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Index to Financial Statements

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 2020

or

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

Commission File Number 001-32318

DEVON ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware |  | 73-1567067
(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer identification No.)
333 West Sheridan Avenue, Oklahoma City, Oklahoma |  | 73102-5015
(Address of principal executive offices) |  | (Zip code)

Registrant’s telephone number, including area code: (405) 235-3611

Securities registered pursuant to Section 12(b) of the Act:

| 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 |

Securities registered pursuant to Section 12(g) of the Act: None

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 every Interactive Data File required to be submitted 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 such files). Yes ☒ No ☐

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

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

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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

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, 2020 was approximately $4.3 billion, based upon the closing price of $11.34 per share as reported by the New York Stock Exchange on such date. On February 3, 2021, 673.1 million shares of common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Registrant’s definitive Proxy Statement relating to Registrant’s 2020 annual meeting of stockholders have been incorporated by reference in Part III of this Annual Report on Form 10-K.

DEVON ENERGY CORPORATION

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Index to Financial Statements

FORM 10-K

TABLE OF CONTENTS

PART I |  | 6
Items 1 and 2. Business and Properties |  | 6
Item 1A. Risk Factors |  | 14
Item 1B. Unresolved Staff Comments |  | 22
Item 3. Legal Proceedings |  | 22
Item 4. Mine Safety Disclosures |  | 22
PART II |  | 23
Item 5. Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |  | 23
Item 6. Selected Financial Data |  | 25
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations |  | 26
Item 7A. Quantitative and Qualitative Disclosures about Market Risk |  | 48
Item 8. Financial Statements and Supplementary Data |  | 49
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |  | 104
Item 9A. Controls and Procedures |  | 104
Item 9B. Other Information |  | 104
PART III |  | 106
Item 10. Directors, Executive Officers and Corporate Governance |  | 106
Item 11. Executive Compensation |  | 106
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |  | 106
Item 13. Certain Relationships and Related Transactions, and Director Independence |  | 106
Item 14. Principal Accountant Fees and Services |  | 106
PART IV |  | 107
Item 15. Exhibits and Financial Statement Schedules |  | 107
Item 16. Form 10-K Summary |  | 116
Signatures |  | 117

2

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Index to Financial Statements

DEFINITIONS

Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon,” the “Company” and “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:

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

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

“ASC” means Accounting Standards Codification.

“ASU” means Accounting Standards Update.

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

“Bcf” means billion cubic feet.

“BKV” means Banpu Kalnin Ventures.

“BLM” means the United States Bureau of Land Management.

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

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

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

“CDM” means Cotton Draw Midstream, L.L.C.

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

“Devon Financing” means Devon Financing Company, L.L.C.

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

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

“EPA” means the United States Environmental Protection Agency.

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

“G&A” means general and administrative expenses.

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

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

“LIBOR” means London Interbank Offered Rate.

“LOE” means lease operating expenses.

“MBbls” means thousand barrels.

“MBoe” means thousand Boe.

“Mcf” means thousand cubic feet.

“Merger” means the merger of Merger Sub with and into WPX, with WPX continuing as the surviving corporation and a wholly-owned subsidiary of the Company, pursuant to the terms of the Merger Agreement.

3

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Index to Financial Statements

“Merger Agreement” means that certain Agreement and Plan of Merger, dated September 26, 2020, by and among the Company, Merger Sub and WPX.

“Merger Sub” means East Merger Sub, Inc., a wholly-owned subsidiary of the Company.

“MMBbls” means million barrels.

“MMBoe” means million Boe.

“MMBtu” means million Btu.

“MMcf” means million cubic feet.

“N/M” means not meaningful.

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

“NYMEX” means New York Mercantile Exchange.

“NYSE” means New York Stock Exchange.

“OPEC” means Organization of the Petroleum Exporting Countries.

“SEC” means United States Securities and Exchange Commission.

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

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

“S&P 500 Index” means Standard and Poor’s 500 index.

“TSR” means total shareholder return.

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

“VIE” means variable interest entity.

“WPX” means WPX Energy, Inc.

“WTI” means West Texas Intermediate.

“/Bbl” means per barrel.

“/d” means per day.

“/MMBtu” means per MMBtu.

4

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Index to Financial Statements

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This report includes “forward-looking statements” as defined by the SEC. Such statements include those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions, and are often identified by use of the words 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. All statements, other than statements of historical facts, included in this report that address activities, events or developments that Devon expects, believes or anticipates will or may occur in the 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 and adversely from our expectations due to a number of factors, including, but not limited to:

| • | the volatility of oil, gas and NGL prices;

| • | risks relating to the COVID-19 pandemic or other future pandemics;

| • | uncertainties inherent in estimating oil, gas and NGL reserves;

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

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

| • | risks related to regulatory, social and market efforts to address climate change;

| • | the uncertainties, costs and risks involved in our operations, including as a result of employee misconduct;

| • | risks related to our hedging activities;

| • | counterparty credit risks;

| • | risks relating to our indebtedness;

| • | cyberattack risks;

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

| • | midstream capacity constraints and potential interruptions in production;

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

| • | competition for assets, materials, people and capital;

| • | risks related to investors attempting to effect change;

| • | our ability to successfully complete mergers, acquisitions and divestitures;

| • | risks related to the Merger, including the risk that we may not realize the anticipated benefits of the Merger or successfully integrate the two legacy businesses; and

| • | any of the other risks and uncertainties discussed in this report.

The forward-looking statements included in this filing speak only as of the date of this report, represent current reasonable management’s expectations as of the date of this filing and are subject to the risks and uncertainties identified above as well as those described elsewhere in this report and in other documents we file from time to time with the SEC. We cannot guarantee the accuracy of our forward-looking statements, and readers are urged to carefully review and consider the various disclosures made in this report and in other documents we file from time to time with the SEC. All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We do not undertake, and expressly disclaim, any duty to update or revise our forward-looking statements based on new information, future events or otherwise.

5

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Index to Financial Statements

PART I

Items 1 and 2. Business and Properties

General

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 onshore areas in the U.S. In October 2020, we completed the sale of our Barnett Shale assets.

On January 7, 2021, Devon and WPX completed an all-stock merger of equals. WPX is an oil and gas exploration and production company with assets in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. This merger enhances the scale of our operations, builds a leading position in the Delaware Basin and accelerates our cash-return business model that prioritizes free cash flow generation and the return of capital to shareholders. In accordance with the Merger Agreement, WPX shareholders received a fixed exchange of 0.5165 shares of Devon common stock for each share of WPX common stock owned. The combined company continues to operate under the name Devon. Our principal and administrative offices are located at 333 West Sheridan, Oklahoma City, OK 73102-5015 (telephone 405-235-3611).

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. Reports filed with the SEC are also made available on its website at www.sec.gov.

Our Strategy

Our business strategy is focused on delivering a consistently competitive shareholder return among our peer 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 dependent on volatile and uncertain commodity prices, we pursue our strategy throughout all commodity price cycles with four fundamental principles.

Proven and responsible operator – We operate our business with the interests of our stakeholders and our environmental, social and governance values in mind. With our vision to be a premier independent oil and natural gas 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.

Premier, sustainable portfolio of assets – As discussed later in this 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 sustainable production extending many years into the future. Due to the strength of oil prices relative to natural gas, we have positioned our portfolio to be more heavily weighted to U.S. oil assets in recent years.

During 2019, we sold our Canadian business, generating $2.6 billion in proceeds. During 2020, we sold our Barnett Shale assets, generating proceeds of $490 million and contingent earnout payments to Devon of up to $260 million based upon future commodity prices, with upside participation beginning at a $2.75 Henry Hub natural gas price or a $50 WTI oil price. On January 7, 2021, Devon and WPX completed an all-stock merger of equals. WPX is an oil and gas exploration and production company with assets in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. As a result of these transactions, our oil production, price realizations and field-level margins will all improve, as we sharpen our focus on five U.S. oil and liquids plays located in the Delaware Basin, Powder River Basin, Anadarko Basin, Williston 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.

With the WPX Merger and continuous improvement initiatives, we are building a scalable, multi-basin portfolio of U.S. oil assets and aggressively improving our cost structure to further expand margins. We have realized annualized cost savings by reducing well costs, production expense, financing costs and G&A costs.

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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.

Human Capital

Delivering strong operational and financial results in a safe, environmentally and socially responsible way requires the expertise and positive contributions of every Devon employee. Consequently, our people are the Company’s most important resource and we seek to hire the best people who share our core values of doing the right thing, delivering results and being good team members and neighbors to our communities. To develop our workforce, we focus on training, safety, wellness, inclusion, diversity and equality. As of December 31, 2020, Devon and its consolidated subsidiaries had approximately 1,400 employees, all located in the U.S.

Employee Safety and Wellness

We prepare our workforce to work safely with comprehensive training and orientation, on-the-job guidance and tools, safety engagements, recognition and other resources. Employees and contractors are expected to comply with safety rules and regulations and are accountable to stopping at-risk work, immediately reporting incidents and near-miss events and informing visitors of emergency alarms and evacuation plans. To safeguard workers on our well sites and neighbors nearby, we plan, design, drill, complete and produce wells using proven best practices, technologies, tools and materials.

In response to the COVID-19 pandemic, we have developed and implemented a number of safety measures to help our employees manage their work and personal responsibilities, with a strong focus on employee well-being, health and safety. Refer to “COVID-19” included in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for information on actions taken by Devon to protect and support its employees during the COVID-19 pandemic.

Beyond employee safety, Devon also prioritizes the physical, mental and financial wellness of our employees. We offer competitive health and financial benefits with incentives designed to promote wellbeing. For example, we encourage employees to take advantage of our wellness programs and activities by getting an annual physical exam or completing a financial wellness series at no cost to employees.

Employee Compensation, Benefits and Development

We strive to attract and retain high-performing individuals across our workforce. One way we do this is by providing competitive compensation and benefits, including annual bonuses; a 401(k) savings plan with a Devon match; stock awards; medical, dental and vision health care coverage; health savings and dependent-care flexible spending accounts; maternity and parental leave for the birth or adoption of a child; an adoption assistance program; alternate work schedules; flexible work hours; part-time work options; telecommuting support; among other benefits.

Devon also looks to our core values to build the workforce we need. We develop our employees’ knowledge and creativity and advance continual learning and career development through ongoing performance, training and development conversations.

Inclusion and Diversity

Devon’s success depends on employees who demonstrate integrity, accountability, perseverance and a passion for building our business and delivering results. Our efforts to create a workforce with these qualities start with offering equal opportunity in all aspects of employment. We do this with employee-led organizations and corporate policies.

We promote inclusion and diversity throughout the Company to bring a range of thoughts, experiences and points of view to our problem-solving and decision-making processes. Devon has an Inclusion and Diversity Leadership Team, which consists of senior leaders who support others by coaching, motivating and breaking down barriers. The Inclusion and Diversity Leadership Team works together with Devon’s all-volunteer Inclusion Action Team to proactively increase diversity and inclusion awareness, identify challenges and find innovative ways to achieve Devon’s inclusion and diversity vision and strategy.

All Devon employees must act in accordance with our Code of Business Conduct and Ethics (“Code”), which sets forth current business practices and guidance to ensure ongoing compliance. Our Code covers topics such as anti-corruption, harassment, discrimination, privacy, cybersecurity, confidential information and how to report Code violations. On an annual basis, Devon employees are required to acknowledge and agree to abide by our Code, as well as complete a training course on the Code and its related policies. Additionally, our directors, officers and employees are required to comply with policies such as our Zero Tolerance Anti-Harassment Policy, Anti-Corruption Policy and Procedure, Conflicts of Interest Policy and Employee Gifts and Entertainment Declaration Policy.

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Additional information regarding Devon’s human capital measures and objectives is contained in Devon’s Sustainability Report published on our company website. 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.

Oil and Gas Properties

WPX Merger Assets

On January 7, 2021, Devon and WPX completed an all-stock merger of equals. WPX is an oil and gas exploration and production company with assets in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. Financial and operational data, such as reserves, production, wells and acreage, provided in this document exclude amounts related to WPX’s assets unless otherwise noted due to the Merger closing subsequent to December 31, 2020. For additional information, please see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

Canadian Business and Barnett Shale Assets – Discontinued Operations

As a result of our divestment of substantially all of our oil and gas assets and operations in Canada, as well as the divestiture of our Barnett Shale assets, amounts associated with these assets are presented as discontinued operations. The 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 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

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Property Profiles

Key summary data from each of our areas of operation as of and for the year ended December 31, 2020 are detailed in the map below.

Delaware Basin – The Delaware Basin is Devon’s most active program in the portfolio. Through capital-efficient drilling programs, it offers exploration and low-risk development opportunities from many geologic reservoirs and play types, including the oil-rich Wolfcamp, Bone Spring, Leonard and Delaware formations. With a significant inventory of oil and liquids-rich drilling opportunities that have multi-zone development potential, Devon has a robust platform to deliver high-margin drilling programs for many years to come. At December 31, 2020, we had eight operated rigs developing this asset in the Wolfcamp and Bone Spring formations. Combined with the Delaware Basin assets acquired in the WPX merger, we plan to invest approximately $1.5 billion of capital in the Delaware Basin in 2021, making it the top-funded asset in the portfolio.

Powder River Basin – This asset is focused on emerging oil opportunities in the Powder River Basin. Devon is currently targeting several Cretaceous oil objectives, including the Turner, Parkman, Teapot and Niobrara formations. Recent drilling success in this basin has expanded our drilling inventory, and we expect further growth as we accelerate activity and continue to de-risk this emerging light-oil opportunity. Devon has several uncompleted wells in its Powder River Basin inventory and has resumed capital activity in early 2021. In 2021, we plan approximately $80 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 has low-cost access to premium Gulf Coast pricing, providing for solid operating margins. As a result of the COVID-19 pandemic and related significant decrease to oil pricing in early 2020, Devon did not pursue any drilling and completion

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activity in the latter half of 2020 for these assets. Devon has several uncompleted wells in its Eagle Ford inventory and has resumed capital activity in early 2021. In 2021, we plan approximately $11 0 million of capital investment.

Anadarko Basin – Our Anadarko Basin development, located primarily in Oklahoma’s Canadian, Kingfisher and Blaine counties, provides long-term optionality through its significant inventory. Our Anadarko Basin position is one of the largest in the industry, providing visible long-term production. At the end of 2019, we announced an agreement with Dow to jointly develop a portion of our Anadarko Basin acreage. This joint venture activity was delayed in response to the challenged macro-economic environment resulting from the COVID pandemic. However, due to improvements in natural gas pricing, the joint venture has commenced in the first quarter of 2021 with a two operated rig program. Dow will fund approximately 65% of the partnership capital requirements through a drilling carry of $100 million over the next four years. In 2021, we plan approximately $75 million of capital investment, net to Devon.

Proved Reserves

Proved oil and gas reserves are those quantities of oil, gas and NGLs which 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. We establish our proved reserves estimates using standard geological and engineering technologies and computational methods, which are generally accepted by the petroleum industry. We primarily prepare our proved reserves additions by analogy using type curves that are based on decline curve analysis of wells in analogous reservoirs. We further establish reasonable certainty of our proved reserves estimates by using one or more of the following methods: geological and geophysical information to establish reservoir continuity between penetrations, rate-transient analysis, analytical and numerical simulations, or other proprietary technical and statistical methods. 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.

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 in compliance with applicable SEC definitions and guidance. Our policies assign responsibilities for compliance in reserves bookings to our Reserve Evaluation Group (the “Group”). 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 and are independent of the operating groups. The Director of the Group has over 30 years of industry experience, a degree in engineering and is a registered professional engineer. The Group also oversees audits and reserves estimates performed by qualified third-party petroleum consulting firms. During 2020, we engaged LaRoche Petroleum Consultants, Ltd. to audit approximately 88% of our proved reserves. Additionally, we have a Reserves Committee that provides additional oversight of our reserves process. The committee consists of five independent members of our Board of Directors with education or business backgrounds relevant to the reserves estimation process.

The following tables present production, price and cost information for each significant field in our asset portfolio and the total company.

|  | Production |
Year Ended December 31, |  | Oil (MMBbls) |  |  | Gas (Bcf) |  |  | NGLs (MMBbls) |  |  | Total (MMBoe) |
2020 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Anadarko Basin |  |  | 7 |  |  |  | 92 |  |  |  | 10 |  |  |  | 33 |
Delaware Basin |  |  | 31 |  |  |  | 91 |  |  |  | 13 |  |  |  | 60 |
Total |  |  | 57 |  |  |  | 221 |  |  |  | 29 |  |  |  | 122 |
2019 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Anadarko Basin |  |  | 11 |  |  |  | 114 |  |  |  | 13 |  |  |  | 43 |
Delaware Basin |  |  | 26 |  |  |  | 65 |  |  |  | 10 |  |  |  | 46 |
Total |  |  | 55 |  |  |  | 219 |  |  |  | 28 |  |  |  | 119 |
2018 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Anadarko Basin |  |  | 12 |  |  |  | 121 |  |  |  | 14 |  |  |  | 45 |
Delaware Basin |  |  | 16 |  |  |  | 42 |  |  |  | 6 |  |  |  | 30 |
Total |  |  | 47 |  |  |  | 206 |  |  |  | 26 |  |  |  | 108 |

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|  | Average Sales Price |  |  |  |  |
Year Ended December 31, |  | Oil (Per Bbl) |  |  | Gas (Per Mcf) |  |  | NGLs (Per Bbl) |  |  | Production Cost (Per Boe) (1) |
2020 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Anadarko Basin (2) |  | $ | 35.80 |  |  | $ | 1.66 |  |  | $ | 12.11 |  |  | $ | 9.61 |
Delaware Basin |  | $ | 37.25 |  |  | $ | 1.08 |  |  | $ | 10.64 |  |  | $ | 5.76 |
Total |  | $ | 35.95 |  |  | $ | 1.48 |  |  | $ | 11.72 |  |  | $ | 7.66 |
2019 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Anadarko Basin |  | $ | 55.13 |  |  | $ | 1.97 |  |  | $ | 15.90 |  |  | $ | 7.36 |
Delaware Basin |  | $ | 54.01 |  |  | $ | 0.99 |  |  | $ | 13.54 |  |  | $ | 6.43 |
Total |  | $ | 54.73 |  |  | $ | 1.79 |  |  | $ | 15.21 |  |  | $ | 7.75 |
2018 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Anadarko Basin |  | $ | 63.81 |  |  | $ | 2.29 |  |  | $ | 25.53 |  |  | $ | 7.16 |
Delaware Basin |  | $ | 57.24 |  |  | $ | 1.80 |  |  | $ | 24.05 |  |  | $ | 8.15 |
Total |  | $ | 61.96 |  |  | $ | 2.34 |  |  | $ | 25.47 |  |  | $ | 8.22 |

| (1) | Represents production expense per Boe excluding production and property taxes.

| (2) | Production cost per Boe was higher in 2020 due to volume commitments which expired at the end of 2020.

Drilling Statistics

The following table summarizes our development and exploratory drilling results.

|  | Development Wells (1) |  |  | Exploratory Wells (1) |  |  | Total Wells (1) |
Year Ended December 31, |  | Productive |  |  | Dry |  |  | Productive |  |  | Dry |  |  | Productive |  |  | Dry |  |  | Total |
2020 |  |  | 106.5 |  |  |  | — |  |  |  | 26.6 |  |  |  | — |  |  |  | 133.2 |  |  |  | — |  |  |  | 133.2 |
2019 |  |  | 161.7 |  |  |  | — |  |  |  | 27.2 |  |  |  | — |  |  |  | 188.9 |  |  |  | — |  |  |  | 188.9 |
2018 |  |  | 154.9 |  |  |  | 3.1 |  |  |  | 69.4 |  |  |  | — |  |  |  | 224.3 |  |  |  | 3.1 |  |  |  | 227.4 |

(1) | Well counts represent net wells completed during each year. Net wells are gross wells multiplied by our fractional working interests.

As of December 31, 2020, there were 156 gross and 77.6 net wells that have been spud and are in the process of drilling, completing or waiting on completion. To effectively manage capital expenditures and provide flexibility in managing drilling rig and well completion schedules, we have a large inventory of drilled but not completed wells. Gross wells are the sum of all wells in which we own a working interest. Net wells are gross wells multiplied by our fractional working interests in each well.

Productive Wells

The following table sets forth our producing wells as of December 31, 2020.

|  | Oil Wells |  |  | Natural Gas Wells |  |  | Total Wells |
|  | Gross (1)(3) |  |  | Net (2) |  |  | Gross (1)(3) |  |  | Net (2) |  |  | Gross (1)(3) |  |  | Net (2) |
Total |  |  | 7,752 |  |  |  | 2,385 |  |  |  | 2,980 |  |  |  | 1,201 |  |  |  | 10,732 |  |  |  | 3,586 |

(1) | Gross wells are the sum of all wells in which we own a working interest.

(2) | Net wells are gross wells multiplied by our fractional working interests in each well.

(3) | Includes 45 and 57 gross oil and gas wells, respectively, which had multiple completions.

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 3,942 gross wells. As operator, we receive reimbursement for direct expenses incurred to perform our duties, as well as monthly per-well producing, drilling, and 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.

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Acreage Statistics

The following table sets forth our developed and undeveloped lease and mineral acreage as of December 31, 2020. Of our 1.8 million net acres, approximately 1.0 million acres are held by production. The acreage in the table includes approximately 0.1 million net acres subject to leases that are scheduled to expire during 2021, 2022 and 2023. Of the 0.1 million net acres set to expire by December 31, 2023, we 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. Subsequent to our merger with WPX, less than 20% of our total net acres are located on federal lands.

|  | Developed |  |  | Undeveloped |  |  | Total |
|  | Gross (1) |  |  | Net (2) |  |  | Gross (1) |  |  | Net (2) |  |  | Gross (1) |  |  | Net (2) |
|  | (Thousands) |
Total |  |  | 953 |  |  |  | 504 |  |  |  | 2,994 |  |  |  | 1,267 |  |  |  | 3,947 |  |  |  | 1,771 |

(1) | Gross acres are the sum of all acres in which we own a working interest.

(2) | Net acres are gross acres multiplied by our fractional working interests in the acreage.

Title to Properties

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, a preliminary title investigation, typically consisting of a review of local title records, is made at the time of acquisitions of undeveloped properties. More thorough title investigations, which generally include a review of title records and the preparation of title opinions by outside legal counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.

Marketing Activities

Oil, Gas and NGL Marketing

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 2021, our production was sold under the following contract terms.

|  | Short-Term |  |  | Long-Term |
|  | Variable |  |  | Fixed |  |  | Variable |  |  | Fixed |
Oil |  |  | 45 | % |  |  | 5 | % |  |  | 50 | % |  |  | — |
Natural gas |  |  | 56 | % |  |  | 3 | % |  |  | 41 | % |  |  | — |
NGLs |  |  | 63 | % |  |  | 25 | % |  |  | 12 | % |  |  | — |

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Delivery Commitments

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, 2020, we were committed to deliver the following fixed quantities of production.

|  | Total |  |  | Less Than 1 Year |  |  | 1-3 Years |  |  | 3-5 Years |  |  | More Than 5 Years |
Natural gas (Bcf) |  |  | 174 |  |  |  | 90 |  |  |  | 52 |  |  |  | 32 |  |  |  | — |
NGLs (MMBbls) |  |  | 7 |  |  |  | 7 |  |  |  | — |  |  |  | — |  |  |  | — |
Total (MMBoe) |  |  | 36 |  |  |  | 22 |  |  |  | 9 |  |  |  | 5 |  |  |  | — |

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.

Competition

See “Item 1A. Risk Factors.”

Public Policy and Government Regulation

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.

Exploration and Production Regulation

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

| • | acquisition of seismic data;

| • | location, drilling and casing of wells;

| • | well design;

| • | hydraulic fracturing;

| • | well production;

| • | spill prevention plans;

| • | emissions and discharge permitting;

| • | use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;

| • | surface usage and the restoration of properties upon which wells have been drilled;

| • | calculation and disbursement of royalty payments and production taxes;

| • | plugging and abandoning of wells;

| • | transportation of production; and

| • | endangered species and habitat.

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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 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. Moreover, the permitting process for oil and gas activities on federal lands can sometimes be subject to delay, which can stall development activities or otherwise adversely impact operations. The federal government has, from time to time, evaluated and, in some cases, 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, President Biden and certain members of his administration have expressed support for, and have taken steps to implement, additional restrictions on oil and gas activities on federal lands, including orders temporarily limiting the approval of new leases and drilling permits to certain high-ranking officials within the Department of the Interior, as well as a pause on entering into future oil and gas leases on public lands.

Environmental, Pipeline Safety and Occupational Regulations

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, and local laws and regulations concerning occupational safety and health as well as the discharge of materials into, and the protection of, the environment and natural resources. Environmental laws and regulations relate to:

| • | the discharge of pollutants into federal and state waters;

| • | assessing the environmental impact of seismic acquisition, drilling or construction activities;

| • | the generation, storage, transportation and disposal of waste materials, including hazardous substances and wastes;

| • | the emission of certain gases into the atmosphere;

| • | the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations;

| • | the development of emergency response and spill contingency plans;

| • | the monitoring, repair and design of pipelines used for the transportation of oil and natural gas;

| • | the protection of threatened and endangered species; and

| • | worker protection.

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 sue operators for alleged violations of environmental law. Environmental organizations also can assert legal and administrative challenges to certain actions of oil and gas regulators, such as the 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 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 and permitting requirements, 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.

Item 1A. Risk Factors

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

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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.

Volatile Oil, Gas and NGL Prices Significantly Impact Our Business

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, over the last five years, monthly NYMEX WTI oil and NYMEX Henry Hub gas prices ranged from highs of over $67 per Bbl and $4.80 per MMBtu, respectively, to lows of under $30 per Bbl and $1.50 per MMBtu, respectively. Such volatility is likely to continue in the future due to numerous factors beyond our control, including, but not limited to:

| • | the domestic and worldwide supply of and demand for oil, gas and NGLs;

| • | volatility and trading patterns in the commodity-futures markets;

| • | conservation and environmental protection efforts;

| • | production levels of members of OPEC, Russia, the U.S. or other producing countries;

| • | geopolitical risks, including political and civil unrest in the Middle East, Africa and South America;

| • | adverse weather conditions, natural disasters, public health crises and other catastrophic events, such as tornadoes, earthquakes, hurricanes and epidemics of infectious diseases;

| • | regional pricing differentials, including in the Delaware Basin and other areas of our operations;

| • | differing quality of production, including NGL content of gas produced;

| • | the level of imports and exports of oil, gas and NGLs and the level of global oil, gas and NGL inventories;

| • | the price and availability of alternative energy sources;

| • | technological advances affecting energy consumption and production, including with respect to electric vehicles;

| • | stockholder activism or activities by non-governmental organizations to restrict the exploration and production of oil and natural gas in order to reduce greenhouse gas emissions;

| • | the overall economic environment;

| • | changes in trade relations and policies, including the imposition of tariffs by the U.S. or China; and

| • | other governmental regulations and taxes.

Our Business Has Been Adversely Impacted by the COVID-19 Pandemic, and We May Experience Continuing or Worsening Adverse Effects From This or Other Pandemics

The COVID-19 pandemic and related economic repercussions have created significant volatility, uncertainty and turmoil in the oil and gas industry. This outbreak and the related responses of governmental authorities and others to limit the spread of the virus significantly reduced global economic activity, resulting in an unprecedented decline in the demand for oil and other commodities during 2020. Combined with other factors, this decline in demand caused a swift and material deterioration in commodity prices in early 2020, which adversely impacted our results of operations for 2020 and contributed to our recognition of a material asset impairment to our oil and gas assets during the first quarter of 2020. The negative effects of COVID-19 on economic prospects across the world have contributed to concerns for the potential of a prolonged economic slowdown and recession. Any such downturns, or protracted periods of depressed commodity prices, could have significant adverse consequences for our financial condition and liquidity. Moreover, any such downturns could also result in similar financial constraints for our non-operating partners, purchasers of our production and other counterparties, thereby increasing the risk that such counterparties default on their obligations to us. Such defaults or more general supply chain disruptions due to the pandemic may also jeopardize the supply of materials, equipment or services for our operations.

The COVID-19 pandemic and related restrictions aimed at mitigating its spread have caused us to modify certain of our business practices, including limiting employee travel, encouraging work-from-home practices and other social distancing measures. There is no certainty that these or any other future measures will be sufficient to mitigate the risks posed by the disease, including the risk of infection of key employees, and our ability to perform certain functions could be disrupted or otherwise impaired by these new

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business practices. For example, our reliance on technology has necessarily increased due to our encouragement of remote communications and other work-from-home practices, which could make us more vulnerable to cyber attacks.

The COVID-19 pandemic and its related effects continue to evolve. The ultimate extent of the impact of the COVID-19 pandemic and any other future pandemic on our business will depend on future developments, including, but not limited to, the nature, duration and spread of the disease, the vaccination and other responsive actions to stop its spread or address its effects and the duration, timing and severity of the related consequences on commodity prices and the economy more generally, including any recession resulting from the pandemic. Any extended period of depressed commodity prices or general economic disruption as a result of a pandemic would adversely affect our business, financial condition and results of operations.

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 reserves estimates may occur as a result of changes in any of these factors. Such revisions to proved reserves could have 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.

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

Our operations are subject to extensive federal, state, 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 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, including corporate successors of former operators. These requirements may result in significant costs associated with the removal of tangible equipment and other restorative actions.

In addition, changes in public policy have affected, and in the future could further affect, our operations. For example, President Biden and certain members of his administration and Congress have expressed support for, and have taken steps to implement, efforts to transition the economy away from fossil fuels and to promote stricter environmental regulations, and such proposals could impose new and more onerous burdens on our industry and business. These and other regulatory and public policy developments could, among other things, restrict production levels, delay necessary permitting, impose price controls, change environmental protection requirements, impose restrictions on pipelines or other necessary infrastructure 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

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fostering general economic uncertainty. 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 leasing and permitting on federal lands, hydraulic fracturing, environmental matters more generally, seismic activity and income taxes, as discussed below.

Federal Lands – President Biden and certain members of his administration have expressed support for, and have taken steps to implement, additional regulation of oil and gas leasing and permitting on federal lands. Such proposals range from more onerous permitting requirements to an outright moratorium on new oil and gas leasing and permitting on federal lands. For example, on January 20, 2021, the Acting Secretary of the Department of the Interior issued an order temporarily limiting the authority to approve certain fossil fuel authorizations on federal lands, including the approval of new leases and new drilling permits, to certain high-ranking officials within the Department of the Interior. In addition, President Biden issued an executive order on January 27, 2021 directing the Secretary of the Interior to pause on entering new oil and gas leases on public lands to the extent possible and to launch a rigorous review of all existing leasing and permitting practices related to fossil fuel development on public lands. While it is not possible at this time to predict the ultimate impact of these or any other future regulatory changes, any additional restrictions or prohibitions on our ability to operate on federal lands could adversely impact our business in the Delaware and Powder River Basins, as well as other areas where we operate under federal leases. Post-merger, less than 20% of our total leasehold resides on federal lands primarily located in the Delaware and Powder River Basins.

