~	~~Propane~~		~~434~~	~~MBbls~~	~~Index~~	~~$0.55/gal~~
~~Q1 2017-Q4 2017~~	~~Normal Butane~~		~~161~~	~~MBbls~~	~~Index~~	~~$0.70/gal~~
~~Q1 2017-Q4 2017~~	~~Natural Gas~~		~~21,685~~	~~MMBtu/d~~	~~Index~~	~~$3.14/MMbtu~~