Hydraulic Fracturing – In recent years, various federal agencies have asserted regulatory authority over certain aspects of the hydraulic fracturing process. For example, the EPA has issued 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 2016 regulations that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. The EPA also released a report in 2016 finding that certain aspects of hydraulic fracturing, such as water withdrawals and wastewater management practices, could result in impacts to water resources in certain circumstances. The BLM 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 adopted, or stated intentions to adopt, laws or regulations that mandate further restrictions on hydraulic fracturing, such as requiring disclosure of chemicals used in hydraulic fracturing, imposing more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations and establishing standards for the capture of air emissions released during hydraulic fracturing. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general or hydraulic fracturing in particular.

Beyond these regulatory efforts, various policy makers, regulatory agencies and political leaders at the federal, state and local levels have proposed implementing even further restrictions on hydraulic fracturing, including prohibiting the technology outright. Although it is not possible at this time to predict the outcome of these or other proposals, any new 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.

Environmental Laws Generally – In addition to regulatory efforts focused on hydraulic fracturing, we are subject to various other federal, state 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 or prior operations on assets we have acquired. 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 impact on our operations and profitability.

Seismic Activity – Earthquakes in northern and central Oklahoma, southeastern New Mexico, western Texas and elsewhere have prompted concerns about seismic activity and possible relationships with the 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.

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 or previously operated, 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 (such as

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intangible drilling costs) and the timing of such deductions, or the rates assessed on our taxable earnings would all impact our income taxes and resulting operating cash flow.

Concerns About Climate Change and Related Regulatory, Social and Market Actions May Adversely Affect Our Business

Continuing and increasing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives, including international agreements, to reduce greenhouse gas emissions, such as carbon dioxide and methane. Policy makers and regulators at both the U.S. federal and state levels have already imposed, or stated intentions to impose, laws and regulations designed to quantify and limit the emission of greenhouse 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; although the methane specific requirements of some of these regulations have been repealed, similar or more stringent emissions requirements may be imposed by the Biden Administration. In addition, several states where we operate, including Wyoming, New Mexico and Texas, have 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 leaders have made, or expressed support for, a variety of proposals, such as the development of cap-and-trade or carbon tax programs. In addition, President Biden has highlighted addressing climate change as a priority of his administration, and he previously released an energy plan calling for a number of sweeping changes to address climate change, including, among other measures, a national mobilization effort to achieve net-zero emissions for the U.S. economy by 2050, through increased use of renewable power, stricter fuel-efficiency standards and support for zero-emission vehicles. President Biden issued a number of executive orders in January 2021 with the purpose of implementing certain of these changes, including the rejoining of the Paris Agreement, a call for the issuance of more stringent methane emissions regulations for oil and gas facilities and an order directing federal agencies to procure electric vehicles. Although the full impact of these orders is uncertain at this time, the adoption and implementation of these or other initiatives may result in the restriction or cancellation of oil and natural gas activities, greater costs of compliance or consumption (thereby reducing demand for our products) or an impairment in our ability to continue our operations in an economic manner.

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 specific fuels or technologies. These initiatives may reduce the competitiveness of carbon-based fuels, such as oil and gas. Moreover, an increasing number of financial institutions, funds and other sources of capital have begun restricting or eliminating their investment in oil and natural gas activities due to their concern regarding climate change. Such restrictions in capital could decrease the value of our business and make it more difficult to fund our operations. 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 an adverse effect on our profitability, financial condition and liquidity.

Our Operations Are Uncertain and Involve Substantial Costs and Risks

Our 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 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:

| • | unexpected drilling conditions, pressure conditions or irregularities in reservoir formations;

| • | equipment failures or accidents;

| • | fires, explosions, blowouts, cratering or loss of well control, as well as the mishandling or underground migration of fluids and chemicals;

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| • | adverse weather conditions and natural disasters, such as tornadoes, earthquakes, hurricanes and extreme temperatures;

| • | issues with title or in receiving governmental permits or approvals;

| • | restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or constrained downstream markets;

| • | environmental hazards or liabilities;

| • | restrictions in access to, or disposal of, water used or produced in drilling and completion operations; and

| • | shortages or delays in the availability of services or delivery of equipment.

The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, as well as significant liabilities. Moreover, certain of these events 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 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.

In addition, we rely on our employees, consultants and sub-contractors to conduct our operations in compliance with applicable laws and standards. Any violation of such laws or standards by these individuals, whether through negligence, harassment, discrimination or other misconduct, could result in significant liability for us and adversely affect our business. For example, negligent operations by employees could result in serious injury, death or property damage, and sexual harassment or racial and gender discrimination could result in legal claims and reputational harm.

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

We enter into 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 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 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.

The Credit Risk of Our Counterparties Could Adversely Affect Us

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 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 obligations and liabilities (including contingent liabilities) owed to, and assumed from, us, particularly during a depressed or volatile commodity price environment. Any such default may result in us being forced to cover the costs of those obligations and liabilities, which could adversely impact our financial results and condition.

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

As of December 31, 2020, we had total indebtedness of $4.3 billion. Our indebtedness and other financial commitments have important consequences to our business, including, but not limited to:

| • | requiring us to dedicate a portion of our cash flows from operations to debt service payments, thereby limiting our ability to fund working capital, capital expenditures, investments or acquisitions and other general corporate purposes;

| • | increasing our vulnerability to general adverse economic and industry conditions, including low commodity price environments; and

| • | limiting our ability to obtain additional financing due to higher costs and more restrictive covenants.

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 asset sales and purchases, liquidity, forecasted production growth and commodity prices. We are currently required to provide letters of credit or other assurances under certain of our contractual arrangements. 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.

Cyber Attacks May Adversely Impact Our Operations

Our business has become increasingly dependent on digital technologies, and we anticipate expanding the use of these technologies in our operations, including through artificial intelligence, process automation and data analytics. Concurrent with the growing dependence on technology is greater sensitivity to cyber attack related activities, which have increasingly targeted our industry. Cyber attackers often attempt to gain unauthorized access to digital systems for purposes of misappropriating confidential and proprietary information, intellectual property or financial assets, corrupting data or causing operational disruptions as well as preventing users from accessing systems or information for the purpose of demanding payment in order for users to regain access. These attacks may be perpetrated by third parties or insiders. 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 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, 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.

We Have Limited Control Over Properties Operated by Others

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.

Midstream Capacity Constraints and Interruptions Impact Commodity Sales

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. All or a portion of our production in 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, the midstream operators may be subject to constraints that limit 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.

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Insurance Does Not Cover All Risks

As discussed above, our business is hazardous and is subject to all of the operating risks normally associated with the exploration, development and production of oil, gas and NGLs. 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, we have limited or no insurance coverage for a variety of other risks, including pollution events that are considered gradual, war and political risks and fines or penalties assessed by governmental authorities. The occurrence of a significant event against which we are not fully insured could have an adverse effect on our profitability, financial condition and liquidity.

Competition for Assets, Materials, People and Capital Can Be Significant

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 and may have established superior strategic long-term positions and relationships, 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 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 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 Acquisition and Divestiture Activities Involve Substantial Risks

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:

| • | mistaken estimates or assumptions about reserves, potential drilling locations, revenues and costs, including synergies and the overall costs of equity or debt;

| • | difficulties in integrating the operations, technologies, products and personnel of the acquired assets or business; and

| • | unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections prove inadequate, including environmental liabilities and title defects.

In addition, from time to time, we may sell or otherwise dispose of certain of our properties or businesses as a result of an evaluation of our asset portfolio and to help enhance our liquidity. These transactions also have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets or business and potential post-closing claims for indemnification. Moreover, volatility in commodity prices may result in fewer potential bidders, unsuccessful sales efforts and a higher risk that buyers may seek to terminate a transaction prior to closing.

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We M ay F ail to R ealize the A nticipated B enefits of the Merger

The ultimate success of the Merger will depend on, among other things, our ability to combine the legacy Devon and WPX businesses in a manner that realizes anticipated synergies and benefits. If we are not able to successfully achieve these synergies, or the cost to achieve these synergies is greater than expected, then the anticipated benefits of the Merger may not be realized fully or at all or may take longer to realize than expected. It is possible that the integration process could result in the loss of key employees, the loss of customers, the disruption of our ongoing businesses, inconsistencies in standards, controls, procedures and policies, unexpected integration issues, higher than expected integration costs and an overall post‑completion integration process that takes longer than originally anticipated. Furthermore, our board of directors and management team consist of directors and employees from each of the legacy companies. The integration of these individuals could require the reconciliation of differing priorities and strategic philosophies, which may not be successful or take longer than anticipated.

Item 1B. Unresolved Staff Comments

Not applicable.

Item 3. Legal Proceedings

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

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is traded on the NYSE under the “DVN” ticker symbol. On February 3, 2021, there were 12,611 holders of record of our common stock. We began paying regular quarterly cash dividends in the second quarter of 1993. Following the closing of the Merger, Devon initiated a “fixed plus variable” dividend strategy. Under this strategy, Devon plans to pay, on a quarterly basis, a fixed dividend amount and, potentially, a variable dividend amount, if any, to its stockholders. The declaration and payment of any future dividend, whether fixed or variable, will remain at the full discretion of the Board of Directors and will depend on Devon’s financial results, cash requirements, future prospects, COVID-19 impacts and other factors deemed relevant by the Devon Board. In determining the amount of the quarterly fixed dividend, the Board expects to consider a number of factors, including Devon’s financial condition, the commodity price environment and a general target of paying out approximately 10% of operating cash flow through the fixed dividend. Any variable dividend amount will be determined on a quarterly basis and will equal up to 50% of “excess free cash flow,” which is a non-GAAP measure and is computed as operating cash flow (a GAAP measure) before balance sheet changes, less capital expenditures and the fixed dividend. A number of factors will be considered when determining if a variable dividend payment will be made. Devon expects that the most critical factors will consist of Devon’s financial condition, including its cash balances and leverage metrics, as well as the commodity price outlook. Additional information on our dividends can be found in Note 18 in “Item 8. Financial Statements and Supplementary Data” of this report.

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Performance Graph

The following graph compares the cumulative TSR over a five-year period on Devon’s common stock with the cumulative total returns of the S&P 500 Index and peer groups of companies to which we compare our performance. In 2020, this peer group was recalibrated to better align with Devon’s go-forward size and operations, in light of our strategic transformation in 2019, and due to consolidation within the industry. The new 2020 peer group includes Apache Corporation, Chesapeake Energy Corporation, Cimarex Energy Co., Continental Resources, Inc., EOG Resources, Inc., Marathon Oil Corporation, Occidental Petroleum Corporation, Ovintiv, Inc. and Pioneer Natural Resources. In 2019, the peer group included Apache Corporation, Chesapeake Energy Corporation, ConocoPhillips, Continental Resources, Inc., EOG Resources, Inc., Hess Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Occidental Petroleum Corporation, Ovintiv, Inc. and Pioneer Natural Resources Company. Anadarko Petroleum Corporation, Concho Resources, Inc. and Noble Energy, Inc. were previously included in these peer groups, but have been excluded as a result of being acquired as part of the continuing consolidation in the industry. The graph was prepared assuming $100 was invested on December 31, 2015 in Devon’s common stock, the peer groups and the S&P 500 Index, and dividends have been reinvested subsequent to the initial investment.

The graph and related information should not be deemed “soliciting material” or to be “filed” with the SEC, nor should such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate such information by reference into such a filing. The graph and information are included for historical comparative purposes only and should not be considered indicative of future stock performance.

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Issuer Purchases of Equity Securities

The following table provides information regarding purchases of our common stock that were made by us during the fourth quarter of 2020 (shares in thousands).

Period |  | Total Number of Shares Purchased (1) |  |  | Average Price Paid per Share |  |  | Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs (2) |  |  | Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (2) |
October 1 - October 31 |  |  | 63 |  |  | $ | 8.98 |  |  |  | — |  |  | $ | 962 |
November 1 - November 30 |  |  | 17 |  |  | $ | 14.41 |  |  |  | — |  |  | $ | 962 |
December 1 - December 31 |  |  | 8 |  |  | $ | 14.93 |  |  |  | — |  |  | $ | — |
Total |  |  | 88 |  |  | $ | 10.58 |  |  |  | — |  |  |  |  |

| (1) | These amounts reflect the shares received by us from employees for the payment of personal income tax withholding on vesting transactions.

| (2) | On December 17, 2019, we announced a $1.0 billion share repurchase program that expired on December 31, 2020. We repurchased 2.2 million common shares for $38 million, or $16.85 per share, under this share repurchase program. For additional information, see Note 18 in “Item 8. Financial Statements and Supplementary Data” of this report.

Under the Devon Plan, eligible employees 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 14,000 shares of our common stock in 2020, 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 this plan through open-market purchases.

Item 6. Selected Financial Data

Not applicable.

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

Introduction

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.

The following discussion and analyses generally focus on 2020 and 2019 items and year-to-year comparisons between 2020 and 2019. Discussions of 2018 items and year-to-year comparisons between 2019 and 2018 that are not included in this report can be found in “Management’s Discussion and Analysis of Financial Condition and Results or Operations” in Part II, Item 7 of our 2019 Annual Report on Form 10-K.

COVID – 19

A novel strain of coronavirus, SARS-CoV-2, causing a disease referred to as COVID-19, was reported to have surfaced in China in late 2019 and has subsequently spread worldwide, resulting in a global pandemic and health crisis. Devon began actively monitoring COVID-19 in January 2020 and formally established a COVID-19 cross-functional planning team at the beginning of March. The COVID-19 team is focused on two key priorities: the health and safety of our employees and contractors and the uninterrupted operation of our business.

| • | Health and safety – The COVID-19 team has developed and implemented a number of safety measures, which have successfully kept our workforce healthy and safe. The COVID-19 team has established an informational campaign to provide employees an understanding of the virus risk factors and safety measures, as well as timely updates from governmental stay-at-home regulations. Expectations have also been set for employees to communicate immediately if they, or someone they have been in contact with, has experienced symptoms or tested positive for COVID-19. Other measures have included closing all of Devon’s office buildings and locations to the public, implementing social distancing and encouraging employees to work from home. Beginning in late March, more than 90% of the workforce assigned to Devon’s Oklahoma City Headquarters office were primarily working from home until the vast majority began a hybrid schedule of working from home and the office late in the second quarter. The COVID-19 team also strongly encourages employees to wear masks, reinforces social distancing measures and continues to perform targeted and routine intensive and deep cleaning of all Devon office locations.

| • | Uninterrupted operation of our business – Beyond workforce safety measures, the COVID-19 team has worked with government officials to ensure our business continues to be deemed an essential business or infrastructure. The COVID-19 team has ensured technology and resources are available for employees to execute their job duties while working from home and implemented further social distancing and contactless initiatives in our oil and gas field operations. The collective efforts of our COVID-19 team and our entire workforce have enabled us to avoid the need to implement COVID-19 containment or mitigation measures, which would require closure or suspension of any of our operations.

This outbreak and the related responses of governmental authorities and others to limit the spread of the virus have significantly reduced global economic activity, resulting in an unprecedented decline in the demand for oil and other commodities. This supply-and-demand imbalance was exacerbated by uncertainty regarding the future global supply of oil due to disputes between Russia and the members of OPEC in March 2020. These factors caused a swift and material deterioration in commodity prices in early 2020, with NYMEX WTI oil prices falling from a high of over $60/Bbl at the beginning of the year to below $20/Bbl in April 2020. By the end of 2020, NYMEX WTI oil prices recovered to approximately $50/Bbl, and we expect oil and other commodity prices to remain volatile for the foreseeable future.

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Overview of 2020 Results

Driven by the coronavirus pandemic, 2020 was a challenging year for the oil and gas industry and our business. Social distancing restrictions, government lockdowns and individual behavior changes all reduced transportation needs, which negatively impacted the demand for oil. The resulting drop in oil prices and cash generated from our operations necessitated a change in our plans. We aggressively reduced our planned capital investment 45%, selectively curtailed production and initiated sustainable cost-reduction measures. Despite these challenges, we continued to improve our capital efficiency and controllable costs per unit of production. Importantly, we maintained competitive leverage and debt metrics.

These market forces led to opportunities for select companies in our industry to create shareholder value from mergers and acquisitions. And, on September 26, 2020, we entered into the Merger Agreement, providing for an all-stock merger of equals with WPX which successfully closed on January 7, 2021. The Merger has created a leading oil producer in the U.S., with an asset base underpinned by premium acreage in the economic core of the Delaware Basin. This strategic combination accelerates our transition to a cash-return business model, including the implementation of a fixed plus variable dividend strategy.

As evidenced by our recent performance highlights below, we remain focused on building economic value by executing on our strategic priorities of disciplined oil volume growth while cutting operational and corporate costs, reducing reinvestment rates to maximize free cash flow, maintaining low leverage, delivering cash returns to our shareholders and pursuing ESG excellence. As we capture synergies and other benefits from the Merger, we expect to improve across all these performance measures.

| • | 2020 oil production totaled 155 MBbls/d, exceeding our plan by 5%.

| • | Operating costs continued to decline in 2020, led by a 29% and 6% decrease from 2019 for G&A and production expenses, respectively.

| • | Reduced workforce to reflect lower and sustainable capital investment program.

| • | Closed on the Barnett Shale transaction on October 1, 2020, receiving net proceeds of $490 million.

| • | Paid a special dividend of $0.26 per share for approximately $100 million on October 1, 2020.

| • | Remained focused on reducing methane emissions and greenhouse gas while also increasing water recycling.

| • | Exited 2020 with $5.2 billion of liquidity, including $2.2 billion of cash, with no near-term debt maturities.

|  | 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 gas prices ranged from average highs of $64.79 per Bbl and $3.11 per MMBtu, respectively, to average lows of $39.59 per Bbl and $2.08 per MMBtu, respectively.

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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 net earnings in recent years have been significantly impacted by divestiture transactions, asset impairments and temporary, noncash adjustments to the value of our commodity hedges. 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 of taxes. Net earnings in 2020 included $2.3 billion of asset impairments on our proved and unproved properties and a $0.1 billion hedge valuation loss, both net of taxes. Excluding these amounts, our core earnings have been more stable over recent years but continue to be heavily influenced by commodity prices.

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Despite our portfolio enhancements, aggressive cost reductions and operational advancements, our 2020 financial results were challenged by commodity prices and deterioration of the macro-economic environment resulting from the unprecedented COVID-19 pandemic. Our earnings decreased from 2019 to 2020 due to a decline in overall commodity prices. Led by a 31% decline in WTI from 2019 to 2020, our unhedged combined realized price decreased 31%, while our hedged price decreased 26%. In response to this commodity price environment, we reduced our aggregate production and G&A expenses 13% compared to 2019.

Like earnings, our operating cash flow is sensitive to volatile commodity prices. EBITDAX, which excludes financial amounts related to discontinued operations, and operating cash flow continue to be impacted from the COVID-19 pandemic and declines in commodity prices. As operating cash flow has declined, we reduced our 2020 capital expenditures by approximately $800 million, or 45% compared to the original capital budget.

As of December 31, 2020, we had $5.2 billion of liquidity comprised of $2.2 billion of cash and $3.0 billion of available credit under our Senior Credit Facility. We had $4.3 billion of debt outstanding with no maturities until the end of 2025. Post-merger, approximately 50% and 55% of our 2021 oil and gas production is hedged, respectively. These contracts consist of a variety of trade types based off the WTI oil benchmark and the Henry Hub natural gas index. Additionally, we have entered into regional basis swaps in an effort to protect price realizations across our portfolio.

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Business and Industry Outlook

In 2020, Devon marked its 49th anniversary in the oil and gas business and its 32nd year as a public company. Due to our financial strength, our strong leadership team and our portfolio of quality assets, during 2020, we were able to successfully navigate through periods of commodity price volatility and economic uncertainty caused by the COVID-19 global pandemic. We also announced a transformational merger of equals with WPX that nearly doubles the size and scale of Devon’s oil production while further strengthening the quality of our portfolio of assets without deteriorating our balance sheet strength. The transaction was completed on January 7, 2021.

With the combination of the Devon and WPX leadership teams, and respective portfolios of quality assets, we expect to build on our successful track record of delivering value for our shareholders while remaining committed to safeguarding our long-term financial strength. With the transaction, Devon creates a leading position in the Delaware Basin while also adding the oily Williston Basin to our portfolio of assets. Looking forward, the strategic combination with WPX accelerates our planned cash return business model that includes targeted capital reinvestment rates of 70 to 80 percent of operating cash flow and a disciplined returns-driven strategy to generate higher free cash flow. Our strategy is underpinned by the maintenance of a disciplined oil growth target of up to 5 percent annually, while achieving margin growth through operational and corporate cost reductions. We expect to prioritize the deployment of our free cash flow toward maintaining a strong balance sheet through debt reduction and returning excess cash to shareholders through cash dividends using our innovative fixed plus variable dividend framework.

Our disciplined growth strategy is in response to current market fundamentals that indicate a slow recovery in global oil demand along with market prices for crude oil and natural gas that remain inherently volatile. In 2020, WTI oil prices averaged $39.59 per barrel versus $57.02 per barrel in 2019. Crude prices experienced tremendous volatility in 2020 with a geopolitical price war in March, followed by a steep decline in global oil demand related to the COVID-19 pandemic and associated lockdowns. Looking ahead, current market fundamentals indicate that 2021 crude pricing is expected to improve, supported by a slow recovery in demand with the easing of lockdown measures, the rollout of COVID-19 vaccines and declines in shale production. These factors indicate a balanced market by the second half of 2021. However, uncertainty still exists depending on actions taken by OPEC+ countries in supporting a balanced global crude supply. Natural gas and NGL prices also faced strong headwinds in early 2020 due to the COVID-19 pandemic as lockdowns negatively impacted demand. During the summer of 2020, U.S. gas prices were pressured by U.S. liquefied natural gas export cancellations from decreased global demand outlook. Looking forward, gas and NGL prices have improved due to declines in associated gas volumes, and strong recovery in global demand.

To mitigate our exposure to commodity market 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 currently adding 2021 hedge positions at desirable prices where post-merger we currently have approximately 50% of our anticipated oil volumes and 55% of our anticipated gas volumes hedged. We are also actively adding attractive hedges for 2022. Further insulating our cash flow, we continue to examine and, when appropriate, execute attractive regional basis swap hedges to protect price realizations across our portfolio.

In connection with the Merger, we announced expected annual cost savings and margin improvements of $575 million, including legacy Devon cost reductions already underway and additional synergies expected through the integration of the WPX business with that of Devon. With our 2021 capital program, we expect to continue our capital-efficiency focus and our steadfast commitment to capital discipline. To achieve our 2021 capital program objectives that maximize free cash flow, over 70 percent of our 2021 spend will be focused on our highest margin U.S. oil play, the Delaware Basin. We expect to continue to leverage the strengths of our multi-basin strategy and deploy the remainder of our 2021 capital in our remaining core areas of the Eagle Ford, Anadarko Basin, Powder River Basin and Williston Basin. In total, our 2021 operating plan is expected to maintain our oil production at similar levels as 2020 on a pro forma combined basis.

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Results of Operations

The following graph, discussion and analysis are intended to provide an understanding of our results of operations and 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 35.

Continuing Operations

Our 2020 net loss from continuing operations was $2.5 billion, compared to a net loss from continuing operations of $79 million for 2019. The graph below shows the change in net loss from 2019 to 2020. 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.

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Production Volumes

|  | 2020 |  |  | % of Total |  |  | 2019 |  |  | Change |
Oil (MBbls/d) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Delaware Basin |  |  | 85 |  |  |  | 55 | % |  |  | 70 |  |  |  | +21 | %
Powder River Basin |  |  | 19 |  |  |  | 12 | % |  |  | 17 |  |  |  | +11 | %
Eagle Ford |  |  | 24 |  |  |  | 15 | % |  |  | 23 |  |  |  | +1 | %
Anadarko Basin |  |  | 20 |  |  |  | 13 | % |  |  | 31 |  |  |  | - 35 | %
Other |  |  | 7 |  |  |  | 5 | % |  |  | 9 |  |  |  | - 25 | %
Total |  |  | 155 |  |  |  | 100 | % |  |  | 150 |  |  |  | +3 | %

|  | 2020 |  |  | % of Total |  |  | 2019 |  |  | Change |
Gas (MMcf/d) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Delaware Basin |  |  | 248 |  |  |  | 41 | % |  |  | 177 |  |  |  | +40 | %
Powder River Basin |  |  | 23 |  |  |  | 4 | % |  |  | 24 |  |  |  | - 3 | %
Eagle Ford |  |  | 77 |  |  |  | 13 | % |  |  | 79 |  |  |  | - 3 | %
Anadarko Basin |  |  | 252 |  |  |  | 42 | % |  |  | 314 |  |  |  | - 20 | %
Other |  |  | 3 |  |  |  | 0 | % |  |  | 5 |  |  |  | - 34 | %
Total |  |  | 603 |  |  |  | 100 | % |  |  | 599 |  |  |  | +1 | %

|  | 2020 |  |  | % of Total |  |  | 2019 |  |  | Change |
NGLs (MBbls/d) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Delaware Basin |  |  | 37 |  |  |  | 47 | % |  |  | 27 |  |  |  | +35 | %
Powder River Basin |  |  | 3 |  |  |  | 3 | % |  |  | 2 |  |  |  | +17 | %
Eagle Ford |  |  | 10 |  |  |  | 14 | % |  |  | 11 |  |  |  | - 5 | %
Anadarko Basin |  |  | 27 |  |  |  | 35 | % |  |  | 36 |  |  |  | - 23 | %
Other |  |  | 1 |  |  |  | 1 | % |  |  | 1 |  |  |  | - 40 | %
Total |  |  | 78 |  |  |  | 100 | % |  |  | 77 |  |  |  | +1 | %

|  | 2020 |  |  | % of Total |  |  | 2019 |  |  | Change |
Combined (MBoe/d) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Delaware Basin |  |  | 163 |  |  |  | 49 | % |  |  | 127 |  |  |  | +28 | %
Powder River Basin |  |  | 26 |  |  |  | 8 | % |  |  | 23 |  |  |  | +14 | %
Eagle Ford |  |  | 46 |  |  |  | 14 | % |  |  | 47 |  |  |  | - 2 | %
Anadarko Basin |  |  | 90 |  |  |  | 27 | % |  |  | 119 |  |  |  | - 24 | %
Other |  |  | 8 |  |  |  | 2 | % |  |  | 11 |  |  |  | - 26 | %
Total |  |  | 333 |  |  |  | 100 | % |  |  | 327 |  |  |  | +2 | %

From 2019 to 2020, a 2% increase in production volumes contributed to a $116 million increase in earnings. Continued development in the Delaware Basin and Powder River Basin resulted in higher production volumes during 2020 compared to 2019. These increases were partially offset by significantly lower activity in the Anadarko Basin. Additionally, 2020 capital expenditures were reduced by 45% in response to the challenged macro-economic environment, negatively impacting volumes across the portfolio.

Due to the Merger and increased activity across our portfolio, we expect volumes to increase in 2021 and range from approximately 543 to 580 MBoe/d.

Field Prices

|  | 2020 |  |  | Realization |  |  | 2019 |  |  | Change |
Oil (per Bbl) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
WTI index |  | $ | 39.59 |  |  |  |  |  |  | $ | 57.02 |  |  |  | - 31 | %
Realized price, unhedged |  | $ | 35.95 |  |  | 91% |  |  | $ | 54.73 |  |  |  | - 34 | %
Cash settlements |  | $ | 4.81 |  |  |  |  |  |  | $ | 1.71 |  |  |  |  |
Realized price, with hedges |  | $ | 40.76 |  |  | 103% |  |  | $ | 56.44 |  |  |  | - 28 | %

|  | 2020 |  |  | Realization |  |  | 2019 |  |  | Change |
Gas (per Mcf) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Henry Hub index |  | $ | 2.08 |  |  |  |  |  |  | $ | 2.63 |  |  |  | - 21 | %
Realized price, unhedged |  | $ | 1.48 |  |  | 71% |  |  | $ | 1.79 |  |  |  | - 17 | %
Cash settlements |  | $ | 0.18 |  |  |  |  |  |  | $ | 0.14 |  |  |  |  |
Realized price, with hedges |  | $ | 1.66 |  |  | 80% |  |  | $ | 1.93 |  |  |  | - 14 | %

|  | 2020 |  |  | Realization |  |  | 2019 |  |  | Change |
NGLs (per Bbl) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Mont Belvieu blended index (1) |  | $ | 15.91 |  |  |  |  |  |  | $ | 19.22 |  |  |  | - 17 | %
Realized price, unhedged |  | $ | 11.72 |  |  | 74% |  |  | $ | 15.21 |  |  |  | - 23 | %
Cash settlements |  | $ | 0.18 |  |  |  |  |  |  | $ | 1.61 |  |  |  |  |
Realized price, with hedges |  | $ | 11.90 |  |  | 75% |  |  | $ | 16.82 |  |  |  | - 29 | %

| (1) | Based upon composition of our NGL barrel.

|  | 2020 |  |  | 2019 |  |  | Change |
Combined (per Boe) |  |  |  |  |  |  |  |  |  |  |  |
Realized price, unhedged |  | $ | 22.10 |  |  | $ | 31.93 |  |  |  | - 31 | %
Cash settlements |  | $ | 2.60 |  |  | $ | 1.43 |  |  |  |  |
Realized price, with hedges |  | $ | 24.70 |  |  | $ | 33.36 |  |  |  | - 26 | %

From 2019 to 2020, field prices contributed to a $1.2 billion decrease in earnings. Unhedged realized oil, gas and NGL prices decreased primarily due to lower WTI, Henry Hub and Mont Belvieu index prices. These decreases were partially offset by favorable hedge cash settlements across each of our products.

Hedge Settlements

|  | 2020 |  |  | 2019 |  |  | Change |
|  | Q |  |  |  |  |  |  |  |  |
Oil |  | $ | 271 |  |  | $ | 93 |  |  |  | +191 | %
Natural gas |  |  | 40 |  |  |  | 31 |  |  |  | +29 | %
NGL |  |  | 5 |  |  |  | 46 |  |  |  | - 89 | %
Total cash settlements (1) |  | $ | 316 |  |  | $ | 170 |  |  |  | +86 | %

| (1) | Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.

Cash settlements as presented in the tables above represent realized gains or losses related to the instruments described in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.

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Production Expenses

|  | 2020 |  |  | 2019 |  |  | Change |
LOE |  | $ | 425 |  |  | $ | 462 |  |  |  | - 8 | %
Gathering, processing & transportation |  |  | 508 |  |  |  | 463 |  |  |  | +10 | %
Production taxes |  |  | 170 |  |  |  | 251 |  |  |  | - 32 | %
Property taxes |  |  | 20 |  |  |  | 21 |  |  |  | - 5 | %
Total |  | $ | 1,123 |  |  | $ | 1,197 |  |  |  | - 6 | %
Per Boe: |  |  |  |  |  |  |  |  |  |  |  |
LOE |  | $ | 3.49 |  |  | $ | 3.87 |  |  |  | - 10 | %
Gathering, processing & transportation |  | $ | 4.17 |  |  | $ | 3.88 |  |  |  | +7 | %
Percent of oil, gas and NGL sales: |  |  |  |  |  |  |  |  |  |  |  |
Production taxes |  |  | 6.3 | % |  |  | 6.6 | % |  |  | - 4 | %

Gathering, processing and transportation costs increased in 2020 compared to 2019 due to higher volumes and Anadarko volume commitments which expired at the end of 2020. These increases were offset by lower production taxes resulting from lower oil, gas and NGL sales. Additionally, LOE costs decreased due to reduced activity levels and cost saving initiatives resulting from the challenged macro-economic environment.

Due to the Merger and increased activity across our portfolio, we expect 2021 production expenses to be approximately $2 billion.

Field-Level Cash Margin

The table below presents the field-level cash margin for each of our operating areas. Field-level cash margin is computed as oil, gas and NGL revenues less production expenses and is not prepared in 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.

|  | 2020 |  |  | $ per BOE |  |  | 2019 |  |  | $ per BOE |
Field-level cash margin (non-GAAP) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Delaware Basin |  | $ | 946 |  |  | $ | 15.86 |  |  | $ | 1,157 |  |  | $ | 25.00 |
Powder River Basin |  |  | 159 |  |  | $ | 16.93 |  |  |  | 246 |  |  | $ | 28.64 |
Eagle Ford |  |  | 229 |  |  | $ | 13.46 |  |  |  | 446 |  |  | $ | 25.80 |
Anadarko Basin |  |  | 204 |  |  | $ | 6.22 |  |  |  | 685 |  |  | $ | 15.81 |
Other |  |  | 34 |  |  | $ | 10.93 |  |  |  | 78 |  |  | $ | 20.56 |
Total |  | $ | 1,572 |  |  | $ | 12.89 |  |  | $ | 2,612 |  |  | $ | 21.90 |

DD&A and Asset Impairments

|  | 2020 |  |  | 2019 |  |  | Change |  |
Oil and gas per Boe |  | $ | 9.90 |  |  | $ | 11.72 |  |  |  | - 16 | % |
Oil and gas |  | $ | 1,207 |  |  | $ | 1,398 |  |  |  | - 14 | % |
Other property and equipment |  |  | 93 |  |  |  | 99 |  |  |  | - 6 | % |
Total |  | $ | 1,300 |  |  | $ | 1,497 |  |  |  | - 13 | % |
Asset impairments |  | $ | 2,693 |  |  | $ | — |  |  | N/M |  |

Asset impairments were $2.7 billion in 2020 due to significant decreases in commodity prices since the end of 2019 resulting primarily from the COVID-19 pandemic. For additional information, see Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report.

DD&A decreased in 2020 compared to 2019 due to lower rates resulting from impairments recorded in the first quarter of 2020.

General and Administrative Expense

|  | 2020 |  |  | 2019 |  |  | Change |
Labor and benefits |  | $ | 206 |  |  | $ | 307 |  |  |  | - 33 | %
Non-labor |  |  | 132 |  |  |  | 168 |  |  |  | - 21 | %
Total |  | $ | 338 |  |  | $ | 475 |  |  |  | - 29 | %

Labor and benefits and non-labor expenses decreased $137 million primarily as a result of continued workforce reductions and cost savings initiatives. For additional information on the workforce reductions, see Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.

Subsequent to the Merger, we expect 2021 general and administrative expense to range from approximately $400 to $420 million.

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Other Items

|  | 2020 |  |  | 2019 |  |  | Change in earnings |
Commodity hedge valuation changes (1) |  | $ | (161 | ) |  | $ | (624 | ) |  | $ | 463 |
Marketing and midstream operations |  |  | (35 | ) |  |  | 53 |  |  |  | (88 | )
Exploration expenses |  |  | 167 |  |  |  | 58 |  |  |  | (109 | )
Asset dispositions |  |  | (1 | ) |  |  | (48 | ) |  |  | (47 | )
Net financing costs |  |  | 270 |  |  |  | 250 |  |  |  | (20 | )
Restructuring and transaction costs |  |  | 49 |  |  |  | 84 |  |  |  | 35 |
Other expenses |  |  | (34 | ) |  |  | 4 |  |  |  | 38 |
|  |  |  |  |  |  |  |  |  | $ | 272 |

| (1) | Included as a component of oil, gas and NGL derivatives 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 relationship between contract prices and the associated forward curves.

Marketing and midstream operations decreased $88 million in 2020 compared to 2019 primarily due to lower commodity prices resulting from the challenged macro-economic environment, as well as downstream product inventory impairments of $17 million recognized in 2020.

Exploration expense increased $109 million in 2020 compared to 2019 primarily due to recognizing $152 million in unproved asset impairments in 2020 compared to $18 million in 2019.

Restructuring and transaction costs in 2020 and 2019 primarily relate to workforce reductions and the associated employee severance benefits related to announced cost reduction plans. Restructuring and transaction costs in 2020 also included approximately $8 million of transaction costs associated with the Merger. We expect to incur additional restructuring and transaction costs in 2021 related to the Merger of approximately $160 million to $200 million. These costs primarily relate to planned workforce reductions and the associated employee severance benefits, costs to modify or abandon vendor contracts and the acceleration of certain employee benefits triggered by the Merger.

Income Taxes

|  | 2020 |  |  | 2019 |
Current benefit |  | $ | (219 | ) |  | $ | (5 | )
Deferred benefit |  |  | (328 | ) |  |  | (25 | )
Total benefit |  | $ | (547 | ) |  | $ | (30 | )
Effective income tax rate |  |  | 18 | % |  |  | 28 | %

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

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Discontinued Operations

The table below presents key components from discontinued operations for the time periods presented. Discontinued operations include the Canadian business that Devon sold in June 2019 and also the Barnett Shale assets that Devon sold in October 2020. For additional information on discontinued operations, see Note 19 in “Part I. Financial Information – Item 1. Financial Statements” of this report.

|  | 2020 |  |  | 2019 |
Oil, gas and NGL sales |  | $ | 263 |  |  | $ | 1,227 |
Oil, gas and NGL derivatives |  | $ | — |  |  | $ | (113 | )
Production expenses |  | $ | 214 |  |  | $ | 599 |
Asset impairments |  | $ | 182 |  |  | $ | 785 |
Asset dispositions |  | $ | 1 |  |  | $ | (222 | )
Financing costs, net |  | $ | (3 | ) |  | $ | 87 |
Restructuring and transaction costs |  | $ | 9 |  |  | $ | 248 |
Loss from discontinued operations before income taxes |  | $ | (152 | ) |  | $ | (632 | )
Income tax benefit |  | $ | (24 | ) |  | $ | (358 | )
Loss from discontinued operations, net of tax |  | $ | (128 | ) |  | $ | (274 | )
Production (MMBoe): |  |  |  |  |  |  |  |
Barnett Shale |  |  | 27 |  |  |  | 37 |
Canada |  |  | — |  |  |  | 19 |
Total production |  |  | 27 |  |  |  | 56 |
Realized price, unhedged (per Boe) - Barnett Shale |  | $ | 9.89 |  |  | $ | 13.30 |
Realized price, unhedged (per Boe) - Canada |  | N/A |  |  | $ | 38.98 |

Net earnings (loss) from discontinued operations, net of tax increased approximately $146 million. This change is primarily due to the timing of Devon’s completion of its divestiture of its Canadian business in the second quarter of 2019 as well as the closing of the Barnett Shale divestiture in the fourth quarter of 2020. During 2019, Devon recognized a $223 million gain on the sale of its Canadian operations as well as income tax benefits of $216 million and $142 million related to its Canadian business and Barnett Shale properties, respectively. These increases were largely offset by a decrease attributable to a proved oil and gas property impairment of approximately $748 million related to the Barnett Shale in the fourth quarter of 2019. Due to the timing of the completion of these divestitures, there was minimal activity of a comparable nature during 2020.

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Capital Resources, Uses and Liquidity

Sources and Uses of Cash

The following table presents the major changes in cash and cash equivalents for the time periods presented below.

|  | Year ended December 31, |
|  | 2020 |  |  | 2019 |
Operating cash flow from continuing operations |  | $ | 1,464 |  |  | $ | 2,043 |
Divestitures of property and equipment |  |  | 34 |  |  |  | 390 |
Capital expenditures |  |  | (1,153 | ) |  |  | (1,910 | )
Acquisitions of property and equipment |  |  | (8 | ) |  |  | (31 | )
Debt activity, net |  |  | — |  |  |  | (162 | )
Repurchases of common stock |  |  | (38 | ) |  |  | (1,849 | )
Common stock dividends |  |  | (257 | ) |  |  | (140 | )
Contributions from noncontrolling interests |  |  | 21 |  |  |  | 116 |
Distributions to noncontrolling interests |  |  | (14 | ) |  |  | — |
Other |  |  | (18 | ) |  |  | (26 | )
Net change in cash, cash equivalents and restricted cash from discontinued operations |  |  | 362 |  |  |  | 967 |
Net change in cash, cash equivalents and restricted cash |  | $ | 393 |  |  | $ | (602 | )
Cash, cash equivalents and restricted cash at end of period |  | $ | 2,237 |  |  | $ | 1,844 |

Operating Cash Flow – Continuing Operations

Our operating cash flow decreased $579 million, or 28%, to approximately $1.5 billion from 2019 to 2020. In 2020, our operating cash flow completely funded our capital expenditures program, dividend payments and repurchases of our common stock. This allowed us to use available cash balances to fund other capital uses.

Divestitures of Property and Investments – Continuing Operations

During 2020 and 2019, as part of our announced divestiture programs, we sold non-core U.S. upstream assets for $34 million and $390 million, respectively. For further 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, |
|  | 2020 |  |  | 2019 |
Delaware Basin |  | $ | 734 |  |  | $ | 912 |
Powder River Basin |  |  | 172 |  |  |  | 308 |
Eagle Ford |  |  | 172 |  |  |  | 194 |
Anadarko Basin |  |  | 23 |  |  |  | 396 |
Other |  |  | 8 |  |  |  | 36 |
Total oil and gas |  |  | 1,109 |  |  |  | 1,846 |
Midstream |  |  | 31 |  |  |  | 42 |
Other |  |  | 13 |  |  |  | 22 |
Total capital expenditures |  | $ | 1,153 |  |  | $ | 1,910 |
Acquisitions |  | $ | 8 |  |  | $ | 31 |

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Capital expenditures consist primarily of amounts related to our oil and gas exploration and development operations, midstream operations and other corporate activities. The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties. Our capital program is designed to operate within or near operating cash flow and may fluctuate with changes to commodity prices and other factors impacting cash flow. This is evidenced by our operating cash flow fully funding capital expenditures in 2020 and 2019. Our capital expenditures are lower in 2020 primarily due to a 45% reduction in capital spend in response to the COVID-19 pandemic and the associated macroeconomic implications.

Debt Activity, Net

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

Repurchases of Common Stock and Shareholder Distributions

We repurchased 2.2 million shares of common stock for $38 million in 2020 and 68.6 million shares of common stock for $1.8 billion in 2019 under a share repurchase program authorized by our Board of Directors. For additional information, see Note 18 in “Item 8. Financial Statements and Supplementary Data” in this report.

Devon paid common stock dividends of $257 million and $140 million during 2020 and 2019, respectively. Dividends paid on common stock during 2020 include a $0.26 special dividend paid to shareholders on October 1, 2020, which totaled $97 million. Beginning with the second quarter of 2020, we increased our quarterly dividend 22% to $0.11 per share. We previously increased our quarterly dividend to $0.09 per share commencing with the second quarter of 2019. For additional information, see Note 18 in “Item 8. Financial Statements and Supplementary Data” of this report.

Contributions from Noncontrolling Interests

During 2020 and 2019, we received approximately $21 million and $116 million, respectively, in cash contributions from our partner in CDM.

Distributions to Noncontrolling Interests

During 2020, we paid approximately $14 million in cash distributions to our partner in CDM.

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 Canadian business that Devon sold in June 2019 and the Barnett Shale assets that Devon divested in October 2020.

|  | Year ended December 31, |
|  | 2020 |  |  | 2019 |
Operating activities |  | $ | (110 | ) |  | $ | 28 |
Divestitures of property and equipment - Canadian operations |  |  | 2 |  |  |  | 2,608 |
Divestitures of property and equipment - Barnett Shale assets |  |  | 480 |  |  |  | — |
Capital expenditures and other |  |  | (1 | ) |  |  | (136 | )
Investing activities |  |  | 481 |  |  |  | 2,472 |
Debt activity, net |  |  | — |  |  |  | (1,552 | )
Other |  |  | — |  |  |  | (26 | )
Financing activities |  |  | — |  |  |  | (1,578 | )
Settlements of intercompany foreign denominated assets/liabilities |  |  | — |  |  |  | 32 |
Other |  |  | (9 | ) |  |  | 13 |
Effect of exchange rate changes on cash |  |  | (9 | ) |  |  | 45 |
Net change in cash, cash equivalents and restricted cash of discontinued operations |  | $ | 362 |  |  | $ | 967 |

Operating cash flow in 2020 decreased $138 million as a result of the divestitures referenced above and cash taxes paid related to divested Canadian operations.

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On October 1, 2020, Devon completed the sale of its Barnett Shale assets for proceeds, net of purchase price adjustments, of $490 million. 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.

Cash flows from financing activities includes the $1.5 billion of senior notes retired prior to maturity in 2019.

Liquidity

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

On January 7, 2021, Devon and WPX completed an all-stock merger of equals. WPX is an oil and gas exploration and production company with assets in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. On the closing date of the Merger, each share of WPX common stock was automatically converted into the right to receive 0.5165 of a share of Devon common stock. Based on the closing price of Devon’s common stock on January 7, 2021, the total value of the Devon common stock issued to holders of WPX common stock as part of this transaction was approximately $5.4 billion. For additional information, please see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

With this strategic merger, we are accelerating our transition to a cash-return business model, which moderates growth, emphasizes capital efficiencies and prioritizes cash returns to shareholders. These principles will position Devon to be a consistent builder of economic value through the cycle. The post-merger scalability is expected to enhance Devon’s free cash flow, credit profile and decrease the overall cost of capital.

Historically, our primary sources of capital funding and liquidity have been our operating cash flow, cash on hand and asset divestiture proceeds. Additionally, we maintain a commercial paper program, supported by our revolving line of credit, which can be accessed as needed to supplement operating cash flow and cash balances. If needed, we can also issue debt and equity securities, including through transactions under our shelf registration statement filed with the SEC. We estimate the combination of our sources of capital will continue to be adequate to fund our planned post-merger capital requirements as discussed in this section as well as accelerate our cash-return business model.

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 2020, we held approximately $2.2 billion of cash, inclusive of $190 million of cash restricted for retained obligations related to divested assets. Our operating cash flow forecasts are sensitive to many variables and include a measure of uncertainty as these variables may differ from our expectations.

Commodity Prices – The most uncertain and volatile variables for our operating cash flow are the prices of the oil, gas and NGLs we produce and sell. Prices are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other highly variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in prices and are beyond our control.

To mitigate some of the risk inherent in prices, we utilize various derivative financial instruments to protect a portion of our production against downside price risk. We 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 favorable market conditions. The key terms to our oil, gas and NGL derivative financial instruments as of December 31, 2020 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. Additionally, as commodity prices begin to recover from the COVID-19 pandemic, we remain committed to a maintenance capital program for the foreseeable future. We do not intend to add any growth projects until market fundamentals recover, excess inventory clears up and OPEC+ curtailed volumes are effectively absorbed by the world markets.

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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.

Cost savings from 2020 initiatives and synergies resulting from the Merger are expected to be attained through cost reductions and efficiencies related to our capital programs, G&A, financing costs and production expenses. We anticipate the planned $575 million reduction of annualized costs will occur by year-end 2021. Approximately 35% of the reduced costs are related to our capital programs and the remainder relate to our operating expenses, including G&A, interest expense and production expenses.

Restructuring and Transaction Related Costs – Merger-related restructuring and transaction costs cash outflows are expected to range from $220 million to $255 million. These payments will relate to workforce reductions and the associated employee severance benefits, costs to modify or abandon vendor contracts and the acceleration of certain employee benefits triggered by the Merger.

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

Assumption and Repayment of WPX Debt

In February 2021, Devon redeemed bonds issued by WPX with a maturity date of 2022 pursuant to a make whole call provision in the related indenture. The total principal related to this redemption was approximately $43 million, with an additional $2 million cash premium paid to complete the make whole redemption.

In conjunction with the Merger closing on January 7, 2021, Devon is assuming a principal value of $3.3 billion of WPX debt.

Credit Availability

We have $3.0 billion of available borrowing capacity under our Senior Credit Facility at December 31, 2020. The Senior Credit Facility matures on October 5, 2024, with the option to extend the maturity date by two additional one-year periods subject to lender consent. Subsequent to October 5, 2023, the borrowing capacity decreases to $2.8 billion. The Senior Credit Facility supports our $3.0 billion of short-term credit under our commercial paper program. As of December 31, 2020, there were no borrowings under our commercial paper program. See Note 14 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%. As of December 31, 2020, we were in compliance with this covenant with a 25% debt-to-capitalization ratio.

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 credit agreement. 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.

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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 production growth opportunities. Our credit rating from Standard and Poor’s Financial Services is BBB- with a stable outlook. Our credit rating from Fitch is BBB with a positive outlook. Our credit rating from Moody’s Investor Service is Ba1 with a stable outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

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

Fixed Plus Variable Dividend

Following the closing of the Merger, Devon initiated a new “fixed plus variable” dividend strategy. The fixed dividend is currently paid quarterly at a rate of $0.11 per share, and the Board of Directors will consider a number of factors when setting the quarterly dividend, if any, including a general target of paying out approximately 10% of operating cash flow through the fixed dividend. In addition to the fixed quarterly dividend, Devon may pay a variable dividend up to 50 percent of its excess free cash flow, which is a non-GAAP measure. Each quarter’s excess free cash flow is computed as operating cash flow (a GAAP measure) before balance sheet changes, less capital expenditures and the fixed dividend. The declaration and payment of any future dividend, whether fixed or variable, will remain at the full discretion of our Board of Directors and will depend on Devon’s financial results, cash requirements, future prospects, COVID-19 impacts and other factors deemed relevant by the Board.

In February 2021, Devon announced an approximately $128 million variable cash dividend in the amount of $0.19 per share payable in the first quarter of 2021. The variable dividend is in addition to the fixed quarterly dividend of $0.11 per share.

Capital Expenditures

Our 2021 post-merger exploration and development budget is expected to be approximately $1.6 billion to $1.8 billion.

Contractual Obligations

As of December 31, 2020, our material contractual obligations include debt, interest expense, asset retirement obligations, lease obligations, retained obligations related to our Barnett Shale assets and Canadian business, operational agreements, drilling and facility obligations and various tax obligations. As discussed above, we estimate the combination of our sources of capital will continue to be adequate to fund our short- and long-term contractual obligations, including the obligations we assumed through the Merger. See Notes 6, 8, 14, 15, 16 and 20 in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion.

Contingencies and Legal Matters

For a detailed discussion of contingencies and legal matters, see Note 20 in “Item 8. Financial Statements and Supplementary Data” of this report.

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.

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Oil and Gas Assets Accounting, Classification, Reserves & Valuation

Successful Efforts Method of Accounting and 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, 2020, 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, 2020, Devon had approximately $82 million of undeveloped leasehold. Of the remaining undeveloped leasehold costs at December 31, 2020, approximately $1 million is scheduled to expire in 2021. The leasehold expiring in 2021 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 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 firm. In 2020, 88% of our reserves were subjected to such an audit.

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.

Valuation of Long-Lived Assets

Long-lived assets used in operations, including proved and unproved oil and gas properties, are depreciated and 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 a judgmental assessment of the lowest level (“common operating field”) for which there are 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.

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Management evaluates assets for impairment through an established process in 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 value. Because there usually is 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. 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. 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.

Besides the risk-adjusted estimates of reserves and future production volumes, future commodity prices are the largest driver in the variability of undiscounted pre-tax cash flows. For our impairment determinations, we historically have utilized NYMEX forward strip prices for the first five years and applied internally generated price forecasts for subsequent years. In response to the COVID-19 pandemic, the NYMEX forward market became highly illiquid as evidenced by materially reduced trading volumes for periods beyond 2021. Therefore, we altered our price forecast assumptions to perform our March 31, 2020 impairment computations. Specifically, we supplemented the NYMEX forward strip prices with price forecasts published by reputable investment banks and reservoir engineering firms to estimate our future revenues as of March 31, 2020.

We also estimate and escalate or de-escalate future capital and operating costs by using a method that correlates cost movements to price movements similar to recent history. To measure indicated impairments, we use a market-based weighted-average cost of capital to discount the future net cash flows. Changes to any of the reserves or market-based assumptions can significantly affect estimates of undiscounted and discounted pre-tax cash flows and impact the recognition and amount of impairments.

Reduced demand from the COVID-19 pandemic and management of production levels from OPEC caused WTI pricing to decrease more than 60% during the first quarter of 2020. As a result, we reduced our planned 2020 capital investment 45%. With materially lower commodity prices and reduced near-term investment, we assessed all our oil and gas fields for impairment as of March 31, 2020 and recognized proved and unproved impairments totaling $2.8 billion. The impairments relate to our Anadarko Basin and Rockies fields in which our basis included acquisitions completed in 2016 and 2015, respectively, when commodity prices were much higher than they are today.

We assessed our Eagle Ford asset for impairment as of June 30, 2020 and September 30, 2020 utilizing the same methodology we applied for the impairment assessments for all of our and oil and gas fields in the first quarter of 2020. Our Eagle Ford asset’s sum of undiscounted cash flows exceeded the carrying value indicating no impairment as of September 30, 2020. Further, as a result of improved oil pricing, the cushion increased significantly from March 31, 2020 to December 31, 2020. If prices significantly deteriorate and/or management lowers the planned capital investment in the Eagle Ford field, our Eagle Ford asset could be subject to a material impairment of 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. 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 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. Due to an unprecedented downturn in the commodity price environment and the resulting asset impairments, Devon had significant deferred tax assets at March 31, 2020. Accordingly, we reassessed the realizability of our deferred tax assets in future periods and recorded a 100% valuation allowance against our net deferred tax assets during the first quarter of 2020. As of December 31, 2020, we remain in a full valuation allowance position.

Further, in the event we were to undergo an “ownership change” (as defined in Section 382 of the Internal Revenue Code of 1986, as amended), our ability to use net operating losses and tax credits generated prior to the ownership change may be limited. Generally, an “ownership change” occurs if one or more shareholders, each of whom owns five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the lowest percentage of stock owned

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by those shareholders at any time during the preceding three-year period. See Note 8 in “Item 8. Financial Statements and Supplementary Data” in this report for further discussion regarding our net operating losses and tax credits available to be carried forward and used in future years. No ownership change occurred during 2020 for Devon. The Merger did cause an ownership change for WPX and increased the likelihood Devon could experience an ownership change over the next three years.

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. We perform a qualitative assessment to determine whether it is more likely than not that the fair value of goodwill is less than its carrying amount. As part of our qualitative assessment, we considered the general macro-economic, industry and market conditions, changes in cost factors, actual and expected financial performance, significant changes in management, strategy or customers and stock performance. If the qualitative assessment determines that a quantitative goodwill impairment test is required, then the fair value is compared to the carrying value. If the fair value is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. Because quoted market prices are not available, the fair value is estimated based upon a valuation analyses including comparable companies and transactions and premiums paid.

Because the trading price of our common stock decreased 73% during the first quarter of 2020 in response to the COVID-19 pandemic, we performed a goodwill impairment test as of March 31, 2020. While the cushion narrowed significantly since the previous impairment evaluation, we concluded an impairment was not required as of March 31, 2020. The two most critical judgements included in the March 31, 2020, test were the period utilized to determine Devon’s market capitalization and the control premium. For the test performed as of March 31, 2020, we derived our market capitalization by using our average common stock price from the latter two thirds of March 2020, to align with the time in the quarter subsequent to a key OPEC+ meeting and the date COVID-19 was officially classified as a pandemic. We applied a control premium based on recent comparable market transactions.

Subsequent to the end of the first quarter of 2020, Devon’s common stock price increased approximately 129% during the remainder of 2020 but remains less than our average trading price before the events experienced in the first quarter of 2020. Although our common stock price and commodity prices are in a period of high volatility, a sustained period of depressed commodity prices would adversely affect our estimates of future operating results, which could result in future goodwill impairments due to the potential impact on the cash flows of our operations. The impairment of goodwill has no effect on liquidity or capital resources. However, it would adversely affect our results of operations in the period recognized.

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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 2020 Results” in this Item 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 a substitute for analysis of our results reported under GAAP. Core earnings (loss) attributable to Devon, as well as the per share amount, represent net earnings excluding certain noncash and other items that are typically excluded by securities analysts in their published estimates of our financial results. For more information on the results of discontinued operations for our Barnett Shale assets, Canadian operations and for EnLink and the General Partner, see Note 19 in “Item 8. Financial Statements and Supplementary Data” in this report. Our non-GAAP measures are typically used as a quarterly performance measure. Amounts excluded for 2020 relate to asset dispositions, noncash asset impairments (including unproved asset impairments), deferred tax asset valuation allowance, fair value changes in derivative financial instruments and foreign currency, change in tax legislation and restructuring and transaction costs associated with the workforce reductions in 2020.

Amounts excluded for 2019 relate to asset dispositions, the gain on the sale of Canadian operations, noncash asset impairments (including noncash Barnett Shale and 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 2019 and restructuring and transaction costs associated with the divestment of our Canadian operations in 2019.

Amounts excluded for 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.

We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates published by securities analysts. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers.

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

| Year ended December 31, |
| Before tax |  |  | After tax |  |  | After Noncontrolling Interests |  |  | Per Diluted Share |
2020 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Continuing Operations |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Loss attributable to Devon (GAAP) | $ | (3,090 | ) |  | $ | (2,543 | ) |  | $ | (2,552 | ) |  | $ | (6.78 | )
Adjustments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Asset dispositions |  | (1 | ) |  |  | — |  |  |  | — |  |  |  | (0.00 | )
Asset and exploration impairments |  | 2,847 |  |  |  | 2,207 |  |  |  | 2,207 |  |  |  | 5.87 |
Deferred tax asset valuation allowance |  | — |  |  |  | 230 |  |  |  | 230 |  |  |  | 0.60 |
Fair value changes in financial instruments |  | 161 |  |  |  | 125 |  |  |  | 125 |  |  |  | 0.32 |
Change in tax legislation |  | — |  |  |  | (113 | ) |  |  | (113 | ) |  |  | (0.29 | )
Restructuring and transaction costs |  | 49 |  |  |  | 38 |  |  |  | 38 |  |  |  | 0.10 |
Core loss attributable to Devon (Non-GAAP) | $ | (34 | ) |  | $ | (56 | ) |  | $ | (65 | ) |  | $ | (0.18 | )
Discontinued Operations |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Loss attributable to Devon (GAAP) | $ | (152 | ) |  | $ | (128 | ) |  | $ | (128 | ) |  | $ | (0.34 | )
Adjustments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Asset dispositions |  | 1 |  |  |  | 19 |  |  |  | 19 |  |  |  | 0.05 |
Asset impairments |  | 182 |  |  |  | 143 |  |  |  | 143 |  |  |  | 0.37 |
Fair value changes in foreign currency and other |  | (8 | ) |  |  | (5 | ) |  |  | (5 | ) |  |  | (0.01 | )
Restructuring and transaction costs |  | 9 |  |  |  | 6 |  |  |  | 6 |  |  |  | 0.02 |
Core earnings attributable to Devon (Non-GAAP) | $ | 32 |  |  | $ | 35 |  |  | $ | 35 |  |  | $ | 0.09 |
Total |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Loss attributable to Devon (GAAP) | $ | (3,242 | ) |  | $ | (2,671 | ) |  | $ | (2,680 | ) |  | $ | (7.12 | )
Adjustments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Continuing Operations |  | 3,056 |  |  |  | 2,487 |  |  |  | 2,487 |  |  |  | 6.60 |
Discontinued Operations |  | 184 |  |  |  | 163 |  |  |  | 163 |  |  |  | 0.43 |
Core loss attributable to Devon (Non-GAAP) | $ | (2 | ) |  | $ | (21 | ) |  | $ | (30 | ) |  | $ | (0.09 | )
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 |

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| Year ended December 31, |
| Before tax |  |  | After tax |  |  | After Noncontrolling Interests |  |  | Per Diluted Share |
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 |

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.

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Below are reconciliations of net earnings to EBITDAX and a further reconciliation to Field-Level Cash Margin.

|  | Year ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
Net earnings (loss) (GAAP) |  | $ | (2,671 | ) |  | $ | (353 | ) |  | $ | 3,224 |
Net (earnings) loss from discontinued operations, net of tax |  |  | 128 |  |  |  | 274 |  |  |  | (2,510 | )
Financing costs, net |  |  | 270 |  |  |  | 250 |  |  |  | 580 |
Income tax expense (benefit) |  |  | (547 | ) |  |  | (30 | ) |  |  | 230 |
Exploration expenses |  |  | 167 |  |  |  | 58 |  |  |  | 128 |
Depreciation, depletion and amortization |  |  | 1,300 |  |  |  | 1,497 |  |  |  | 1,228 |
Asset impairments |  |  | 2,693 |  |  |  | — |  |  |  | 156 |
Asset dispositions |  |  | (1 | ) |  |  | (48 | ) |  |  | (278 | )
Share-based compensation |  |  | 76 |  |  |  | 83 |  |  |  | 104 |
Derivative and financial instrument non-cash valuation changes |  |  | 161 |  |  |  | 623 |  |  |  | (938 | )
Restructuring and transaction costs |  |  | 49 |  |  |  | 84 |  |  |  | 97 |
Accretion on discounted liabilities and other |  |  | (34 | ) |  |  | 5 |  |  |  | 54 |
EBITDAX (non-GAAP) |  |  | 1,591 |  |  |  | 2,443 |  |  |  | 2,075 |
Marketing and midstream revenues and expenses, net |  |  | 35 |  |  |  | (53 | ) |  |  | (33 | )
Commodity derivative cash settlements |  |  | (316 | ) |  |  | (170 | ) |  |  | 420 |
General and administrative expenses, cash-based |  |  | 262 |  |  |  | 392 |  |  |  | 470 |
Field-level cash margin (non-GAAP) |  | $ | 1,572 |  |  | $ | 2,612 |  |  | $ | 2,932 |

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Item 7A. Quantitative and 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 gas and 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 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, 2020 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, 2020, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net liability positions by approximately $118 million.

Interest Rate Risk

At December 31, 2020, we had total debt of $4.3 billion. All of our debt is based on fixed interest rates averaging 6.0%.

Foreign Currency Risk

Devon has certain Canadian dollar obligations associated with its divested Canadian operations which are to be paid with the cash restricted for retained obligations. These balances are remeasured using the applicable exchange rate as of the end of the reporting period. A 10% unfavorable change in the Canadian-to-U.S. dollar exchange rate would not have materially impacted our December 31, 2020 balance sheet for these items. See Note 19 in “Item 8. Financial Statements and Supplementary Data” in this report for additional information.

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Item 8. Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

Report of Independent Registered Public Accounting Firm |  | 50
Consolidated Financial Statements |  |
Consolidated Statements of Comprehensive Earnings |  | 54
Consolidated Statements of Cash Flows |  | 55
Consolidated Balance Sheets |  | 56
Consolidated Statements of Equity |  | 57
Notes to Consolidated Financial Statements |  | 58
Note 1 – Summary of Significant Accounting Policies |  | 58
Note 2 – Divestitures |  | 67
Note 3 – Derivative Financial Instruments |  | 69
Note 4 – Share-Based Compensation |  | 70
Note 5 – Asset Impairments |  | 73
Note 6 – Restructuring and Transaction Costs |  | 74
Note 7 – Other, Net |  | 75
Note 8 – Income Taxes |  | 75
Note 9 – Net Earnings (Loss) Per Share From Continuing Operations |  | 80
Note 10 – Other Comprehensive Earnings |  | 81
Note 11 – Supplemental Information to Statements of Cash Flows |  | 82
Note 12 – Accounts Receivable |  | 82
Note 13 – Property, Plant and Equipment |  | 83
Note 14 – Debt and Related Expenses |  | 84
Note 15 – Leases |  | 85
Note 16 – Asset Retirement Obligations |  | 87
Note 17 – Retirement Plans |  | 88
Note 18 – Stockholders’ Equity |  | 91
Note 19 – Discontinued Operations and Assets Held For Sale |  | 93
Note 20 – Commitments and Contingencies |  | 96
Note 21 – Fair Value Measurements |  | 98
Note 22 – Supplemental Information on Oil and Gas Operations (Unaudited) |  | 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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Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

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, 2020 and 2019, the related consolidated statements of comprehensive earnings, equity, and cash flows for each of the years in the three-year period ended December 31, 2020, and the related notes (collectively, the consolidated financial statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway 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, 2020 and 2019, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2020, 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, 2020 based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Change in Accounting Principles

As discussed in Note 1 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).

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.” Our responsibility is to express an opinion on 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 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 regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial 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 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.

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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.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to 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 any way our opinion on the consolidated financial 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.

Estimate of future cash flows of proved and unproved oil and gas reserves used to assess the recoverability of the carrying value and to estimate the fair value of certain oil and gas properties

As discussed in Notes 1, 5, and 13 to the consolidated financial statements, the Company performs recoverability tests for the carrying value of its oil and gas properties for each relevant asset group. The recoverability tests are performed if events and circumstances indicate that the carrying value of the asset group may not be recoverable. The Company estimates the undiscounted future net cash flows expected to be generated from the oil and gas properties and compares such future net cash flows to the carrying amount of the oil and gas property to determine if the carrying amount is recoverable. When the carrying amount of an oil and gas property exceeds its estimated undiscounted future net cash flows, the carrying amount is impaired to its estimated fair value by applying a discount rate to the undiscounted future cash flows. The determination of the undiscounted cash flows for the recoverability test and the determination of fair value for impairment is largely driven by the underlying estimate of proved and unproved oil and gas reserves as determined by the Company’s internal reservoir engineers. To estimate the oil and gas properties’ future cash flows, internal reservoir engineers take into consideration the estimate of risk-adjusted future production quantities, future operating and capital cost assumptions, and projected oil and gas prices inclusive of market differentials. During the first quarter of 2020, the Company recorded an impairment of approximately $2.7 billion related to its Anadarko Basin and Rockies oil and gas properties.

We identified the estimate of future cash flows from proved and unproved oil and gas reserves used to assess the recoverability of the carrying value and to estimate the fair value of certain of the company’s oil and gas properties as a critical audit matter. There was a high degree of subjective auditor judgment in evaluating the key assumptions used to estimate the undiscounted and discounted future cash flows of the proved and unproved oil and gas properties. The key assumptions used in these estimates were current and forecasted commodity prices, forecasted operating and capital costs, future production quantities, risk adjustment factors associated with the proved and unproved reserve volumes, and the discount rate applied to determine fair value.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s processes to estimate proved and unproved oil and gas reserves used to determine undiscounted and discounted future cash flows. We assessed compliance of the methodology used by the Company’s internal 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. We compared the estimated future proved and unproved production quantities used by the Company in the current period to historical production trends. We evaluated the professional qualifications of the Company’s internal reservoir engineers and the knowledge, skills, and ability of the Company’s internal reservoir engineers. We also tested the processes and methodologies used by internal reservoir engineers to estimate unproved future production quantities. 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 forecasted commodity price assumptions 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. In addition, we involved valuation professionals with specialized skills and knowledge, who assisted in:

—Evaluating the discount rate by comparing it against a discount rate range that was independently developed using publicly available market data for comparable entities.

—Evaluating the forecasted commodity price assumptions by comparing to the median and average of forward price estimates from analysts and other industry sources.

—Evaluating the risk-adjustment factors for unproved reserves selected by the Company, by comparing to the guideline factors ranges by reserve class in published industry surveys adjusted for current market factors.

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— Evaluating the overall fair value of proved and unproved oil and gas properties by reconciling it to the Company’s market capitalization as of the measurement date.

Estimate of proved oil and gas reserves used in the depletion of proved oil and gas properties

As discussed in Notes 1 and 13 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 also periodically evaluates whether changes in the estimated proved oil and gas reserves for each common operating field have occurred that would require a change in the rate of depletion to be applied to the production realized. 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. The company recorded depletion expense of $1.2 billion for the year ended December 31, 2020.

We identified the estimate of proved oil and gas reserves used in 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 following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s depletion expense process, including controls related to the estimate of proved oil and gas reserves. We analyzed and assessed the determination of depletion expense for compliance with 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 Company in prior periods to the actual production amounts realized and the current 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. We evaluated (1) the professional qualifications of the Company’s internal reservoir engineers as well as the external reservoir engineers and external engineering firm, (2) the knowledge, skills, and ability of the Company’s internal and external reservoir engineers, and (3) the relationship of the external reservoir engineers and external engineering firm to the Company. We read and considered the report of the Company’s external reservoir engineers in connection with our evaluation of the Company’s reserve estimates.

Evaluation of potential impairment of goodwill for the U.S. reporting unit

As discussed in Note 1 to the consolidated financial statements, the total goodwill balance was approximately $753 million as of December 31, 2020. During the completion of the first quarter qualitative goodwill impairment assessment, the Company determined an evaluation of goodwill for potential impairment was required for the U.S. reporting unit as a result of declines in the trading price of its common stock. Evaluating goodwill for potential impairment involves comparing the fair value of the reporting unit to its carrying value. If the fair value is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. The fair value is estimated based upon valuation analysis involving the trading price of the Company’s outstanding equity shares, and consideration of a control premium determined by reviewing comparable companies and transactions. A key assumption in the valuation analysis is the control premium, which is derived from the assessment of control premiums from comparable companies’ recent transactions. In performing the evaluation of goodwill for impairment in the first quarter, the Company concluded that the fair value of the U.S. reporting unit exceeded the carrying value and therefore no impairment was recognized.

We identified the evaluation of potential impairment of goodwill for the U.S. reporting unit as a critical audit matter. Specifically, a high degree of auditor judgment and specialized skills were required to evaluate the control premium used to estimate of the fair value of the reporting unit. Changes to the control premium could have a significant effect on the Company’s estimate of the fair value of the U.S. reporting unit.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s goodwill impairment process, including controls related to the control premium. We performed a sensitivity analysis to determine the significant assumptions used to evaluate goodwill impairment, individually and in the aggregate, which required challenging auditor judgment. We involved a valuation professional with specialized skills and knowledge, who assisted in:

—Evaluating the control premium used by comparing it to a control premium that was independently developed using publicly available market data

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—Developing an estimate of the fair value of the reporting unit and comparing it to the Company’s fair value estimate.

/s/ KPMG, LLP

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

Oklahoma City, Oklahoma

February 17, 2021

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Index to Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGS

|  | Year Ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
|  | (Millions, except per share amounts) |
Oil, gas and NGL sales |  | $ | 2,695 |  |  | $ | 3,809 |  |  | $ | 4,085 |
Oil, gas and NGL derivatives |  |  | 155 |  |  |  | (454 | ) |  |  | 457 |
Marketing and midstream revenues |  |  | 1,978 |  |  |  | 2,865 |  |  |  | 4,354 |
Total revenues |  |  | 4,828 |  |  |  | 6,220 |  |  |  | 8,896 |
Production expenses |  |  | 1,123 |  |  |  | 1,197 |  |  |  | 1,153 |
Exploration expenses |  |  | 167 |  |  |  | 58 |  |  |  | 128 |
Marketing and midstream expenses |  |  | 2,013 |  |  |  | 2,812 |  |  |  | 4,321 |
Depreciation, depletion and amortization |  |  | 1,300 |  |  |  | 1,497 |  |  |  | 1,228 |
Asset impairments |  |  | 2,693 |  |  |  | — |  |  |  | 156 |
Asset dispositions |  |  | (1 | ) |  |  | (48 | ) |  |  | (278 | )
General and administrative expenses |  |  | 338 |  |  |  | 475 |  |  |  | 574 |
Financing costs, net |  |  | 270 |  |  |  | 250 |  |  |  | 580 |
Restructuring and transaction costs |  |  | 49 |  |  |  | 84 |  |  |  | 97 |
Other, net |  |  | (34 | ) |  |  | 4 |  |  |  | (7 | )
Total expenses |  |  | 7,918 |  |  |  | 6,329 |  |  |  | 7,952 |
Earnings (loss) from continuing operations before income taxes |  |  | (3,090 | ) |  |  | (109 | ) |  |  | 944 |
Income tax expense (benefit) |  |  | (547 | ) |  |  | (30 | ) |  |  | 230 |
Net earnings (loss) from continuing operations |  |  | (2,543 | ) |  |  | (79 | ) |  |  | 714 |
Net earnings (loss) from discontinued operations, net of income taxes |  |  | (128 | ) |  |  | (274 | ) |  |  | 2,510 |
Net earnings (loss) |  |  | (2,671 | ) |  |  | (353 | ) |  |  | 3,224 |
Net earnings attributable to noncontrolling interests |  |  | 9 |  |  |  | 2 |  |  |  | 160 |
Net earnings (loss) attributable to Devon |  | $ | (2,680 | ) |  | $ | (355 | ) |  | $ | 3,064 |
Basic net earnings (loss) per share: |  |  |  |  |  |  |  |  |  |  |  |
Basic earnings (loss) from continuing operations per share |  | $ | (6.78 | ) |  | $ | (0.21 | ) |  | $ | 1.43 |
Basic earnings (loss) from discontinued operations per share |  |  | (0.34 | ) |  |  | (0.68 | ) |  |  | 4.71 |
Basic net earnings (loss) per share |  | $ | (7.12 | ) |  | $ | (0.89 | ) |  | $ | 6.14 |
Diluted net earnings (loss) per share: |  |  |  |  |  |  |  |  |  |  |  |
Diluted earnings (loss) from continuing operations per share |  | $ | (6.78 | ) |  | $ | (0.21 | ) |  | $ | 1.42 |
Diluted earnings (loss) from discontinued operations per share |  |  | (0.34 | ) |  |  | (0.68 | ) |  |  | 4.68 |
Diluted net earnings (loss) per share |  | $ | (7.12 | ) |  | $ | (0.89 | ) |  | $ | 6.10 |
Comprehensive earnings (loss): |  |  |  |  |  |  |  |  |  |  |  |
Net earnings (loss) |  | $ | (2,671 | ) |  | $ | (353 | ) |  | $ | 3,224 |
Other comprehensive earnings (loss), net of tax: |  |  |  |  |  |  |  |  |  |  |  |
Foreign currency translation, discontinued operations |  |  | — |  |  |  | 78 |  |  |  | (152 | )
Release of Canadian cumulative translation adjustment, discontinued operations |  |  | — |  |  |  | (1,237 | ) |  |  | — |
Pension and postretirement plans |  |  | (8 | ) |  |  | 13 |  |  |  | 44 |
Other comprehensive loss, net of tax |  |  | (8 | ) |  |  | (1,146 | ) |  |  | (108 | )
Comprehensive earnings (loss): |  |  | (2,679 | ) |  |  | (1,499 | ) |  |  | 3,116 |
Comprehensive earnings attributable to noncontrolling interests |  |  | 9 |  |  |  | 2 |  |  |  | 160 |
Comprehensive earnings (loss) attributable to Devon |  | $ | (2,688 | ) |  | $ | (1,501 | ) |  | $ | 2,956 |

See accompanying notes to consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS

|  | Year Ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
Cash flows from operating activities: |  |  |  |  |  |  |  |  |  |  |  |
Net earnings (loss) |  | $ | (2,671 | ) |  | $ | (353 | ) |  | $ | 3,224 |
Adjustments to reconcile net earnings (loss) to net cash from operating activities: |  |  |  |  |  |  |  |  |  |  |  |
Net (earnings) loss from discontinued operations, net of income taxes |  |  | 128 |  |  |  | 274 |  |  |  | (2,510 | )
Depreciation, depletion and amortization |  |  | 1,300 |  |  |  | 1,497 |  |  |  | 1,228 |
Asset impairments |  |  | 2,693 |  |  |  | — |  |  |  | 156 |
Leasehold impairments |  |  | 152 |  |  |  | 18 |  |  |  | 94 |
Accretion on discounted liabilities |  |  | 32 |  |  |  | 33 |  |  |  | 27 |
Total (gains) losses on commodity derivatives |  |  | (155 | ) |  |  | 454 |  |  |  | (457 | )
Cash settlements on commodity derivatives |  |  | 316 |  |  |  | 166 |  |  |  | (420 | )
Gains on asset dispositions |  |  | (1 | ) |  |  | (48 | ) |  |  | (278 | )
Deferred income tax expense (benefit) |  |  | (328 | ) |  |  | (25 | ) |  |  | 247 |
Share-based compensation |  |  | 88 |  |  |  | 115 |  |  |  | 137 |
Early retirement of debt |  |  | — |  |  |  | — |  |  |  | 312 |
Other |  |  | 5 |  |  |  | (6 | ) |  |  | (19 | )
Changes in assets and liabilities, net |  |  | (95 | ) |  |  | (82 | ) |  |  | (158 | )
Net cash from operating activities - continuing operations |  |  | 1,464 |  |  |  | 2,043 |  |  |  | 1,583 |
Cash flows from investing activities: |  |  |  |  |  |  |  |  |  |  |  |
Capital expenditures |  |  | (1,153 | ) |  |  | (1,910 | ) |  |  | (2,116 | )
Acquisitions of property and equipment |  |  | (8 | ) |  |  | (31 | ) |  |  | (55 | )
Divestitures of property and equipment |  |  | 34 |  |  |  | 390 |  |  |  | 500 |
Net cash from investing activities - continuing operations |  |  | (1,127 | ) |  |  | (1,551 | ) |  |  | (1,671 | )
Cash flows from financing activities: |  |  |  |  |  |  |  |  |  |  |  |
Repayments of long-term debt |  |  | — |  |  |  | (162 | ) |  |  | (922 | )
Early retirement of debt |  |  | — |  |  |  | — |  |  |  | (304 | )
Repurchases of common stock |  |  | (38 | ) |  |  | (1,849 | ) |  |  | (2,956 | )
Dividends paid on common stock |  |  | (257 | ) |  |  | (140 | ) |  |  | (149 | )
Contributions from noncontrolling interests |  |  | 21 |  |  |  | 116 |  |  |  | — |
Distributions to noncontrolling interests |  |  | (14 | ) |  |  | — |  |  |  | — |
Shares exchanged for tax withholdings |  |  | (18 | ) |  |  | (25 | ) |  |  | (39 | )
Other |  |  | — |  |  |  | (1 | ) |  |  | (7 | )
Net cash from financing activities - continuing operations |  |  | (306 | ) |  |  | (2,061 | ) |  |  | (4,377 | )
Net change in cash, cash equivalents and restricted cash of continuing operations |  |  | 31 |  |  |  | (1,569 | ) |  |  | (4,465 | )
Cash flows from discontinued operations: |  |  |  |  |  |  |  |  |  |  |  |
Operating activities |  |  | (110 | ) |  |  | 28 |  |  |  | 1,121 |
Investing activities |  |  | 481 |  |  |  | 2,472 |  |  |  | 2,726 |
Financing activities |  |  | — |  |  |  | (1,578 | ) |  |  | 174 |
Effect of exchange rate changes on cash |  |  | (9 | ) |  |  | 45 |  |  |  | 206 |
Net change in cash, cash equivalents and restricted cash of discontinued operations |  |  | 362 |  |  |  | 967 |  |  |  | 4,227 |
Net change in cash, cash equivalents and restricted cash |  |  | 393 |  |  |  | (602 | ) |  |  | (238 | )
Cash, cash equivalents and restricted cash at beginning of period |  |  | 1,844 |  |  |  | 2,446 |  |  |  | 2,684 |
Cash, cash equivalents and restricted cash at end of period |  | $ | 2,237 |  |  | $ | 1,844 |  |  | $ | 2,446 |
Reconciliation of cash, cash equivalents and restricted cash: |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 2,047 |  |  | $ | 1,464 |  |  | $ | 2,414 |
Restricted cash |  |  | 190 |  |  |  | 380 |  |  |  | 32 |
Total cash, cash equivalents and restricted cash |  | $ | 2,237 |  |  | $ | 1,844 |  |  | $ | 2,446 |

See accompanying notes to consolidated financial statements.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

|  | December 31, 2020 |  |  | December 31, 2019 |
ASSETS |  |  |  |  |  |  |  |
Current assets: |  |  |  |  |  |  |  |
Cash, cash equivalents and restricted cash |  | $ | 2,237 |  |  | $ | 1,844 |
Accounts receivable |  |  | 601 |  |  |  | 832 |
Current assets associated with discontinued operations |  |  | — |  |  |  | 896 |
Income taxes receivable |  |  | 174 |  |  |  | 47 |
Other current assets |  |  | 248 |  |  |  | 232 |
Total current assets |  |  | 3,260 |  |  |  | 3,851 |
Oil and gas property and equipment, based on successful efforts accounting, net |  |  | 4,436 |  |  |  | 7,558 |
Other property and equipment, net ($102 million and $80 million related to CDM in 2020 and 2019, respectively) |  |  | 957 |  |  |  | 1,035 |
Total property and equipment, net |  |  | 5,393 |  |  |  | 8,593 |
Goodwill |  |  | 753 |  |  |  | 753 |
Right-of-use assets |  |  | 223 |  |  |  | 243 |
Other long-term assets |  |  | 283 |  |  |  | 196 |
Long-term assets associated with discontinued operations |  |  | — |  |  |  | 81 |
Total assets |  | $ | 9,912 |  |  | $ | 13,717 |
LIABILITIES AND EQUITY |  |  |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |  |  |
Accounts payable |  | $ | 242 |  |  | $ | 428 |
Revenues and royalties payable |  |  | 662 |  |  |  | 730 |
Current liabilities associated with discontinued operations |  |  | — |  |  |  | 459 |
Other current liabilities |  |  | 536 |  |  |  | 310 |
Total current liabilities |  |  | 1,440 |  |  |  | 1,927 |
Long-term debt |  |  | 4,298 |  |  |  | 4,294 |
Lease liabilities |  |  | 246 |  |  |  | 244 |
Asset retirement obligations |  |  | 358 |  |  |  | 380 |
Other long-term liabilities |  |  | 551 |  |  |  | 426 |
Long-term liabilities associated with discontinued operations |  |  | — |  |  |  | 185 |
Deferred income taxes |  |  | — |  |  |  | 341 |
Stockholders' equity: |  |  |  |  |  |  |  |
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 382 million and 382 million shares in 2020 and 2019, respectively |  |  | 38 |  |  |  | 38 |
Additional paid-in capital |  |  | 2,766 |  |  |  | 2,735 |
Retained earnings |  |  | 208 |  |  |  | 3,148 |
Accumulated other comprehensive loss |  |  | (127 | ) |  |  | (119 | )
Total stockholders’ equity attributable to Devon |  |  | 2,885 |  |  |  | 5,802 |
Noncontrolling interests |  |  | 134 |  |  |  | 118 |
Total equity |  |  | 3,019 |  |  |  | 5,920 |
Total liabilities and equity |  | $ | 9,912 |  |  | $ | 13,717 |

See accompanying notes to consolidated financial statements.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | Other |  |  |  |  |  |  |  |  |  |  |  |  |
|  |  |  |  |  |  |  |  |  | Additional |  |  |  |  |  |  | Comprehensive |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Common Stock |  |  | Paid-In |  |  | Retained |  |  | Earnings |  |  | Treasury |  |  | Noncontrolling |  |  | Total |
|  | Shares |  |  | Amount |  |  | Capital |  |  | Earnings |  |  | (Loss) |  |  | Stock |  |  | Interests |  |  | Equity |
|  | (Unaudited) |
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 |
Net earnings (loss) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (2,680 | ) |  |  | — |  |  |  | — |  |  |  | 9 |  |  |  | (2,671 | )
Other comprehensive loss, net of tax |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (8 | ) |  |  | — |  |  |  | — |  |  |  | (8 | )
Restricted stock grants, net of cancellations |  |  | 3 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Common stock repurchased |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (57 | ) |  |  | — |  |  |  | (57 | )
Common stock retired |  |  | (3 | ) |  |  | — |  |  |  | (57 | ) |  |  | — |  |  |  | — |  |  |  | 57 |  |  |  | — |  |  |  | — |
Common stock dividends |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (260 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (260 | )
Share-based compensation |  |  | — |  |  |  | — |  |  |  | 88 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 88 |
Contributions from noncontrolling interests |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 21 |  |  |  | 21 |
Distributions to noncontrolling interests |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (14 | ) |  |  | (14 | )
Balance as of December 31, 2020 |  |  | 382 |  |  | $ | 38 |  |  | $ | 2,766 |  |  | $ | 208 |  |  | $ | (127 | ) |  | $ | — |  |  | $ | 134 |  |  | $ | 3,019 |

See accompanying notes to consolidated financial statements.

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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 onshore areas in the U.S.

As further discussed in Note 19, Devon sold its Barnett Shale assets on October 1, 2020, sold its Canadian operations on June 27, 2019 and sold its ownership interests in EnLink and the General Partner on July 18, 2018. Prior to December 31, 2020, 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.

Additionally, prior to December 31, 2020, 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. Under the terms of the Canadian and Barnett disposition agreements, Devon retained certain long-term obligations for firm transportation, office leases and potential income tax matters. Appropriate assets and liabilities related to these obligations have been recognized on Devon’s consolidated balance sheet. Because these amounts will be settled over a period extending as far as 13 years in the future, these assets and liabilities have been reclassified as part of Devon’s continuing operations as of December 31, 2020.

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, entities in which it holds a controlling 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 part of this transaction, Devon contributed gathering system and compression assets in the Cotton Draw area to CDM in exchange for a $100 million cash distribution funded by QLCP. Devon will continue to operate the assets pursuant to the management services agreement. QLCP also committed $40 million of expansion capital to CDM to fund the build out of the assets over the next several years. As of December 31, 2020, QLCP has funded approximately $37 million of the $40 million committed expansion capital to CDM. Devon holds a controlling interest in CDM and the portions of CDM’s net earnings and equity not attributable to Devon’s controlling interest are shown separately as noncontrolling interests in the accompanying consolidated 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. During 2020, QLCP contributions to and distributions from CDM were approximately $21 million and $14 million, respectively. During 2019, QLCP contributions to CDM were approximately $116 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 19, Devon’s oil and gas exploration and production activities are solely focused in the U.S. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of its business.

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;

| • | income taxes;

| • | asset retirement obligations;

| • | obligations related to employee pension and postretirement benefits;

| • | legal and environmental risks and exposures; and

| • | general credit risk associated with receivables and other assets.

Revenue Recognition

Upstream Revenues

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, control has transferred and collectability of the revenue is probable. Devon’s performance obligations are satisfied at a point in time. This occurs when control is transferred to the purchaser upon delivery of contract specified production volumes at a specified point. The transaction price used to recognize revenue is a 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 within 30 days of the end of the production month. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying consolidated statements of comprehensive earnings.

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Oil sales

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 where 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.

Natural gas and NGL sales

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

Marketing revenues are 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 to third parties at a contractually fixed or determinable price, delivery occurs at a specified point or performance has occurred, control has transferred and collectability of the revenue is probable. 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 are reported on a gross basis when Devon takes control of the products and has risks and rewards of ownership.

Midstream Revenues

Devon’s midstream activity relates entirely to its interest in CDM. CDM provides gathering, compression and dehydration services to Devon and other producers’ natural gas production. An evaluation is performed to determine whether CDM is a principal or agent in these transactions. Under the terms of these gathering, compression and dehydration contracts, CDM has concluded it is the agent as title to the gas production remains with the CDM affiliate producer or a third-party producer. Revenue is recognized on a net basis since CDM is strictly providing a service. Costs to maintain CDM’s assets are presented as marketing and midstream expenses in the consolidated statements of comprehensive earnings. Revenue is recognized for sales at the time the gathering, compression and dehydration service has been rendered or performed.

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Satisfaction of Performance Obligations and Revenue Recognitions

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.

Transaction Price Allocated to Remaining Performance Obligations

Most of Devon’s contracts are short-term in nature with a contract term of one year or less. Devon applies the practical expedient 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 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.

Contract Balances

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, 2020. Devon’s product sales and marketing contracts do not give rise to contract assets.

Disaggregation of Revenue

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

|  | Year Ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
Oil |  | $ | 2,034 |  |  | $ | 2,988 |  |  | $ | 2,941 |
Gas |  |  | 326 |  |  |  | 391 |  |  |  | 482 |
NGL |  |  | 335 |  |  |  | 430 |  |  |  | 662 |
Oil, gas and NGL sales |  |  | 2,695 |  |  |  | 3,809 |  |  |  | 4,085 |
Oil |  |  | 936 |  |  |  | 1,534 |  |  |  | 2,745 |
Gas |  |  | 488 |  |  |  | 645 |  |  |  | 738 |
NGL |  |  | 554 |  |  |  | 686 |  |  |  | 871 |
Marketing and midstream revenues |  |  | 1,978 |  |  |  | 2,865 |  |  |  | 4,354 |
Total revenues from contracts with customers |  | $ | 4,673 |  |  | $ | 6,674 |  |  | $ | 8,439 |

Customers

During 2020, Devon had two customers that accounted for approximately 13% and 10% of Devon’s consolidated sales revenue, respectively.

During 2019, no purchaser accounted for more than 10% of Devon’s consolidated sales revenue.

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

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Derivative Financial Instruments

Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices and interest rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price 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. 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. 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.

Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. As of December 31, 2020, Devon did not have any open interest rate swap contracts.

All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Amounts related to contracts allowed to be netted upon payment subject to a master netting arrangement with the same counterparty are reported on a net basis 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, 2020, 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.

By using derivative financial instruments to hedge exposures to changes in commodity prices and 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, 2020, Devon held no cash collateral of its counterparties nor posted collateral to its counterparties.

General and Administrative Expenses

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

Share-Based Compensation

Devon grants share-based awards to members of its Board of Directors, management and 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 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 statements of comprehensive earnings.

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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.

Income Taxes

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 significant negative evidence, such as cumulative losses in recent years. See Note 8 for further discussion.

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.

Net Earnings (Loss) Per Share Attributable to Devon

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 unvested performance share units.

Cash, Cash Equivalents and Restricted Cash

Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents. Subsequent to the sale of its Canadian operations in June 2019 and the sale of its Barnett Shale assets in October 2020, management presented approximately $190 million of Devon’s cash balance as of December

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31, 2020, as restricted to fund retained long-term obligations related to the disposed assets. These o bligations primarily relate to abandoned Canadian firm transportation and office lease agreements. This cash is not legally restricted and can be used by Devon for other general corporate purposes. Additionally, this restricted cash is included within continuing operations on the consolidated balance sheets at December 31, 2020.

Accounts Receivable

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 records an allowance for credit losses based on a forward-looking “expected loss” model. Credit risk is assessed by class of account type, which includes cash equivalents and oil and gas, marketing and midstream, joint interest and other accounts receivable. These classes are further evaluated using a probability-weighted scenario assessment based on historical losses and a probability of future default. This evaluation is supported by an assessment of risk factors such as the age of the receivable, current macro-economic conditions, credit rating of the counterparty and our historical loss rate.

Property and Equipment

Oil and Gas Property and Equipment

Devon follows the successful efforts method of accounting for its oil and gas properties. Exploration costs, 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 costs of drilling development wells, including those that are unsuccessful, are capitalized. Devon groups its oil and gas properties 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 proved oil and gas properties 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. 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, net of estimated salvage 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

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impairment 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.

Proved properties are assessed for impairment when events or changes in circumstances dictate that the 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 reserve cash flows is less than the carrying value of the asset, the carrying value is written down to 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.

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.

Devon capitalizes interest costs incurred that are attributable to material unproved oil and gas properties and major development projects of oil and gas properties.

Other Property and Equipment

Costs for midstream assets that are in use are depreciated over the assets’ estimated useful lives, using the 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 corporate construction projects are also capitalized.

Asset Retirement Obligations

Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites 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.

Leases

Devon adopted ASU No. 2016-02, Leases (Topic 842), as of January 1, 2019, using the modified retrospective transition approach. ASC 842 supersedes the previous lease accounting requirements in ASC 840 and requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. ASC 842 establishes a right-of-use model that requires a lessee to recognize a right-of-use asset and lease liability on the

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balance sheet for all leases with a term longer than 12 months. At adoption, using the modified retrospective transition approach, Devon recorded right-of-use lease assets of $410 million and lease liabilities of $380 million. Additionally, Devon recorded a $8 million before tax, $7 million net of tax, cumulative-effect adjustment to reduce retained earnings.

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

Goodwill

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 a 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 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 goodwill impairment test is performed. The quantitative goodwill impairment test requires the fair value of the reporting unit be compared to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. The fair value of the reporting unit is estimated based upon market capitalization, comparable transactions of similar companies and premiums paid.

Devon performed impairment tests of goodwill in the fourth quarters of 2020, 2019 and 2018. No impairment was required as a result of the annual tests in these time periods. Additionally, because the trading price of our common stock decreased 73% during the first quarter of 2020 in response to the COVID-19 pandemic, we performed a goodwill impairment test as of March 31, 2020. While the cushion narrowed significantly since the 2019 impairment evaluation, we concluded an impairment was not required as of March 31, 2020. Due to substantial recovery in the price of Devon’s common stock subsequent to the first quarter of 2020, there was no risk associated with the impairment of goodwill as of December 31, 2020.

Commitments and Contingencies

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.

Fair Value Measurements

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:

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| • | Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

| • | Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.

| • | Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model.

Foreign Currency Translation Adjustments

The U.S. dollar is the functional currency for Devon’s consolidated operations. Devon’s divested Canadian operations used the Canadian dollar as the functional currency. Prior to completing the divestiture in 2019, assets and liabilities of the Canadian 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 were translated using an average exchange rate during the reporting period.

The disposition of substantially all of Devon’s Canadian oil and gas assets and operations in 2019 resulted in Devon releasing its historical cumulative foreign currency translation adjustment of $1.2 billion from accumulated other comprehensive earnings to be included within the gain computation.

Noncontrolling Interests

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.

2. | Acquisitions and Divestitures

WPX Merger

On January 7, 2021, Devon and WPX completed an all-stock merger of equals. WPX is an oil and gas exploration and production company with assets in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. On the closing date of the Merger, each share of WPX common stock was automatically converted into the right to receive 0.5165 of a share of Devon common stock. No fractional shares of Devon’s common stock were issued in the Merger, and holders of WPX common stock instead received cash in lieu of fractional shares of Devon common stock, if any. Based on the closing price of Devon’s common stock on January 7, 2021, the total value of Devon common stock issued to holders of WPX common stock as part of this transaction was approximately $5.4 billion.

The transaction will be accounted for using the acquisition method of accounting, with Devon being treated as the accounting acquirer. Under the acquisition method of accounting, the assets and liabilities of WPX and its subsidiaries will be recorded at their respective fair values as of the date of completion of the Merger and added to Devon’s. The preliminary purchase price assessment remains an ongoing process and is subject to change for up to one year subsequent to the closing date of the Merger. Determining the fair value of the assets and liabilities of WPX requires judgment and certain assumptions to be made, the most significant of these being related to the valuation of WPX’s oil and gas properties. The Merger is structured as a tax-free reorganization for United States federal income tax purposes.

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In February 2021, Devon redeemed bonds issued by WPX with a maturity date of 2022 pursuant to a make whole provision in the related indenture. The total principal related to this redemption was approximately $43 million, with an additional $2 million cash premium paid to complete the make whole redemption.

Discontinued Operations

On October 1, 2020, Devon completed the sale of its Barnett Shale assets to BKV for proceeds, net of purchase price adjustments, of $490 million, including a $170 million deposit previously received in April 2020. The agreement with BKV also provides for contingent earnout payments to Devon of up to $260 million based upon future commodity prices, with upside participation beginning at a $2.75 Henry Hub natural gas price or a $50 WTI oil price. The contingent payment period commences on January 1, 2021 and has a term of four years. Devon recognized a $748 million asset impairment related to these assets in the fourth quarter of 2019 and incremental asset impairments totaling $182 million during 2020. Additional information can be found in Note 19.

In June 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) in 2019. Additional information can be found in Note 19.

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 discontinued operations. For additional information, see Note 19.

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 18. Additional information on these discontinued operations can be found in Note 19.

Continuing Operations

In the fourth quarter of 2020, Devon entered into an agreement to divest non-core assets in the Rockies for proceeds of approximately $12 million. The transaction includes contingent earnout payments of up to approximately $8 million and is expected to close in the first quarter of 2021. As of December 31, 2020, the associated assets and liabilities were classified as assets held for sale and included in other current assets and other current liabilities, respectively, in the accompanying consolidated balance sheet. Estimated total proved reserves related to these assets were approximately 3 MMBoe as of December 31, 2020. The December 31, 2020 assets and liabilities held for sale primarily relate to oil and gas property and equipment and asset retirement obligations, respectively.

During the first quarter of 2020, Devon entered into a farmout agreement in which the third party to the agreement can participate in the development of certain Devon-owned, non-operated interests in the Delaware Basin. Under the agreement, Devon will periodically transfer working interests to the third party, who will then fund its share of operating and development costs. Once certain investment hurdles are met, a portion of the working interest held by the third party will revert to Devon. No material activity occurred during 2020.

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.

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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.

3. | Derivative Financial Instruments

Commodity Derivatives

As of December 31, 2020, Devon had the following open oil derivative positions. The first table presents Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The second table presents Devon’s oil derivatives that settle against the respective indices noted within the table.

|  | Price Swaps |  |  | Price Collars |
Period |  | Volume (Bbls/d) |  |  | Weighted Average Price ($/Bbl) |  |  | Volume (Bbls/d) |  |  | Weighted Average Floor Price ($/Bbl) |  |  | Weighted Average Ceiling Price ($/Bbl) |
Q1-Q4 2021 |  |  | 28,040 |  |  | $ | 37.60 |  |  |  | 32,726 |  |  | $ | 40.77 |  |  | $ | 50.77 |
Q1-Q2 2022 |  |  | 1,249 |  |  | $ | 45.16 |  |  |  | 9,856 |  |  | $ | 38.24 |  |  | $ | 48.24 |

|  | Oil Basis Swaps |
Period |  | Index |  | Volume (Bbls/d) |  |  | Weighted Average Differential to WTI ($/Bbl) |
Q1-Q4 2021 |  | Midland Sweet |  |  | 7,000 |  |  | $ | 1.27 |

As of December 31, 2020, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas derivatives that settle against the respective indices noted within the table.

|  | Price Swaps |  |  | Price Collars |
Period |  | Volume (MMBtu/d) |  |  | Weighted Average Price ($/MMBtu) |  |  | Volume (MMBtu/d) |  |  | Weighted Average Floor Price ($/MMBtu) |  |  | Weighted Average Ceiling Price ($/MMBtu) |
Q1-Q4 2021 |  |  | 32,699 |  |  | $ | 2.76 |  |  |  | 179,055 |  |  | $ | 2.45 |  |  | $ | 2.95 |
Q1-Q4 2022 |  |  | 6,961 |  |  | $ | 2.85 |  |  |  | 54,901 |  |  | $ | 2.66 |  |  | $ | 3.16 |

|  | Natural Gas Basis Swaps |
Period |  | Index |  | Volume (MMBtu/d) |  |  | Weighted Average Differential to Henry Hub ($/MMBtu) |
Q1-Q4 2021 |  | El Paso Natural Gas |  |  | 35,000 |  |  | $ | (0.92 | )

As of December 31, 2020, Devon did not have any open NGL derivative positions.

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Financial Statement Presentation

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

|  | Year Ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
Commodity derivatives: |  |  |  |  |  |  |  |  |  |  |  |
Oil, gas and NGL derivatives |  | $ | 155 |  |  | $ | (454 | ) |  | $ | 457 |
Marketing and midstream revenues |  |  | — |  |  |  | 1 |  |  |  | (1 | )
Interest rate derivatives: |  |  |  |  |  |  |  |  |  |  |  |
Other expenses |  |  | — |  |  |  | — |  |  |  | 65 |
Net gains (losses) recognized |  | $ | 155 |  |  | $ | (453 | ) |  | $ | 521 |

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

|  | December 31, 2020 |  |  | December 31, 2019 |
Commodity derivative assets: |  |  |  |  |  |  |  |
Other current assets |  | $ | 5 |  |  | $ | 49 |
Other long-term assets |  |  | 1 |  |  |  | 1 |
Total derivative assets |  | $ | 6 |  |  | $ | 50 |
Commodity derivative liabilities: |  |  |  |  |  |  |  |
Other current liabilities |  | $ | 143 |  |  | $ | 30 |
Other long-term liabilities |  |  | 5 |  |  |  | 1 |
Total derivative liabilities |  | $ | 148 |  |  | $ | 31 |

4. | Share-Based Compensation

In 2017, Devon’s stockholders approved the 2017 Plan. Subject to the terms of the 2017 Plan, awards may be made for a total of 33.5 million shares of Devon common stock, plus the number of shares available for issuance under the 2015 Plan (including shares subject to outstanding awards that were transferred to the 2017 Plan in accordance with its terms). The 2017 Plan authorizes the Compensation Committee, which consists of independent, non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards or units, performance units and stock appreciation rights to eligible employees. The 2017 Plan also authorizes the grant of nonqualified stock options, restricted stock awards or units and stock appreciation rights to non-employee directors. To calculate the number of shares that may be granted in awards under the 2017 Plan, options and stock appreciation rights represent one share and other awards represent 2.3 shares.

The vesting for certain share-based awards was accelerated in 2020, 2019 and 2018 in conjunction with the reduction of workforce activities described in Note 6 and is included in restructuring and transaction costs in the accompanying consolidated statements of comprehensive earnings.

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The table below presents the share-based compensation expense included in Devon’s accompanying consolidated statements of comprehensive earnings.

|  | Year Ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
G&A |  | $ | 76 |  |  | $ | 83 |  |  | $ | 104 |
Exploration expenses |  |  | 1 |  |  |  | 1 |  |  |  | 2 |
Restructuring and transaction costs |  |  | 11 |  |  |  | 31 |  |  |  | 31 |
Total |  | $ | 88 |  |  | $ | 115 |  |  | $ | 137 |
Related income tax benefit |  | $ | — |  |  | $ | 13 |  |  | $ | 17 |

The following table presents a summary of Devon’s unvested restricted stock awards, performance-based restricted stock awards and performance share units granted under the plans.

|  |  |  |  | Performance-Based |  |  | Performance |
|  | Restricted Stock Awards |  |  | Restricted Stock Awards |  |  | Share Units |
|  | Awards |  |  | Weighted Average Grant-Date Fair Value |  |  | Awards |  |  | Weighted Average Grant-Date Fair Value |  |  | Units |  |  |  |  |  | Weighted Average Grant-Date Fair Value |
|  | (Thousands, except fair value data) |
Unvested at 12/31/19 |  |  | 4,984 |  |  | $ | 29.65 |  |  |  | 153 |  |  | $ | 33.88 |  |  |  | 2,155 |  |  |  |  |  | $ | 40.35 |
Granted |  |  | 3,056 |  |  | $ | 21.90 |  |  |  | — |  |  | $ | — |  |  |  | 688 |  |  |  |  |  | $ | 27.89 |
Vested |  |  | (2,388 | ) |  | $ | 28.96 |  |  |  | (109 | ) |  | $ | 29.51 |  |  |  | (455 | ) |  |  |  |  | $ | 52.56 |
Forfeited |  |  | (336 | ) |  | $ | 24.52 |  |  |  | — |  |  | $ | — |  |  |  | (394 | ) |  |  |  |  | $ | 47.30 |
Unvested at 12/31/20 |  |  | 5,316 |  |  | $ | 25.82 |  |  |  | 44 |  |  | $ | 44.70 |  |  |  | 1,994 |  |  | (1 | ) |  | $ | 31.89 |

(1) | A maximum of 3.2 million common shares could be awarded based upon Devon’s final TSR ranking.

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

|  | 2020 |  |  | 2019 |  |  | 2018 |
Restricted Stock Awards and Units |  | $ | 44 |  |  | $ | 127 |  |  | $ | 111 |
Performance-Based Restricted Stock Awards |  | $ | 2 |  |  | $ | 4 |  |  | $ | 10 |
Performance Share Units |  | $ | 10 |  |  | $ | 4 |  |  | $ | 20 |

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, 2020.

|  |  |  |  |  | Performance-Based |  |  |  |  |
|  | Restricted Stock |  |  | Restricted Stock |  |  | Performance |
|  | Awards |  |  | Awards |  |  | Share Units |
Unrecognized compensation cost |  | $ | 70 |  |  | $ | — |  |  | $ | 10 |
Weighted average period for recognition (years) |  |  | 2.4 |  |  |  | 0.4 |  |  |  | 1.7 |

Restricted Stock Awards

Restricted stock awards are subject to the terms, conditions, restrictions and limitations, if any, that the Compensation Committee deems appropriate, including restrictions on continued employment. Generally, the

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service requirement for vesting ranges from one to four years. Dividends declared during the vesting period with respect to restricted stock awards will not be paid until the underlying award vests. Devon estimates the fair values of restricted stock awards as the closing price of Devon’s common stock on the grant date of the award, which is expensed over the applicable vesting period.

Performance-Based Restricted Stock Awards

Performance-based restricted stock awards were granted to certain members of Devon’s senior management. Vesting of the awards is dependent on Devon meeting certain internal performance targets and the recipient meeting certain service requirements. Generally, the service requirement for vesting ranges from one to four years. In order for awards to vest, the performance target must be met in the first year. If the performance target is met, the recipient is entitled to dividends under the same terms described above for nonperformance-based restricted stock. If the performance target and service period requirements are not met, the award does not vest. Devon estimates the fair values of the awards as the closing price of Devon’s common stock on the grant date of the award, which is expensed over the applicable vesting period. No performance-based restricted stock awards were granted in 2020, 2019 and 2018.

Performance Share Units

Performance share units are granted to certain members of Devon’s management and employees. Each unit that vests entitles the recipient to one share of Devon common stock. The vesting of these units is based on comparing Devon’s TSR to the TSR of a predetermined group of peer companies over the specified three-year performance period. The vesting of units may be between zero and 200% of the units granted depending on Devon’s TSR as compared to the peer group on the vesting date.

At the end of the vesting period, recipients receive dividend equivalents with respect to the number of units vested. The fair value of each performance share unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a risk-free interest rate based on U.S. Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of Devon and the designated peer group; and (iii) an estimated ranking of Devon among the designated peer group. The fair value of the unit on the date of grant is expensed over the applicable vesting period. The following table presents the assumptions related to performance share units granted.

|  | 2020 |  | 2019 |  |  | 2018 |
Grant-date fair value |  |  | $ | 27.89 |  |  |  | $ | 28.43 |  |  | — |  | $ | 29.53 |  |  | $ | 36.23 |  |  | — |  | $ | 37.88 |
Risk-free interest rate |  | 1.36% |  | 2.48% |  |  | 2.28% |
Volatility factor |  | 38.4% |  | 39.1% |  |  | 45.8% |
Contractual term (years) |  | 2.89 |  | 2.89 |  |  | 2.89 |

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5. | Asset Impairments

The following table presents a summary of Devon’s asset impairments. Unproved impairments shown below are included in exploration expenses in the consolidated statements of comprehensive earnings.

|  | Year Ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
Proved oil and gas assets |  | $ | 2,664 |  |  | $ | — |  |  | $ | 109 |
Other assets |  |  | 29 |  |  |  | — |  |  |  | 47 |
Total asset impairments |  | $ | 2,693 |  |  | $ | — |  |  | $ | 156 |
Unproved impairments |  | $ | 152 |  |  | $ | 18 |  |  | $ | 95 |

Proved Oil and Gas and Other Asset Impairments

Reduced demand from the COVID-19 pandemic caused an unprecedented downturn in the price of oil. As a result, Devon reduced 2020 planned capital spend by 45% in March 2020. With materially lower commodity prices and reduced near-term investment, Devon assessed all of its oil and gas common operating fields for impairment as of March 31, 2020. For impairment determination, Devon historically utilized NYMEX forward strip prices for the first five years and applied internally generated price forecasts for subsequent years. In response to the COVID-19 pandemic, the NYMEX forward market became highly illiquid as evidenced by materially reduced trading volumes for periods beyond 2021. Therefore, Devon supplemented the NYMEX forward strip prices with price forecasts published by reputable investment banks and reservoir engineering firms to estimate future revenues as of March 31, 2020. For WTI, the range of pricing utilized in the first ten years of impairment reserve cash flows was approximately $23 to $50, and the weighted average of WTI pricing was approximately $39. For Henry Hub pricing utilized in the first ten years of impairment reserve cash flows, the range was approximately $1.29 - $2.63, with a weighted average Henry Hub price of approximately $1.85. To measure the indicated impairment in the first quarter of 2020, Devon used a market-based weighted-average cost of capital of 9% to discount the future net cash flows. These inputs are categorized as level 3 in the fair value hierarchy.
Devon recognized approximately $2.7 billion of proved asset impairments during the first quarter of 2020. These impairments related to the Anadarko Basin and Rockies fields in which the cost basis included acquisitions completed in 2016 and 2015, respectively, when commodity prices were much higher than in 2020. During 2020, Devon recognized approximately $29 million of non-oil and gas asset impairments.
In 2018, Devon recognized $109 million of proved asset impairments relating to U.S. non-core assets no longer in its development plans and approximately $47 million of non-oil and gas asset impairments.

Unproved Impairments

Due to the downturn in the commodity price environment and reduced near-term investment as discussed above, Devon recognized $152 million of unproved impairments in 2020. Of these unproved impairments, $116 million related primarily to the Rockies field and $36 million related to certain non-core acreage Devon no longer intends to pursue for exploration opportunities. In 2019 and 2018, Devon allowed certain non-core acreage to expire without plans for development resulting in unproved impairments.

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6. | Restructuring and Transaction Costs

The following table summarizes Devon’s restructuring and transaction costs.

|  | Year Ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
Restructuring |  | $ | 41 |  |  | $ | 84 |  |  | $ | 97 |
Transaction costs |  |  | 8 |  |  |  | — |  |  |  | — |
Total |  | $ | 49 |  |  | $ | 84 |  |  | $ | 97 |

Restructuring

2020 Workforce Reductions

In the third quarter of 2020, Devon announced a cost reduction plan designed to deliver sustainable cost savings by year-end 2020. As a result, Devon recognized $41 million of restructuring expenses during 2020. Of these expenses, $11 million and $9 million resulted from accelerated vesting of share-based grants and settlements and curtailments of defined retirement benefits, respectively, which are both noncash charges.

Prior Years’ Restructurings

During 2019 and 2018, Devon recognized restructuring expenses of $84 million and $97 million, respectively. Of these expenses recognized in 2019, $31 million and $7 million resulted from accelerated vesting of share-based grants and settlements of defined retirement benefits, respectively. Of these expenses recognized in 2018, $31 million and $14 million resulted from accelerated vesting of share-based grants and settlements of defined retirement benefits, respectively.

The following table summarizes Devon’s restructuring liabilities presented in the accompanying consolidated balance sheets.

|  | Other |  |  | Other |  |  |  |  |
|  | Current |  |  | Long-term |  |  |  |  |
|  | Liabilities |  |  | Liabilities |  |  | Total |
Balance as of December 31, 2018 |  | $ | 39 |  |  | $ | 3 |  |  | $ | 42 |
Changes due to 2019 workforce reductions |  |  | 18 |  |  |  | — |  |  |  | 18 |
Changes related to prior years' restructurings |  |  | (37 | ) |  |  | (2 | ) |  |  | (39 | )
Balance as of December 31, 2019 |  | $ | 20 |  |  | $ | 1 |  |  | $ | 21 |
Changes related to 2020 workforce reductions |  |  | 3 |  |  |  | — |  |  |  | 3 |
Changes related to prior years' restructurings |  |  | (18 | ) |  |  | — |  |  |  | (18 | )
Changes related to retained liabilities previously classified as discontinued operations |  |  | 30 |  |  |  | 136 |  |  |  | 166 |
Balance as of December 31, 2020 |  | $ | 35 |  |  | $ | 137 |  |  | $ | 172 |

As of December 31, 2020, approximately $30 million and $136 million of liabilities were reclassified from liabilities associated with discontinued operations to other current and long-term liabilities, respectively, on the consolidated balance sheets.

Transaction Costs

On September 26, 2020, Devon and WPX entered into the Merger Agreement, providing for an all-stock merger of equals which was completed on January 7, 2021. Devon incurred approximately $8 million in bank, legal

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and accounting fees in the fourth quarter of 2020 related to the Merger. Devon expects to incur additional transaction costs in connection with the Merger closing in 2021.

7. Other, Net

The following table summarizes Devon’s other expenses presented in the accompanying consolidated comprehensive statement of earnings.

|  | Year Ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
Asset retirement obligation accretion |  | $ | 20 |  |  | $ | 21 |  |  | $ | 26 |
Severance tax refunds |  |  | (40 | ) |  |  | — |  |  |  | (5 | )
Other |  |  | (14 | ) |  |  | (17 | ) |  |  | (28 | )
Total |  | $ | (34 | ) |  | $ | 4 |  |  | $ | (7 | )

During 2020 and 2018, Devon received severance tax refunds related to prior periods of $40 million and $5 million, respectively.

8. | Income Taxes

Income Tax Expense (Benefit)

The following table presents Devon’s income tax components.

|  | Year Ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
Current income tax benefit: |  |  |  |  |  |  |  |  |  |  |  |
U.S. federal |  | $ | (219 | ) |  | $ | (3 | ) |  | $ | (14 | )
Various states |  |  | — |  |  |  | (2 | ) |  |  | (3 | )
Total current income tax benefit |  |  | (219 | ) |  |  | (5 | ) |  |  | (17 | )
Deferred income tax expense (benefit): |  |  |  |  |  |  |  |  |  |  |  |
U.S. federal |  |  | (304 | ) |  |  | 8 |  |  |  | 184 |
Various states |  |  | (24 | ) |  |  | (33 | ) |  |  | 63 |
Total deferred income tax expense (benefit) |  |  | (328 | ) |  |  | (25 | ) |  |  | 247 |
Total income tax expense (benefit) |  | $ | (547 | ) |  | $ | (30 | ) |  | $ | 230 |

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Total income tax expense differed from the amounts computed by applying the U.S. federal income tax rate to earnings (loss) from continuing operations before income taxes as a result of the following:

|  | Year Ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
Earnings (loss) from continuing operations before income taxes |  | $ | (3,090 | ) |  | $ | (109 | ) |  | $ | 944 |
U.S. statutory income tax rate |  |  | 21 | % |  |  | 21 | % |  |  | 21 | %
Change in tax legislation |  |  | 4 | % |  |  | 0 | % |  |  | 0 | %
State income taxes |  |  | 1 | % |  |  | 24 | % |  |  | 5 | %
Change in unrecognized tax benefits |  |  | 0 | % |  |  | (13 | %) |  |  | (2 | %)
Audit settlements |  |  | 0 | % |  |  | 15 | % |  |  | (2 | %)
Other |  |  | (1 | %) |  |  | (19 | %) |  |  | 2 | %
Deferred tax asset valuation allowance |  |  | (7 | %) |  |  | 0 | % |  |  | 0 | %
Effective income tax rate |  |  | 18 | % |  |  | 28 | % |  |  | 24 | %

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

Devon assesses the realizability of its deferred tax assets. If Devon concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws.

2020

The Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) became law on March 27, 2020. The CARES Act allows net operating losses generated in taxable years beginning after December 31, 2017 and before January 1, 2021 to be carried back five years to offset taxable income and recoup previously paid taxes. As a result, Devon intends to carry net operating losses generated in 2019 and 2020 back to 2014 and 2015, respectively, and recorded a $220 million current income tax benefit, partially offset by a $107 million deferred income tax expense. The net $113 million income tax benefit recorded in 2020 is the result of the higher U.S. federal income tax rate in the carry back periods.

Throughout 2019, Devon maintained a valuation allowance against certain deferred tax assets, including certain tax credits and state net operating losses. Since then, reduced demand from the COVID-19 pandemic has caused an unprecedented downturn in the commodity price environment. As a result, Devon recorded significant impairments during the first quarter of 2020 and is now in a net deferred tax asset position. Devon reassessed its position and recorded a 100% valuation allowance against all U.S. federal and state net deferred tax assets and has maintained a full valuation allowance position throughout 2020.

2019

On June 27, 2019, Devon completed the sale of substantially all of its oil and gas assets and operations in Canada. Devon’s foreign earnings have not been considered indefinitely reinvested since the announcement of the plan to separate the assets in the first quarter of 2019. As the separation took the form of an asset sale and Devon

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retained certain non-operating obligations to be settled over time, Devon did not record a deferred tax asset or corresponding valuation allowance related to its Canadian investment in 2019.

Devon recorded tax impacts related to the Barnett Shale and Canadian assets in discontinued operations.

During 2019, Devon recorded a tax expense of $14 million related to unrecognized tax benefits, due to a change in tax positions taken in prior periods.

In the fourth quarter of 2019, Devon entered into an audit agreement with the Canada Revenue Agency. The Canadian income tax expense resulting from this agreement is reflected in discontinued operations. However, the agreement also resulted in a $16 million tax benefit to Devon’s U.S. continuing operations.

The “other” effect is composed of permanent differences, including stock compensation, for which the dollar amounts do not increase or decrease in relation to the change in pre-tax earnings. Generally, permanent adjustments, as well as the state income tax, have an insignificant impact on Devon’s effective income tax rate. However, these items had a more noticeable impact to the rate in 2019 due to the low relative net loss in the period.

2018

Through the first six months of 2018, Devon maintained a 100% valuation allowance against its deferred tax assets resulting from prior year cumulative financial losses, oil and gas impairments and significant net operating losses for U.S. federal and state income tax. However, upon closing the EnLink divestiture in the third quarter of 2018, Devon realized a pre-tax gain of $2.6 billion. Based on its net deferred tax liability position, current period projected net operating loss utilization, and projections of future taxable income, Devon reassessed its position and determined that it was no longer in a full valuation allowance position, maintaining only valuation allowances against certain deferred tax assets, including certain tax credits and state net operating losses. As part of its reassessment, Devon determined that apart from the sale of EnLink and the General Partner, Devon would have remained in a full valuation allowance position. Accordingly, the deferred tax benefit resulting from the release of the valuation allowance that was generated in the first two quarters was allocated to continuing operations, while the $259 million of the deferred tax benefit resulting from the release of the remainder of the full valuation allowance position was allocated entirely to discontinued operations.

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Deferred Tax Assets and Liabilities

The following table presents the tax effects of temporary differences that gave rise to Devon’s deferred tax assets and liabilities.

|  | December 31, |
|  | 2020 |  |  | 2019 |
Deferred tax assets: |  |  |  |  |  |  |  |
Capital loss carryforwards |  | $ | 547 |  |  | $ | — |
Investment in subsidiary |  |  | 441 |  |  |  | — |
Net operating loss carryforwards |  |  | 238 |  |  |  | 306 |
Accrued liabilities |  |  | 125 |  |  |  | 35 |
Asset retirement obligation |  |  | 94 |  |  |  | 123 |
Pension benefit obligation |  |  | 43 |  |  |  | 39 |
Other |  |  | 96 |  |  |  | 66 |
Total deferred tax assets before valuation allowance |  |  | 1,584 |  |  |  | 569 |
Less: valuation allowance |  |  | (1,355 | ) |  |  | (106 | )
Net deferred tax assets |  |  | 229 |  |  |  | 463 |
Deferred tax liabilities: |  |  |  |  |  |  |  |
Property and equipment |  |  | (213 | ) |  |  | (800 | )
Other |  |  | — |  |  |  | (4 | )
Total deferred tax liabilities |  |  | (213 | ) |  |  | (804 | )
Net deferred tax asset (liability) |  | $ | 16 |  |  | $ | (341 | )

The $16 million net Canadian deferred tax asset as of December 31, 2020, is expected to be realized by the end of 2022. Included in Devon’s Canadian net deferred tax asset balance are $593 million of deferred tax assets primarily related to capital loss carryforwards and a $577 million valuation allowance against Canadian deferred tax assets.

Devon has a deductible outside basis difference in its investment in its consolidated Canadian subsidiary. In the fourth quarter of 2020, it became apparent that this basis difference would reverse within the foreseeable future. As such, Devon recorded a $441 million deferred tax asset with a corresponding increase to its U.S. deferred tax asset valuation allowance. The tax benefit associated with recording this deferred tax asset and the offsetting tax expense associated with the corresponding change in valuation allowance are recorded in discontinued operations.

At December 31, 2020, Devon has recognized $238 million of deferred tax assets related to various net operating loss carryforwards available to offset future taxable income. Devon has $581 million of U.S. federal net operating loss carryforwards ($431 million expiring in 2037 with the remainder having an indefinite life) and $2.5 billion of U.S. state net operating loss carryforwards expiring between 2021 and 2040. In the current environment, Devon currently does not anticipate utilizing all of its U.S. federal or state net operating loss carryforwards, as indicated by the full valuation allowance against its U.S. deferred tax assets.

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Unrecognized Tax Benefits

The following table presents changes in Devon’s unrecognized tax benefits.

|  | December 31, |
|  | 2020 |  |  | 2019 |
|  | (Millions) |
Balance at beginning of year |  | $ | 65 |  |  | $ | 51 |
Tax positions taken in prior periods |  |  | (42 | ) |  |  | 14 |
Balance at end of year |  | $ | 23 |  |  | $ | 65 |

Devon recognized no net interest or penalties in 2020 and its unrecognized tax benefit balance included no interest and penalties at December 31, 2020. Devon recognized a net interest benefit of $5 million in 2019 and its unrecognized tax benefit balance included no interest and penalties at December 31, 2019. At December 31, 2020 and December 31, 2019, there were $23 million and $65 million, respectively, of unrecognized tax benefits that if recognized would affect the annual effective tax rate. Due to regulatory changes during 2020, $42 million of Devon’s current unrecognized tax benefits were reclassified as deferred unrecognized tax benefits. The deferred unrecognized tax benefits of $50 million and $7 million, respectively, at December 31, 2020 and December 31, 2019 are not included in the table above but are accounted for in Devon’s deferred tax disclosure above. Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities.

Jurisdiction |  | Tax Years Open
U.S. Federal |  | 2017-2020
Various U.S. states |  | 2016-2020
Canada |  | 2004-2020

Certain statute of limitation expirations are scheduled to occur in the next twelve months. However, Devon is currently in various stages of the administrative review process for certain open tax years. In addition, Devon is currently subject to various income tax audits that have not reached the administrative review process.

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9. | Net Earnings (Loss) Per Share from Continuing Operations

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

|  | Year Ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
Net earnings (loss) from continuing operations: |  |  |  |  |  |  |  |  |  |  |  |
Net earnings (loss) from continuing operations |  | $ | (2,552 | ) |  | $ | (81 | ) |  | $ | 714 |
Attributable to participating securities |  |  | (4 | ) |  |  | (2 | ) |  |  | (8 | )
Basic and diluted earnings (loss) from continuing operations |  | $ | (2,556 | ) |  | $ | (83 | ) |  | $ | 706 |
Common shares: |  |  |  |  |  |  |  |  |  |  |  |
Common shares outstanding - total |  |  | 383 |  |  |  | 407 |  |  |  | 499 |
Attributable to participating securities |  |  | (6 | ) |  |  | (6 | ) |  |  | (5 | )
Common shares outstanding - basic |  |  | 377 |  |  |  | 401 |  |  |  | 494 |
Dilutive effect of potential common shares issuable |  |  | — |  |  |  | — |  |  |  | 3 |
Common shares outstanding - diluted |  |  | 377 |  |  |  | 401 |  |  |  | 497 |
Net earnings (loss) per share from continuing operations: |  |  |  |  |  |  |  |  |  |  |  |
Basic |  | $ | (6.78 | ) |  | $ | (0.21 | ) |  | $ | 1.43 |
Diluted |  | $ | (6.78 | ) |  | $ | (0.21 | ) |  | $ | 1.42 |
Antidilutive options (1) |  |  | — |  |  |  | 1 |  |  |  | 1 |

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

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10. | Other Comprehensive Earnings

Components of other comprehensive earnings consist of the following:

|  | Year Ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
Foreign currency translation: |  |  |  |  |  |  |  |  |  |  |  |
Beginning accumulated foreign currency translation and other |  | $ | — |  |  | $ | 1,159 |  |  | $ | 1,309 |
Change in cumulative translation adjustment |  |  | — |  |  |  | 78 |  |  |  | (166 | )
Release of Canadian cumulative translation adjustment (1) |  |  | — |  |  |  | (1,237 | ) |  |  | — |
Income tax benefit |  |  | — |  |  |  | — |  |  |  | 14 |
Other |  |  | — |  |  |  | — |  |  |  | 2 |
Ending accumulated foreign currency translation and other |  |  | — |  |  |  | — |  |  |  | 1,159 |
Pension and postretirement benefit plans: |  |  |  |  |  |  |  |  |  |  |  |
Beginning accumulated pension and postretirement benefits |  |  | (119 | ) |  |  | (132 | ) |  |  | (143 | )
Net actuarial gain and prior service cost arising in current year |  |  | (34 | ) |  |  | (10 | ) |  |  | (3 | )
Recognition of net actuarial loss and prior service cost in earnings (2) |  |  | 7 |  |  |  | 6 |  |  |  | 12 |
Curtailment and settlement of pension benefits |  |  | 16 |  |  |  | 21 |  |  |  | 47 |
Income tax expense |  |  | 3 |  |  |  | (4 | ) |  |  | (12 | )
Other (3) |  |  | — |  |  |  | — |  |  |  | (33 | )
Ending accumulated pension and postretirement benefits |  |  | (127 | ) |  |  | (119 | ) |  |  | (132 | )
Accumulated other comprehensive earnings (loss), net of tax |  | $ | (127 | ) |  | $ | (119 | ) |  | $ | 1,027 |

(1) | In conjunction with the sale of substantially all of its oil and gas assets and operations in Canada, Devon released the cumulative translation adjustment as part of its gain on the disposition of its Canadian business. See Note 19 for additional details.

(2) | These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of other expenses in the accompanying consolidated statements of comprehensive earnings. See Note 17 for additional details.

(3) | As a result of Devon’s early adoption of ASU 2018-02 in the fourth quarter of 2018, Devon reclassified $33 million from accumulated other comprehensive income to retained earnings in the December 31, 2018 consolidated balance sheet.

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1 1. | Supplemental Information to Statements of Cash Flows

|  | Year Ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
Changes in assets and liabilities, net: |  |  |  |  |  |  |  |  |  |  |  |
Accounts receivable |  | $ | 231 |  |  | $ | (3 | ) |  | $ | (69 | )
Other current assets |  |  | (97 | ) |  |  | (7 | ) |  |  | (152 | )
Other long-term assets |  |  | (9 | ) |  |  | 17 |  |  |  | (7 | )
Accounts payable |  |  | (38 | ) |  |  | (54 | ) |  |  | (3 | )
Revenues and royalties payable |  |  | (71 | ) |  |  | 8 |  |  |  | 106 |
Other current liabilities |  |  | (68 | ) |  |  | (66 | ) |  |  | 3 |
Other long-term liabilities |  |  | (43 | ) |  |  | 23 |  |  |  | (36 | )
Total |  | $ | (95 | ) |  | $ | (82 | ) |  | $ | (158 | )
Supplementary cash flow data - total operations: |  |  |  |  |  |  |  |  |  |  |  |
Interest paid |  | $ | 259 |  |  | $ | 308 |  |  | $ | 385 |
Income taxes paid |  | $ | 171 |  |  | $ | 6 |  |  | $ | 40 |

As of December 31, 2020 and 2019, Devon had approximately $100 million and $250 million, respectively, of accrued capital expenditures included in “Total property and equipment, net” and “Accounts payable” on the consolidated balance sheets.

1 2. | Accounts Receivable

Components of accounts receivable include the following:

|  | December 31, 2020 |  |  | December 31, 2019 |
Oil, gas and NGL sales |  | $ | 335 |  |  | $ | 452 |
Joint interest billings |  |  | 57 |  |  |  | 168 |
Marketing and midstream revenues |  |  | 195 |  |  |  | 207 |
Other |  |  | 25 |  |  |  | 13 |
Gross accounts receivable |  |  | 612 |  |  |  | 840 |
Allowance for doubtful accounts |  |  | (11 | ) |  |  | (8 | )
Net accounts receivable |  | $ | 601 |  |  | $ | 832 |

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13.Property, Plant and Equipment

Capitalized Costs

The following table reflects the aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas activities.

|  | December 31, 2020 |  |  | December 31, 2019 |
Property and equipment: |  |  |  |  |  |  |  |
Proved |  | $ | 27,589 |  |  | $ | 27,668 |
Unproved and properties under development |  |  | 392 |  |  |  | 583 |
Total oil and gas |  |  | 27,981 |  |  |  | 28,251 |
Less accumulated DD&A |  |  | (23,545 | ) |  |  | (20,693 | )
Oil and gas property and equipment, net |  |  | 4,436 |  |  |  | 7,558 |
Other property and equipment |  |  | 1,737 |  |  |  | 1,725 |
Less accumulated DD&A |  |  | (780 | ) |  |  | (690 | )
Other property and equipment, net (1) |  |  | 957 |  |  |  | 1,035 |
Property and equipment, net |  | $ | 5,393 |  |  | $ | 8,593 |

(1) | $102 million and $80 million related to CDM in 2020 and 2019, respectively.

During 2020, Devon recognized asset impairments of $2.7 billion primarily related to proved oil and gas assets and $152 million of unproved impairments, which significantly reduced the carrying value of its property and equipment, net. See Note 5 for additional details.

Suspended Exploratory Well Costs

The following summarizes the changes in suspended exploratory well costs for the three years ended December 31, 2020.

|  | Year Ended December 31,
|  | 2020 |  | 2019 |  |  | 2018 |  |
Beginning balance |  | $ | 82 |  | $ | 98 |  |  | $ | 100 |  |
Additions pending determination of proved reserves |  |  | 148 |  |  | 278 |  |  |  | 658 |  |
Charges to exploration expense |  |  | (3 | ) |  | — |  |  |  | — |  |
Reclassifications to proved properties |  |  | (209 | ) |  | (294 | ) |  |  | (660 | ) |
Ending balance |  | $ | 18 |  | $ | 82 |  |  | $ | 98 |  |

Devon had no projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling as of December 31, 2020, 2019 and 2018, respectively.

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1 4. | Debt and Related Expenses

See below for a summary of debt instruments and balances. The notes and debentures are senior, unsecured obligations of Devon.

|  | December 31, 2020 |  |  | December 31, 2019 |
5.85% due December 15, 2025 |  | $ | 485 |  |  | $ | 485 |
7.50% due September 15, 2027 (1) |  |  | 73 |  |  |  | 73 |
7.875% due September 30, 2031 |  |  | 675 |  |  |  | 675 |
7.95% due April 15, 2032 |  |  | 366 |  |  |  | 366 |
5.60% due July 15, 2041 |  |  | 1,250 |  |  |  | 1,250 |
4.75% due May 15, 2042 |  |  | 750 |  |  |  | 750 |
5.00% due June 15, 2045 |  |  | 750 |  |  |  | 750 |
Net discount on debentures and notes |  |  | (20 | ) |  |  | (20 | )
Debt issuance costs |  |  | (31 | ) |  |  | (35 | )
Total long-term debt |  | $ | 4,298 |  |  | $ | 4,294 |

(1) | This instrument was assumed by Devon in April 2003 in conjunction with the merger with Ocean Energy. The fair value and effective rates of this note at the time assumed was $169 million and 6.5%. This instrument is the unsecured and unsubordinated obligation of Devon OEI Operating, L.L.C. and is guaranteed by Devon Energy Production Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon.

Debt maturities as of December 31, 2020, excluding debt issuance costs, premiums and discounts, are as follows:

|  | Total |
2021 |  | $ | — |
2022 |  |  | — |
2023 |  |  | — |
2024 |  |  | — |
2025 |  |  | 485 |
Thereafter |  |  | 3,864 |
Total |  | $ | 4,349 |

Credit Lines

Devon has a $3.0 billion Senior Credit Facility. As of December 31, 2020, Devon had $2 million in outstanding letters of credit under the Senior Credit Facility. There were no borrowings under the Senior Credit Facility as of December 31, 2020.

In connection with the closing of the sale of its Canadian business, Devon reallocated and terminated all Canadian commitments under the Senior Credit Facility in accordance with the terms of the credit agreement governing the Senior Credit Facility. The termination of the Canadian subfacility was effective as of June 27, 2019, and such termination did not decrease the $3.0 billion in total revolving commitments under, or otherwise modify the terms of, the Senior Credit Facility. Subsequent to Devon’s divestment of substantially all of its oil and gas assets and operations in Canada, Devon entered into an amendment and extension agreement on December 13, 2019 to, among other things, (i) effect the extension of the maturity date of the Senior Credit Facility from October 5, 2023 to October 5, 2024 with respect to the consenting lenders, (ii) modify the maximum number of maturity extension requests during the term of the Senior Credit Facility from two to three and (iii) eliminate various references to the terminated Canadian subfacility. As a result of this amendment, Devon has the option to extend the October 5, 2024 maturity date by two additional one-year periods subject to lender consent, and the maximum

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borrowing capacity of the Senior Credit Facility becomes $2.8 billion after October 5, 2023. Amounts borrowed under the Senior Credit Facility may, at the election of Devon, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, Devon may elect to borrow at the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $6 million.

The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the accompanying consolidated financial statements. For example, total capitalization is adjusted to add back noncash financial write-downs such as asset impairments. As of December 31, 2020, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 25%.

Commercial Paper

Devon’s Senior Credit Facility supports its $3.0 billion of short-term credit under its commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR or the money market rate as found in the commercial paper market. As of December 31, 2020, Devon had no outstanding commercial paper borrowings.

Financing Costs, Net

The following schedule includes the components of net financing costs.

|  | Year Ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
Interest based on debt outstanding |  | $ | 259 |  |  | $ | 260 |  |  | $ | 287 |
Early retirement of debt |  |  | — |  |  |  | — |  |  |  | 312 |
Interest income |  |  | (12 | ) |  |  | (33 | ) |  |  | (32 | )
Other |  |  | 23 |  |  |  | 23 |  |  |  | 13 |
Total net financing costs |  | $ | 270 |  |  | $ | 250 |  |  | $ | 580 |

During 2018, Devon recognized a $312 million charge on early retirement of debt, consisting of $304 million in cash retirement costs and $8 million of noncash charges. These costs, along with other charges associated with retiring the debt, are included in net financing costs in the consolidated statements of comprehensive earnings.

1 5. | Leases

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

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The following table presents Devon’s right-of-use assets and lease liabilities.

|  | December 31, 2020 |  |  | December 31, 2019 |
|  | Finance |  |  | Operating |  |  | Total |  |  | Finance |  |  | Operating |  |  | Total |
Right-of-use assets |  | $ | 220 |  |  | $ | 3 |  |  | $ | 223 |  |  | $ | 229 |  |  | $ | 14 |  |  | $ | 243 |
Lease liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current lease liabilities (1) |  | $ | 8 |  |  | $ | 1 |  |  | $ | 9 |  |  | $ | 7 |  |  | $ | 10 |  |  | $ | 17 |
Long-term lease liabilities |  |  | 244 |  |  |  | 2 |  |  |  | 246 |  |  |  | 240 |  |  |  | 4 |  |  |  | 244 |
Total lease liabilities |  | $ | 252 |  |  | $ | 3 |  |  | $ | 255 |  |  | $ | 247 |  |  | $ | 14 |  |  | $ | 261 |

(1) | Current lease liabilities are included in other current liabilities on the consolidated balance sheets.

The following table presents Devon’s total lease cost.

|  |  | Year Ended December 31, |
|  |  | 2020 |  |  | 2019 |
Operating lease cost | Property, plant and equipment; G&A |  | $ | 10 |  |  | $ | 40 |
Short-term lease cost (1) | Property, plant and equipment; G&A |  |  | 45 |  |  |  | 84 |
Financing lease cost: |  |  |  |  |  |  |  |  |
Amortization of right-of-use assets | DD&A |  |  | 8 |  |  |  | 8 |
Interest on lease liabilities | Net financing costs |  |  | 11 |  |  |  | 10 |
Variable lease cost | G&A |  |  | — |  |  |  | 2 |
Lease income | G&A |  |  | (8 | ) |  |  | (5 | )
Net lease cost |  |  | $ | 66 |  |  | $ | 139 |

(1) | Short-term lease cost excludes leases with terms of one month or less.

The following table presents Devon’s additional lease information.

|  | Year Ended December 31, |
|  | 2020 |  |  | 2019 |
|  | Finance |  |  | Operating |  |  | Finance |  |  | Operating |
Cash outflows for lease liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating cash flows |  | $ | 7 |  |  | $ | 2 |  |  | $ | 7 |  |  | $ | 2 |
Investing cash flows |  | $ | — |  |  | $ | 8 |  |  | $ | — |  |  | $ | 41 |
Right-of-use assets obtained in exchange for new lease liabilities |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 3 |
Weighted average remaining lease term (years) |  |  | 7.0 |  |  |  | 4.1 |  |  |  | 8.0 |  |  |  | 2.2 |
Weighted average discount rate |  |  | 4.2 | % |  |  | 2.9 | % |  |  | 4.2 | % |  |  | 3.2 | %

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The following table presents Devon’s maturity analysis as of December 31, 2020 for leases expiring in each of the next 5 years and thereafter.

|  | Finance |  |  | Operating |  |  | Total |
2021 |  | $ | 7 |  |  | $ | 1 |  |  | $ | 8 |
2022 |  |  | 8 |  |  |  | 1 |  |  |  | 9 |
2023 |  |  | 8 |  |  |  | 1 |  |  |  | 9 |
2024 |  |  | 8 |  |  |  | — |  |  |  | 8 |
2025 |  |  | 8 |  |  |  | — |  |  |  | 8 |
Thereafter |  |  | 290 |  |  |  | — |  |  |  | 290 |
Total lease payments |  |  | 329 |  |  |  | 3 |  |  |  | 332 |
Less: interest |  |  | (77 | ) |  |  | — |  |  |  | (77 | )
Present value of lease liabilities |  | $ | 252 |  |  | $ | 3 |  |  | $ | 255 |

Devon rents or subleases certain real estate to third parties. The following table presents Devon’s expected lease income as of December 31, 2020 for each of the next 5 years and thereafter.

|  | Operating |
|  | Lease Income |
2021 |  | $ | 8 |
2022 |  |  | 8 |
2023 |  |  | 8 |
2024 |  |  | 9 |
2025 |  |  | 8 |
Thereafter |  |  | 52 |
Total |  | $ | 93 |

1 6. | Asset Retirement Obligations

The following table presents the changes in asset retirement obligations.

|  | Year Ended December 31, |
|  | 2020 |  |  | 2019 |
Asset retirement obligations as of beginning of period |  | $ | 398 |  |  | $ | 484 |
Liabilities incurred |  |  | 18 |  |  |  | 20 |
Liabilities settled and divested |  |  | (29 | ) |  |  | (66 | )
Liabilities reclassified as held for sale |  |  | (42 | ) |  |  | — |
Revision of estimated obligation |  |  | 4 |  |  |  | (61 | )
Accretion expense on discounted obligation |  |  | 20 |  |  |  | 21 |
Asset retirement obligations as of end of period |  |  | 369 |  |  |  | 398 |
Less current portion |  |  | 11 |  |  |  | 18 |
Asset retirement obligations, long-term |  | $ | 358 |  |  | $ | 380 |

During 2019, Devon reduced its asset retirement obligations by $61 million, primarily due to changes in the future cost estimates and retirement dates for its oil and gas assets. During 2019, Devon also reduced its asset retirement obligations by $42 million as a result of Devon’s 2019 divestitures. For additional information, see Note 2.

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1 7. | Retirement Plans

Defined Contribution Plans

Devon sponsors defined contribution plans covering its employees. Such plans include its 401(k) plan and enhanced contribution plan. Contributions are primarily based upon percentages of annual compensation and years of service. In addition, each plan is subject to regulatory limitations by the U.S. government. Devon contributed $33 million, $34 million and $40 million to these plans in 2020, 2019 and 2018, respectively.

Defined Benefit Plans

Devon has various non-contributory defined benefit pension plans, including qualified plans and nonqualified plans covering eligible employees and former employees meeting certain age and service requirements. Benefits under the defined benefit plans have been closed to new employees; however, eligible employees have continued to accrue benefits based upon years of service and compensation. However, effective December 31, 2020, Devon’s benefits committee approved a freeze of all future benefit accruals under the Plan.

Benefits are primarily funded from assets held in the plans’ trusts.

Devon’s investment objective for its plans’ assets is to achieve stability of the funded status while providing long-term growth of invested capital and income to ensure benefit payments can be funded when required. Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing. Devon’s target allocations for its plan assets are 85% fixed income and 15% equity. See the following discussion for Devon’s pension assets by asset class.

Fixed-income – Devon’s fixed-income securities consist of U.S. Treasury obligations, bonds issued by investment-grade companies from diverse industries and asset-backed securities. These fixed-income securities are actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices and were $617 million and $240 million at December 31, 2020 and 2019, respectively. Also included in 2019 were commingled funds that primarily invest in long-term bonds and U.S. Treasury securities. These fixed income securities can be redeemed on demand but are not actively traded. The fair values of these securities are based upon the net asset values provided by the investment managers and were $233 million at December 31, 2019.

Equity – Devon’s equity securities include commingled global equity funds that invest in large, mid and small capitalization stocks across the world’s developed and emerging markets and international large cap equity securities. These equity securities can be sold on demand but are not actively traded. The fair values of these securities are based upon the net asset values provided by the investment managers and were $110 million and $112 million at December 31, 2020 and 2019, respectively.

Other – Devon’s other securities include short-term investment funds and a hedge fund that invest both long and short term using a variety of investment strategies. The fair value of these securities is based upon the net asset values provided by investment managers and were $18 million and $109 million at December 31, 2020 and 2019, respectively.

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Defined Postretirement Plans

Devon also has defined benefit postretirement plans that provide benefits for substantially all qualifying retirees. Benefit obligations for such plans are estimated based on Devon’s future cost-sharing intentions. Devon’s funding policy for the plans is to fund the benefits as they become payable with available cash and cash equivalents.

Benefit Obligations and Funded Status

The following table summarizes the benefit obligations, assets, funded status and balance sheet impacts associated with Devon’s defined pension and postretirement plans. Devon’s benefit obligations and plan assets are measured each year as of December 31. The accumulated benefit obligation for pension plans approximated the projected benefit obligation at December 31, 2020 and 2019.

|  | Pension Benefits |  |  | Postretirement Benefits |
|  | 2020 |  |  | 2019 |  |  | 2020 |  |  | 2019 |
Change in benefit obligation: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Benefit obligation at beginning of year |  | $ | 924 |  |  | $ | 916 |  |  | $ | 14 |  |  | $ | 17 |
Service cost |  |  | 5 |  |  |  | 7 |  |  |  | — |  |  |  | — |
Interest cost |  |  | 25 |  |  |  | 32 |  |  |  | — |  |  |  | — |
Actuarial loss (gain) |  |  | 116 |  |  |  | 91 |  |  |  | (1 | ) |  |  | (3 | )
Plan amendments |  |  | 2 |  |  |  | 3 |  |  |  | — |  |  |  | — |
Plan curtailments |  |  | (14 | ) |  |  | (3 | ) |  |  | 1 |  |  |  | 1 |
Plan settlements |  |  | (28 | ) |  |  | (75 | ) |  |  | — |  |  |  | — |
Participant contributions |  |  | — |  |  |  | — |  |  |  | 2 |  |  |  | 2 |
Benefits paid |  |  | (49 | ) |  |  | (47 | ) |  |  | (3 | ) |  |  | (3 | )
Benefit obligation at end of year |  |  | 981 |  |  |  | 924 |  |  |  | 13 |  |  |  | 14 |
Change in plan assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fair value of plan assets at beginning of year |  |  | 694 |  |  |  | 685 |  |  |  | — |  |  |  | — |
Actual return on plan assets |  |  | 114 |  |  |  | 118 |  |  |  | — |  |  |  | — |
Employer contributions |  |  | 14 |  |  |  | 13 |  |  |  | 1 |  |  |  | 1 |
Participant contributions |  |  | — |  |  |  | — |  |  |  | 2 |  |  |  | 2 |
Plan settlements |  |  | (28 | ) |  |  | (75 | ) |  |  | — |  |  |  | — |
Benefits paid |  |  | (49 | ) |  |  | (47 | ) |  |  | (3 | ) |  |  | (3 | )
Fair value of plan assets at end of year |  |  | 745 |  |  |  | 694 |  |  |  | — |  |  |  | — |
Funded status at end of year |  | $ | (236 | ) |  | $ | (230 | ) |  | $ | (13 | ) |  | $ | (14 | )
Amounts recognized in balance sheet: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other long-term assets |  | $ | 10 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Other current liabilities |  |  | (14 | ) |  |  | (13 | ) |  |  | (2 | ) |  |  | (2 | )
Other long-term liabilities |  |  | (232 | ) |  |  | (217 | ) |  |  | (11 | ) |  |  | (12 | )
Net amount |  | $ | (236 | ) |  | $ | (230 | ) |  | $ | (13 | ) |  | $ | (14 | )
Amounts recognized in accumulated other comprehensive earnings: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net actuarial loss (gain) |  | $ | 201 |  |  | $ | 183 |  |  | $ | (12 | ) |  | $ | (12 | )
Prior service cost (credit) |  |  | — |  |  |  | 5 |  |  |  | — |  |  |  | (1 | )
Total |  | $ | 201 |  |  | $ | 188 |  |  | $ | (12 | ) |  | $ | (13 | )

During 2020, Devon’s qualified plan experienced a partial plan settlement due to ongoing lump sum payments. Devon’s qualified and non-qualified plans experienced curtailments due to plan freezes and reductions in force.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Certain of Devon’s pension plans have a combined projected benefit obligation or accumulated benefit obligation in excess of plan assets at December 31, 2020 and December 31, 2019, as presented in the table below.

|  | December 31, |
|  | 2020 |  |  | 2019 |
Projected benefit obligation |  | $ | 246 |  |  | $ | 924 |
Accumulated benefit obligation (1) |  | $ | 246 |  |  | $ | 223 |
Fair value of plan assets |  | $ | — |  |  | $ | 694 |

(1) | The projected and accumulated benefit obligation for the qualified pension plan was not in excess of plan assets as of December 31, 2020. The 2019 qualified pension plan contained $690 million of accumulated benefit obligations which were not in excess of plan assets.

The following table presents the components of net periodic benefit cost and other comprehensive earnings.

|  | Pension Benefits |  |  | Postretirement Benefits |
|  | 2020 |  |  | 2019 |  |  | 2018 |  |  | 2020 |  |  | 2019 |  |  | 2018 |
Net periodic benefit cost: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Service cost |  | $ | 5 |  |  | $ | 7 |  |  | $ | 9 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Interest cost |  |  | 25 |  |  |  | 32 |  |  |  | 38 |  |  |  | — |  |  |  | — |  |  |  | — |
Expected return on plan assets |  |  | (41 | ) |  |  | (38 | ) |  |  | (48 | ) |  |  | — |  |  |  | — |  |  |  | — |
Recognition of net actuarial loss (gain) (1) |  |  | 5 |  |  |  | 7 |  |  |  | 13 |  |  |  | — |  |  |  | (1 | ) |  |  | (1 | )
Recognition of prior service cost (1) |  |  | 3 |  |  |  | 1 |  |  |  | 1 |  |  |  | (1 | ) |  |  | (1 | ) |  |  | (1 | )
Total net periodic benefit cost (2) |  |  | (3 | ) |  |  | 9 |  |  |  | 13 |  |  |  | (1 | ) |  |  | (2 | ) |  |  | (2 | )
Other comprehensive loss (earnings): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Actuarial loss (gain) arising in current year |  |  | 27 |  |  |  | 7 |  |  |  | 5 |  |  |  | (1 | ) |  |  | (2 | ) |  |  | (1 | )
Prior service cost arising in current year |  |  | 2 |  |  |  | 3 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Recognition of net actuarial gain (loss), including settlement expense, in net periodic benefit cost (3) |  |  | (9 | ) |  |  | (22 | ) |  |  | (59 | ) |  |  | 1 |  |  |  | 1 |  |  |  | 1 |
Recognition of prior service cost, including curtailment, in net periodic benefit cost (3) |  |  | (7 | ) |  |  | (2 | ) |  |  | (2 | ) |  |  | 1 |  |  |  | 1 |  |  |  | 1 |
Total other comprehensive loss (earnings) |  |  | 13 |  |  |  | (14 | ) |  |  | (56 | ) |  |  | 1 |  |  |  | — |  |  |  | 1 |
Total |  | $ | 10 |  |  | $ | (5 | ) |  | $ | (43 | ) |  | $ | — |  |  | $ | (2 | ) |  | $ | (1 | )

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

(2) | The service cost component of net periodic benefit cost is included in G&A expense and the remaining components of net periodic benefit costs are included in other expenses in the accompanying consolidated statements of comprehensive earnings.

(3) | These amounts include restructuring costs that were reclassified out of other comprehensive earnings in 2020, 2019 and 2018. See Note 6 for further discussion.

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Assumptions

|  | Pension Benefits |  |  | Postretirement Benefits |
|  | 2020 |  |  | 2019 |  |  | 2018 |  |  | 2020 |  |  | 2019 |  |  | 2018 |
Assumptions to determine benefit obligations: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Discount rate |  | 2.38% |  |  | 3.14% |  |  | 4.09% |  |  | 1.82% |  |  | 2.81% |  |  | 4.01% |
Rate of compensation increase |  | 2.50% |  |  | 2.50% |  |  | 2.50% |  |  | N/A |  |  | N/A |  |  | N/A |
Assumptions to determine net periodic benefit cost: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Discount rate - service cost |  | 3.47% |  |  | 3.74% |  |  | 3.77% |  |  | 3.25% |  |  | 3.99% |  |  | 4.13% |
Discount rate - interest cost |  | 2.75% |  |  | 3.36% |  |  | 3.14% |  |  | 2.31% |  |  | 3.21% |  |  | 2.67% |
Rate of compensation increase |  | 2.50% |  |  | 2.50% |  |  | 2.50% |  |  | N/A |  |  | N/A |  |  | N/A |
Expected return on plan assets |  | 6.00% |  |  | 5.75% |  |  | 5.75% |  |  | N/A |  |  | N/A |  |  | N/A |

Discount rate - Future pension and post-retirement obligations are discounted based on the rate at which obligations could be effectively settled, considering the timing of expected future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk.

Expected return on plan assets – This was determined by evaluating input from external consultants and economists, as well as long-term inflation assumptions and consideration of target allocation of investment types.

Mortality rate – Devon utilized the Society of Actuaries produced mortality tables.

Other assumptions – For measurement of the 2020 benefit obligation for the other postretirement medical plans, a 6.9% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2021. The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2029 and remain at that level thereafter.

Expected Cash Flows

Devon expects benefit plan payments to average approximately $57 million a year for the next five years and $264 million total for the five years thereafter. Of these payments to be paid in 2021, $17 million is expected to be funded from Devon’s available cash, cash equivalents and other assets.

1 8. | Stockholders’ Equity

The authorized capital stock of Devon consists of 1.0 billion shares of common stock, par value $0.10 per share, and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors.

Share Repurchase Program

In 2018, Devon announced a share repurchase program totaling $4.0 billion. In February 2019, Devon announced a further expansion to $5.0 billion with a December 31, 2019 expiration date. In December 2019, Devon announced a new $1.0 billion share repurchase program with a December 31, 2020 expiration date.

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The table below provides information regarding purchases of Devon’s common stock that were made under the respective share repurchase programs (shares in thousands).

|  | Total Number of Shares Purchased |  |  | Dollar Value of Shares Purchased |  |  | Average Price Paid per Share |
$5.0 Billion Plan |  |  |  |  |  |  |  |  |  |  |  |
2018 |  |  | 78,149 |  |  | $ | 2,978 |  |  | $ | 38.11 |
2019 |  |  | 68,625 |  |  |  | 1,827 |  |  |  | 26.62 |
Total inception-to-date |  |  | 146,774 |  |  | $ | 4,805 |  |  | $ | 32.74 |
$1.0 Billion Plan |  |  |  |  |  |  |  |  |  |  |  |
2020 |  |  | 2,243 |  |  | $ | 38 |  |  | $ | 16.85 |
Total inception-to-date |  |  | 2,243 |  |  | $ | 38 |  |  | $ | 16.85 |

Dividends

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

| Amounts |  |  | Rate Per Share |
Year Ended 2020: |  |  |  |  |  |  |
First quarter | $ | 34 |  |  | $ | 0.09 |
Second quarter |  | 42 |  |  | $ | 0.11 |
Third quarter |  | 43 |  |  | $ | 0.11 |
Fourth quarter |  | 41 |  |  | $ | 0.11 |
Fourth quarter (special dividend) |  | 97 |  |  | $ | 0.26 |
Total year-to-date | $ | 257 |  |  |  |  |
Year Ended 2019: |  |  |  |  |  |  |
First quarter | $ | 34 |  |  | $ | 0.08 |
Second quarter |  | 37 |  |  | $ | 0.09 |
Third quarter |  | 35 |  |  | $ | 0.09 |
Fourth quarter |  | 34 |  |  | $ | 0.09 |
Total year-to-date | $ | 140 |  |  |  |  |
Year Ended 2018: |  |  |  |  |  |  |
First quarter | $ | 32 |  |  | $ | 0.06 |
Second quarter |  | 42 |  |  | $ | 0.08 |
Third quarter |  | 38 |  |  | $ | 0.08 |
Fourth quarter |  | 37 |  |  | $ | 0.08 |
Total year-to-date | $ | 149 |  |  |  |  |

Devon raised its quarterly dividend by 22%, to $0.11 per share, beginning in the second quarter of 2020. Devon also increased its quarterly dividend rate in both the second quarter of 2019 from $0.08 to $0.09 and in 2018 from $0.06 to $0.08.

On October 1, 2020, Devon paid a $0.26 per share special dividend to holders of record as of August 14, 2020.

In February 2021, Devon announced an approximately $128 million variable cash dividend in the amount of $0.19 per share payable in the first quarter of 2021.

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Noncontrolling Interests

As discussed in Note 1, the noncontrolling interests’ share of CDM’s net earnings and the contributions from and distributions to the noncontrolling interests are presented as components of equity.

WPX Merger

On January 7, 2021, Devon and WPX completed an all-stock merger of equals. On the closing date of the Merger, each share of WPX common stock was automatically converted into the right to receive 0.5165 of a share of Devon common stock. No fractional shares of Devon’s common stock were issued in the Merger, and holders of WPX common stock instead received cash in lieu of fractional shares of Devon common stock, if any. Based on the closing price of Devon’s common stock on January 7, 2021, approximately 290 million shares of Devon common stock were issued to holders of WPX common stock for a total value of approximately $5.4 billion.

1 9. | Discontinued Operations

Barnett Shale

On December 17, 2019, Devon announced that it had entered into an agreement to sell its Barnett Shale assets to BKV. Devon concluded that the transaction was a strategic shift and met the requirements of assets held for sale and discontinued operations upon the authorization to enter the agreement by Devon’s Board of Directors. As part of its assessment, Devon effectively exited its last natural gas focused asset and the transaction resulted in a material reduction to total assets, revenues, net earnings and total proved reserves. Estimated proved reserves associated with Devon’s Barnett Shale assets were approximately 45% of the total proved reserves. As a result, Devon classified the results of operations and cash flows related to its Barnett Shale assets, inclusive of Barnett properties divested in previous reporting periods located primarily in Johnson and Wise counties, Texas, as discontinued operations on its consolidated financial statements.

In conjunction with the divestiture agreement, which was amended in April 2020, Devon recognized a $182 million and $748 million asset impairment related to the Barnett Shale assets in 2020 and 2019, respectively, primarily due to the difference between the net carrying value and the purchase price, net of estimated customary purchase price adjustments, which qualifies as a level 2 fair value measurement. Approximately $88 million of the U.S. reporting unit goodwill was allocated to the Barnett Shale assets. Additionally, Devon ceased depreciation for all plant, property and equipment classified as assets held for sale on the date the sales agreement was approved by the Board of Directors.

On October 1, 2020, Devon completed the sale of its Barnett Shale assets to BKV for proceeds, net of purchase price adjustments, of $490 million, including a $170 million deposit previously received in April 2020. Additionally, the agreement provides for contingent earnout payments to Devon of up to $260 million based upon future commodity prices, with upside participation beginning at a $2.75 Henry Hub natural gas price or a $50 WTI oil price. The contingent payment period commences on January 1, 2021 and has a term of four years. The valuation of the future contingent earnout payments included within other current assets in the December 31, 2020 balance sheet was $66 million. The value was derived utilizing a Monte Carlo valuation model and qualifies as a level 3 fair value measurement.

As of December 31, 2020, Devon has classified approximately $20 million of cash as restricted cash on the consolidated balance sheets for obligations associated with the abandonment of certain gas processing contracts related to divestitures of other Barnett Shale assets that occurred in 2018. Cash payments for these charges total approximately $2 million per quarter.

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Canada

In the second quarter of 2019, Devon completed the sale of its Canadian business for $2.6 billion ($3.4 billion Canadian dollars), net of purchase price adjustments, and recognized a pre-tax gain of $223 million ($425 million net of tax, primarily due to a significant deferred tax benefit) in 2019. Current (cash) income and withholding taxes associated with the Canadian business were approximately $175 million and were paid in the first half of 2020. Devon concluded that the transaction was a strategic shift and met the requirements of assets held for sale and discontinued operations based upon the following: 1) Devon was exiting its entire heavy oil and Canadian operations; 2) Devon’s Canadian operations were a separate reportable segment and a component of Devon’s business; and 3) the transaction resulted in a material reduction in total assets, revenues, net earnings and total proved reserves. The disposition of substantially all of Devon’s Canadian oil and gas assets resulted in Devon releasing its historical cumulative foreign currency translation adjustment of $1.2 billion from accumulated other comprehensive earnings to be included within the gain computation. The historical cumulative foreign currency translation portion of the gain is not taxable.

During the third quarter of 2019, Devon utilized a portion of the sales proceeds to early retire $500 million of the 4.00% senior notes due July 15, 2021 and $1.0 billion of the 3.25% senior notes due May 15, 2022. Devon recognized a charge on the early retirement of these notes consisting of $52 million in cash retirement costs and $6 million of noncash charges.

As of December 31, 2020, Devon has classified approximately $170 million of cash as restricted cash on the consolidated balance sheets for obligations retained related to the Canadian business. The remaining obligations consist of a firm transportation agreement and office leases. Cash payments for these charges total approximately $8 million per quarter.

EnLink

On June 6, 2018, Devon announced that it had entered into an agreement to sell its aggregate ownership interests in EnLink and the General Partner for $3.125 billion. Upon entering into the agreement to sell its ownership interest in June 2018, Devon concluded that the transaction was a strategic shift and met the requirements of assets held for sale and discontinued operations. As a result, Devon classified the results of operations and cash flows related to EnLink and the General Partner as discontinued operations on its consolidated financial statements.

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

As part of the sale agreement, Devon extended its fixed-fee gathering and processing contracts with respect to the Bridgeport and Cana plants with EnLink through 2029. Although the agreements were extended to 2029, the minimum volume commitments for the Bridgeport and Cana plants expired at the end of 2018. Devon had minimum volume commitments for gathering and processing of 77-128 MMcf/d with EnLink at the Chisholm plant which expired at the end of 2020.

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

During 2020, 2019 and from the period of July 19, 2018 through December 31, 2018, Devon had net outflows of approximately $430 million, $560 million and $380 million with EnLink, respectively, which primarily related to gathering and processing expenses. These net outflows represent gross cash amounts and not net working interest amounts.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

Year ended December 31, |  | Barnett Shale |  |  | Canada |  |  | EnLink |  |  | Total |
2020 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil, gas and NGL sales |  | $ | 263 |  |  | $ | — |  |  | $ | — |  |  | $ | 263 |
Total revenues |  |  | 263 |  |  |  | — |  |  |  | — |  |  |  | 263 |
Production expenses |  |  | 214 |  |  |  | — |  |  |  | — |  |  |  | 214 |
Asset impairments |  |  | 182 |  |  |  | — |  |  |  | — |  |  |  | 182 |
Asset dispositions |  |  | (4 | ) |  |  | 5 |  |  |  | — |  |  |  | 1 |
General and administrative expenses |  |  | — |  |  |  | 3 |  |  |  | — |  |  |  | 3 |
Financing costs, net |  |  | — |  |  |  | (3 | ) |  |  | — |  |  |  | (3 | )
Restructuring and transaction costs |  |  | — |  |  |  | 9 |  |  |  | — |  |  |  | 9 |
Other expenses |  |  | 10 |  |  |  | (1 | ) |  |  | — |  |  |  | 9 |
Total expenses |  |  | 402 |  |  |  | 13 |  |  |  | — |  |  |  | 415 |
Earnings (loss) from discontinued operations before income taxes |  |  | (139 | ) |  |  | (13 | ) |  |  | — |  |  |  | (152 | )
Income tax benefit |  |  | (11 | ) |  |  | (13 | ) |  |  | — |  |  |  | (24 | )
Net earnings (loss) from discontinued operations, net of tax |  | $ | (128 | ) |  | $ | — |  |  | $ | — |  |  | $ | (128 | )
2019 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil, gas and NGL sales |  | $ | 486 |  |  | $ | 741 |  |  | $ | — |  |  | $ | 1,227 |
Oil, gas and NGL derivatives |  |  | — |  |  |  | (113 | ) |  |  | — |  |  |  | (113 | )
Marketing and midstream revenues |  |  | — |  |  |  | 38 |  |  |  | — |  |  |  | 38 |
Total revenues |  |  | 486 |  |  |  | 666 |  |  |  | — |  |  |  | 1,152 |
Production expenses |  |  | 306 |  |  |  | 293 |  |  |  | — |  |  |  | 599 |
Exploration expenses |  |  | — |  |  |  | 13 |  |  |  | — |  |  |  | 13 |
Marketing and midstream expenses |  |  | — |  |  |  | 18 |  |  |  | — |  |  |  | 18 |
Depreciation, depletion and amortization |  |  | 77 |  |  |  | 128 |  |  |  | — |  |  |  | 205 |
Asset impairments |  |  | 748 |  |  |  | 37 |  |  |  | — |  |  |  | 785 |
Asset dispositions |  |  | 1 |  |  |  | (223 | ) |  |  | — |  |  |  | (222 | )
General and administrative expenses |  |  | — |  |  |  | 34 |  |  |  | — |  |  |  | 34 |
Financing costs, net |  |  | — |  |  |  | 87 |  |  |  | — |  |  |  | 87 |
Restructuring and transaction costs |  |  | — |  |  |  | 248 |  |  |  | — |  |  |  | 248 |
Other expenses |  |  | 11 |  |  |  | 6 |  |  |  | — |  |  |  | 17 |
Total expenses |  |  | 1,143 |  |  |  | 641 |  |  |  | — |  |  |  | 1,784 |
Earnings (loss) from discontinued operations before income taxes |  |  | (657 | ) |  |  | 25 |  |  |  | — |  |  |  | (632 | )
Income tax benefit |  |  | (142 | ) |  |  | (216 | ) |  |  | — |  |  |  | (358 | )
Net earnings (loss) from discontinued operations, net of tax |  | $ | (515 | ) |  | $ | 241 |  |  | $ | — |  |  | $ | (274 | )
2018 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil, gas and NGL sales |  | $ | 777 |  |  | $ | 814 |  |  | $ | — |  |  | $ | 1,592 |
Oil, gas and NGL derivatives |  |  | — |  |  |  | 151 |  |  |  | — |  |  |  | 150 |
Marketing and midstream revenues |  |  | — |  |  |  | 95 |  |  |  | 3,567 |  |  |  | 3,662 |
Total revenues |  |  | 777 |  |  |  | 1,060 |  |  |  | 3,567 |  |  |  | 5,404 |
Production expenses |  |  | 467 |  |  |  | 605 |  |  |  | — |  |  |  | 1,072 |
Exploration expenses |  |  | — |  |  |  | 48 |  |  |  | — |  |  |  | 48 |
Marketing and midstream expenses |  |  | — |  |  |  | 42 |  |  |  | 2,912 |  |  |  | 2,954 |
Depreciation, depletion and amortization |  |  | 100 |  |  |  | 330 |  |  |  | 244 |  |  |  | 674 |
Asset dispositions |  |  | 14 |  |  |  | — |  |  |  | (2,607 | ) |  |  | (2,593 | )
General and administrative expenses |  |  | — |  |  |  | 76 |  |  |  | 65 |  |  |  | 141 |
Financing costs, net |  |  | — |  |  |  | 14 |  |  |  | 98 |  |  |  | 112 |
Restructuring and transaction costs |  |  | — |  |  |  | 17 |  |  |  | — |  |  |  | 17 |
Other expenses |  |  | (34 | ) |  |  | 182 |  |  |  | (8 | ) |  |  | 140 |
Total expenses |  |  | 547 |  |  |  | 1,314 |  |  |  | 704 |  |  |  | 2,565 |
Earnings (loss) from discontinued operations before income taxes |  |  | 230 |  |  |  | (254 | ) |  |  | 2,863 |  |  |  | 2,839 |
Income tax expense (benefit) |  |  | 50 |  |  |  | (124 | ) |  |  | 403 |  |  |  | 329 |
Net earnings (loss) from discontinued operations, net of tax |  |  | 180 |  |  |  | (130 | ) |  |  | 2,460 |  |  |  | 2,510 |
Net earnings attributable to noncontrolling interests |  |  | — |  |  |  | — |  |  |  | 160 |  |  |  | 160 |
Net earnings (loss) from discontinued operations, attributable to Devon |  | $ | 180 |  |  | $ | (130 | ) |  | $ | 2,300 |  |  | $ | 2,350 |

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Prior to December 31, 2020, activity on the consolidated statement of comprehensive earnings and assets and liabilities on the consolidated balance sheet related to Devon’s Barnett Shale and Canadian operations were classified as discontinued operations. Under the terms of the Canadian and Barnett disposition agreements, Devon retained certain long-term obligations for firm transportation, office leases and potential income tax matters. Appropriate assets and liabilities related to these obligations have been recognized on Devon's consolidated balance sheet. Because these amounts will be settled over a period extending as far as 13 years in the future, these assets and liabilities have been reclassified as part of Devon's continuing operations as of December 31, 2020.

The following table presents the carrying amounts of the assets and liabilities associated with discontinued operations on the consolidated balance sheet as of December 31, 2019.

|  | As of December 31, 2019 |
|  | Barnett Shale |  |  | Canada |  |  | Total |
Accounts receivable |  | $ | 38 |  |  | $ | 1 |  |  | $ | 39 |
Other current assets |  |  | 5 |  |  |  | 2 |  |  |  | 7 |
Oil and gas property and equipment, based on successful efforts accounting, net |  |  | 751 |  |  |  | — |  |  |  | 751 |
Other property and equipment, net |  |  | 11 |  |  |  | — |  |  |  | 11 |
Goodwill |  |  | 88 |  |  |  | — |  |  |  | 88 |
Other long-term assets |  |  | — |  |  |  | 81 |  |  |  | 81 |
Total assets associated with discontinued operations |  | $ | 893 |  |  | $ | 84 |  |  | $ | 977 |
Accounts payable |  | $ | 15 |  |  | $ | 4 |  |  | $ | 19 |
Revenues and royalties payable |  |  | 44 |  |  |  | 3 |  |  |  | 47 |
Other current liabilities |  |  | 19 |  |  |  | 233 |  |  |  | 252 |
Asset retirement obligations |  |  | 141 |  |  |  | — |  |  |  | 141 |
Other long-term liabilities |  |  | 16 |  |  |  | 169 |  |  |  | 185 |
Total liabilities associated with discontinued operations |  | $ | 235 |  |  | $ | 409 |  |  | $ | 644 |

20. | Commitments and Contingencies

Devon is party to various legal actions arising in connection with its business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to likely involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals. Actual amounts could differ materially from management’s estimates.

Royalty Matters

Numerous oil and natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. Devon is currently named as a defendant in a number of such lawsuits, including some lawsuits in which the plaintiffs seek to certify classes of similarly situated plaintiffs. Among the allegations typically asserted in these suits are claims that Devon used below-market prices, made improper deductions, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in underpayment of royalties in connection with oil, natural gas and NGLs produced and sold. Devon is also involved in governmental agency proceedings and royalty audits and is subject to related contracts and regulatory controls in the ordinary course of business, some that may lead to additional royalty claims. As of December 31, 2020, Devon has accrued approximately $40 million in other current liabilities pertaining to such royalty matters.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Environmental and Other Matters

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

Beginning in 2013, various parishes in Louisiana filed suit against numerous oil and gas companies, including Devon, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused substantial environmental contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The plaintiffs’ claims against Devon relate primarily to the operations of several of Devon’s corporate predecessors. The plaintiffs seek, among other things, payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. Although Devon cannot predict the ultimate outcome of these matters, Devon believes these claims to be baseless and intends to vigorously defend against the proceedings.

Various states, municipalities and other governmental and private parties have filed legal proceedings against numerous oil and gas companies, including Devon, seeking relief to abate alleged impacts of climate change. These proceedings include far-reaching claims for monetary damages and injunctions to address the alleged impacts of climate change. Although Devon cannot predict the ultimate outcome of these matters, Devon believes these claims to be baseless and intends to vigorously defend against the proceedings.

In November 2020, the Department of the Interior, Bureau of Safety and Environmental Enforcement, ordered several oil and gas operators, including Devon, to perform decommissioning and reclamation activities related to two California offshore oil and gas production platforms and related facilities. The current operator and owner of the platforms contends that it does not have the financial ability to perform these obligations and relinquished the related federal lease in October 2020. In response to the apparent insolvency of the current operator, the government has ordered the former operators and alleged former lease record title owners to decommission the platforms. The government contends that an alleged corporate predecessor of Devon owned a partial interest in the subject lease and platforms. Although Devon cannot predict the ultimate outcome of this matter, Devon denies any obligation to decommission the subject platforms, has appealed the order, and believes any decommissioning obligation related to the subject platforms should be assumed by others.

Commitments

The following table presents Devon’s commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2020.

Year Ending December 31, |  | Drilling and Facility Obligations |  |  | Operational Agreements |  |  | Office and Equipment Leases |
2021 |  | $ | 84 |  |  | $ | 241 |  |  | $ | 54 |
2022 |  |  | 38 |  |  |  | 251 |  |  |  | 29 |
2023 |  |  | 36 |  |  |  | 212 |  |  |  | 28 |
2024 |  |  | 26 |  |  |  | 197 |  |  |  | 10 |
2025 |  |  | 7 |  |  |  | 162 |  |  |  | 9 |
Thereafter |  |  | — |  |  |  | 483 |  |  |  | 289 |
Total |  | $ | 191 |  |  | $ | 1,546 |  |  | $ | 419 |

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Devon has certain drilling and facility obligations under contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction. The value of the drilling obligations reported is based on gross contractual value.

Devon has certain operational agreements whereby Devon has committed to transport or process certain volumes of oil, gas and NGLs for a fixed fee. Devon has entered into these agreements to aid the movement of its production to downstream markets.

Devon leases certain office space and equipment under financing and operating lease arrangements.

2 1. | Fair Value Measurements

The following table provides carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. The carrying values of cash, restricted cash, accounts receivable, other current receivables, accounts payable, other current payables, accrued expenses and lease liabilities included in the accompanying consolidated balance sheets approximated fair value at December 31, 2020 and December 31, 2019, as applicable. Therefore, such financial assets and liabilities are not presented in the following table.

|  |  |  |  |  |  |  |  |  | Fair Value Measurements Using: |
|  | Carrying |  |  | Total Fair |  |  | Level 1 |  |  | Level 2 |
|  | Amount |  |  | Value |  |  | Inputs |  |  | Inputs |
December 31, 2020 assets (liabilities): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash equivalents |  | $ | 1,436 |  |  | $ | 1,436 |  |  | $ | 1,436 |  |  | $ | — |
Commodity derivatives |  | $ | 6 |  |  | $ | 6 |  |  | $ | — |  |  | $ | 6 |
Commodity derivatives |  | $ | (148 | ) |  | $ | (148 | ) |  | $ | — |  |  | $ | (148 | )
Debt |  | $ | (4,298 | ) |  | $ | (5,365 | ) |  | $ | — |  |  | $ | (5,365 | )
December 31, 2019 assets (liabilities): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash equivalents |  | $ | 702 |  |  | $ | 702 |  |  | $ | 702 |  |  | $ | — |
Commodity derivatives |  | $ | 50 |  |  | $ | 50 |  |  | $ | — |  |  | $ | 50 |
Commodity derivatives |  | $ | (31 | ) |  | $ | (31 | ) |  | $ | — |  |  | $ | (31 | )
Debt |  | $ | (4,294 | ) |  | $ | (5,376 | ) |  | $ | — |  |  | $ | (5,376 | )

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

Level 1 Fair Value Measurements

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

Level 2 Fair Value Measurements

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

Debt – Devon’s debt instruments do not consistently trade actively in an established market. The fair values of its debt are estimated based on rates available for debt with similar terms and maturity when active trading is not available.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

2 2. | Supplemental Information on Oil and Gas Operations (Unaudited)

Supplemental unaudited information regarding Devon’s oil and gas activities is presented in this note. All of Devon’s reserves are located within the U.S.

The supplemental information in the tables below excludes amounts for all periods presented related to Devon’s discontinued operations, which consist of Devon’s Canadian operations that were sold in 2019 and its Barnett Shale assets, inclusive of properties divested in previous reporting periods located primarily in Johnson and Wise counties, Texas, which were sold in October 2020. Amounts excluded for 2019 and 2018 consisted of 612 MMBoe and 1,104 MMBoe, respectively, of estimated proved reserves and $940 million and $3,042 million, respectively, of discounted future net cash flows, which related to both Devon’s Canadian operations and its Barnett Shale assets. For additional information on these discontinued operations, see Note 19.

Costs Incurred

The following tables reflect the costs incurred in oil and gas property acquisition, exploration and development activities.

|  | Year Ended December 31, |
|  | 2020 |  | 2019 |  |  | 2018 |
Property acquisition costs: |  |  |  |  |  |  |  |  |  |  |
Proved properties |  | $ | — |  | $ | — |  |  | $ | 2 |
Unproved properties |  |  | 8 |  |  | 35 |  |  |  | 70 |
Exploration costs |  |  | 159 |  |  | 312 |  |  |  | 679 |
Development costs |  |  | 820 |  |  | 1,499 |  |  |  | 1,505 |
Costs incurred |  | $ | 987 |  | $ | 1,846 |  |  | $ | 2,256 |

Development costs in the tables above include additions and revisions to Devon’s asset retirement obligations.

Results of Operations

The following tables include revenues and expenses associated with Devon’s oil and gas producing activities. They do not include any allocation of Devon’s interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of Devon’s oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil, gas and NGL sales after deducting costs, including DD&A and after giving effect to permanent differences.

|  | Year Ended December 31,
|  | 2020 |  |  | 2019 |  |  | 2018 |  |
Oil, gas and NGL sales |  | $ | 2,695 |  |  | $ | 3,809 |  |  | $ | 4,085 |  |
Production expenses |  |  | (1,123 | ) |  |  | (1,197 | ) |  |  | (1,153 | ) |
Exploration expenses |  |  | (167 | ) |  |  | (58 | ) |  |  | (128 | ) |
Depreciation, depletion and amortization |  |  | (1,207 | ) |  |  | (1,398 | ) |  |  | (1,134 | ) |
Asset dispositions |  |  | — |  |  |  | 37 |  |  |  | 276 |  |
Asset impairments |  |  | (2,664 | ) |  |  | — |  |  |  | (109 | ) |
Accretion of asset retirement obligations |  |  | (20 | ) |  |  | (21 | ) |  |  | (26 | ) |
Income tax expense |  |  | — |  |  |  | (270 | ) |  |  | (416 | ) |
Results of operations |  | $ | (2,486 | ) |  | $ | 902 |  |  | $ | 1,395 |  |
Depreciation, depletion and amortization per Boe |  | $ | 9.90 |  |  | $ | 11.72 |  |  | $ | 10.51 |  |

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Proved Reserves

The following table presents Devon’s estimated proved reserves by product.

|  | Oil (MMBbls) |  |  | Gas (Bcf) (1) |  |  | NGL (MMBbls) |  |  | Combined (MMBoe) |
Proved developed and undeveloped reserves: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
December 31, 2017 |  |  | 254 |  |  |  | 1,810 |  |  |  | 231 |  |  |  | 787 |
Revisions due to prices |  |  | 12 |  |  |  | 7 |  |  |  | 2 |  |  |  | 15 |
Revisions other than price |  |  | (10 | ) |  |  | (102 | ) |  |  | (27 | ) |  |  | (53 | )
Extensions and discoveries |  |  | 93 |  |  |  | 358 |  |  |  | 54 |  |  |  | 206 |
Production |  |  | (47 | ) |  |  | (206 | ) |  |  | (26 | ) |  |  | (108 | )
Sale of reserves |  |  | (6 | ) |  |  | (65 | ) |  |  | (7 | ) |  |  | (24 | )
December 31, 2018 |  |  | 296 |  |  |  | 1,802 |  |  |  | 227 |  |  |  | 823 |
Revisions due to prices |  |  | (7 | ) |  |  | (86 | ) |  |  | (6 | ) |  |  | (28 | )
Revisions other than price |  |  | (13 | ) |  |  | (50 | ) |  |  | (9 | ) |  |  | (31 | )
Extensions and discoveries |  |  | 76 |  |  |  | 269 |  |  |  | 39 |  |  |  | 160 |
Purchase of reserves |  |  | 3 |  |  |  | 7 |  |  |  | 1 |  |  |  | 6 |
Production |  |  | (55 | ) |  |  | (219 | ) |  |  | (28 | ) |  |  | (119 | )
Sale of reserves |  |  | (24 | ) |  |  | (102 | ) |  |  | (13 | ) |  |  | (54 | )
December 31, 2019 |  |  | 276 |  |  |  | 1,621 |  |  |  | 211 |  |  |  | 757 |
Revisions due to prices |  |  | (26 | ) |  |  | (209 | ) |  |  | (17 | ) |  |  | (78 | )
Revisions other than price |  |  | 18 |  |  |  | 119 |  |  |  | 17 |  |  |  | 55 |
Extensions and discoveries |  |  | 71 |  |  |  | 188 |  |  |  | 33 |  |  |  | 135 |
Purchase of reserves |  |  | 1 |  |  |  | 19 |  |  |  | 3 |  |  |  | 7 |
Production |  |  | (57 | ) |  |  | (221 | ) |  |  | (28 | ) |  |  | (122 | )
Sale of reserves |  |  | (1 | ) |  |  | (5 | ) |  |  | (1 | ) |  |  | (2 | )
December 31, 2020 |  |  | 282 |  |  |  | 1,512 |  |  |  | 218 |  |  |  | 752 |
Proved developed reserves: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
December 31, 2017 |  |  | 175 |  |  |  | 1,455 |  |  |  | 168 |  |  |  | 585 |
December 31, 2018 |  |  | 196 |  |  |  | 1,427 |  |  |  | 166 |  |  |  | 600 |
December 31, 2019 |  |  | 198 |  |  |  | 1,344 |  |  |  | 167 |  |  |  | 589 |
December 31, 2020 |  |  | 194 |  |  |  | 1,244 |  |  |  | 173 |  |  |  | 574 |
Proved developed-producing reserves: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
December 31, 2017 |  |  | 163 |  |  |  | 1,384 |  |  |  | 160 |  |  |  | 554 |
December 31, 2018 |  |  | 188 |  |  |  | 1,394 |  |  |  | 162 |  |  |  | 582 |
December 31, 2019 |  |  | 191 |  |  |  | 1,327 |  |  |  | 165 |  |  |  | 578 |
December 31, 2020 |  |  | 190 |  |  |  | 1,223 |  |  |  | 171 |  |  |  | 564 |
Proved undeveloped reserves: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
December 31, 2017 |  |  | 79 |  |  |  | 355 |  |  |  | 63 |  |  |  | 202 |
December 31, 2018 |  |  | 100 |  |  |  | 375 |  |  |  | 61 |  |  |  | 223 |
December 31, 2019 |  |  | 78 |  |  |  | 277 |  |  |  | 44 |  |  |  | 168 |
December 31, 2020 |  |  | 88 |  |  |  | 268 |  |  |  | 45 |  |  |  | 178 |

(1) | Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. NGL reserves are converted to Boe on a one-to-one basis with oil. The conversion rates are not necessarily indicative of the relationship of oil, natural gas and NGL prices.

Price Revisions

Reserves decreased 78 MMBoe in 2020 primarily due to price decreases in the trailing 12 month averages for oil, gas and NGLs.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Reserves decreased 28 MMBoe in 2019 primarily due to price decreases in the trailing 12 month averages for oil, gas and NGLs. Reserves increased 15 MMBoe in 2018 primarily due to price increases in the trailing 12 month averages for oil, gas and NGLs.

Revisions Other Than Price

2020 – Total revisions other than price (55 MMBoe) were primarily due to well performance exceeding previous estimates (75 MMBoe) and the removal of proved undeveloped locations as noted below (-20 MMBoe). The most significant well performance revisions were attributable to the Delaware Basin (40 MMBoe) and the STACK region of the Anadarko Basin (22 MMBoe).

2019 – Total revisions other than price in 2019 were primarily due to changes in previously adopted development plans in the STACK region of the Anadarko Basin (-9 MMBoe) and in the Delaware Basin (-6 MMBoe). An additional downward revision of 5 MMBoe was the result of reduced recovery estimates attributable to continued evaluation of analogous offset well performance primarily in the STACK region of the Anadarko Basin.

2018 – Total revisions other than price primarily related to Devon’s development programs evaluation of certain oil and dry gas regions, with the largest revisions being made in the STACK region of the Anadarko Basin.

Extensions and Discoveries

Each year, Devon’s proved reserves extensions and discoveries consist of adding proved undeveloped reserves to locations classified as undeveloped at year-end and adding proved developed reserves from successful development wells drilled on locations outside the areas classified as proved at the previous year-end. Therefore, it is not uncommon for Devon’s total proved extensions and discoveries to differ from the extensions and discoveries for Devon’s proved undeveloped reserves. Furthermore, because annual additions are classified according to reserve determinations made at the previous year-end and because Devon operates a multi-basin portfolio with assets at varying stages of maturity, extensions and discoveries for proved developed and proved undeveloped reserves can differ significantly in any particular year.

2020 – Of the 135 MMBoe of additions from extensions and discoveries, 117 MMBoe were in the Delaware Basin, 8 MMBoe were in the STACK region of the Anadarko Basin, 5 MMBoe in the Powder River Basin and 5 MMBoe in Eagle Ford.

2019 – Of the 160 MMBoe of additions from extensions and discoveries, 77 MMBoe were in the Delaware Basin, 37 MMBoe were in the STACK region of the Anadarko Basin, 28 MMBoe in the Powder River Basin and 18 MMBoe in Eagle Ford. In 2019, there were no additions related to infill drilling activities.

2018 – Approximately 85% of the additions were through focused efforts in the STACK region of the Anadarko Basin (87 MMBoe) and the Delaware Basin (88 MMBoe). The remaining extensions were added throughout the remainder of Devon’s portfolio.

The 2018 extensions and discoveries included 21 MMBoe related to additions from Devon’s infill drilling activities, primarily relating to the STACK region of the Anadarko Basin.

Sale of Reserves

During 2020, 2019 and 2018, Devon had U.S. non-core asset divestitures. For additional information on these divestitures, see Note 2.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Proved Undeveloped Reserves

The following table presents the changes in Devon’s total proved undeveloped reserves during 2020 (MMBoe).

|  | Total |
Proved undeveloped reserves as of December 31, 2019 |  |  | 168 |
Extensions and discoveries |  |  | 105 |
Revisions due to prices |  |  | (8 | )
Revisions other than price |  |  | (20 | )
Purchase of reserves |  |  | 2 |
Sale of reserves |  |  | (1 | )
Conversion to proved developed reserves |  |  | (68 | )
Proved undeveloped reserves as of December 31, 2020 |  |  | 178 |

Total proved undeveloped reserves increased 6% from 2019 to 2020 with the year-end 2020 balance representing 24% of total proved reserves. Over 87% of the 105 MMBoe in extensions and discoveries were the result of Devon’s focus on drilling and development activities in the Delaware Basin. This continued development in the Delaware Basin also led to the conversion of 68 MMBoe, or 40% of the 2019 proved undeveloped reserves. Costs incurred to develop and convert Devon’s proved undeveloped reserves were approximately $448 million for 2020. Proved undeveloped reserves revisions other than price were primarily due to changes in previously adopted development plans in the STACK region of the Anadarko Basin (-12 MMBoe) and the Delaware Basin (-8 MMBoe).

Standardized Measure

The following tables reflect Devon’s standardized measure of discounted future net cash flows from its proved reserves.

|  | Year Ended December 31, |
|  | 2020 |  | 2019 |  |  | 2018 |
Future cash inflows |  | $ | 14,957 |  | $ | 20,750 |  |  | $ | 27,759 |
Future costs: |  |  |  |  |  |  |  |  |  |  |
Development |  |  | (1,747 | ) |  | (2,093 | ) |  |  | (2,957 | )
Production |  |  | (7,964 | ) |  | (9,174 | ) |  |  | (10,991 | )
Future income tax expense |  |  | — |  |  | (1,037 | ) |  |  | (2,036 | )
Future net cash flow |  |  | 5,246 |  |  | 8,446 |  |  |  | 11,775 |
10% discount to reflect timing of cash flows |  |  | (1,774 | ) |  | (3,048 | ) |  |  | (4,625 | )
Standardized measure of discounted future net cash flows |  | $ | 3,472 |  | $ | 5,398 |  |  | $ | 7,150 |

Future cash inflows, development costs and production costs were computed using the same assumptions for prices and costs that were used to estimate Devon’s proved oil and gas reserves at the end of each year. For 2020 estimates, Devon’s future realized prices were assumed to be $37.35 per Bbl of oil, $1.37 per Mcf of gas and $10.76 per Bbl of NGLs. Of the $1.7 billion of future development costs as of the end of 2020, $0.6 billion, $0.4 billion and $0.2 billion are estimated to be spent in 2021, 2022 and 2023, respectively.

Future development costs include not only development costs but also future asset retirement costs. Included as part of the $1.7 billion of future development costs are $0.3 billion of future asset retirement costs. The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The principal changes in Devon’s standardized measure of discounted future net cash flows are as follows:

|  | Year Ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
Beginning balance |  | $ | 5,398 |  |  | $ | 7,150 |  |  | $ | 5,954 |
Net changes in prices and production costs |  |  | (3,277 | ) |  |  | (2,323 | ) |  |  | 1,533 |
Oil, gas and NGL sales, net of production costs |  |  | (1,572 | ) |  |  | (2,612 | ) |  |  | (2,932 | )
Changes in estimated future development costs |  |  | 402 |  |  |  | 303 |  |  |  | (273 | )
Extensions and discoveries, net of future development costs |  |  | 988 |  |  |  | 1,690 |  |  |  | 2,944 |
Purchase of reserves |  |  | 23 |  |  |  | 43 |  |  |  | — |
Sales of reserves in place |  |  | (7 | ) |  |  | (481 | ) |  |  | (120 | )
Revisions of quantity estimates |  |  | 147 |  |  |  | (359 | ) |  |  | (152 | )
Previously estimated development costs incurred during the period |  |  | 537 |  |  |  | 857 |  |  |  | 787 |
Accretion of discount |  |  | 285 |  |  |  | 506 |  |  |  | 648 |
Net change in income taxes and other |  |  | 548 |  |  |  | 624 |  |  |  | (1,239 | )
Ending balance |  | $ | 3,472 |  |  | $ | 5,398 |  |  | $ | 7,150 |

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

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

Based on their evaluation, our principal executive and principal financial officers have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of December 31, 2020 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting for Devon, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of Devon’s management, including our principal executive and principal financial officers, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission (the “2013 COSO Framework”). Based on this evaluation under the 2013 COSO Framework, which was completed on February 17, 2021, management concluded that its internal control over financial reporting was effective as of December 31, 2020.

The effectiveness of our internal control over financial reporting as of December 31, 2020 has been audited by KPMG LLP, an independent registered public accounting firm who audited our consolidated financial statements as of and for the year ended December 31, 2020, as stated in their report, which is included under “Item 8. Financial Statements and Supplementary Data” of this report.

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the fourth quarter of 2020 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

On December 30, 2020, Devon held a special meeting of stockholders (the “Meeting”) to consider and approve the issuance of shares of Devon common stock in the Merger (the “Stock Issuance”). More than 70% of the outstanding shares of Devon common stock were present at the Meeting, and over 99% of the votes cast were in favor of approval of the Stock Issuance. During the weeks following the closing of the Merger, Devon learned that several stockholders had received their proxy materials for the Meeting after the date of the Meeting. Upon investigation, Devon learned that, while the electronic distribution of proxy materials to stockholders had been timely completed, certain stockholders who were to receive proxy materials by mail had not timely received those materials. The company retained by Devon to process and distribute proxy materials for the Meeting has indicated that, contrary to prior communication on the subject, certain of the proxy materials were not timely delivered to the U.S. Postal Service, resulting in late delivery of such proxy materials to the holders of less than 15% of the outstanding shares of Devon common stock, including record holders of approximately 0.55% of the outstanding

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shares. In light of Devon’s good faith belief that the proxy materials had been mailed, the overwhelming vote by the Devon stockholders in favor of approval of the Stock Issuance proposal at the Meeting, which approval c ould not have been altered by the votes of the affected stockholders, and the closing of the Merger and other significant actions taken in reliance upon the approval of the Stock Issuance at the Meeting, Devon is fil ing an application with the Delaware Chancery Court under Section 205 of the Delaware General Corporation Law seeking an order confirming the validity of the Meeting and the notice of meeting issued in connection therewith.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information called for by this Item 10 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and applicable information in Regulations under the Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2020.

Item 11. Executive Compensation

The information called for by this Item 11 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and applicable information in Regulations under the Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2020.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information called for by this Item 12 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and applicable information in Regulations under the Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2020.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information called for by this Item 13 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and applicable information in Regulations under the Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2020.

Item 14. Principal Accountant Fees and Services

The information called for by this Item 14 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and applicable information in Regulations under the Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2020.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) The following documents are included as part of this report:

1. Consolidated Financial Statements

Reference is made to the Index to Consolidated Financial Statements and Consolidated Financial Statement Schedules appearing at “Item 8. Financial Statements and Supplementary Data” in this report.

2. Consolidated Financial Statement Schedules

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.

3. Exhibits

Exhibit No. |  | Description
2.1 |  | Purchase Agreement, dated June 5, 2018, by and among Devon Gas Services, L.P. and Southwestern Gas Pipeline, L.L.C., as sellers, and Enlink Midstream Manager, LLC, Registrant, and GIP III Stetson I, L.P. and GIP III Stetson II, L.P., as acquirors (incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed June 7, 2018; File No. 001-32318).
2.2 |  | Agreement of Purchase and Sale, dated as of May 28, 2019, among Devon Canada Corporation, Devon Canada Crude Marketing Corporation and Canadian Natural Resources Limited (incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed May 31, 2019; File No. 001-32318).
2.3 |  | Purchase and Sale Agreement, dated December 17, 2019, by and between Devon Energy Production Company, L.P. and BKV Barnett, LLC (incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed December 18, 2019; File No. 001-32318).*
2.4 |  | First Amendment to Purchase and Sale Agreement, dated April 13, 2020, by and between Devon Energy Production Company, L.P., BKV Barnett, LLC, and solely with respect to certain provisions therein, BKV Oil & Gas Capital Partners, L.P. (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed April 14, 2020; File No. 001-32318).
2.5 |  | Agreement and Plan of Merger, dated September 26, 2020, by and among Registrant, East Merger Sub, Inc., and WPX Energy, Inc. (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K, filed September 28, 2020; File No. 001-32318).
3.1 |  | Registrant’s Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of Registrant’s Form 10-K filed February 21, 2013; File No. 001-32318).
3.2 |  | Registrant’s Bylaws (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K filed January 27, 2016; File No. 001-32318).
4.1 |  | Indenture, dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed July 12, 2011; File No. 001-32318).
4.2 |  | Supplemental Indenture No. 1, dated as of July 12, 2011, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 5.60% Senior Notes due 2041 (incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed July 12, 2011; File No. 001-32318).

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Exhibit No. |  | Description
4.3 |  | Supplemental Indenture No. 2, dated as of May 14, 2012, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 4.750% Senior Notes due 2042 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed May 14, 2012; File No. 001-32318).
4.4 |  | Supplemental Indenture No. 4, dated as of June 16, 2015, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 5.000% Senior Notes due 2045 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed June 16, 2015; File No. 001-32318).
4.5 |  | Supplemental Indenture No. 5, dated as of December 15, 2015, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 5.850% Senior Notes due 2025 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed December 15, 2015; File No. 001-32318).
4.6 |  | Indenture, dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York), as Trustee (incorporated by reference to Exhibit 4.1 of Registrant’s Form 8-K filed April 9, 2002; File No. 000-30176).
4.7 |  | Supplemental Indenture No. 1, dated as of March 25, 2002, to Indenture dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.95% Senior Debentures due 2032 (incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed April 9, 2002; File No. 000-30176).
4.8 |  | Supplemental Indenture No. 4, dated as of March 22, 2018, to Indenture dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.95% Senior Notes due 2032 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed March 22, 2018; File No. 000-32318).
4.9 |  | Indenture, dated as of October 3, 2001, among Devon Financing Company, L.L.C. (f/k/a Devon Financing Corporation, U.L.C.), as Issuer, Registrant, as Guarantor, and The Bank of New York Mellon Trust Company, N.A., originally The Chase Manhattan Bank, as Trustee, relating to the 7.875% Debentures due 2031 (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-4 filed October 31, 2001; File No. 333-68694).
4.10 |  | Assignment and Assumption Agreement, dated as of June 19, 2019, by and between Devon Financing Company, L.L.C. and Registrant, relating to that certain Indenture, dated as of October 3, 2001, by and among Devon Financing Company, L.L.C. (f/k/a Devon Financing Company, U.L.C.), as Issuer, Devon Energy Corporation, as Guarantor, and The Bank of New York Mellon Trust Company, N.A., as successor to The Chase Manhattan Bank, as Trustee, and the 7.875% Debentures due 2031 issued thereunder (incorporated by reference to Exhibit 4.1 to Registrant’s Form 10-Q filed August 7, 2019; File No. 001-32318).
4.11 |  | Senior Indenture, dated as of September 1, 1997, between Devon OEI Operating, L.L.C. (as successor to Seagull Energy Corporation) and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York), as Trustee, and related Specimen of 7.50% Senior Notes due 2027 (incorporated by reference to Exhibit 4.4 to Ocean Energy Inc.’s Form 10-K filed March 23, 1998; File No. 001-08094).
4.12 |  | First Supplemental Indenture, dated as of March 30, 1999, to Senior Indenture dated as of September 1, 1997, by and among Devon OEI Operating, L.L.C., its Subsidiary Guarantor, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes due 2027 (incorporated by reference to Exhibit 4.10 to Ocean Energy, Inc.’s Form 10-Q filed May 17, 1999; File No. 001-08094).

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Exhibit No. |  | Description
4.13 |  | Second Supplemental Indenture, dated as of May 9, 2001, to Senior Indenture dated as of September 1, 1997, by and among Devon OEI Operating, L.L.C., its Subsidiary Guarantor, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes due 2027 (incorporated by reference to Exhibit 99.4 to Ocean Energy, Inc.’s Form 8-K filed May 14, 2001; File No. 033-06444).
4.14 |  | Third Supplemental Indenture, dated as of December 31, 2005, to Senior Indenture dated as of September 1, 1997, by and among Devon OEI Operating, L.L.C., as Issuer, Devon Energy Production Company, L.P., as Successor Guarantor, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes due 2027 (incorporated by reference to Exhibit 4.27 of Registrant’s Form 10-K filed March 3, 2006; File No. 001-32318).
4.15 |  | Stockholders’ Agreement, by and among Devon Energy Corporation, Felix Investment Holdings II, LLC, and EnCap Energy Capital Fund X, L.P., dated January 7, 2021. (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 7, 2021; File No. 001-32318).
4.16 |  | Registration Rights Agreement, by and between Devon Energy Corporation and Felix Investment Holdings II, LLC, dated January 7, 2021 (incorporated by reference to Exhibit 10.2 to Registrant’s Form 8-K filed January 7, 2021; File No. 001-32318).
4.17 |  | Indenture, dated as of September 8, 2014, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Form 8-K filed September 8, 2014; File No. 001-35322).
4.18 |  | First Supplemental Indenture, dated as of September 8, 2014, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 5.25% Senior Notes due 2024 (incorporated herein by reference to Exhibit 4.2 to WPX Energy, Inc.’s Form 8-K filed September 8, 2014; File No. 001-35322).
4.19 |  | Second Supplemental Indenture, dated as of July 22, 2015, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 8.25% Senior Notes due 2023 (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Form 8-K filed July 22, 2015; File No. 001-35322).
4.20 |  | Third Supplemental Indenture, dated as of May 23, 2018, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A. as trustee, relating to the 5.750% Senior Notes due 2026 (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Form 8-K filed May 23, 2018; File No. 001-35322).
4.21 |  | Fourth Supplemental Indenture, dated as of September 24, 2019, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A. as trustee, relating to the 5.250% Senior Notes due 2027 (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.'s Form 8-K filed with the SEC on September 24, 2019; File No. 001-35322).
4.22 |  | Fifth Supplemental Indenture, dated as of January 10, 2020, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A. as trustee, relating to the 4.500% Senior Notes due 2030 (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Form 8-K filed June 17, 2020; File No. 001-35322).
4.23 |  | Sixth Supplemental Indenture, dated as of June 17, 2020, between WPX Energy, Inc. and the Bank of New York Mellon Trust Company, N.A. as trustee, related to the 5.875% Senior Notes due 2028 (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Form 8-K filed January 10, 2020; File No. 001-35322).
4.24 |  | Description of Securities Registered under Section 12 of the Securities Exchange Act of 1934.

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Exhibit No. |  | Description
10.1 |  | Credit Agreement, dated as of October 5, 2018, among Registrant, as U.S. Borrower, Devon Canada Corporation, as Canadian Borrower, Bank of America, N.A., as Administrative Agent, Swing Line Lender and an L/C Issuer, and each Lender and L/C Issuer from time to time party thereto (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K filed October 9, 2018; File No. 001-32318).
10.2 |  | First Amendment to Credit Agreement and Extension Agreement, dated as of December 13, 2019, by and among Registrant, as U.S. Borrower, Devon Canada Corporation, as Canadian Borrower, Bank of America, N.A., individually and as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-K filed February 19, 2020; File No. 001-32318).
10.3 |  | Devon Energy Corporation 2009 Long-Term Incentive Plan (as amended and restated effective June 6, 2012) (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed June 8, 2012; File No. 001-32318).**
10.4 |  | 2013 Amendment (effective as of March 6, 2013) to the Devon Energy Corporation 2009 Long-Term Incentive Plan (as amended and restated effective June 6, 2012) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 1, 2013; File No. 001-32318).**
10.5 |  | Devon Energy Corporation 2015 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to Registrant’s Form S-8 filed June 3, 2015; File No. 333-204666).**
10.6 |  | Devon Energy Corporation 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to Registrant’s Form S-8 filed June 7, 2017; File No. 333-218561).**
10.7 |  | 2021 Amendment (effective as of January 7, 2021) to the Devon Energy Corporation 2017 Long-Term Incentive Plan.**
10.8 |  | WPX Energy, Inc. 2013 Incentive Plan, and amendments No. 1 and No. 2 thereto (incorporated by reference to Exhibit 10.1 to WPX Energy, Inc.’s Form 8-K filed with the SEC on February 19, 2018; File No. 001-35322).**
10.9 |  | Amendment No. 3 to the WPX Energy, Inc. 2013 Incentive Plan (incorporated by reference to Appendix A to WPX Energy, Inc.’s definitive proxy statement on Schedule 14A filed March 29, 2018; File No. 001-35322).**
10.10 |  | Devon Energy Corporation Annual Incentive Compensation Plan (amended and restated effective as of January 1, 2017) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed June 12, 2017; File No. 001-32318).**
10.11 |  | Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated effective as of April 15, 2014) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed August 6, 2014; File No. 001-32318).**
10.12 |  | Amendment 2014-2, executed May 9, 2014, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (incorporated by reference to Exhibit 10.11 to Registrant’s Form 10-K filed February 20, 2015; File No. 001-32318).**
10.13 |  | Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (incorporated by reference to Exhibit 10.13 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).**
10.14 |  | Amendment 2018-1, executed August 21, 2018, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (incorporated by reference to Exhibit 10.10 to Registrant’s Form 10-K filed February 20, 2019; File No. 001-32318).**
10.15 |  | Amendment 2020-1, executed December 23, 2020, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan.**

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Exhibit No. |  | Description
10.16 |  | Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.15 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318).**
10.17 |  | Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Benefit Restoration Plan (incorporated by reference to Exhibit 10.6 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318).**
10.18 |  | Amendment 2015-1, executed April 15, 2015, to the Devon Energy Corporation Benefit Restoration Plan (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 6, 2015; File No. 001-32318).**
10.19 |  | Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.17 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).**
10.20 |  | Amendment 2020-1, executed December 23, 2020, to the Devon Energy Corporation Benefit Restoration Plan.**
10.21 |  | Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318).**
10.22 |  | Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Defined Contribution Restoration Plan (incorporated by reference to Exhibit 10.7 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318).**
10.23 |  | Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Defined Contribution Restoration Plan (incorporated by reference to Exhibit 10.20 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).**
10.24 |  | Amendment 2018-1, executed August 21, 2018, to the Devon Energy Corporation Defined Contribution Restoration Plan (incorporated by reference to Exhibit 10.18 to Registrant’s Form 10-K filed February 20, 2019; File No. 001-32318).**
10.25 |  | Amendment 2019-1, executed June 19, 2019, to the Devon Energy Corporation Defined Contribution Restoration Plan (as amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed August 7, 2019; File No. 001-32318).**
10.26 |  | Amendment 2020-1, executed December 23, 2020, to the Devon Energy Corporation Defined Contribution Restoration Plan.**
10.27 |  | Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.17 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318).**
10.28 |  | Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental Contribution Plan (incorporated by reference to Exhibit 10.8 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318).**
10.29 |  | Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental Contribution Plan (incorporated by reference to Exhibit 10.23 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).**
10.30 |  | Amendment 2019-1, executed June 19, 2019, to the Devon Energy Corporation Supplemental Contribution Plan (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed August 7, 2019; File No. 001-32318).**

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Exhibit No. |  | Description
10.31 |  | Amendment 2020-1, executed December 23, 2020, to the Devon Energy Corporation Supplemental Contribution Plan.**
10.32 |  | Devon Energy Corporation Supplemental Executive Retirement Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.18 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318).**
10.33 |  | Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental Executive Retirement Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.25 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).**
10.34 |  | Amendment 2019-1, executed June 19, 2019, to the Devon Energy Corporation Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.3 to Registrant’s Form 10-Q filed August 7, 2019; File No. 001-32318).**
10.35 |  | Amendment 2020-1, executed December 23, 2020, to the Devon Energy Corporation Supplemental Executive Retirement Plan.**
10.36 |  | Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318).**
10.37 |  | Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental Retirement Income Plan (incorporated by reference to Exhibit 10.9 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318).**
10.38 |  | Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental Retirement Income Plan (incorporated by reference to Exhibit 10.28 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).**
10.39 |  | Amendment 2019-1, effective September 10, 2019, to the Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed November 6, 2019; File No. 001-32318).**
10.40 |  | Amendment 2020-1, executed December 23, 2020, to the Devon Energy Corporation Supplemental Retirement Income Plan.**
10.41 |  | Devon Energy Corporation Incentive Savings Plan (amended and restated effective January 1, 2018) (incorporated by reference to Exhibit 10.28 to Registrant’s Form 10-K filed February 21, 2018; File No. 001-32318).**
10.42 |  | Amendment 2018-1, executed December 14, 2018, to the Devon Energy Corporation Incentive Savings Plan (incorporated by reference to Exhibit 10.28 to Registrant’s Form 10-K filed February 20, 2019; File No. 001-32318).**
10.43 |  | Amendment 2019-1, executed June 19, 2019, to the Devon Energy Corporation Incentive Savings Plan (incorporated by reference to Exhibit 10.4 to Registrant’s Form 10-Q filed August 7, 2019; File No. 001-32318).**
10.44 |  | Amended and Restated Form of Employment Agreement between Registrant and certain executive officers (incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 27, 2009; File No. 001-32318).**
10.45 |  | Form of Amendment No. 1 to the Amended and Restated Employment Agreement between Registrant and certain executive officers (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed April 25, 2011; File No. 001-32318).**
10.46 |  | Form of Employment Agreement between Registrant and certain executive officers (incorporated by reference to Exhibit 10.22 to Registrant’s Form 10-K filed February 28, 2014; File No. 001-32318).**

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Exhibit No. |  | Description
10.47 |  | Employment Agreement, dated effective April 19, 2017, by and between Registrant and Mr. Jeffrey L. Ritenour (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K, filed on April 20, 2017; File No. 001-32318).**
10.48 |  | Employment Agreement, dated effective September 13, 2019, by and between Registrant and Mr. David G. Harris (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed September 16, 2019; File No. 001-32318).**
10.49 |  | Employment Agreement, dated January 7, 2021, by and between Registrant and Richard E. Muncrief (incorporated by reference to Exhibit 10.3 to Registrant’s Form 8-K filed January 7, 2021; File No. 001-32318).**
10.50 |  | Employment Agreement, dated January 7, 2021, by and between Registrant and Clay M. Gaspar (incorporated by reference to Exhibit 10.4 to Registrant’s Form 8-K filed January 7, 2021; File No. 001-32318).**
10.51 |  | Employment Agreement, dated January 7, 2021, by and between Registrant and Dennis C. Cameron (incorporated by reference to Exhibit 10.5 to Registrant’s Form 8-K filed January 7, 2021; File No. 001-32318).**
10.52 |  | Employment Letter Agreement, dated as of September 26, 2020, by and between Registrant and David A. Hager (incorporated by reference to Exhibit 10.2 to Registrant’s Form 8-K filed September 28, 2020; File No. 001-32318).**
10.53 |  | Employment Letter Agreement, dated as of September 26, 2020, by and between Registrant and Richard E. Muncrief (incorporated by reference to Exhibit 10.3 to Registrant’s Form 8-K filed September 28, 2020; File No. 001-32318).**
10.54 |  | Employment Letter Agreement, dated as of September 26, 2020, by and between Registrant and Clay M. Gaspar (incorporated by reference to Exhibit 10.4 to Registrant’s Form 8-K filed September 28, 2020; File No. 001-32318).**
10.55 |  | Employment Letter Agreement, dated as of September 26, 2020, by and between Registrant and Dennis C. Cameron (incorporated by reference to Exhibit 10.45 to Registrant’s Form 8-K filed September 28, 2020; File No. 001-32318).**
10.56 |  | Severance Agreement, dated March 2, 2010, between Registrant and Tana K. Cashion.**
10.57 |  | WPX Energy Nonqualified Deferred Compensation Plan, effective January 1, 2013 (incorporated herein by reference to Exhibit 10.16 to WPX Energy, Inc.’s Form 10-K filed February 28, 2013; File No. 001-35322).**
10.58 |  | WPX Energy Board of Directors Nonqualified Deferred Compensation Plan, effective January 1, 2013 (incorporated herein by reference to Exhibit 10.17 to WPX Energy, Inc.’s Form 10-K filed February 28, 2013; File No. 001-35322).**
10.59 |  | Employment Agreement, dated April 29, 2014, between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Form 8-K filed May 2, 2014; File No. 001-35322).**
10.60 |  | Form of Amended and Restated Change in Control Agreement between WPX Energy, Inc. and Tier One Executives (incorporated herein by reference to Exhibit 10.32 to WPX Energy, Inc.’s Form 10-Q filed August 2, 2018; File No. 001-35322).**
10.61 |  | Amended and Restated WPX Energy Executive Severance Pay Plan (incorporated herein by reference to Exhibit 10.33 to WPX Energy, Inc.’s Form 10-Q filed August 2, 2018; File No. 001-35322).**
10.62 |  | Form of Indemnity Agreement between Registrant and non-management directors (incorporated by reference to Exhibit 10.40 to Registrant’s Form 10-K filed February 19, 2020; File No. 001-32318).**

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Exhibit No. |  | Description
10.63 |  | 2017 Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2015 Long-Term Incentive Plan between Registrant and executive officers for performance based restricted stock awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 3, 2017; File No. 001-32318).**
10.64 |  | 2018 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2017 Long-Term Incentive Plan between Registrant and executive officers for restricted stock awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed on May 2, 2018; File No. 001-32318).**
10.65 |  | 2019 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2017 Long-Term Incentive Plan between Registrant and executive officers for restricted stock awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 1, 2019; File No. 001-32318).**
10.66 |  | 2020 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2017 Long-Term Incentive Plan between Registrant and certain officers for restricted stock awarded (CEO and EVP form) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 6, 2020; File No. 001-32318).**
10.67 |  | 2020 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2017 Long-Term Incentive Plan between Registrant and certain officers for restricted stock awarded (SVP form) (incorporated by reference to Exhibit 10.3 to Registrant’s Form 10-Q filed May 6, 2020; File No. 001-32318).**
10.68 |  | 2018 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2017 Long-Term Incentive Plan between Registrant and executive officers for performance based restricted share units awarded (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed May 2, 2018; File No. 001-32318).**
10.69 |  | 2019 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2017 Long-Term Incentive Plan between Registrant and executive officers for performance based restricted share units awarded (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed May 1, 2019; File No. 001-32318).**
10.70 |  | 2020 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2017 Long-Term Incentive Plan between Registrant and certain officers for performance based restricted share units awarded (CEO and EVP form) (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed May 6, 2020; File No. 001-32318).**
10.71 |  | 2020 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2017 Long-Term Incentive Plan between Registrant and certain officers for performance based restricted share units awarded (SVP form) (incorporated by reference to Exhibit 10.4 to Registrant’s Form 10-Q filed May 6, 2020; File No. 001-32318).**
10.72 |  | 2020 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2017 Long-Term Incentive Plan between Registrant and all non-management directors for restricted stock awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed August 5, 2020; File No. 001-32318).**
10.73 |  | Form of Restricted Stock Award Agreement between WPX Energy, Inc. and Non-Employee Directors (incorporated herein by reference to Exhibit 10.13 to WPX Energy, Inc.’s Form 10-K filed February 28, 2012; File No. 001-35322).**
10.74 |  | Form of Nonqualified Stock Option Agreement between WPX Energy, Inc. and certain executive officers (incorporated herein by reference to Exhibit 10.15 to WPX Energy, Inc.’s Form 10-Q filed May 7, 2014; File No. 001-35322).**

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Exhibit No. |  | Description
10.75 |  | Form of Nonqualified Stock Option Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Form 8-K filed May 2, 2014; File No. 001-35322).**
10.76 |  | Form of Restricted Stock Unit Award between WPX Energy, Inc. and Non-Employee Directors (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Form 8-K filed September 3, 2014; File No. 001-35322).**
10.77 |  | Form of Amended and Restated Time-Based Restricted Stock Agreement between WPX Energy, Inc. and certain executive officers (incorporated by reference to Exhibit 10.2 to WPX Energy, Inc.’s Form 8-K filed February 19, 2018; File No. 001-35322).**
10.78 |  | Form of Amended and Restated Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and certain executive officers (incorporated by reference to Exhibit 10.3 to WPX Energy, Inc.’s Form 8-K filed February 19, 2018; File No. 001-35322).**
10.79 |  | Form of Omnibus Amendment to Performance-Based Restricted Stock Unit Agreements between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.40 to WPX Energy, Inc.’s Form 10-Q filed August 2, 2018; File No. 001-35322).**
10.80 |  | Form of Amended and Restated Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and certain executive officers (incorporated by reference to Exhibit 10.35 to WPX Energy, Inc.’s Form 10-K filed February 21, 2019; File No. 001-35322).**
10.81 |  | Form of Amended and Restated Restricted Stock Unit Award Agreement between WPX Energy, Inc. and Non-Employee Directors (incorporated herein by reference to Exhibit 10.38 to WPX Energy, Inc.’s Form 10-Q filed August 6, 2019; File No. 001-35322).**
10.82 |  | Form of Amended Exhibit B to Amended and Restated Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and certain executive officers (incorporated herein by reference to Exhibit 10.39 to WPX Energy, Inc.’s Form 10-Q filed August 2, 2019; File No. 001-35322).**
10.83 |  | Form of Global Amendment to Performance-Based Restricted Stock Unit Agreements between WPX Energy, Inc. and certain executive officers (incorporated by reference to Exhibit 10.1 to WPX Energy, Inc.’s Form 8-K filed January 7, 2021; File No. 001-35322).**
10.84 |  | Tax Sharing Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.3 to WPX Energy, Inc.’s Form 8-K filed January 6, 2012; File No. 001-35322).
21 |  | List of Subsidiaries.
23.1 |  | Consent of KPMG LLP.
23.2 |  | Consent of LaRoche Petroleum Consultants, Ltd.
31.1 |  | Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 |  | Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 |  | Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 |  | Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99 |  | Report of LaRoche Petroleum Consultants, Ltd.
101.INS |  | Inline XBRL Instance Document – the XBRL Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH |  | Inline XBRL Taxonomy Extension Schema Document.
101.CAL |  | Inline XBRL Taxonomy Extension Calculation Linkbase Document.

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Exhibit No. |  | Description
101.DEF |  | Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB |  | Inline XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE |  | Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104 |  | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

* | Portions of this exhibit have been omitted in accordance with Item 601(b)(2)(ii) of Regulation S-K.

**Indicates management contract or compensatory plan or arrangement.

Item 16. Form 10-K Summary

Not applicable.

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SIG NATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

|  | DEVON ENERGY CORPORATION
| By: | /s/ JEFFREY L. RITENOUR
|  | Jeffrey L. Ritenour
|  | Executive Vice President and Chief Financial Officer

February 17, 2021

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

/s/ RICHARD E. MUNCRIEF |  | President, Chief Executive Officer and | February 17, 2021
Richard E. Muncrief |  | Director (Principal executive officer) |
/s/ JEFFREY L. RITENOUR |  | Executive Vice President | February 17, 2021
Jeffrey L. Ritenour |  | and Chief Financial Officer (Principal financial officer) |
/s/ JEREMY D. HUMPHERS |  | Senior Vice President | February 17, 2021
Jeremy D. Humphers |  | and Chief Accounting Officer (Principal accounting officer) |
/s/ DAVID A. HAGER |  | Executive Chairman of the Board | February 17, 2021
David A. Hager |  |  |
/s/ BARBARA M. BAUMANN |  | Director | February 17, 2021
Barbara M. Baumann |  |  |
/s/ JOHN E. BETHANCOURT |  | Director | February 17, 2021
John E. Bethancourt |  |  |
/s/ ANN G. FOX |  | Director | February 17, 2021
Ann G. Fox |  |  |
/s/ KELT KINDICK |  | Director | February 17, 2021
Kelt Kindick |  |  |
/s/ JOHN KRENICKI JR. |  | Director | February 17, 2021
John Krenicki Jr. |  |  |
/s/ KARL F. KURZ |  | Director | February 17, 2021
Karl F. Kurz |  |  |
/s/ ROBERT A. MOSBACHER, JR. |  | Director | February 17, 2021
Robert A. Mosbacher, Jr. |  |  |
/s/ D. MARTIN PHILLIPS |  | Director | February 17, 2021
D. Martin Phillips |  |  |
/s/ DUANE C. RADTKE |  | Director | February 17, 2021
Duane C. Radtke |  |  |

/s/ VALERIE M. WILLIAMS |  | Director | February 17, 2021
Valerie M. Williams |  |  |

117